v»EPA Inventory of U.S. Greenhouse Gas
      Emissions and Sinks: 1990-2007

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INVENTORY OF U.S. GREENHOUSE GAS
        EMISSIONS AND SINKS:
             199O-2OO7
               April 15,2009
       U.S. Environmental Protection Agency
         1200 Pennsylvania Avenue, N.W.
            Washington, DC 20460
                 U.S.A.

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Acknowledgments
         The Environmental Protection Agency would like to acknowledge the many individual and organizational
         contributors to this document, without whose efforts this report would not be complete. Although the complete
         list of researchers, government employees, and consultants who have provided technical and editorial support
is too long to list here, EPA's Office of Atmospheric Programs would like to thank some key contributors and reviewers
whose work has significantly improved this year's report.
    Work on fuel combustion and industrial process emissions was led by Leif Hockstad and Mausami Desai. Work on
methane emissions from the energy sector was directed by Lisa Hanle. Calculations for the waste sector were led by Melissa
Weitz. Tom Wirth directed work on the Agriculture chapter, and Kimberly Klunich directed work on the Land Use, Land-
Use Change, and Forestry chapter. Work on emissions of HFCs, PFCs, and SF6 was directed by Deborah Ottinger and Dave
Godwin. John Davies directed the work  on mobile combustion and transportation.
    Within the EPA, other Offices also contributed data, analysis, and technical review for this report. The Office of
Transportation and Air Quality and the Office of Air Quality Planning and Standards provided analysis and review for several
of the source categories addressed in this report. The Office of Solid Waste and the Office of Research and Development
also contributed analysis and research.
    The Energy Information Administration and the Department of Energy contributed invaluable data and analysis on
numerous energy-related  topics.  The U.S. Forest Service prepared the forest carbon inventory,  and the Department of
Agriculture's Agricultural Research Service and the Natural Resource Ecology Laboratory at Colorado State University
contributed leading research on nitrous oxide and carbon fluxes from soils.
    Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal Highway
Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of Commerce,
the National Agricultural Statistics Service, the Federal Aviation Administration, and the Department of Defense.
    We would also like to thank Marian Martin Van Pelt, Randy Freed, and their staff at ICF International's Energy,  Climate
and Transportation Practice, including Don Robinson, Diana Pape, Susan Asam, Michael Grant, Mark Flugge, Rubab Bhangu,
Robert Lanza, Chris Steuer, Lauren Pederson, Kamala Jayaraman, Jeremy  Scharfenberg, Mollie Averyt, Stacy Hetzel,
Lauren Smith, Zachary Schaffer, Vineet Aggarwal, Colin McGroarty, Hemant Mallya, Victoria Thompson, Jean Kim,
Erin Gray, Tristan Kessler, Sarah Menassian, Katrin Moffroid,  Veronica Kennedy, Aaron Beaudette, Nikhil Nadkarni,
Joseph Herr, and Toby Krasney for synthesizing this report and preparing many of the individual analyses. Eastern Research
Group, RTI International, Raven Ridge Resources, and Arcadis also provided significant analytical support.

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         The United States Environmental Protection Agency (EPA) prepares the official U.S. Inventory of Greenhouse Gas
         Emissions and Sinks to comply with existing commitments under the United Nations Framework Convention
         on Climate Change (UNFCCC).1 Under decision 3/CP.5 of the UNFCCC Conference of the Parties, national
inventories for UNFCCC Annex I parties should be provided to the UNFCCC Secretariat each year by April 15.
    In an effort to engage the public and researchers across the country, the EPA has instituted an annual public review
and comment process for this document. The availability of the draft document is announced via Federal Register Notice
and is posted on the EPA web site.2 Copies are also mailed upon request. The public comment period is generally limited
to 30 days; however, comments received after the closure of the public comment period are accepted and considered for
the next edition of this annual report.
1 See Article 4(l)(a) of the United Nations Framework Convention on Climate Change .
2 See .
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Table  of  Contents
Acknowledgments	      i

Table of Contents	      v

List of Tables, Figures, and Boxes	    viii
   Tables	    viii
   Figures	    xvii
   Boxes	    xix

Executive Summary	  ES-1
   ES.l. Background Information	   ES-2
   ES.2. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks  	   ES-3
   ES.3. Overview of Sector Emissions and Trends	  ES-12
   ES.4. Other Information	  ES-15

1. Introduction	    1-1
   1.1.  Background Information	    1-2
   1.2.  Institutional Arrangements	    1-7
   1.3.  Inventory Process	    1-7
   1.4.  Methodology and Data Sources	   1-10
   1.5.  Key Categories	   1-11
   1.6.  Quality Assurance and Quality Control (QA/QC)	   1-11
   1.7.  Uncertainty Analysis of Emission Estimates	   1-14
   1.8.  Completeness	   1-15
   1.9.  Organization of Report	   1-15

2. Trends in Greenhouse Gas Emissions	    2-1
   2.1.  Recent Trends in U.S. Greenhouse Gas Emissions	    2-1
   2.2.  Emissions by Economic Sector	   2-17
   2.3.  Indirect Greenhouse Gas Emissions (CO, NOX, NMVOCs, and SO2)	   2-28

3. Energy	    3-1
   3.1.  Fossil Fuel Combustion (IPCC Source Category 1A)	    3-4
   3.2.  Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A)	   3-31
   3.3.  Coal Mining (IPCC Source Category IBla)	   3-36
   3.4.  Abandoned Underground Coal Mines (IPCC Source Category IB la)	   3-38
   3.5.  Natural Gas Systems (IPCC Source Category lB2b)	   3-42
   3.6.  Petroleum Systems (IPCC Source Category lB2a)	   3-46
   3.7.  Incineration of Waste (IPCC Source Category 1A5)	   3-51
   3.8.  Energy Sources of Indirect Greenhouse Gas Emissions	   3-54

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    3.9.  International Bunker Fuels (IPCC Source Category 1: Memo Items)	   3-55
    3.10. Wood Biomass and Ethanol Consumption (IPCC Source Category 1A)	   3-59

4.  Industrial Processes	    3-1
    4.1.  Cement Production (IPCC Source Category 2A1)	    4-5
    4.2.  Lime Production (IPCC Source Category 2A2)	    4-7
    4.3.  Limestone and Dolomite Use (IPCC Source Category 2A3)	   4-10
    4.4.  Soda Ash Production and Consumption (IPCC Source Category 2A4)	   4-13
    4.5.  Ammonia Production (IPCC Source Category 2B1) and Urea Consumption	   4-15
    4.6.  Nitric Acid Production (IPCC Source Category 2B2)	   4-19
    4.7.  Adipic Acid Production (IPCC Source Category 2B3)	   4-20
    4.8.  Silicon Carbide Production (IPCC Source Category 2B4) and Consumption	   4-23
    4.9.  Petrochemical Production (IPCC Source Category 2B5)	   4-25
    4.10. Titanium Dioxide Production (IPCC Source Category 2B5)	   4-28
    4.11. Carbon Dioxide Consumption (IPCC Source Category 2B5)	   4-30
    4.12. Phosphoric Acid Production (IPCC Source Category  2B5)	   4-32
    4.13. Iron and Steel Production (IPCC Source Category 2C1) and Metallurgical Coke Production	   4-35
    4.14 Ferroalloy Production (IPCC Source Category 2C2)	   4-44
    4.15 Aluminum Production (IPCC Source Category 2C3)	   4-46
    4.16 Magnesium Production and Processing (IPCC Source Category 2C4)	   4-50
    4.17. Zinc Production (IPCC Source Category 2C5)	   4-53
    4.18. Lead Production (IPCC Source Category 2C5)	   4-56
    4.19. HCFC-22 Production (IPCC Source Category 2E1)	   4-57
    4.20. Substitution of Ozone Depleting Substances (IPCC Source Category 2F)	   4-59
    4.21. Semiconductor Manufacture (IPCC Source Category 2F6)	   4-63
    4.22. Electrical Transmission and Distribution (IPCC Source Category 2F7)	   4-69
    4.23. Industrial Sources of Indirect Greenhouse Gases	   4-74

5.  Solvent and Other Product Use	    5-1
    5.1.  Nitrous Oxide from Product Uses (IPCC Source Category 3D)	    5-1
    5.2.  Indirect Greenhouse Gas Emissions from Solvent Use	    5-3

6.  Agriculture	    6-1
    6.1.  Enteric Fermentation (IPCC Source Category 4A)	    6-2
    6.2.  Manure Management (IPCC Source Category 4B)	    6-7
    6.3.  Puce Cultivation (IPCC Source Category 4C)	   6-13
    6.4.  Agricultural Soil Management (IPCC Source Category 4D)	   6-18
    6.5.  Field Burning of Agricultural Residues (IPCC Source Category 4F)	   6-32

7.  Land Use, Land-Use Change, and Forestry	    7-1
    7.1.  Representation of the U.S. Land Base	    7-4
    7.2.  Forest Land Remaining Forest Land	   7-13
    7.3.  Land Converted to Forest Land (IPCC Source Category 5A2)	   7-27
    7.4.  Cropland Remaining Cropland (IPCC Source Category 5B1)	   7-27

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    7.5.  Land Converted to Cropland (IPCC Source Category 5B2)	   7-38
    7.6.  Grassland Remaining Grassland (IPCC Source Category 5C1)	   7-42
    7.7.  Land Converted to Grassland (IPCC Source Category 5C2)	   7-47
    7.8.  Wetlands Remaining Wetlands (IPCC Source Category 5D1)	   7-52
    7.9.  Settlements Remaining Settlements	   7-56
    7.10. Land Converted to Settlements (Source Category 5E2)	   7-61
    7.11. Other (IPCC Source Category 5G)	   7-61

8.  Waste	    8-1
    8.1.  Landfills (IPCC Source Category 6A1)	    8-2
    8.2.  Wastewater Treatment (IPCC Source Category 6B)	    8-6
    8.3.  Composting (IPCC Source Category 6D)	   8-17
    8.4.  Waste Sources of Indirect Greenhouse Gases	    8-19

9.  Other	    9-1

10. Recalculations and Improvements	  10-1

11. References	  11-1

List of Annexes (Annexes available on CD version only)
    ANNEX 1. Key Category Analysis
    ANNEX 2 Methodology and Data for Estimating C02 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 CLLj, N2O, and Indirect Greenhouse Gases from Stationary Combustion
    3.2.  Methodology for Estimating Emissions of CLL,, N2O, and Indirect Greenhouse Gases from Mobile Combustion
         and Methodology for and Supplemental Information on Transportation-Related GHG Emissions
    3.3.  Methodology for Estimating CH4 Emissions from Coal Mining
    3.4.  Methodology for Estimating CFL, and CO2 Emissions  from Natural Gas Systems
    3.5.  Methodology for Estimating CFL, and CO2 Emissions  from Petroleum Systems
    3.6.  Methodology for Estimating CO2 and N2O Emissions  from the 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 CFL, 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 Cropland
         and Grassland
    3.14. Methodology for Estimating CH4 Emissions from Landfills
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    ANNEX 4. IPCC Reference Approach for Estimating C02 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
    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

List of Tables, Figures, and Boxes
    Tables
    Table ES-1: Global Warming Potentials (100-Year Time Horizon) Used in This Report	   ES-3
    Table ES-2: Recent Trends in U.S.  Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)	   ES-5
    Table ES-3: CO2 Emissions from Fossil Fuel Combustion by
         Fuel Consuming End-Use Sector (Tg CO2 Eq.)	   ES-9
    Table ES-4: Recent Trends in U.S.  Greenhouse Gas Emissions and Sinks by
         Chapter/IPCC Sector (Tg CO2 Eq.)	  ES-13
    Table ES-5: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)	  ES-14
    Table ES-6: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)	  ES-15
    Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq.)	  ES-16
    Table ES-8: U.S. Greenhouse Gas Emissions by Economic Sector with
         Electricity-Related Emissions Distributed (Tg CO2 Eq.)	  ES-17
    Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100)	  ES-18
    Table ES-10: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)	  ES-19
    Table 1-1: Global Atmospheric Concentration, Rate of Concentration Change, and
         Atmospheric Lifetime (years) of Selected Greenhouse Gases	     1-3
    Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report	     1-7
    Table 1-3: Comparison of 100-Year GWPs	     1-8
    Table 1-4: Key Categories for  the United States (1990-2007)	    1-12
    Table 1-5: Estimated Overall Inventory Quantitative Uncertainty (Tg CO2 Eq. and Percent)	    1-14
    Table 1-6: IPCC Sector Descriptions	    1-16
    Table 1-7: List of Annexes	    1-17
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Table 2-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)  	     2-4
Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)	     2-6
Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by
     Chapter/IPCC Sector (Tg CO2 Eq.)	     2-8
Table 2-4: Emissions from Energy (Tg CO2 Eq.)	    2-10
Table 2-5: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)	    2-11
Table 2-6: Emissions from Industrial Processes (Tg CO2 Eq.)	    2-13
Table 2-7: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.)	    2-13
Table 2-8: Emissions from Agriculture (Tg CO2 Eq.) 	    2-14
Table 2-9: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)	    2-15
Table 2-10:  Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)	    2-16
Table 2-11:  Emissions from Waste (Tg CO2 Eq.)	    2-17
Table 2-12:  U.S. Greenhouse Gas Emissions Allocated to Economic Sectors
     (Tg CO2 Eq. and Percent of Total in 2007)	    2-18
Table 2-13:  Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)	    2-21
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 2007	    2-22
Table 2-15:  Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)	    2-24
Table 2-16:  Recent Trends in Various U.S. Data (Index  1990 = 100)	    2-27
Table 2-17:  Emissions of NOX, CO, NMVOCs, and SO2 (Gg)	    2-29
Table 3-1: CO2, CFL,, and N2O Emissions from Energy (Tg CO2 Eq.)	     3-2
Table 3-2: CO2, CH4, and N2O Emissions from Energy (Gg)	     3-3
Table 3-3: CO2, CK4, and N2O Emissions from Fossil Fuel Combustion (Tg CO2 Eq.)	     3-4
Table 3-4: CO2, CK4, and N2O Emissions from Fossil Fuel Combustion (Gg)	     3-4
Table 3-5: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.)	     3-5
Table 3-6: Annual Change in CO2 Emissions  from  Fossil Fuel Combustion for
     Selected Fuels and Sectors (Tg CO2 Eq. and Percent)	     3-6
Table 3-7: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by Sector (Tg CO2 Eq.)	     3-8
Table 3-8: CO2, CK4, and N2O Emissions from Fossil Fuel Combustion by
     End-Use Sector (Tg CO2 Eq.)	     3-9
Table 3-9: CO2 Emissions from Stationary Combustion (Tg CO2 Eq.)	    3-10
Table 3-10:  CFL, Emissions from Stationary Combustion (Tg CO2 Eq.)	    3-11
Table 3-11:  N2O Emissions from Stationary Combustion (Tg CO2 Eq.)	    3-12
Table 3-12:  CO2 Emissions from Fossil Fuel Combustion in Transportation
     End-Use Sector (Tg CO2 Eq.)	    3-15
Table 3-13:  CK4 Emissions from Mobile Combustion (Tg CO2 Eq.)	    3-17
Table 3-14:  N2O Emissions from Mobile Combustion (Tg CO2 Eq.)	    3-18
Table 3-15:  Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu)	    3-21
Table 3-16:  Carbon Intensity from All Energy Consumption by Sector (Tg CO2 Eq./QBtu)	    3-22
Table 3-17:  Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related
     Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq. and Percent)	    3-24
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Table 3-18: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from
     Energy-Related Stationary Combustion, Including Biomass (Tg CO2 Eq. and Percent)	    3-26
Table 3-19: Tier 2 Quantitative Uncertainty Estimates for CFLj and N2O Emissions from
     Mobile Combustion (Tg CO2 Eq. and Percent)	    3-29
Table 3-20: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2 Eq.)	    3-31
Table 3-21: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)	    3-32
Table 3-22: 2007 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions	    3-33
Table 3-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses
     of Fossil Fuels (Tg CO2 Eq.  and Percent)	    3-35
Table 3-24: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses
     of Fossil Fuels (Percent)	    3-35
Table 3-25: CK4 Emissions from Coal Mining (Tg CO2 Eq.)	    3-36
Table 3-26: CH4 Emissions from Coal Mining (Gg)	    3-36
Table 3-27: Coal Production (Thousand Metric Tons)	    3-37
Table 3-28: Tier 2 Quantitative Uncertainty Estimates for CFLj Emissions from
     Coal Mining (Tg CO2 Eq. and Percent)	    3-38
Table 3-29: CK4 Emissions from Abandoned Underground Coal Mines (Tg CO2 Eq.) 	    3-39
Table 3-30: CK4 Emissions from Abandoned Underground Coal Mines (Gg)  	    3-39
Table 3-31: Number of Gas sy Abandoned Mines Occurring in U. S. Basins Grouped by
     Class According to Post-abandonment State	    3-41
Table 3-32: Tier 2 Quantitative Uncertainty Estimates for CFLj Emissions from
     Abandoned Underground Coal Mines (Tg CO2 Eq. and Percent)	    3-42
Table 3-33: CK4 Emissions from Natural Gas Systems (Tg CO2 Eq.)	    3-42
Table 3-34: CK4 Emissions from Natural Gas Systems (Gg)	    3-42
Table 3-35: Non-combustion CO2 Emissions from Natural Gas Systems (Tg CO2 Eq.)	    3-43
Table 3-36: Non-combustion CO2 Emissions from Natural Gas Systems (Gg)	    3-43
Table 3-37: Tier 2 Quantitative Uncertainty Estimates for CFLj and Non-energy CO2 Emissions from
     Natural Gas Systems (Tg CO2 Eq. and Percent)	    3-45
Table 3-38: CK4 Emissions from Petroleum Systems (Tg CO2 Eq.)	    3-47
Table 3-39: CK4 Emissions from Petroleum Systems (Gg)	    3-47
Table 3-40: CO2 Emissions from Petroleum Systems (Tg CO2 Eq.)	    3-47
Table 3-41: CO2 Emissions from Petroleum Systems (Gg)	    3-47
Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CFLj and CO2 Emissions from
     Petroleum Systems (Tg CO2 Eq. and Percent)	    3-49
Table 3-43: Potential Emissions from CO2 Capture and Transport  (Tg CO2 Eq.)	    3-50
Table 3-44: Potential Emissions from CO2 Capture and Transport  (Gg)	    3-50
Table 3-45: CO2 and N2O Emissions from the Incineration of Waste (Tg CO2 Eq.)	    3-52
Table 3-46: CO2 and N2O Emissions from the Incineration of Waste (Gg)	    3-52
Table 3-47: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted	    3-53
Table 3-48: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from the
     Incineration of Waste (Tg CO2 Eq. and Percent)	    3-53

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Table 3-49: NOX, CO, and NMVOC Emissions from Energy-Related Activities (Gg)	   3-54
Table 3-50: CO2, CLL,, and N2O Emissions from International Bunker Fuels (Tg CO2 Eq.)	   3-56
Table 3-51: CO2, CLL,, and N2O Emissions from International Bunker Fuels (Gg)	   3-56
Table 3-52: Aviation Jet Fuel Consumption for International Transport (Million Gallons)	   3-57
Table 3-53: Marine Fuel Consumption for International Transport (Million Gallons)	   3-57
Table 3-54: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.)	   3-60
Table 3-55: CO2 Emissions from Wood Consumption by End-Use Sector (Gg)	   3-60
Table 3-56: CO2 Emissions from Ethanol Consumption (Tg CO2 Eq.)	   3-60
Table 3-57: CO2 Emissions from Ethanol Consumption (Gg)	   3-60
Table 3-58: Woody Biomass Consumption by Sector (Trillion Btu)	   3-61
Table 3-59: Ethanol Consumption by Sector (Trillion Btu)	   3-61
Table 4-1: Emissions from Industrial Processes (Tg CO2 Eq.)	    4-3
Table 4-2: Emissions from Industrial Processes (Gg)	    4-4
Table 4-3: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg)	    4-5
Table 4-4: Clinker Production (Gg)	    4-6
Table 4-5: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Cement Production (Tg CO2 Eq. and Percent)	    4-6
Table 4-6: CO2 Emissions from Lime Production (Tg CO2 Eq. and Gg)	    4-7
Table 4-7: Potential, Recovered, and Net CO2 Emissions from Lime Production (Gg)	    4-7
Table 4-8: High-Calcium- and Dolomitic-Quicklime, High-Calcium- and Dolomitic-Hydrated, and
     Dead-Burned-Dolomite Lime Production (Gg)	    4-8
Table 4-9: Adjusted Lime Production (Gg)	    4-9
Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Lime Production (Tg CO2 Eq. and Percent)	   4-10
Table 4-11: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.)	   4-11
Table 4-12: CO2 Emissions from Limestone & Dolomite Use (Gg)	   4-11
Table 4-13: Limestone and Dolomite Consumption  (Thousand Metric Tons)	   4-12
Table 4-14: Dolomitic Magnesium Metal Production Capacity (Metric Tons)	   4-12
Table 4-15: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Limestone and Dolomite Use (Tg CO2 Eq. and Percent)	   4-13
Table 4-16: CO2 Emissions from Soda Ash Production and Consumption (Tg CO2 Eq.)	   4-14
Table 4-17: CO2 Emissions from Soda Ash Production and Consumption (Gg)	   4-14
Table 4-18: Soda Ash Production and Consumption (Gg)	   4-15
Table 4-19: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Soda Ash Production and Consumption (Tg CO2 Eq. and Percent)	   4-15
Table 4-20: CO2 Emissions from Ammonia Production and Urea Consumption (Tg CO2 Eq.)	   4-16
Table 4-21: CO2 Emissions from Ammonia Production and Urea Consumption (Gg)	   4-16
Table 4-22: Ammonia Production, Urea Production, Urea Net Imports, and Urea Exports  (Gg)	   4-17
Table 4-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Ammonia Production and Urea Consumption (Tg CO2 Eq. and Percent)	   4-18
Table 4-24: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg)	   4-19
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    Table 4-25: Nitric Acid Production (Gg)	   4-20
    Table 4-26: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from
         Nitric Acid Production (Tg CO2 Eq. and Percent)	   4-20
    Table 4-27: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg)	   4-21
    Table 4-28: Adipic Acid Production (Gg)	   4-22
    Table 4-29: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from
         Adipic Acid Production (Tg CO2 Eq. and Percent)	   4-23
    Table 4-30: CO2 and CFLj Emissions from Silicon Carbide Production and Consumption (Tg CO2 Eq.)	   4-23
    Table 4-31: CO2 and CFLj Emissions from Silicon Carbide Production and Consumption (Gg)	   4-23
    Table 4-32: Production and Consumption of Silicon Carbide (Metric Tons)	   4-24
    Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CH4 and CO2 Emissions from
         Silicon Carbide Production and Consumption (Tg CO2 Eq. and Percent)	   4-24
    Table 4-34: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.)	   4-25
    Table 4-35: CO2 and CFLj Emissions from Petrochemical Production (Gg)	   4-25
    Table 4-36: Production of Selected Petrochemicals (Thousand Metric Tons)	   4-26
    Table 4-37: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock
         (Secondary Feedstock) Consumption (Thousand Metric Tons)	   4-27
    Table 4-38: Tier 2 Quantitative Uncertainty Estimates for CO2 and CK4 Emissions from Petrochemical
         Production and CO2 Emissions from Carbon Black Production (Tg CO2 Eq. and Percent)	   4-27
    Table 4-39: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg)	   4-28
    Table 4-40: Titanium Dioxide Production (Gg)	   4-29
    Table 4-41: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
         Titanium Dioxide Production (Tg CO2 Eq. and Percent)	   4-29
    Table 4-42: CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and Gg)	   4-30
    Table 4-43: CO2 Production (Gg CO2) and the Percent Used for Non-EOR Applications for
         Jackson Dome and Bravo Dome	   4-31
    Table 4-44: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
         CO2 Consumption  (Tg CO2 Eq. and Percent)	   4-32
    Table 4-45: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg)	   4-33
    Table 4-46: Phosphate Rock Domestic Production, Exports, and Imports (Gg)	   4-33
    Table 4-47: Chemical Composition of Phosphate Rock (Percent by Weight)	   4-34
    Table 4-48: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
         Phosphoric Acid Production  (Tg CO2 Eq. and Percent)	   4-35
    Table 4-49: CO2 and CH4 Emissions from Metallurgical Coke Production  (Tg CO2 Eq.)	   4-37
    Table 4-50: CO2 and CK4 Emissions from Metallurgical Coke Production  (Gg)	   4-37
    Table 4-51: CO2 Emissions from Iron and Steel Production (Tg CO2 Eq.)	   4-38
    Table 4-52: CO2 Emissions from Iron and Steel Production (Gg)	   4-38
    Table 4-53: CFLj Emissions from Iron and Steel Production (Tg CO2 Eq.)	   4-38
    Table 4-54: CFLj Emissions from Iron and Steel Production (Gg)	   4-38
xii

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Table 4-55: Material Carbon Contents for Metallurgical Coke Production	    4-39
Table 4-56: CFL, Emission Factor for Metallurgical Coke Production (g CFL/metric ton)	    4-39
Table 4-57: Production and Consumption Data for the Calculation of CO2 and CFL, Emissions from
     Metallurgical Coke Production (Thousand Metric Tons)	    4-39
Table 4-58: Production and Consumption Data for the Calculation of CO2 Emissions from
     Metallurgical Coke Production (million ft3)	    4-40
Table 4-59: CO2 Emission Factors for Sinter Production and Direct Reduced Iron Production	    4-40
Table 4-60: Material Carbon Contents for Iron and Steel Production	    4-40
Table 4-61: CFL, Emission Factors for Sinter and Pig Iron Production	    4-41
Table 4-62: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from
     Iron and Steel Production (Thousand Metric Tons)	    4-41
Table 4-63: Production and Consumption Data for the Calculation of CO2 Emissions from Iron and
     Steel Production (million ft3 unless otherwise specified)	    4-42
Table 4-64: Tier 2 Quantitative Uncertainty Estimates for CO2 and CFL, Emissions from Iron and
     Steel Production (Tg CO2 Eq. and Percent)	    4-43
Table 4-65: CO2 and CH4 Emissions from Ferroalloy Production (Tg CO2 Eq.)	    4-44
Table 4-66: CO2 and CK4 Emissions from Ferroalloy Production (Gg)	    4-44
Table 4-67: Production of Ferroalloys (Metric Tons)	    4-45
Table 4-68: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from
     Ferroalloy Production (Tg CO2 Eq. and Percent)	    4-46
Table 4-69: CO2 Emissions from Aluminum Production (Tg CO2 Eq. and Gg)	    4-47
Table 4-70: PFC Emissions from Aluminum Production (Tg CO2 Eq.)	    4-47
Table 4-71: PFC Emissions from Aluminum Production (Gg)	    4-47
Table 4-72: Production of Primary Aluminum (Gg)	    4-49
Table 4-73: Tier 2 Quantitative Uncertainty Estimates for CO2 and PFC Emissions from
     Aluminum Production (Tg CO2 Eq. and Percent)	    4-50
Table 4-74: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg)	    4-50
Table 4-75: SF6 Emission Factors (kg SF6 per metric ton of Magnesium)	    4-51
Table 4-76: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from
     Magnesium Production and Processing (Tg CO2 Eq. and Percent)	    4-52
Table 4-77: CO2 Emissions from Zinc Production (Tg CO2 Eq. and Gg)	    4-53
Table 4-78: Zinc Production (Metric Tons)	    4-55
Table 4-79: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Zinc Production (Tg CO2 Eq. and Percent)	    4-56
Table 4-80: CO2 Emissions from Lead Production (Tg  CO2 Eq. and Gg)	    4-56
Table 4-81: Lead Production (Metric Tons)	    4-57
Table 4-82: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
     Lead Production (Tg CO2 Eq. and Percent)	    4-57
Table 4-83: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg)	    4-58
Table 4-84: HCFC-22 Production (Gg)	    4-59
                                                                                                    xiii

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    Table 4-85: Quantitative Uncertainty Estimates for HFC-23 Emissions from
         HCFC-22 Production (Tg CO2 Eq. and Percent)	    4-59
    Table 4-86: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.)	    4-60
    Table 4-87: Emissions of HFCs and PFCs from ODS Substitution (Mg)	    4-60
    Table 4-88: Emissions of FfFCs and PFCs from ODS Substitutes (Tg CO2 Eq.) by Sector	    4-61
    Table 4-89: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from
         ODS Substitutes (Tg CO2 Eq. and Percent)	    4-63
    Table 4-90: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.)	    4-64
    Table 4-91: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)	    4-64
    Table 4-92: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from
         Semiconductor Manufacture (Tg CO2 Eq. and Percent)	    4-68
    Table 4-93: SF6 Emissions from Electric Power Systems and Electrical Equipment
         Manufacturers (Tg CO2 Eq.)	    4-69
    Table 4-94: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Gg)	    4-69
    Table 4-95: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission
         and Distribution (Tg CO2 Eq. and Percent)	    4-72
    Table 4-96: 2007 Potential and Actual Emissions of HFCs, PFCs, and SF6 from
         Selected Sources (Tg CO2 Eq.)	    4-73
    Table 4-97: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)	    4-74
    Table 5-1: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg)	     5-1
    Table 5-2: N2O Production (Gg)	     5-2
    Table 5-3: N2O Emissions from N2O Product Usage (Tg CO2 Eq. and Gg)	     5-2
    Table 5-4: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions From N2O Product Usage
          (Tg CO2 Eq. and Percent)	     5-3
    Table 5-5: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)	     5-4
    Table 6-1: Emissions from Agriculture (Tg CO2 Eq.)  	     6-1
    Table 6-2: Emissions from Agriculture (Gg)  	     6-2
    Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.)	     6-3
    Table 6-4: CK4 Emissions from Enteric Fermentation (Gg)	     6-3
    Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CK4 Emissions from
         Enteric Fermentation (Tg CO2 Eq. and Percent)	     6-5
    Table 6-6: CFLj and N2O Emissions from Manure Management (Tg CO2 Eq.)	     6-8
    Table 6-7: CH4 and N2O Emissions from Manure Management (Gg)	     6-9
    Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O (Direct and Indirect)
         Emissions from Manure Management (Tg CO2 Eq. and Percent)	    6-12
    Table 6-9: CH4 Emissions from Puce Cultivation (Tg CO2 Eq.)	    6-14
    Table 6-10: CH4 Emissions from Puce Cultivation (Gg)	    6-15
    Table 6-11: Puce Areas Harvested (Hectares)	    6-16
    Table 6-12: Ratooned Area as Percent of Primary Growth Area	    6-16
    Table 6-13: Non-USDA Data Sources for Puce Harvest Information	    6-17
xiv

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Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from
     Rice CultivationManure Management (Tg CO2 Eq. and Percent)	    6-17
Table 6-15: N2O Emissions from Agricultural Soils (Tg CO2 Eq.)	    6-20
Table 6-16: N2O Emissions from Agricultural Soils (Gg)	    6-20
Table 6-17: Direct N2O Emissions from Agricultural Soils by Land Use Type and
     N Input Type (Tg CO2 Eq.)	    6-20
Table 6-18: Indirect N2O Emissions from all Land-Use Types (Tg CO2 Eq.)	    6-21
Table 6-19: Quantitative Uncertainty Estimates of N2O Emissions from
     Agricultural Soil Management in 2007 (Tg CO2 Eq. and Percent)	    6-30
Table 6-20: CH4 and N2O Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.)	    6-33
Table 6-21: CK4, N2O, CO, and NOX Emissions from Field Burning of Agricultural Residues (Gg)	    6-33
Table 6-22: Agricultural Crop Production (Gg of Product)	    6-35
Table 6-23: Percent of Rice Area Burned by State	    6-35
Table 6-24: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues	    6-36
Table 6-25: Greenhouse Gas Emission Ratios and Conversion Factors	    6-36
Table 6-26: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from
     Field Burning of Agricultural Residues  (Tg CO2 Eq. and Percent)	    6-37
Table 7-1: Net CO2 Flux from Carbon Stock Changes in Land Use,
     Land-Use Change, and Forestry (Tg CO2 Eq.)	     7-2
Table 7-2: Net CO2 Flux from Carbon Stock Changes in Land Use,
     Land-Use Change, and Forestry (Tg C)	     7-2
Table 7-3: Emissions from Land Use, Land-Use Change,  and Forestry (Tg CO2 Eq.)	     7-3
Table 7-4: Emissions from Land Use, Land-Use Change,  and Forestry (Gg)	     7-3
Table 7-5: Land Use, Land-Use Change, and Forestry on Managed Land (Thousands of Hectares)	     7-5
Table 7-6: Net Annual Changes in C Stocks (Tg CO2/yr) in Forest and Harvested Wood Pools	    7-16
Table 7-7: Net Annual Changes in C Stocks (Tg C/yr) in Forest and Harvested Wood Pools	    7-16
Table 7-8: Forest Area (1000 ha) and C Stocks (Tg C) in Forest and Harvested Wood Pools	    7-17
Table 7-9: Estimates of CO2 (Tg/yr) Emissions for the Lower 48 States and Alaska	    7-18
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)	    7-21
Table 7-11: Estimated Non-CO2 Emissions from Forest Fires (Tg CO2 Eq.) for U.S. Forests	    7-24
Table 7-12: Estimated Non-CO2 Emissions from Forest Fires (Gg) for U.S. Forests	    7-24
Table 7-13: Estimated Carbon Released from Forest Fires for U.S. Forests	    7-24
Table 7-14: Quantitative Uncertainty Estimates of Non-CO2 Emissions from
     Forest Fires in Forest Land Remaining Forest Land (Tg CO2 Eq. and Percent)	    7-25
Table 7-15: N2O Fluxes from Soils in Forest Land Remaining Forest Land (Tg CO2 Eq. and Gg N2O) 	    7-26
Table 7-16: Quantitative Uncertainty Estimates of N2O Fluxes from Soils in
     Forest Land Remaining Forest Land (Tg CO2 Eq. and Percent)	    7-27
Table 7-17: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg CO2 Eq.)	    7-29
Table 7-18: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg C)	    7-29
                                                                                                     XV

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    Table 7-19: Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within
         Cropland Remaining Cropland (Tg CO2 Eq. and Percent)	   7-33
    Table 7-20: CO2 Emissions from Liming of Agricultural Soils (Tg CO2 Eq.)	   7-35
    Table 7-21: CO2 Emissions from Liming of Agricultural Soils (Tg C)	   7-35
    Table 7-22: Applied Minerals (Million Metric Tons)	   7-35
    Table 7-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
         Liming of Agricultural Soils  (Tg CO2 Eq. and Percent)	   7-36
    Table 7-24: CO2Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg CO2 Eq.)	   7-37
    Table 7-25: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg C)	   7-37
    Table 7-26: Applied Urea (Million Metric Tons)	   7-37
    Table 7-27: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from
         Urea Fertilization (Tg CO2 Eq. and Percent)	   7-38
    Table 7-28: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg CO2 Eq.)	   7-39
    Table 7-29: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg C)	   7-39
    Table 7-30: Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within
         Land Converted to Cropland (Tg CO2 Eq. and Percent)	   7-42
    Table 7-31: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg CO2 Eq.)	   7-43
    Table 7-32: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg C)	   7-43
    Table 7-33: Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within
         Grassland Remaining Grassland (Tg CO2 Eq. and Percent)	   7-46
    Table 7-34: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg CO2 Eq.)	   7-48
    Table 7-35: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg C)	   7-48
    Table 7-36: Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within
         Land Converted to Grassland (Tg CO2 Eq. and Percent)	   7-51
    Table 7-37: Emissions from Lands Undergoing Peat  Extraction (Tg CO2 Eq.)	   7-53
    Table 7-38: Emissions from Lands Undergoing Peat  Extraction (Gg)	   7-53
    Table 7-39: Peat Production of Lower 48 States (in thousands of Metric Tons)	   7-53
    Table 7-40: Peat Production of Alaska (in thousands  of Cubic Meters)	   7-54
    Table 7-41: Tier-2 Quantitative Uncertainty Estimates for CO2 and N2O Emissions from
         Lands Undergoing Peat Extraction	   7-55
    Table 7-42: Net C Flux from Urban Trees (Tg CO2 Eq. and Tg C) 	   7-56
    Table 7-43: C Stocks (Metric Tons C), Annual C Sequestration (Metric Tons C/yr), Tree Cover (Percent),
         and Annual C Sequestration per Area of Tree Cover (kg C/m2 cover-yr) for 15 U.S. Cities	   7-58
    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)	   7-59
    Table 7-45: N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2 Eq. and Gg N2O)	   7-60
    Table 7-46: Quantitative Uncertainty Estimates of N2O Emissions from Soils in
         Settlements Remaining Settlements (Tg CO2 Eq. and Percent)	   7-61
    Table 7-47: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg CO2 Eq.)	   7-62
    Table 7-48: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C)	   7-62
xvi

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Table 7-49: Moisture Content (%), C Storage Factor, Proportion of Initial C Sequestered (%),
     Initial C Content (%), and Half-Life (years) for Landfilled Yard Trimmings and
     Food Scraps in Landfills	    7-63
Table 7-50: C Stocks in Yard Trimmings and Food Scraps in Landfills (Tg C)	    7-64
Table 7-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and
     Food Scraps in Landfills (Tg CO2 Eq. and Percent)	    7-65
Table 8-1: Emissions from Waste (Tg CO2 Eq.)	     8-1
Table 8-2: Emissions from Waste (Gg)	     8-2
Table 8-3: CFL, Emissions from Landfills (Tg CO2 Eq.)	     8-3
Table 8-4: CH4 Emissions from Landfills (Gg)	     8-3
Table 8-5: Tier 2 Quantitative Uncertainty Estimates for CK4 Emissions from Landfills
     (Tg CO2 Eq. and Percent)	     8-5
Table 8-6: CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.)	     8-7
Table 8-7: CFL, and N2O Emissions from Domestic and Industrial Wastewater Treatment (Gg)	     8-7
Table 8-8: U.S. Population (Millions) and Domestic Wastewater BOD5 Produced (Gg)	     8-9
Table 8-9: Industrial Wastewater CH4 Emissions by Sector for 2007	     8-9
Table 8-10: U.S. Pulp and Paper; Meat and Poultry; Vegetables, Fruits and Juices Production;
     and Fuels Production (Tg)	    8-10
Table 8-11: Variables Used to Calculate Percent Wastewater Treated Anaerobically by Industry	    8-11
Table 8-12: Wastewater How (m3/ton) and BOD Production (g/L) for U.S. Vegetables,
     Fruits and Juices Production	    8-12
Table 8-13: U.S. Population (Millions), Available Protein [kg/(person-year)], and
     Protein Consumed [kg/(person-year)]	    8-15
Table 8-14: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from
     Wastewater Treatment (Tg CO2 Eq. and Percent)	    8-16
Table 8-15: CFL, and N2O Emissions from Composting (Tg CO2 Eq.)	    8-18
Table 8-16: CFL, and N2O Emissions from Composting (Gg)	    8-18
Table 8-17: U.S. Waste Composted (Gg)	    8-19
Table 8-18: Tier 1 Quantitative Uncertainty Estimates for Emissions from Composting
     (Tg CO2 Eq. and Percent)	    8-19
Table 8-19: Emissions of NOX, CO, and NMVOCs from Waste (Gg)	    8-19
Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.) 	    10-3
Table 10-2: Revisions to Net Flux of CO2 to the Atmosphere from Land Use,
     Land-Use Change, and Forestry (Tg CO2 Eq.)	    10-5
Figures
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas	    ES-4
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions	    ES-4
Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990	    ES-4
Figure ES-4: 2007 Greenhouse Gas Emissions by Gas 	    ES-7
Figure ES-5: 2007 Sources of CO2 Emissions	    ES-7
Figure ES-6: 2007 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	    ES-8
                                                                                                    xvii

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    Figure ES-7: 2007 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion	    ES-8
    Figure ES-8: 2007 Sources of CFL, Emissions	  ES-10
    Figure ES-9: 2007 Sources of N2O Emissions	  ES-11
    Figure ES-10: 2007 Sources of HFCs, PFCs, and SF6 Emissions	  ES-12
    Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector	  ES-12
    Figure ES-12: 2007 U.S. Energy Consumption by Energy Source	  ES-13
    Figure ES-13: Emissions Allocated to Economic Sectors	  ES-16
    Figure ES-14 Emissions with Electricity Distributed to Economic Sectors	  ES-17
    Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product	  ES-18
    Figure ES-16: 2007 Key Categories	  ES-20
    Figure 2-1: U.S. Greenhouse Gas Emissions by Gas	     2-1
    Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions	     2-2
    Figure 2-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990	     2-2
    Figure 2-4: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector	     2-8
    Figure 2-5: 2007 Energy Chapter Greenhouse Gas  Sources	     2-8
    Figure 2-6: 2007 U.S. Fossil Carbon Hows (Tg CO2 Eq.)	     2-9
    Figure 2-7: 2007 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	     2-9
    Figure 2-8: 2007 End-Use Sector Emissions from Fossil Fuel Combustion	    2-10
    Figure 2-9: 2007 Industrial Processes Chapter Greenhouse Gas  Sources	    2-12
    Figure 2-10:  2007 Agriculture Chapter Greenhouse Gas Emision Sources	    2-14
    Figure 2-11:  2007 Waste Chapter Greenhouse Gas  Emission Sources	    2-16
    Figure 2-12:  Emissions Allocated to Economic Sectors	    2-18
    Figure 2-13:  Emissions with Electricity Distributed to Economic Sectors	    2-21
    Figure 2-14:  U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product	    2-27
    Figure 3-1: 2007 Energy Chapter Greenhouse Gas  Emission Sources	     3-1
    Figure 3-2: 2007 U.S. Fossil Carbon Hows (Tg CO2 Eq.)	     3-2
    Figure 3-3: 2007 U.S. Energy Consumption by Energy Source	     3-6
    Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)	     3-6
    Figure 3-5: 2007 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	     3-6
    Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1950-2007)	     3-7
    Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1950-2007)	     3-7
    Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the
          United States (1974-2007)	     3-7
    Figure 3-9: Electricity Generation Retail Sales by End-Use Sector (1974-2007)	    3-11
    Figure 3-10:  Industrial Production Indices (Index 2002=100)	    3-13
    Figure 3-11:  Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2007 ....    3-16
    Figure 3-12:  Sales of New Passenger Cars and Light-Duty Trucks, 1990-2007	    3-16
    Figure 3-13:  Mobile Source CFLj and N2O Emissions	    3-17
    Figure 3-14:  U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita
          and Per Dollar GDP	    3-22
xviii

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Figure 4-1: 2007 Industrial Processes Chapter Greenhouse Gas Emission Sources	    4-1
Figure 6-1: 2007 Agriculture Chapter Greenhouse Gas Emission Sources	    6-1
Figure 6-2: Sources and Pathways of N that Result in N2O Emissions from
      Agricultural Soil Management	   6-19
Figure 6-3: Major Crops, Average Annual Direct N2O Emissions by State,
      Estimated Using the DAYCENT Model, 1990-2007 (Tg CO2 Eq./year)	   6-22
Figure 6-4: Grasslands, Average Annual Direct N2O Emissions by State,
      Estimated Using the DAYCENT Model, 1990-2007 (Tg CO2 Eq./year)	   6-22
Figure 6-5: Major Crops, Average Annual N Losses Leading to Indirect N2O Emissions by State,
      Estimated Using the DAYCENT Model, 1990-2007 (Gg N/year)	   6-23
Figure 6-6: Grasslands, Average Annual N Losses Leading to Indirect N2O Emissions, by State,
      Estimated Using the DAYCENT Model, 1990-2007 (Gg N/year)	   6-23
Figure 6-7: Comparison of Measured Emissions at Field Sites with Modeled Emissions
      Using the DAYCENT Simulation Model	   6-31
Figure 7-1: Percent of Total Land Area in the General Land Use Categories for 2007	    7-6
Figure 7-2: Forest Sector Carbon Pools and Hows	   7-14
Figure7-3: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools	   7-15
Figure 7-4: Average C Density in the Forest Tree Pool in the Conterminous United States, 2008	   7-17
Figure 7-5: Total Net Annual CO2 Flux For Mineral Soils Under Agricultural Management within States,
      2007, Cropland Remaining Cropland	   7-29
Figure 7-6: Total Net Annual CO2 Flux For Organic Soils Under Agricultural Management within States,
      2007, Cropland Remaining Cropland	   7-30
Figure 7-7: Total Net Annual CO2 Flux For Mineral Soils Under Agricultural Management within States,
      2007, Land Converted to Cropland	   7-40
Figure 7-8: Total Net Annual CO2 Flux For Organic Soils Under Agricultural Management within States,
      2007, Land Converted to Cropland	   7-40
Figure 7-9: Total Net Annual CO2 Flux For Mineral Soils Under Agricultural Management within States,
      2007, Grassland Remaining Grassland	   7-44
Figure 7-10: Total Net Annual CO2 Flux For Organic Soils Under Agricultural Management within States,
      2007, Grassland Remaining Grassland	   7-44
Figure 7-11: Total Net Annual CO2 Flux For Mineral Soils Under Agricultural Management within States,
      2007, Land Converted to Grassland	   7-49
Figure 7-12: Total Net Annual CO2 Flux For Organic Soils Under Agricultural Management within States,
      2007, Land Converted to Grassland	   7-49
Figure 8-1: 2007 Waste Chapter Greenhouse Gas  Emission Sources	    8-1
Boxes
Box ES-1: Recalculations of Inventory Estimates	   ES-2
Box ES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data	  ES-18
Box 1-1: The IPCC Fourth Assessment Report and Global Warming Potentials	    1-8
Box 1-2: IPCC Reference Approach	   1-10
                                                                                                    xix

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    Box 2-1: Methodology for Aggregating Emissions by Economic Sector	   2-26
    Box 2-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data	   2-27
    Box 2-3: Sources and Effects of Sulfur Dioxide	   2-28
    Box 3-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends	    3-7
    Box 3-2: Carbon Intensity of U.S. Energy Consumption	   3-21
    Box 3-3: Carbon Dioxide Transport, Injection, and Geological Storage	   3-50
    Box 4-1: Potential Emission Estimates of FfFCs, PFCs, and SF6	   4-73
    Box 6-1: Tier 1 vs. Tier 3 Approach for Estimating N2O Emissions	   6-24
    Box 6-2: Comparison of Tier 2 U.S. Inventory Approach and IPCC (2006) Default Approach	   6-36
    Box 7-1: CO2 Emissions from Forest Fires	   7-18
    Box 7-2: Tier 3 Inventory for Soil C Stocks Compared to Tier 1 or 2 Approaches	   7-32
    Box 8-1: Biogenic Emissions and Sinks of Carbon	    8-6
XX

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Executive   Summary
           An emissions inventory that identifies and quantifies a country's primary anthropogenic1 sources and sinks of
           greenhouse gases is essential for addressing climate change. This inventory adheres to both (1) a comprehensive
           and detailed set of methodologies for estimating sources and sinks of anthropogenic greenhouse gases, and (2)
a common and consistent mechanism that enables Parties to the United Nations Framework Convention on Climate Change
(UNFCCC) to compare the relative contribution of different emission sources and greenhouse gases to climate change.
    In 1992, the United States signed and ratified the UNFCCC. As stated in Article 2 of the UNFCCC, "The ultimate
objective of this Convention and any related legal instruments that the Conference of the Parties may adopt is to achieve, in
accordance with the relevant provisions of the Convention, stabilization of greenhouse gas concentrations in the atmosphere
at a level that would prevent dangerous anthropogenic interference with the climate system. Such a level should be achieved
within a time-frame sufficient to allow ecosystems to adapt naturally to climate change, to ensure that food production is
not threatened and to enable economic development to proceed in a sustainable manner."2
    Parties to the Convention, by ratifying, "shall develop, periodically update, publish and make available...national
inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the
Montreal Protocol, using comparable methodologies..."3 The United States views this report as an opportunity to fulfill
these commitments.
    This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990 through
2007. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC Parties, the estimates presented
here were calculated using methodologies consistent with those recommended in the Revised 1996IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997), the IPCC Good Practice Guidance and Uncertainty
Management  in National  Greenhouse Gas Inventories (IPCC 2000), and the IPCC Good Practice Guidance for Land
Use, Land-Use Change, and Forestry (IPCC 2003). Additionally, the U.S. emissions inventory has begun to incorporate
new methodologies and data from the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006). The
structure of this report is consistent with the UNFCCC guidelines for inventory reporting.4 For most source categories, the
Intergovernmental Panel on Climate Change (IPCC) methodologies were expanded, resulting in a more comprehensive
and detailed estimate of emissions.
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).
2Article 2 of the UNFCCC published by the UNEP/WMO Information Unit on Climate Change. See .
3 Article 4(l)(a) of the UNFCCC (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 .
                                                                                   Executive Summary  ES-1

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Box ES-1: Recalculations of Inventory Estimates
      Each year, emission and sink estimates are recalculated and revised for all years in the Inventory of U.S. Greenhouse Gas Emissions and
  Sinks, as attempts are made to improve both the analyses themselves, through the use of better methods or data, and the overall usefulness
  of the report. In this effort, the United States follows the IPCC Good Practice Guidance (IPCC 2000), which states, regarding recalculations
  of the time series, "It is good practice to recalculate historic emissions when methods are changed or refined, when  new source categories
  are included in the national inventory, or when errors in the estimates are identified and corrected." In general, recalculations are made to the
  U.S. greenhouse  gas emission estimates either to incorporate new methodologies or,  most commonly, to update recent historical data.
      In each Inventory report, the results of all methodology changes and historical data updates are presented  in the "Recalculations
  and Improvements" chapter; detailed descriptions of each recalculation are contained  within each source's description contained in the
  report, if applicable. In general, when methodological changes have been implemented, the entire time series (in the  case of the most
  recent Inventory  report,  1990 through 2006) has been recalculated to reflect the change, per IPCC Good Practice Guidance. Changes
  in historical data are generally the result of changes in statistical data supplied by other agencies. References for the data are provided
  for  additional information.
ES.1.   Background Information

    Naturally occurring greenhouse gases include water
vapor, carbon dioxide (CO2), methane (CK4), nitrous oxide
(N2O), and ozone (O3). Several  classes of halogenated
substances that contain fluorine, chlorine, or bromine are also
greenhouse gases, but they are, for the most part, solely a
product of industrial activities. Chlorofluorocarbons (CFCs)
and hydrochlorofluorocarbons (HCFCs) are halocarbons that
contain chlorine, while halocarbons that contain bromine
are referred  to as bromofluorocarbons (i.e., halons). As
stratospheric ozone depleting substances,  CFCs, HCFCs,
and halons are covered under the Montreal Protocol on
Substances that Deplete the Ozone Layer. The  UNFCCC
defers to this earlier international treaty. Consequently,
Parties to the UNFCCC are not required to include these
gases in their national greenhouse gas emission inventories.5
Some other fluorine-containing halogenated substances —
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and
sulfur hexafluoride (SF6)—do not deplete stratospheric ozone
but are potent greenhouse gases. These latter substances are
addressed by the UNFCCC and accounted for in national
greenhouse gas emission inventories.
5 Emission estimates of CFCs, HCFCs, halons and other ozone depleting
substances are included in the annexes of this Inventory for informational
purposes.
    There are also several gases that do not have a direct
global warming effect but indirectly affect terrestrial and/or
solar radiation absorption by influencing  the formation or
destruction of greenhouse gases, including tropospheric and
stratospheric ozone. These gases include carbon monoxide
(CO), oxides of nitrogen (NOX), and non-CFLj volatile organic
compounds (NMVOCs). Aerosols, which  are  extremely
small particles or liquid droplets, such as those produced by
sulfur dioxide (SO2) or elemental carbon emissions, can also
affect the absorptive characteristics of the  atmosphere.
    Although the  direct greenhouse gases CO2, CK4, and
N2O occur naturally in the atmosphere, human activities have
changed their atmospheric concentrations.  From  the pre-
industrial era (i.e., ending about 1750) to 2005, concentrations
of these greenhouse gases have increased globally by 36,148,
and 18 percent, respectively (IPCC 2007).
    Beginning in  the 1950s, the use of  CFCs  and other
stratospheric ozone depleting substances  (ODS) increased
by nearly 10 percent per year until the mid-1980s, when
international concern about ozone depletion  led to the
entry  into force of the Montreal Protocol. Since then, the
production of ODS is being phased out. In recent years, use
of ODS substitutes such as HFCs and PFCs has grown as
they begin to be phased in as replacements for  CFCs and
HCFCs. Accordingly, atmospheric concentrations  of these
substitutes have been growing (IPCC 2007).
ES-2   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Global Warming Potentials
    Gases in the atmosphere can contribute to the greenhouse
effect both directly and indirectly. Direct effects occur when
the gas  itself absorbs radiation. Indirect radiative forcing
occurs when chemical transformations  of the substance
produce other greenhouse gases, when a gas influences
the atmospheric lifetimes of other gases, and/or when a
gas affects atmospheric processes that alter  the radiative
balance of the earth (e.g., affect cloud formation or albedo).6
The IPCC developed the Global Warming Potential (GWP)
concept to compare the ability of each greenhouse gas to trap
heat in the atmosphere relative to another gas.
    The GWP of a greenhouse gas is defined as the ratio of
the time-integrated radiative forcing from the instantaneous
release of 1 kilogram (kg) of a trace  substance relative to
that of 1 kg of a reference gas (IPCC 2001). Direct radiative
effects occur when the gas itself is a  greenhouse gas. The
reference gas used is CO2, and therefore GWP-weighted
emissions are measured in teragrams (or million metric
tons) of CO2 equivalents (Tg CO2 Eq.).7'8 All gases in this
Executive Summary are presented in units of Tg CO2 Eq.
    The UNFCCC  reporting guidelines for national
inventories were updated in 2006,9 but continue to require
the use of GWPs from the IPCC Second Assessment Report
(SAR) (IPCC 1996).  This requirement ensures that current
estimates of aggregate greenhouse gas emissions  for 1990
to 2007 are consistent with estimates developed prior to the
publication of the IPCC Third Assessment Report (TAR)
and the IPCC Fourth Assessment Report (AR4). Therefore,
to comply with international reporting standards under the
UNFCCC, official emission  estimates are reported by the
United States using  SAR  GWP values. All estimates  are
provided throughout the report in both CO2 equivalents and
unweighted units. A comparison of emission values using the
SAR GWPs versus the TAR and AR4 GWPs can be found in
Chapter 1 and, in more detail, in Annex 6.1 of this report. The
GWP values used in this report are listed in Table ES-1.
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
C^FIO
CeF-14
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
  Source: IPCC (1996)
  * The CH4 GWP includes the direct effects and those indirect effects due
   to the production of tropospheric ozone and stratospheric water vapor.
   The indirect effect due to the production of C02 is not included.
    Global warming potentials are not provided for CO,
NOX, NMVOCs, SO2, and aerosols  because there  is no
agreed-upon method to estimate the contribution of gases that
are short-lived in the atmosphere, spatially variable, or have
only indirect effects on radiative forcing (IPCC 1996).

ES.2.  Recent Trends in
U.S. Greenhouse Gas Emissions
and Sinks
6 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.
7 Carbon comprises 12/44'hs of carbon dioxide by weight.
8 One teragram is equal to 1012 grams (g) or one million metric tons.
9 See .
    In 2007, total U.S. greenhouse gas emissions were
7,150.1 Tg CO2 Eq. Overall, total U.S. emissions have risen
by 17 percent from 1990 to 2007. Emissions rose from 2006
to 2007, increasing by 1.4 percent (99.0 Tg CO2 Eq.). The
following factors were primary contributors to this increase:
(1) cooler winter and warmer summer conditions in 2007
than in 2006 increased the demand for heating fuels and
contributed to the increase in the demand for electricity, (2)
increased consumption of fossil fuels to generate electricity
and (3) a significant decrease (14.2 percent) in hydropower
generation used to meet this demand.
                                                                                     Executive Summary  ES-3

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    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 2007.
    Figure ES-4 illustrates the relative contribution of the
direct greenhouse gases to total U.S.  emissions in 2007.
The primary greenhouse gas emitted by human activities
in the United States was CO2, representing approximately
85.4 percent of total greenhouse gas emissions. The largest
source of CO2, and of overall greenhouse gas  emissions,
was fossil fuel combustion. CH4 emissions, which have
declined from 1990 levels,  resulted primarily from
enteric fermentation associated with domestic livestock,
decomposition of wastes in landfills, and natural gas
systems. Agricultural soil management and mobile source
fuel combustion were the major sources of N2O emissions.
The emissions of substitutes for ozone depleting substances
and emissions of HFC-23 during the production of HCFC-
22 were the primary  contributors to aggregate HFC
emissions. Electrical transmission and distribution systems
accounted for most SF6 emissions, while PFC emissions
resulted as a by-product of primary aluminum production
and from semiconductor manufacturing.
    Overall, from  1990 to 2007, total emissions of CO2
increased by 1,026.7 Tg CO2 Eq. (20.2 percent), while CH4
and N2O emissions decreased  by 31.2 Tg CO2 Eq.  (5.1
percent) and 3.1  Tg CO2 Eq. (1.0 percent), respectively.
During the same period, aggregate weighted emissions
of FfFCs, PFCs, and SF6 rose by 59.0 Tg CO2 Eq. (65.2
percent). From 1990 to 2007, FfFCs increased by 88.6 Tg
CO2 Eq. (240.0 percent), PFCs decreased by 13.3 Tg CO2 Eq.
(64.0 percent), and SF6 decreased by 16.3 Tg CO2 Eq. (49.8
percent). Despite being emitted in smaller quantities relative
to the other principal greenhouse gases, emissions of HFCs,
PFCs, and SF6 are significant because  many of them have
extremely high global warming  potentials and, in the cases
of PFCs and SF6, long atmospheric lifetimes. Conversely,
U.S. greenhouse gas emissions were partly offset by carbon
sequestration in forests, trees in urban areas, agricultural
soils, and landfilled yard trimmings and food scraps, which,
in aggregate, offset 14.9 percent of total emissions in 2007.
The following sections describe each gas's contribution to
total U.S. greenhouse gas emissions in more detail.
Figure ES-1
         U.S. Greenhouse Gas Emissions by Gas
               HFCs, PFCs, & SFt
               Nitrous Oxide
      8,000 -
      7,000 -
      6,000 -
   S 5,000 -
   o
   m 4,000 -
      3,000 -
      2,000 -
      1,000-
        o-
                          Methane
                          Carbon Dioxide
                          to CN TT J2 0  ^
                                  i- CM co -^ in to r-
Figure ES-2
Annual Percent Change in U.S. Greenhouse Gas Emissions
   0%
   -2% J
            2.1%
         1.7% H 1.7%
                iliiil   Mill  I

       iiiliiiiiiiiiiiii
Figure ES-3
       Cumulative Change in U.S. Greenhouse Gas
              Emissions Relative to 1990
   1,100
   1,000
     900
     800
  S  700
  o~  600
  m  500
     400
     300
     200
     100
     0
    -100
                                       1,051
                                966
                                     952
-45
iiiliiiiiiiiiiiii
ES-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
  Gas/Source
1990
1995
2000
2005
2006
2007
  C02                                           5,076.7        5,407.9
    Fossil Fuel Combustion                        4,708.9        5,013.9
       Electricity Generation                        1,809.71     1,938.9
       Transportation                             1,484.51     1,598.7
       Industrial                                    834.2          862.6
       Residential                                   337.7          354.4
       Commercial                                 214.5          224.4
       U.S. Territories                                28.3           35.0
    Non-Energy Use of Fuels                         117.0          137.5
    Iron and Steel Production &
     Metallurgical Coke Production                   109.8          103.1
    Cement Production                               33.3           36.8
    Natural Gas Systems                             33.7           33.8
    Incineration of Waste                             10.9           15.7
    Lime Production                                 11.5           13.3
    Ammonia Production and Urea Consumption        16.8           17.8
    Cropland Remaining Cropland                       7.11          7.0
    Limestone and Dolomite Use                        5.11          6.7
    Aluminum  Production                              6.8            5.7
    Soda Ash Production and Consumption               4.11          4.3
    Petrochemical Production                           2.2            2.8
    Titanium Dioxide Production                         1.2            1.5
    Carbon Dioxide Consumption                        1.4            1.4
    Ferroalloy Production                               2.2            2.0
    Phosphoric Acid Production                         1.5            1.5
    Wetlands Remaining Wetlands                       1.0            1.0
    Zinc Production                                   0.91         1.0
    Petroleum  Systems                                0.41         0.3
    Lead Production                                   0.31         0.3
    Silicon Carbide Production and Consumption          0.41         0.3
    Land Use, Land-Use Change,
     and Forestry (Sink)3                           (841.4)        (851.0)
    Biomass—Wood                               215.2          229.1
    International Bunker Fuels"                       114.3          101.6
    Biomass—Ethanol13                                4.2M         7.7
  CH4                                             616.6          615.8
    Enteric Fermentation                             133.2          143.6
    Landfills                                       149.2          144.3
    Natural Gas Systems                            129.6          132.6
    Coal Mining                                     84.1           67.1
    Manure Management                             30.4           34.5
    Forest Land Remaining Forest Land                  4.61         6.1
    Petroleum  Systems                              33.9           32.0
    Wastewater Treatment                            23.5           24.8
    Stationary  Combustion                             7.41         7.1
    Rice Cultivation                                   7.11          7.6
    Abandoned Underground Coal Mines                 6.0            8.2
    Mobile Combustion                                4.7B         4.3

                           5,955.2
                           5,561.5
                           2,283.2
                           1,800.3
                             844.6
                             370.4
                             226.9
                              36.2
                             144.5

                              95.1
                              41.2
                              29.4
                              17.5
                              14.1
                              16.4
                               7.5
                               5.1
                               6.1
                               4.2
                               3.0
                               1.8
                               1.4
                               1.9
                               1.4
                               1.2
                               1.1
                               0.3
                               0.3
                               0.2

                           (717.5)
                             218.1
                              99.0
                               9.2
                             591.1
                             134.4
                             122.3
                             130.8
                              60.5
                              37.9
                              20.6
                              30.3
                              25.2
                               6.6
                               7.5
                               7.4
                               3.4
                            6,090.8
                            5,723.5
                            2,381.0
                            1,881.5
                             828.0
                             358.0
                             221.8
                              53.2
                             138.1

                              73.2
                              45.9
                              29.5
                              19.5
                              14.4
                              12.8
                                7.9
                                6.8
                                4.1
                                4.2
                                2.8
                                1.8
                                1.3
                                1.4
                                1.4
                                1.1
                                0.5
                                0.3
                                0.3
                                0.2

                          (1,122.7)
                             208.9
                             111.5
                              22.6
                             561.7
                             136.0
                             127.8
                             106.3
                              57.1
                              41.8
                              14.2
                              28.3
                              24.3
                                6.7
                                6.8
                                5.6
                                2.5
                        6,014.9
                        5,635.4
                        2,327.3
                        1,880.9
                          844.5
                          321.9
                          206.0
                           54.8
                          145.1

                           76.1
                           46.6
                           29.5
                           19.8
                           15.1
                           12.3
                            7.9
                            8.0
                            3.8
                            4.2
                            2.6
                            1.9
                            1.7
                            1.5
                            1.2
                            0.9
                            0.5
                            0.3
                            0.3
                            0.2

                       (1,050.5)
                          209.9
                          110.5
                           30.5
                          582.0
                          138.2
                          130.4
                          104.8
                           58.4
                           41.9
                           31.3
                           28.3
                           24.5
                            6.3
                            5.9
                            5.5
                            2.4
                    6,103.4
                    5,735.8
                    2,397.2
                    1,887.4
                     845.4
                     340.6
                     214.4
                       50.8
                     133.9

                       77.4
                       44.5
                       28.7
                       20.8
                       14.6
                       13.8
                        8.0
                        6.2
                        4.3
                        4.1
                        2.6
                        1.9
                        1.9
                        1.6
                        1.2
                        1.0
                        0.5
                        0.3
                        0.3
                        0.2

                  (1,062.6)
                     209.8
                     108.8
                       38.0
                     585.3
                     139.0
                     132.9
                     104.7
                       57.6
                       44.0
                       29.0
                       28.8
                       24.4
                        6.6
                        6.2
                        5.7
                        2.3
                                                                                                Executive Summary  ES-5

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Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.) (continued)
  Gas/Source
  1990
  1995
  2000
  2005
2006
  Total
6,098.7
6,463.3
7,008.2
2007
    Composting                                       0.31          0.71           1.3             1.6        1.6         1.7
    Petrochemical Production                           0.91          1.11           1.2             1.1        1.0         1.0
    Field Burning of Agricultural Residues                 0.71          0.71          0.81          0.9        0.8         0.9
    Iron and Steel Production &
     Metallurgical Coke Production                      1.0             1.0l          0.9 •          0.7        0.7         0.7
    Ferroalloy Production                                +1           +1            +1           +         +          +
    Silicon Carbide Production and Consumption           +1           +1            +1           +         +          +
    International Bunker Fuels6                          0.2 H          0.71           0.71          0.1        0.1         0.1
  N20                                              315.0          334.1          329.2           315.9      312.1      311.9
    Agricultural Soil Management                     200.3          202.3          204.5           210.6      208.4      207.9
    Mobile Combustion                               43.7           53.7           52.8            36.7       33.5       30.1
    Nitric Acid Production                             20.0           22.3           21.9            18.6       18.2       21.7
    Manure Management                             12.1           12.9           14.0            14.2       14.6       14.7
    Stationary Combustion                            12.8           13.3           14.5            14.8       14.5       14.7
    Adipic Acid Production                            15.3           17.3             6.2             5.9        5.9         5.9
    Wastewater Treatment                              3.71          4.01          4.51          4.8        4.8         4.9
    N20 from Product Uses                             4.41          4.61          4.91          4.4        4.4         4.4
    Forest Land Remaining Forest  Land                   0.51          0.81          2.4l          1.8        3.5         3.3
    Composting                                       0.4l          0.81          1.41          1.7        1.8         1.8
    Settlements Remaining Settlements                   1.0             1.2             1.2             1.5        1.5         1.6
    Field Burning of Agricultural Residues                 0.4l          0.4l          0.51          0.5        0.5         0.5
    Incineration of Waste                               0.51          0.51          0.4l          0.4        0.4         0.4
    Wetlands Remaining Wetlands                        +1           +1            +1           +         +          +
    International Bunker Fuels6                          7.71          0.91          0.91          1.0        1.0         1.0
  MFCs                                             36.9           61.8          100.1           116.1      119.1      125.5
    Substitution of Ozone Depleting Substances0          0.31        28.5           71.2           100.0      105.0      108.3
    HCFC-22 Production                              36.4           33.0           28.6            15.8       13.8       17.0
    Semiconductor Manufacture                         0.2!          0.31          0.31          0.2        0.3         0.3
  PFCs                                             20.8           15.6           13.5             6.2        6.0         7.5
    Aluminum Production                             18.5           11.8             8.61          3.0        2.5         3.8
    Semiconductor Manufacture                         2.2             3.8             4.91          3.2        3.5         3.6
  SF6                                               32.8           28.1           19.2            17.9       17.0       16.5
    Electrical Transmission and Distribution             26.8           21.6           15.1            14.0       13.2       12.7
    Magnesium Production and Processing               5.41          5.6             3.0             2.9        2.9         3.0
    Semiconductor Manufacture                         0.51          0.91          1.11          1.0        1.0         0.8
7,108.6    7,051.1    7,150.1
  Net Emissions (Sources and Sinks)
5,257.3
5,612.3
6,290.7
5,985.9    6,000.6    6,087.5
  + Does not exceed 0.05 Tg C02 Eq.
  a Parentheses indicate negative values or sequestration. The net C02 flux total includes both emissions and sequestration, and constitutes a sink in the
   United States. Sinks are only included in net emissions total.
  b Emissions from International Bunker Fuels and Biomass Combustion are not included in totals.
  c Small amounts of PFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
ES-6  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Figure ES-4
                        Figure ES-5
         2007 Greenhouse Gas Emissions by Gas
        MFCs, PFCs, & SF6
                  N,0
2.1%
4.4%
8.2%
                  CO
                                   85.4%
Carbon Dioxide Emissions
    The global carbon cycle is made up of large carbon flows
and reservoirs. Billions of tons of carbon in the form of CO2
are absorbed by oceans and living biomass (i.e., sinks) and are
emitted to the atmosphere annually through natural processes
(i.e., sources). When in equilibrium, carbon fluxes among
these various reservoirs are roughly balanced.  Since the
Industrial Revolution (i.e., about 1750), global atmospheric
concentrations of CO2 have risen about 36 percent (IPCC
2007), principally due  to the combustion of fossil fuels.
Within the United States, fuel combustion accounted for 94
percent of CO2 emissions in 2007. Globally, approximately
29,195 Tg of CO2 were added to the atmosphere through the
combustion of fossil fuels in 2006, of which the United States
accounted for about 20 percent.10 Changes in land use and
forestry practices can also emit CO2 (e.g., through conversion
of forest land to agricultural or urban use) or can act as a sink
for CO2 (e.g., through net additions to forest biomass).
    U.S.  anthropogenic sources  of CO2 are shown in
Figure ES-5. As the largest source of U.S. greenhouse gas
emissions, CO2 from fossil fuel combustion has accounted
for approximately 79 percent of GWP-weighted emissions
since 1990, growing slowly from 77 percent of total
GWP-weighted  emissions in 1990 to 80 percent in 2007.
Emissions of CO2 from fossil fuel combustion increased at
an average  annual rate of 1.3 percent from 1990 to 2007.
10 Global CO2 emissions from fossil fuel combustion were taken from
Energy Information Administration International Energy Annual 2006
(EIA2008b).
                                     2007 Sources of CO? Emissions
        Fossil Fuel Combustion
       Non-Energy Use of Fuels
       Iron and Steel Production
   & Metallurgical Coke Production
          Cement Production
         Natural Gas Systems
         Incineration of Waste
           Lime Production
       Ammonia Production and
          Urea Consumption
    Cropland Remaining Cropland
     Limestone and Dolomite Use
         Aluminum Production
Soda Ash Production and Consumption
       Petrochemical Production
     Titanium Dioxide Production
     Carbon Dioxide Consumption
         Ferroalloy Production
      Phosphoric Acid Production
    Wetlands Remaining Wetlands
           Zinc Production
          Petroleum Systems | <0.5
           Lead Production
                                                                                                            5,735.8
                              Silicon Carbide Production and
                                       Consumption
                      <0.5
                      <0.5
                                                            75   100
                                                            TgCO,Eq.
                                                                     125   150
                       The fundamental factors influencing this  trend include
                       (1) a generally growing domestic economy over the last 17
                       years, and (2) significant overall growth in emissions from
                       electricity generation and transportation activities. Between
                       1990 and 2007, CO2 emissions from fossil fuel combustion
                       increased from 4,708.9 Tg CO2 Eq. to 5,735.8 Tg CO2 Eq.
                       —a 21.8 percent total increase over the eighteen-year period.
                       From 2006 to 2007, these emissions increased by 100.4 Tg
                       CO2Eq. (1.8 percent).
                            Historically, changes in emissions from fossil fuel
                       combustion have been the dominant factor  affecting U.S.
                       emission trends. Changes in CO2 emissions from fossil fuel
                       combustion are influenced by many long-term and short-term
                       factors, including population and economic growth, energy
                       price fluctuations, technological  changes, and seasonal
                       temperatures. On an annual basis, the overall consumption
                       of fossil fuels in the United States generally fluctuates in
                       response to changes in general economic conditions, energy
                       prices, weather, and the availability of non-fossil alternatives.
                       For example, in a year with increased consumption of
                       goods and services, low fuel prices, severe summer and
                       winter weather conditions, nuclear plant closures, and lower
                                                                                         Executive Summary  ES-7

-------
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.
    The five major fuel consuming sectors contributing to
CO2 emissions from fossil fuel combustion are electricity
generation, transportation, industrial, residential, and
commercial. CO2 emissions are produced by the electricity
generation sector as they consume  fossil  fuel to provide
electricity to one of the other four sectors, or "end-use"
sectors. For the discussion below,  electricity generation
emissions have been  distributed to each end-use  sector
on the basis of each sector's share of aggregate electricity
consumption. This method of distributing emissions assumes
that each end-use sector consumes electricity that is generated
from the national average mix of fuels according to their
carbon intensity. Emissions from electricity generation are
also addressed separately after the end-use sectors have
been discussed.
    Note that emissions from U.S. territories are calculated
separately due to a lack of specific consumption data for the
individual end-use sectors.
    Figure ES-6, Figure ES-7, and Table ES-3 summarize CO2
emissions from fossil fuel combustion by end-use sector.
    Transportation End- Use Sector. Transportation activities
(excluding international bunker fuels)  accounted for 33
percent of CO2 emissions from fossil fuel combustion in
2007.n Virtually all of the energy consumed in this end-use
sector  came from petroleum products. Nearly 60 percent
of the  emissions resulted from gasoline consumption for
personal vehicle use. The remaining emissions came from
other transportation activities, including the combustion of
diesel fuel in heavy-duty vehicles and jet fuel in aircraft.
    Industrial End-Use Sector. Industrial  CO2  emissions,
resulting both directly from the combustion of fossil fuels and
indirectly from the generation of electricity that is consumed
by industry, accounted for 27 percent of CO2 from fossil
fuel combustion in 2007. Just over half of these emissions
resulted from direct fossil fuel combustion to produce steam
and/or heat for industrial processes. The remaining emissions
11 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 2007.
resulted from consuming electricity for motors, electric
furnaces, ovens, lighting, and other applications.
    Residential and Commercial End-Use Sectors.  The
residential and commercial end-use sectors accounted for
21 and 18 percent,  respectively,  of CO2 emissions from
fossil fuel combustion in 2007. Both sectors relied heavily
on electricity for meeting energy demands, with 72 and
79 percent, respectively, of their emissions attributable to
electricity consumption for lighting, heating, cooling, and
Figure ES-6
           2007 C02 Emissions from Fossil Fuel
           Combustion by Sector and Fuel Type
      2,500 -|
      2,000 -
      1,500 -
      1,000 -
       500 -
        0 -1
                 Natural Gas
                 Petroleum
                I Coal
Relative Contribution
  by Fuel Type
             31     |
              1     1
                     .2      o     ••= o
                     i=      '•=     « '•=
                     W      TO     ^ TO
                     =      I     si
                            2
  Note: Electricity generation also includes emissions of less than 0.5 Tg C02 Eq. from geothermal-based
  electricity generation.
Figure ES-7
    2,500 -

    2,000 -
  S 1,500 -
  o
    1,000 -
      500 -
                                                                  0 J
          ""007 End-Use Sector Emissions of C02
              from Fossil Fuel Combustion
   From Electricity
   Consumption
  I From Direct Fossil
   Fuel Combustion
            U.S.    Commercial  Residential  Industrial Transportation
          Territories
ES-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table ES-3: C02 Emissions from Fossil Fuel Combustion by Fuel Consuming End-Use Sector (Tg C02 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories3
Total
Electricity Generation
a Fuel consumption by U.S. territories (i.e., American Samoa
included in this report.
1990
1,487.5 1
1,484.5 1
3.0
1,516.8 1
834.2
682.6
927.1
337.7
589.4
749.2
214.5
534.7
28.3
4,708.9 5
1,809.7 1
, Guam, Puerto Rico

1995
,601.7
,598.7
3.0 1
,575.5
862.6
712.9 1
993.3
354.41
638.8
808.5
224.41
584.1
35.0
,013.9
,938.9
2000
1,803.7
1,800.3
3.4l
1,629.6
844.6
785.0
1,128.2
370.4
757.9
963.8
226.9
736.8
36.2
5,561.5
2,283.2
, U.S. Virgin Islands, Wake Island,


2005
1,886.2
1,881.5
4.7
1,558.5
828.0
730.5
1,207.2
358.0
849.2
1,018.4
221.8
796.6
53.2
5,723.5
2,381.0
and other U.

Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated
national electricity consumption by each end-use sector.




2006
1,885.4
1,880.9
4.5
1,550.7
844.5
706.2
1,145.9
321.9
824.1
998.6
206.0
792.5
54.8
5,635.4
2,327.3
,S. Pacific Islands)

2007
1,892.2
1,887.4
4.8
1,553.4
845.4
708.0
1,198.0
340.6
857.4
1,041.4
214.4
827.1
50.8
5,735.8
2,397.2
is

based on aggregate


operating appliances. The remaining emissions were due to
the consumption of natural gas and petroleum for heating
and cooking.
    Electricity Generation. The United States relies on
electricity to meet a significant portion of its energy demands,
especially for lighting, electric motors, heating, and air
conditioning. Electricity generators consumed 36 percent of
U.S. energy from fossil fuels and emitted 42 percent of the
CO2 from fossil fuel combustion in 2007. The type of fuel
combusted by electricity generators has a significant effect
on their emissions. For example, some electricity is generated
with low CO2 emitting energy technologies, particularly non-
fossil options  such as nuclear, hydroelectric, or geothermal
energy. However, electricity generators rely on coal for over
half of their total energy requirements and accounted for 94
percent of all coal consumed for energy in the United States
in 2007. Consequently, changes in electricity demand have
a significant impact on coal consumption and associated
CO2 emissions.
    Other significant CO2 trends included the following:
•   CO2 emissions from non-energy use of fossil fuels have
    increased 16.9 Tg CO2 Eq. (14.5 percent) from 1990 to
    2007. Emissions from non-energy uses of fossil fuels
    were 133.9 Tg CO2 Eq. in 2007, which constituted 2.2
percent of total national CO2 emissions, approximately
the same proportion as in 1990.
CO2 emissions from iron and steel production and
metallurgical coke production increased slightly from
2006 to 2007 (1.3 Tg CO2 Eq.), but have decreased by
29.5 percent to 77.4 Tg CO2 Eq. from 1990 to 2007,
due to restructuring of the industry, technological
improvements, and increased scrap utilization.
In 2007, CO2  emissions from cement production
decreased slightly by 2.0 Tg CO2 Eq. (4.4 percent) from
2006 to 2007. This  decrease occurs despite the overall
increase over the time series. After falling in 1991 by two
percent from 1990 levels, cement production emissions
grew every year through 2006. Overall, from 1990 to
2007, emissions from cement production increased by
34 percent, an increase of 11.2 Tg CO2 Eq.
CO2 emissions from incineration of waste (20.8 Tg CO2
Eq. in 2007) increased by 9.8 Tg CO2 Eq. (90 percent) from
1990 to 2007, as the volume of plastics and other fossil
carbon-containing materials in the waste stream grew.
Net CO2 sequestration from Land Use, Land-Use
Change, and Forestry increased by 221.1 Tg CO2 Eq. (26
percent) from 1990 to 2007. This increase was primarily
due to an increase in the rate of net carbon accumulation
                                                                                    Executive Summary ES-9

-------
    in forest carbon stocks, particularly in aboveground and
    below ground tree biomass. Annual carbon accumulation
    in landfilled yard trimmings and food scraps slowed
    over this period, while the rate of carbon accumulation
    in urban trees increased.

Methane Emissions
    According to the IPCC, CH4 is more than 20 times as
effective as CO2 at trapping heat in the atmosphere. Over the
last two hundred and fifty years, the concentration of CH4
in the atmosphere increased by 148 percent (IPCC 2007).
Anthropogenic sources of CH^ include landfills, natural gas
and petroleum systems, agricultural activities, coal mining,
wastewater treatment, stationary and mobile combustion, and
certain industrial processes (see Figure ES-8).
    Some significant trends in U.S. emissions of CH4 include
the following:
•   Enteric fermentation is the largest anthropogenic source
    of CH4 emissions in the United States. In 2007, enteric
    fermentation CFL, emissions were 139.0 Tg  CO2 Eq.
    (approximately 24  percent  of total CH4 emissions),
    which represents an increase of 5.8 Tg CO2 Eq., or 4.3
    percent, since 1990.
•   Landfills are the second largest anthropogenic source
    of CH4 emissions in the United States, accounting
    for approximately 23 percent of total CFL, emissions
    (132.9 Tg CO2 Eq.) in 2007. From 1990 to 2007, net
    CH4 emissions from landfills decreased by  16.3 Tg
    CO2 Eq. (11 percent), with small increases occurring
    in some interim years, including 2007. This downward
    trend in overall emissions is the result of increases in
    the amount of landfill gas collected and combusted,12
    which  has more than offset  the  additional CH4
    emissions resulting from an increase in the amount of
    municipal solid waste landfilled.
•   CFLj emissions from natural gas systems were 104.7
    Tg CO2 Eq. in 2007; emissions have declined by  24.9
    Tg CO2 Eq. (19 percent)  since 1990. This decline
    has been due  to improvements in technology and
    management practices, as well as some replacement of
    old equipment.
Figure ES-8
             2007 Sources of CH* Emissions
               Enteric Fermentation
                      Landfills
               Natural Gas Systems
                    Coal Mining
               Manure Management
       Forest Land Remaining Forest Land
                Petroleum Systems
              Wastewater Treatment
              Stationary Combustion
                  Rice Cultivation
      Abandoned Underground Coal Mines
                Mobile Combustion
                    Composting
            Petrocbemical Production
      Field Burning of Agricultural Residues
            Iron and Steel Production
         & Metallurgical Coke Production
               Ferroalloy Production
  Silicon Carbide Production and Consumption
<0.5
<0.5
                              20 40  60  80  100 120 140
                                     Tg CO, Eq.
    In 2007, CH4 emissions from coal mining were 57.6 Tg
    CO2 Eq., a 0.8 Tg CO2 Eq. (1.3 percent) decrease over
    2006 emission levels. The overall decline of 26.4 Tg CO2
    Eq. (31 percent) from 1990 results from the mining of less
    gassy coal from underground mines and the increased use
    of CFLj collected from degasification systems.
    CH4 emissions from manure management increased by
    44.7 percent for CFL,, from 30.4 Tg CO2 Eq. in 1990 to
    44.0 Tg CO2 Eq. in 2007. The majority of this increase
    was from swine and dairy cow manure, since the general
    trend in manure management is one of increasing use
    of liquid systems, which tends to produce greater CFL,
    emissions. The increase in liquid systems is the combined
    result of a shift to larger facilities, and to facilities in
    the West and Southwest, all of which tend to use liquid
    systems. Also, new regulations limiting  the application
    of manure nutrients have shifted manure management
    practices at smaller dairies from daily spread to manure
    managed and stored on site.
12 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.
ES-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Nitrous Oxide  Emissions
    N2O is produced by biological processes that occur in
soil and water and by a variety of anthropogenic activities
in the agricultural, energy-related, industrial, and waste
management fields. While total N2O emissions are much
lower than CO2 emissions, N2O is approximately 300 times
more powerful than CO2 at trapping heat in the atmosphere.
Since 1750, the global atmospheric concentration of N2O
has risen by approximately 18 percent (IPCC 2007). The
main anthropogenic activities producing N2O in the United
States are agricultural soil management, fuel combustion
in motor vehicles, nitric  acid production, stationary
fuel combustion, manure management, and adipic  acid
production (see Figure ES-9).
    Some significant trends in U.S. emissions of N2O include
the following:
•   Agricultural soils produced approximately 67 percent of
    N2O emissions in the United States in 2007. Estimated
    emissions from this  source in 2007 were 207.9 Tg
    CO2 Eq. Annual N2O emissions from agricultural  soils
    fluctuated between 1990  and 2007,  although overall
    emissions were 3.8 percent higher  in 2007 than in
    1990. N2O emissions from this source have not shown
    any  significant long-term trend, as they are highly
    sensitive to the amount of N applied to soils, which has
    not changed significantly over the time-period, and to
    weather patterns and crop type.
Figure ES-9
            2007 Sources of N,0 Emissions
                                             207.9
       Agricultural Soil Management
             Mobile Combustion
           Nitric Acid Production
           Manure Management
           Stationary Combustion
           Adipic Acid Production ^|
           Wastewater Treatment ^|
           N20 from Product Uses ^|
    Forest Land Remaining Forest Land |
                 Composting |
    Settlements Remaining Settlements |
   Field Burning of Agricultural Residues | 
-------
Figure ES-10
Figure ES-11
     2007 Sources of MFCs, PFCs, and SF6 Emissions
    Substitution of Ozone
    Depleting Substances
    HCFC-22 Production
  Electrical Transmission
       and Distribution
                                              108.3
   Aluminum Production
   Magnesium Production
       and Processing
                       10
                             20     30
                              Tg CO, Eq.
                                         40
                                               50
    required under the Montreal Protocol come into effect,
    especially after 1994 when full market penetration
    was made for the first generation of new technologies
    featuring ODS substitutes.
•   HFC emissions from  the production of HCFC-22
    decreased by 53 percent (19.4 Tg CO2 Eq.) from
    1990 to 2007, due to a steady decline in the emission
    rate of HFC-23 (i.e., the amount of HFC-23 emitted
    per kilogram of HCFC-22 manufactured) and the
    use of thermal oxidation at some plants to reduce
    HFC-23 emissions.
•   SF6 emissions from  electric power transmission and
    distribution systems decreased by 53  percent (14.1
    Tg CO2 Eq.) from 1990 to 2007, primarily because of
    higher purchase prices for SF6 and efforts by industry
    to reduce emissions.
•   PFC emissions from aluminum production decreased by
    79 percent (14.7 Tg CO2 Eq.) from 1990 to 2007, due
    to both industry emission reduction efforts and lower
    domestic aluminum production.

ES.3.   Overview  of Sector Emissions
and  Trends
    In accordance with the Revised 1996 IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997), and the 2003 UNFCCC Guidelines on
Reporting and Review (UNFCCC 2003), Figure ES-11 and
Table ES-4 aggregate emissions and sinks by these chapters.
        U.S. Greenhouse Gas Emissions and Sinks
                by Chapter/IPCC Sector
               Industrial Processes
                             Waste
      7,500
      7,000
      6,500
      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)-I
Land Use, Land-Use Change and Forestry (sinks)
   Note: Relatively smaller amounts of GWP-weighted emissions are also emitted from the Solvent and
   Other Product Use sectors.
Emissions of all gases can be summed from each source
category from Intergovernmental Panel on Climate Change
(IPCC) guidance. Over the eighteen-year period of 1990 to
2007, total emissions in the Energy, Industrial Processes, and
Agriculture sectors climbed by 976.7 Tg CO2 Eq. (19 percent),
28.5Tg CO2 Eq. (9 percent), and28.9Tg CO2 Eq. (8 percent),
respectively. Emissions decreased in the Waste and Solvent
and Other Product Use sectors by 11.5 Tg CO2 Eq. (6 percent)
and less than 0.1 Tg CO2 Eq. (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
192.5 Tg CO2 Eq. (23 percent).

Energy
    The Energy chapter contains emissions of all greenhouse
gases resulting from stationary and mobile energy activities
including fuel combustion and fugitive fuel emissions.
Energy-related activities, primarily fossil fuel combustion,
accounted for the vast majority of U.S. CO2 emissions for
the period of 1990 through 2007. In 2007, approximately
85 percent of the energy consumed in the United States (on
a Btu basis) was produced through the combustion of fossil
fuels. The remaining 15 percent came from other  energy
sources  such as hydropower, biomass, nuclear, wind,  and
solar energy (see Figure ES-12). Energy-related activities are
also responsible for CFL, and N2O emissions (35 percent and
14 percent of total U.S. emissions of each gas, respectively).
ES-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg C02 Eq.)
  Chapter/IPCC Sector
           1990
  1995
  2000
   2005
2006
2007
  Energy
  Industrial Processes
  Solvent and Other Product Use
  Agriculture
  Land Use, Land-Use Change, and
   Forestry (Emissions)
  Waste
                                   6,059.9
                                     356.3
                                       4.9
                                     399.4
                                      33.0
                                     154.6

                           6,169.2
                             337.6
                               4.4
                             410.8
                              26.4
                             160.2
                        6,084.4
                         343.9
                           4.4
                         410.3
                          45.1
                         163.0
                     6,170.3
                       353.8
                         4.4
                       413.1
                        42.9
                       165.6
  Total Emissions
         6,098.7
6,463.3
7,008.2
 7,108.6    7,051.1    7,150.1
  Net C02 Flux from Land Use, Land-Use
   Change, and Forestry (Sinks)3
         (841.4)
(851.0)
(717.5)
(1,122.7)   (1,050.5)   (1,062.6)
  Net Emissions (Sources and Sinks)
         5,257.3
5,612.3
6,290.7
 5,985.9    6,000.6    6,087.5
  aThe net C02 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are only included in net emissions total.
  Note: Totals may not sum due to independent rounding. Parentheses indicate negative values or sequestration.
Figure ES-12
     2007 U.S. Energy Consumption by Energy Source
             Renewable
               Nuclear

             Natural Gas


                 Coal
              Petroleum
                                   7%
22%
                                   22%
                                   39%
Overall, emission sources in the Energy chapter account
for a combined 86.3 percent of total U.S. greenhouse gas
emissions in 2007.

Industrial Processes
    The Industrial Processes chapter contains byproduct
or fugitive emissions of greenhouse gases from industrial
processes  not directly related to energy activities such as
fossil fuel  combustion. For example, industrial processes can
chemically transform raw materials, which often release waste
gases such as CO2, CLL,, and N2O. These processes include iron
and steel production and metallurgical coke production, cement
production, ammonia production  and urea consumption,
lime manufacture, limestone and dolomite use (e.g., flux
stone, flue gas desulfurization, and glass manufacturing),
soda ash manufacture and use, titanium dioxide production,
phosphoric acid production, ferroalloy production, CO2
consumption, silicon carbide production and consumption,
aluminum production, petrochemical production, nitric acid
production, adipic acid production, lead production, and zinc
production. Additionally, emissions from industrial processes
release HFCs, PFCs, and SF6. Overall, emission sources in the
Industrial Processes chapter account for 4.9 percent of U.S.
greenhouse gas emissions in 2007.

Solvent  and  Other Product Use
    The Solvent and Other Product Use chapter contains
greenhouse gas emissions that are produced as a by-product
of various solvent and other product uses. In the United States,
emissions from N2O from product uses, the only source of
greenhouse gas emissions from this sector, accounted for less
than 0.1 percent of total U.S. anthropogenic greenhouse gas
emissions on a carbon equivalent basis in 2007.

Agriculture
    The Agriculture chapter  contains anthropogenic
emissions from agricultural activities (except fuel
combustion, which is addressed in  the Energy chapter,
and agricultural  CO2 fluxes, which are addressed in the
Land  Use, Land-Use  Change, and Forestry chapter).
Agricultural activities contribute directly to emissions of
greenhouse gases through a variety of processes, including
the following source categories: enteric fermentation
in domestic livestock, livestock manure management,
rice cultivation,  agricultural soil management, and field
burning  of agricultural residues. CH4 and N2O were the
                                                                                      Executive Summary  ES-13

-------
primary greenhouse gases emitted by agricultural activities.
CH4 emissions from enteric fermentation and manure
management represented about 24 percent  and 8 percent
of total CH4 emissions  from anthropogenic activities,
respectively, in 2007. Agricultural soil  management
activities such as fertilizer application and other cropping
practices were the largest source of U.S. N2O emissions in
2007, accounting for 67 percent. In 2007, emission sources
accounted for in the Agriculture chapter were responsible
for 6 percent of total U.S. greenhouse gas emissions.

Land Use, Land-Use Change, and Forestry
    The Land Use, Land-Use Change, and Forestry chapter
contains emissions of  CK4 and N2O, and emissions and
removals of CO2 from forest management, other land-
use activities, and land-use change.  Forest management
practices, tree planting in urban areas, the management of
agricultural soils, and the landfilling of yard trimmings and
food scraps  have resulted in a net uptake (sequestration)
of C in the United States. Forests (including vegetation,
soils, and harvested wood) accounted for approximately 86
percent of total 2007 net CO2 flux, urban trees accounted
for 9 percent, mineral and organic soil carbon stock changes
accounted for 4 percent, and landfilled yard trimmings
and food scraps accounted for  1  percent of the total net
flux in 2007. The net forest sequestration is  a result of net
             forest growth and increasing forest area, as well as a net
             accumulation of carbon stocks in harvested wood pools.
             The net sequestration in urban forests is a result of net tree
             growth in these areas. In agricultural soils, mineral and
             organic soils sequester approximately 70 percent more
             C than is emitted through  these soils, liming, and urea
             fertilization, combined. The mineral soil C sequestration
             is largely due to the conversion of cropland to permanent
             pastures and hay production, a reduction in summer fallow
             areas in semi-arid areas, an increase  in the adoption of
             conservation tillage practices, and an increase in the
             amounts  of  organic fertilizers (i.e., manure and sewage
             sludge) applied to agriculture lands. The landfilled yard
             trimmings and food scraps net sequestration is due to the
             long-term accumulation of yard trimming carbon and food
             scraps in landfills. Land use, land-use change, and forestry
             activities in 2007 resulted in a net C sequestration of 1,062.6
             Tg CO2 Eq. (Table ES-5). This represents an offset of
             approximately 17.4 percent of total U.S. CO2 emissions,
             or 14.9 percent of total greenhouse gas emissions in 2007.
             Between 1990 and 2007, total land use, land-use change,
             and forestry net C flux resulted in a 26.3 percent increase
             in CO2 sequestration, primarily due to an increase in the
             rate of net C accumulation in forest C  stocks, particularly
             in aboveground and belowground tree biomass. Annual
             C accumulation in landfilled yard trimmings and food
Table ES-5: Net C02 Flux from Land Use, Land-Use Change, and Forestry (Tg C02 Eq.)
  Sink Category
  1990
  1995
  2000
   2005
2006
2007
  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)
                                       (975.7)
                                        (18.3)
                                          5.9
                                         (4.6)
                                        (26.7)
                                        (93.3)
                                    (900.3)
                                     (19.1)
                                       5.9
                                      (4.6)
                                     (26.7)
                                     (95.5)
 (23.5)
 (13.9)
 (11.3)
   (10.2)     (10.4)
          (9.8)
  Total
(841.4)
(851.0)
(717.5)
(1,122.7)   (1,050.5)  (1,062.6)
  Note: Totals may not sum due to independent rounding. Parentheses indicate net sequestration.
ES-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table ES-6: Emissions from Land Use, Land-Use Change, and Forestry (Tg C02 Eq.)
  Source Category
1990
1995
2000
2005
2006
2007
  C02                                          8.1
    Crop|and Remaining Cropland: Liming of
     Agricultural Soils                             4.7
    Cropland Remaining Cropland: Urea Fertilization      2.4
    Wetlands Remaining Wetlands: Peatlands
     Remaining Peatlands                          1.0
  CH4                                          4.6
    Forest Land Remaining Forest Land: Forest Fires      4.6
  N20                                          1.5
    Forest Land Remaining Forest Land: Forest Fires      0.5
    Forest Land Remaining Forest Land: Forest Soils      0.0
    Wetlands Remaining Wetlands: Peatlands
     Remaining Peatlands                           +
    Settlements Remaining Settlements:
     Settlement Soils                              1.0
               8.1

               4.4
               2.7

               1.0
               6.1
               6.1
               2.0
               0.6
               1.2
               8.8

               4.3
               3.2

               1.2
              20.6
              20.6
               3.6
               2.1
               0.3
               1.2
               8.9

               4.3
               3.5

               1.1
              14.2
              14.2
               3.3
               1.4
               0.3
               1.5
           8.8

           4.2
           3.7

           0.9
          31.3
          31.3
           5.0
           3.2
           0.3
           1.5
           9.0

           4.1
           4.0

           1.0
          29.0
          29.0
           4.9
           2.9
           0.3
           1.6
  Total
  + Less than 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
                           33.0
                           26.4
                        45.1
                    42.9
scraps slowed over this period, while the rate of annual C
accumulation increased in urban trees.

    Emissions from Land Use, Land-Use Change, and
Forestry are shown in Table ES-6. The application of crushed
limestone and dolomite to managed land (i.e., soil liming) and
urea fertilization resulted in CO2 emissions  of 8.0 Tg CO2
Eq. in 2007, an increase of 13 percent relative to 1990. The
application of synthetic fertilizers to forest  and settlement
soils in 2007 resulted in direct N2O emissions of 1.6 Tg
CO2 Eq. Direct N2O emissions from fertilizer application
increased by approximately 61 percent between 1990 and
2007. Non-CO2 emissions from forest fires in 2007 resulted
in CILj emissions of 29.0 Tg CO2 Eq., and in N2O emissions
of 2.9 Tg CO2 Eq. CO2 and N2O emissions from peatlands
totaled 1.0 Tg CO2 Eq. and less than 0.01 Tg  CO2 Eq. in
2007, respectively.


Waste
    The Waste chapter  contains emissions from waste
management activities  (except incineration of waste,
which is addressed in the Energy chapter).  Landfills were
the largest source of anthropogenic CH4 emissions in the
Waste chapter, accounting for 23 percent of total U.S. CH4
           emissions.13 Additionally, wastewater treatment accounts
           for 4 percent of U.S. CH4 emissions. N2O emissions from
           the discharge of wastewater treatment effluents into aquatic
           environments were estimated, as were N2O emissions from
           the treatment process  itself. Emissions of CFL, and N2O
           from composting  grew from 1990 to 2007, and resulted
           in emissions  of  1.7 Tg CO2 Eq. and 1.8 Tg CO2 Eq.,
           respectively. Overall, in 2007, emission sources accounted
           for in the Waste chapter generated 2.3 percent of total U. S.
           greenhouse gas emissions.


           ES.4.  Other Information
            Emissions by Economic Sector
               Throughout the Inventory of U.S. Greenhouse Gas
            Emissions and Sinks report, emission estimates are grouped
            into six sectors (i.e., chapters) defined by the IPCC: Energy;
            Industrial Processes; Solvent Use; Agriculture;  Land Use,
            Land-Use Change, and Forestry; and Waste. While it is
            13 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.
                                                                                     Executive Summary  ES-15

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Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq.)
Implied Sectors
Electric Power Industry
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total Emissions
Land Use, Land-Use Change,
and Forestry (Sinks)
Net Emissions (Sources and Sinks)
1990
1,859.1
1, 543.6 1
1,496.0
428.5
392.9
344.51
34.1
6,098.7
(841.4)
5,257.3
1995
1,989.0
1,685.2
1,524.5
453.7
401.0
368.8
41.1
6,463.3
(851.0)
5,612.3
2000
2,329.3
1,919.7
1,467.5
470.2
388.2
386.0
47.3
7,008.2
(717.5)
6,290.7
2005
2,429.4
1,998.9
1,364.9
482.6
401.8
370.5
60.5
7,108.6
(1,122.7)
5,985.9
2006
2,375.5
1,994.4
1,388.4
502.9
392.6
334.9
62.3
7,051.1
(1,050.5)
6,000.6
2007
2,445.1
1,995.2
1,386.3
502.8
407.6
355.3
57.7
7,150.1
(1,062.6)
6,087.5
  Note: Totals may not sum due to independent rounding. Emissions include C02, CH4, N20, MFCs, PFCs, and SF6. See Table 2-12 for more detailed data.
important to use this characterization for consistency with
UNFCCC reporting guidelines, it is also useful to allocate
emissions into more commonly used sectoral  categories.
This section reports emissions by the following economic
sectors: Residential, Commercial, Industry, Transportation,
Electricity Generation, Agriculture, and U.S. Territories.
    Table ES-7 summarizes emissions from each of these
sectors, and Figure ES-13 shows the trend in emissions by
sector from 1990 to 2007.
    Using this categorization,  emissions  from electricity
generation accounted for the largest portion (34 percent)
of U.S. greenhouse gas emissions in 2007. Transportation
activities, in  aggregate, accounted for the second largest
portion (28 percent).  Emissions from industry accounted
for 20 percent of U.S. greenhouse gas emissions in  2007.
In contrast to electricity generation and transportation,
emissions from industry have in general declined over the
past decade. The long-term decline in these emissions  has
been due to structural changes in the U.S. economy (i.e., shifts
from a manufacturing-based to a service-based economy),
fuel switching, and energy efficiency improvements. The
remaining 18 percent of U.S. greenhouse gas emissions were
contributed by the residential, agriculture, and commercial
sectors, plus emissions from U.S. territories. The residential
sector accounted for about 5 percent, and primarily consisted
of CO2 emissions from fossil fuel combustion. Activities
related  to agriculture accounted for roughly 7 percent of
U.S. emissions; unlike other economic sectors, agricultural
sector emissions were dominated by N2O emissions from
agricultural soil management and CH^ emissions from enteric
fermentation, rather than CO2 from fossil fuel combustion.
Figure ES-13
         Emissions Allocated to Economic Sectors
2,500 -

2,000 -

1,500-

1,000-

 500-
                                      Electricity Generation
                                          •^
                                          Transportation


                                              Industry
                                            Agriculture
                                           ^Commercial
                                            Residential
                              00000000
  Note: Does not include U.S. Territories.
The commercial sector accounted for about 6 percent of
emissions, while U.S. territories accounted for approximately
1 percent.
    CO2 was also emitted and sequestered by a variety
of activities related  to forest management practices, tree
planting in urban areas, the management of agricultural soils,
and landfilling of yard trimmings.
    Electricity is ultimately consumed in the economic
sectors described above. Table ES-8 presents greenhouse
gas emissions from economic sectors with emissions related
to electricity generation distributed into end-use categories
(i.e., emissions from electricity generation are allocated to
the economic sectors in which the electricity is consumed).
To  distribute electricity emissions among end-use sectors,
emissions from the source categories assigned to electricity
ES-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table ES-8: U.S. Greenhouse Gas Emissions by Economic Sector with Electricity-Related Emissions
Distributed (Tg C02 Eq.)
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)
See Table 2-14 for more detailed data.
Figure ES-14
1990 1995 2000 2005 2006 2007
2,166.5 2,219.8 2,235.5 2,081.2 2,082.3 2,081.2
1,546.7 1,688.3 1, 923.21 2,003.6 1,999.0 2,000.1
942.2 1,000.21 1,140.0 1,214.6 1,201.5 1,251.2
950.0 1,024.21 1,159.21 1,237.0 1,176.1 1,229.8
459.2 489.7 503.2 511.7 530.0 530.1
34.1 41.1 47.3 60.5 62.3 57.7
6,098.7 6,463.3 7,008.2 7,108.6 7,051.1 7,150.1

(841.4) (851.0) (717.5) (1,122.7) (1,050.5) (1,062.6)
5,257.3 5,612.3 6,290.7 5,985.9 6,000.6 6,087.5

CO2 and N2O from incineration of waste, CH^ and N2O from
stationary sources, and SF6 from electrical transmission and
to Economic Sectors
2,500 -
-^~- 	 ' 	 ^^
2,000 -

S 1,500- 	 *^"
o1 ^--"-'
o ^---^
™ *^^- 	
1,000- - 	 * 	 -—__.



° 0
distribution systems.

Industrial
~-
^
Transportation
^---Residential

	 -"
	 .Commercial

Agriculture

IIH
Note: Does not include U.S. Territories.
When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of U.S.
greenhouse gas emissions (30 percent) in 2007. Emissions
from the residential and commercial sectors also increase
substantially when emissions from electricity are included, due

to their relatively large share of electricity consumption (e.g.,
lighting, appliances, etc.). Transportation activities remain the
second largest contributor to total U.S. emissions (28 percent).
In all sectors except agriculture, CO2 accounts for more than
80 percent of greenhouse gas emissions, primarily from the
combustion of fossil fuels. Figure ES-14 shows the trend in
these emissions by sector from 1990 to 2007.

generation were allocated to the residential, commercial,
industry, transportation, and agriculture economic sectors
according to retail sales of electricity.14 These source
categories include CO2 from fossil fuel combustion and the
use of limestone and dolomite for flue gas desulfurization,
Indirect Greenhouse Gases (CO, NOX,
NMVOCs, and S02)
    The reporting requirements of the UNFCCC15 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
14Emissions 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.
15 See .
                                                                                    Executive Summary  ES-17

-------
Box ES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data

      Total emissions can be compared to other economic and social indices to highlight changes over time. These comparisons include: (1)
  emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; (2) emissions
  per unit of fossil fuel consumption, because almost all energy-related emissions involve the combustion of fossil fuels; (3) emissions per
  unit of electricity consumption, because the electric power industry—utilities and nonutilities combined—was the largest source of U.S.
  greenhouse gas emissions in 2007; (4) emissions per unit of total gross domestic product as a measure of national economic activity; or
  (5) emissions per capita.
      Table ES-9 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year. Greenhouse
  gas emissions in the United States have grown at an average annual rate of 0.9 percent since 1990. This rate is slightly slower than that for
  total energy or fossil fuel consumption and much slower than that for either electricity consumption or overall gross domestic product. Total
  U.S. greenhouse gas emissions have also grown slightly slower than national population since 1990 (see Figure ES-15).
  Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100)
  Variable
1995
  GDPb
  Electricity Consumption0
  Fossil Fuel Consumption0
  Energy Consumption0
  Populationd
  Greenhouse Gas Emissions6
  a Average annual growth rate
  b Gross Domestic Product in chained 2000 dollars (BEA 2008)
  c Energy content-weighted values (EIA 2008a)
  11 U.S. Census Bureau (2008)
  e GWP-weighted values
2000
2005
2006
2007
Growth
 Rate3
                138
                155
                127|          134
                117            119
                117            119
                1131          118
                115	V\l_
            159
            135
            117
            118
            119
            115
            162
            137
            119
            120
            120
            117
            2.9%
            1.9%
            1.1%
            1.1%
            1.1%
            0.9%
                            Figure ES-15
                                       U.S. Greenhouse Gas Emissions Per Capita and
                                            Per Dollar of Gross Domestic Product
                                                                                      Real GDP
                                                                                      Population
                                                                                      Emissions
                                                                                      per capita

                                                                                      Emissions
                                                                                      per $GDP
                                     iiiiliiiiiiiiiiiii
                              Source: BEA (2008), U.S. Census Bureau (2008), and emission estimates in this report.
ES-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table ES-10: Emissions of NOX, CO, NMVOCs, and S02 (Gg)
  Gas/Activity
1990
1995
2000
2005
2006
2007
  NO,
    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
  S02
    Stationary Fossil Fuel Combustion
    Industrial Processes
    Mobile Fossil Fuel Combustion
    Oil and Gas Activities
    Incineration of Waste
    Waste
    Solvent Use
    Agricultural Burning
  NA
                NA
             15,612
              8,757
              5,857
                534
                321
                 98
                 39
                  5
                  2
             71,672
             62,519
              4,778
              1,744
              1,439
                860
                324
                  7
                  2
             14,562
              6,292
              3,881
              2,035
              1,450
                545
                243
                115
                 NA
             13,348
             11,641
                852
                600
                233
                 22
                  1
                  0
                 NA
         14,701
          8,271
          5,445
            527
            316
             98
             38
              5
              2
         67,453
         58,322
          4,792
          1,743
          1,438
            825
            323
              7
              2
         14,129
          5,954
          3,867
          1,950
          1,470
            535
            239
            113
             NA
         12,259
         10,650
            845
            520
            221
             22
              1
              0
             NA
         14,250
          7,831
          5,445
            520
            314
             97
             37
              5
              2
         63,875
         54,678
          4,792
          1,743
          1,438
            892
            323
              7
              2
         13,747
          5,672
          3,855
          1,878
          1,470
            526
            234
            111
             NA
         11,725
         10,211
            839
            442
            210
             22
              1
              0
             NA
  NA (Not Available)
  Note: Totals may not sum due to independent rounding.
  Source: EPA (2008), disaggregated based on EPA (2003), except for estimates from field burning of agricultural residues.
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.
     Since 1970, the United States has published estimates
of annual emissions of CO, NOX, NMVOCs, and SO2 (EPA
            2008),16 which are regulated under the Clean Air Act. Table
            ES-10 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.
                                                             16 NOX and CO emission estimates from field burning of agricultural residues
                                                             were estimated separately, and therefore not taken from EPA (2008).
                                                                                           Executive Summary   ES-19

-------
Figure ES-16
                                                  2007 Key Categories
                     C02 Emissions from Stationary Combustion - Coal
                  C02 Emissions from Mobile Combustion: Road & Other
                     C02 Emissions from Stationary Combustion - Gas
                      C02 Emissions from Stationary Combustion - Oil
                     C02 Emissions from Mobile Combustion: Aviation
                Direct N20 Emissions from Agricultural Soil Management
                           CH, Emissions from Enteric Fermentation
                        C02 Emissions from Non-Energy Use of Fuels
                                   CH, Emissions from Landfills
              Emissions from Substitutes for Ozone Depleting Substances
                     Fugitive CH, Emissions from Natural Gas Systems
 C02 Emissions from Iron and Steel Production & Metallurgical Coke Production
                           Fugitive CH, Emissions from Coal Mining
                      C02 Emissions from Mobile Combustion: Marine
                            C02 Emissions from Cement Production
                           CH, Emissions from Manure Management
                        Indirect N20 Emissions from Applied Nitrogen
                      Fugitive CH, Emissions from Petroleum Systems
                           C02 Emissions from Natural Gas Systems
                      Non-C02 Emissions from Stationary Combustion
                   Key Categories as a
                  Portion of all Emissions
                                                        I      I     I      I     I      I     I      I     I     I      I     I
                                                        0     200   400   600   800   1,000  1,200  1,400  1,600  1,800  2,000 2,200
                                                                                    Tg C02 Eq.
  Notes: For a complete discussion of the key source analysis, see Annex 1. Darker bars indicate a Tier 1 level assessment key category. Lighter bars indicate a Tier 2 level assessment key category.
Key Categories
    The IPCC's Good Practice Guidance (IPCC 2000)
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."17 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 identified in either of the
quantitative analyses.
    Figure ES-16 presents 2007 emission estimates for the key
categories as defined by a level analysis (i.e., the contribution
of each source or sink category to the total inventory level).
The UNFCCC reporting guidelines request that key category
analyses be reported at an appropriate level of disaggregation,
which may lead to source and sink category names which
differ from those used elsewhere in the Inventory. For more
information regarding  key categories,  see Section 1.5 and
Annex 1 of the Inventory.

Quality Assurance and  Quality Control
(QA/QC)
    The  United States seeks to  continually improve the
quality, transparency,  and credibility of the Inventory of
U.S. Greenhouse Gas Emissions and Sinks. To assist in these
efforts, the United States implemented a systematic approach
to QA/QC. While QA/QC has always been an integral part
of the U.S. national system for inventory development, the
procedures followed for the current Inventory have been
17 See Chapter 7 "Methodological Choice and Recalculation" in IPCC
(2000). 
ES-20  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
formalized in accordance with the QA/QC plan and the
UNFCCC reporting guidelines.

Uncertainty Analysis of Emission
Estimates
    While the current U.S. emissions Inventory provides a
solid foundation for the development of a more detailed and
comprehensive national inventory, there are uncertainties
associated with the emission estimates. Some of the current
estimates, such as those for CO2 emissions from energy-related
activities and cement processing, are considered to have
low uncertainties. For some other categories of emissions,
however, a lack of data or an incomplete understanding of how
emissions  are generated increases the uncertainty associated
with the estimates presented. Acquiring a better understanding
of the uncertainty associated with inventory estimates is an
important step in helping to prioritize future work and improve
the overall quality of the Inventory. Recognizing the benefit
of conducting an uncertainty analysis, the UNFCCC reporting
guidelines follow the recommendations of the IPCC Good
Practice Guidance (IPCC 2000) and require that countries
provide single estimates of uncertainty for source and sink
categories.
    Currently, a qualitative discussion  of uncertainty is
presented for  all source and sink categories. Within the
discussion of each emission source, specific factors affecting
the uncertainty surrounding the estimates are discussed. Most
sources also contain a quantitative uncertainty assessment,
in accordance with UNFCCC reporting guidelines.
                                                                                    Executive Summary  ES-21

-------
 1,    Introduction
         This report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emissions
         and sinks for the years 1990 through 2007. A summary of these estimates is provided in Table 2-1 and Table 2-2
         by gas and source category in the Trends in Greenhouse Gas Emissions chapter. The emission estimates in these
tables are presented on both a full molecular mass basis and on a Global Warming Potential (GWP) weighted basis in order
to show the relative contribution of each gas to global average radiative forcing.1 This report also discusses the  methods
and data used to calculate these emission estimates.
    In 1992, the United States signed and ratified the United Nations Framework Convention on Climate Change (UNFCCC).
As stated in Article 2 of the UNFCCC, "The ultimate objective of this Convention and any related legal instruments that
the  Conference of the Parties  may adopt is  to achieve, in accordance with the relevant provisions of  the Convention,
stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic
interference with the climate system.  Such a level should be achieved within a time-frame sufficient to allow ecosystems
to adapt naturally to climate change, to ensure that food production is not threatened and to enable economic development
to proceed in a sustainable manner."2 3
    Parties to the Convention, by ratifying,  "shall develop, periodically update, publish and make available...national
inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by the
Montreal Protocol, using comparable methodologies..."4 The United States views this report as an opportunity to fulfill
these commitments under the UNFCCC.
    In 1988, preceding the creation  of the UNFCCC, the World Meteorological Organization  (WMO) and the United
Nations Environment Programme (UNEP) jointly established the Intergovernmental Panel on Climate  Change (IPCC).
The role of the IPCC is to assess on a comprehensive, objective, open, and transparent basis the scientific, technical and
socio-economic information relevant to understanding the scientific basis of risk of human-induced climate change, its
potential impacts and options for adaptation and mitigation (IPCC 2003). Under Working Group 1 of the IPCC, nearly
140 scientists and national experts from more than thirty countries collaborated in the creation of the Revised 1996 IPCC
Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) to ensure that the emission inventories
submitted to the UNFCCC are consistent and comparable between nations. The IPCC accepted the Revised 1996 IPCC
Guidelines at its Twelfth Session (Mexico City, September 11-13, 1996). This report presents information in accordance
with these guidelines. In addition, this Inventory is in accordance with the IPCC Good Practice Guidance and Uncertainty
1 See the section below entitled Global Warming Potentials for an explanation of GWP values.
2 The term "anthropogenic," in this context, refers to greenhouse gas emissions and removals that are a direct result of human activities or are the result
of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
3 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. See  (UNEP/WMO 2000).
4 Article 4(1 )(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 .

                                                                                            Introduction  1-1

-------
Management in National Greenhouse Gas Inventories
and the Good Practice Guidance for Land Use, Land- Use
Change, and Forestry, which further expanded upon the
methodologies in the Revised 1996 IPCC Guidelines. The
IPCC has also accepted the 2006 Guidelines for National
Greenhouse Gas Inventories (IPCC 2006) at its Twenty-Fifth
Session (Mauritius, April 2006). The 2006IPCC Guidelines
build on the previous bodies of work and includes new sources
and gases ".. .as well as updates to the previously published
methods whenever scientific and technical knowledge have
improved since the previous guidelines were issued." Many
of the methodological improvements  presented in the 2006
Guidelines  have been adopted in this  Inventory.
    Overall, this Inventory of anthropogenic greenhouse gas
emissions provides a common and consistent mechanism
through which Parties to the UNFCCC can estimate emissions
and compare the relative contribution of individual sources,
gases, and nations to climate change. The structure of this
report is consistent with the current UNFCCC Guidelines on
Annual Inventories (UNFCCC 2006).

1.1.  Background Information


Greenhouse  Gases
    Although  the earth's atmosphere consists mainly of
oxygen and nitrogen, neither plays a significant role in
enhancing the greenhouse effect because both are essentially
transparent to  terrestrial radiation. The  greenhouse effect
is primarily a function  of the concentration of water
vapor,  carbon dioxide (CO2), and other trace gases in the
atmosphere that absorb the terrestrial radiation leaving the
surface of the earth (IPCC 2001). Changes in the atmospheric
concentrations of these greenhouse gases can alter the balance
of energy transfers between the atmosphere, space, land, and
the  oceans.5 A gauge of these changes is called radiative
forcing, which is a measure of the influence a factor has in
altering the balance of incoming and outgoing energy in the
earth-atmosphere system (IPCC 2001). Holding everything
else constant, increases in greenhouse gas concentrations in
the atmosphere will produce positive  radiative forcing (i.e.,
a net increase in the absorption of energy by the earth).
    Climate  change can be driven by changes in
    the atmospheric concentrations of a number of
    radiatively active gases and aerosols. We have
    clear evidence that human activities have affected
    concentrations, distributions and life cycles of these
    gases (IPCC 1996).

    Naturally occurring greenhouse gases include water
vapor, CO2,  methane (CH4), nitrous oxide (N2O), and
ozone (O3). Several classes of halogenated substances that
contain fluorine, chlorine, or bromine are also  greenhouse
gases, but they are, for the most part, solely a  product
of industrial  activities. Chlorofluorocarbons (CFCs) and
hydrochlorofluorocarbons (HCFCs) are halocarbons that
contain chlorine, while halocarbons that contain bromine
are referred to  as  bromofluorocarbons (i.e., halons). As
stratospheric ozone depleting substances, CFCs, HCFCs, and
halons are covered under the Montreal Protocol on Substances
that Deplete the Ozone Layer. The UNFCCC defers to this
earlier international treaty. Consequently, Parties to the
UNFCCC are not required to include these gases in national
greenhouse gas inventories.6 Some other fluorine-containing
halogenated  substances—hydrofluorocarbons  (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—do
not deplete stratospheric ozone but are potent  greenhouse
gases. These latter substances are addressed by the UNFCCC
and accounted for in national greenhouse gas inventories.
    There are also several gases that, although  they do
not have a commonly agreed upon direct radiative forcing
effect, do influence the global radiation budget. These
tropospheric gases include carbon monoxide (CO), nitrogen
dioxide (NO2), sulfur dioxide  (SO2), and tropospheric
(ground level) O3. Tropospheric ozone is formed by two
precursor pollutants, volatile organic compounds  (VOCs)
and nitrogen  oxides (NOX) in the presence of ultraviolet
light (sunlight). Aerosols are extremely small  particles or
liquid droplets that are often composed of sulfur compounds,
carbonaceous combustion products, crustal materials
and other human induced pollutants. They can affect the
absorptive characteristics of the atmosphere. Comparatively,
however, the level of scientific understanding of aerosols is
still very low  (IPCC 2001).
5 For more on the science of climate change, see NRC (2001).
6 Emission estimates of CFCs, HCFCs, halons and other ozone depleting
substances are included in this document for informational purposes.
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Table 1-1: Global Atmospheric Concentration, Rate of Concentration Change, and Atmospheric Lifetime (years)
of Selected Greenhouse Gases
Atmospheric Variable
Pre-industrial atmospheric concentration
Atmospheric concentration
Rate of concentration change
Atmospheric lifetime0
C02
278 ppm
379 ppm
1 .4 ppm/yr
50-200d
CH4
0.71 5 ppm
1.774 ppm
0.005 ppm/yra
12e
N20
0.270 ppm
0.31 9 ppm
0.26% yr
114e
SF6
Oppt
5.6 ppt
Linear"
3,200
CF4
40 ppt
74 ppt
Linear"
>50,000
  a The growth rate for atmospheric CH4 has been decreasing from 14 ppb/yr in 1984 to almost 0 ppb/yr in 2001, 2004, and 2005 (IPCC 2007).
  b IPCC (2007) identifies the rate of concentration change for SF6 and CF4 as linear.
  c Source: IPCC (1996).
  11 No single lifetime can be defined for C02 because of the different rates of uptake by different removal processes.
  e This lifetime has been defined as an "adjustment time" that takes into account the indirect effect of the gas on its own residence time.
  Source: Pre-industrial atmospheric concentrations, current atmospheric concentrations, and rate of concentration changes for all gases are from IPCC (2007).
  Note: ppt (parts per thousand), ppm (parts per million), ppb (parts per billion).
    Carbon dioxide, CH^, and N2O are continuously emitted
to and removed from the atmosphere by natural processes
on Earth. Anthropogenic activities, however, can cause
additional quantities of these and other greenhouse gases
to be emitted or sequestered, thereby changing their global
average atmospheric concentrations. Natural activities such
as respiration by plants or animals and seasonal  cycles of
plant growth and decay are examples of processes that only
cycle carbon or nitrogen between the atmosphere and organic
biomass. Such processes, except when directly or indirectly
perturbed out of equilibrium by  anthropogenic activities,
generally do not alter average atmospheric greenhouse gas
concentrations over decadal timeframes. Climatic changes
resulting from anthropogenic activities, however, could
have positive or negative feedback effects on these natural
systems. Atmospheric concentrations of these gases, along
with their rates  of growth and atmospheric lifetimes, are
presented in Table 1-1.
    A brief description of each greenhouse gas, its sources,
and its role in the atmosphere is given below. The following
section then explains the concept of  GWPs, which are
assigned to individual gases  as a measure of their relative
average global radiative forcing effect.
    Water  Vapor (H2O). Overall, the most  abundant and
dominant greenhouse gas in the atmosphere is water vapor.
Water vapor is  neither long-lived nor  well mixed in the
atmosphere, varying  spatially from 0 to 2 percent (IPCC
1996). In addition, atmospheric water can exist in several
physical states including gaseous, liquid, and solid. Human
activities are  not  believed to affect directly the average
global concentration of water vapor, but  the radiative
forcing produced by the increased concentrations of other
greenhouse gases may indirectly affect the hydrologic cycle.
While a warmer atmosphere has an increased water holding
capacity, increased concentrations of water vapor affects the
formation of clouds, which can both absorb and reflect solar
and terrestrial radiation. Aircraft contrails, which consist of
water vapor and other aircraft emittants, are similar to clouds
in their radiative forcing effects (IPCC 1999).
    Carbon Dioxide. In nature, carbon is cycled between
various atmospheric, oceanic, land biotic,  marine biotic,
and mineral reservoirs. The largest fluxes occur between the
atmosphere and terrestrial biota, and between the atmosphere
and  surface water of the  oceans.  In the atmosphere,
carbon predominantly exists in its  oxidized form as CO2.
Atmospheric CO2 is part of this global carbon  cycle, and
therefore its fate is a complex function of geochemical
and biological processes. Carbon dioxide  concentrations
in the atmosphere increased from approximately 280 parts
per million by volume (ppmv) in  pre-industrial times to
379 ppmv in 2005, a 35 percent increase (IPCC 2007 and
Hofmann 2004).78 The IPCC definitively states that "the
present atmospheric CO2 increase is caused by anthropogenic
emissions of CO2" (IPCC 2001). The predominant source
of anthropogenic CO2 emissions is the combustion of fossil
fuels. Forest clearing, other biomass burning, and some non-
energy production processes (e.g., cement production) also
emit notable quantities of CO2.
7The pre-industrial period is considered as the time preceding the year
1750 (IPCC 2001).
8 Carbon dioxide concentrations during the last 1,000 years of the pre-
industrial period (i.e., 750-1750), a time of relative climate stability,
fluctuated by about ±10 ppmv around 280 ppmv (IPCC 2001).
                                                                                                Introduction  1-3

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    In its second assessment, the IPCC also stated that" [t]he
increased amount of CO2 [in the atmosphere] is leading
to climate change and will produce, on average, a global
warming of the earth's surface because of its enhanced
greenhouse effect—although the magnitude and significance
of the effects are not fully resolved" (IPCC 1996).
    Methane. Methane is primarily produced through
anaerobic decomposition of organic matter in biological
systems. Agricultural processes such as wetland rice
cultivation, enteric fermentation in animals, and the
decomposition of animal wastes emit CH4, as does the
decomposition of municipal solid wastes. Methane is also
emitted during  the production and  distribution of natural
gas and petroleum, and is released as a by-product of coal
mining and incomplete fossil fuel combustion. Atmospheric
concentrations of CH^ have increased by about 143 percent
since 1750, from a pre-industrial value of about 722 ppb to
1,774 ppb in 2005, although the rate of increase has been
declining. The IPCC has estimated that slightly more than half
of the current CH^ flux to the atmosphere is anthropogenic,
from human activities  such as agriculture, fossil fuel use,
and waste disposal (IPCC 2007).
    Methane is removed from the  atmosphere through a
reaction with the hydroxyl  radical (OH) and is ultimately
converted to CO2. Minor removal processes  also include
reaction with chlorine in the marine boundary layer, a soil
sink, and stratospheric reactions. Increasing emissions of CH4
reduce the concentration of OH, a feedback that may increase
the atmospheric lifetime of CH4 (IPCC 2001).
    Nitrous Oxide. Anthropogenic sources of N2O emissions
include agricultural soils, especially production of nitrogen-
fixing crops and forages, the use of synthetic and manure
fertilizers, and manure deposition by livestock; fossil fuel
combustion, especially from mobile combustion; adipic
(nylon) and nitric acid production; wastewater treatment and
waste incineration; and biomass burning. The atmospheric
concentration of N2O has increased by 18 percent since 1750,
from a pre-industrial value of about 270 ppb to 319 ppb in
2005, a concentration  that  has not  been exceeded during
the last thousand years. Nitrous oxide is primarily removed
from the atmosphere by the photolytic action of sunlight in
the stratosphere (IPCC 2007).
    Ozone. Ozone is present in both the upper stratosphere,9
where it shields the earth from harmful levels of ultraviolet
radiation, and at lower concentrations in the troposphere,10
where it is  the main component  of anthropogenic
photochemical "smog." During the last two decades,
emissions of anthropogenic chlorine and bromine-containing
halocarbons, such as CFCs, have depleted stratospheric
ozone concentrations. This loss of ozone in the stratosphere
has resulted  in negative radiative  forcing, representing
an indirect effect of anthropogenic  emissions  of chlorine
and bromine compounds (IPCC 1996). The depletion of
stratospheric ozone and its radiative forcing was expected to
reach a maximum in about 2000 before starting to recover,
with detection of such recovery not expected to occur much
before 2010 (IPCC 2001).
    The past increase in tropospheric ozone, which is also
a greenhouse gas, is estimated to provide the third largest
increase in direct radiative forcing since the pre-industrial
era, behind CO2 and CH4. Tropospheric ozone is produced
from complex chemical reactions of volatile organic
compounds mixing  with NOX in the presence of sunlight.
The tropospheric concentrations of  ozone  and these other
pollutants are short-lived and, therefore, spatially variable.
(IPCC 2001)
    Halocarbons, Perfluorocarbons, and Sulfur Hexafluoride.
Halocarbons  are, for the most part, man-made chemicals
that have both direct and indirect radiative forcing effects.
Halocarbons  that contain chlorine (CFCs, HCFCs, methyl
chloroform, and carbon tetrachloride) and bromine (halons,
methyl bromide, and hydrobromofluorocarbons [HFCs])
result in stratospheric ozone depletion and are therefore
controlled under the Montreal Protocol on  Substances that
Deplete the Ozone Layer. Although CFCs and HCFCs include
potent global warming  gases, their net radiative forcing
effect on the atmosphere is reduced because  they cause
stratospheric  ozone  depletion, which itself is an important
greenhouse gas in  addition  to shielding  the  earth from
9 The stratosphere is the layer from the troposphere up to roughly 50
kilometers. In the lower regions the temperature is nearly constant but in the
upper layer the temperature increases rapidly because of sunlight absorption
by the ozone layer. The ozone-layer is the part of the stratosphere from 19
kilometers up to 48 kilometers where the concentration of ozone reaches
up to 10 parts per million.
10 The troposphere is the layer from the ground up to 11 kilometers near
the poles  and up to 16 kilometers in equatorial regions (i.e., the lowest
layer of the atmosphere where people live). It contains roughly 80 percent
of the mass of all gases in the atmosphere and is the site for most weather
processes, including most of the water vapor and clouds.
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harmful levels of ultraviolet radiation. Under the Montreal
Protocol, the United States phased out the production and
importation of halons by 1994 and of CFCs by 1996. Under
the Copenhagen Amendments to the Protocol, a cap was
placed on the production and importation of HCFCs by non-
Article 511 countries beginning in 1996, and then followed
by a complete phase-out by the year 2030. While ozone
depleting gases covered under the Montreal Protocol and
its Amendments are not covered by the UNFCCC; they are
reported in this Inventory under Annex 6.2 of this report for
informational purposes.
    HFCs, PFCs, and SF6 are not ozone depleting substances,
and therefore are not covered under the Montreal Protocol.
They are, however, powerful greenhouse gases.  HFCs
are primarily used as replacements for ozone  depleting
substances but also emitted as a by-product of the HCFC-
22 manufacturing process.  Currently, they have a small
aggregate radiative forcing impact, but it is anticipated that
their contribution to overall  radiative forcing will increase
(IPCC 2001). PFCs and SF6 are predominantly emitted from
various  industrial processes  including aluminum smelting,
semiconductor manufacturing, electric power transmission
and distribution,  and magnesium casting. Currently,  the
radiative forcing impact of PFCs and SF6 is also  small,
but they have a significant growth rate, extremely long
atmospheric lifetimes,  and are strong absorbers of infrared
radiation, and therefore have the potential to influence climate
far into the future (IPCC 2001).
    Carbon Monoxide. Carbon monoxide has an indirect
radiative forcing effect by elevating concentrations of CH4
and tropospheric ozone through chemical reactions with
other atmospheric constituents (e.g., the hydroxyl radical,
OH) that would otherwise  assist in destroying CH4 and
tropospheric ozone. Carbon monoxide is created when
carbon-containing fuels are burned incompletely. Through
natural processes in the atmosphere, it is eventually oxidized
to CO2. Carbon monoxide concentrations are both short-lived
in the atmosphere and spatially variable.
    Nitrogen Oxides. The primary climate change effects of
nitrogen oxides (i.e., NO and NO2) are indirect and result
from their role in promoting the formation of ozone in the
troposphere and, to a lesser degree, lower stratosphere,
where it has positive radiative forcing effects.12 Additionally,
NOX emissions from aircraft are also likely to decrease CH4
concentrations, thus having a negative radiative forcing
effect  (IPCC 1999).  Nitrogen oxides are created  from
lightning, soil microbial activity, biomass burning  (both
natural and anthropogenic fires) fuel combustion, and,
in the  stratosphere, from the photo-degradation of  N2O.
Concentrations of NOX are both relatively short-lived in
the atmosphere and spatially variable.
    Nonmethane Volatile Organic Compounds (NMVOCs).
Non-CFLj volatile organic compounds include substances such
as propane, butane, and ethane. These compounds participate,
along with NOX, in the formation of  tropospheric ozone
and other photochemical oxidants. NMVOCs are emitted
primarily from transportation and industrial processes, as
well as biomass burning and non-industrial consumption of
organic solvents. Concentrations of NMVOCs tend to be both
short-lived in the atmosphere and spatially variable.
    Aerosols. Aerosols are extremely small particles or liquid
droplets found in the atmosphere. They can be produced by
natural events such as dust storms and volcanic activity, or by
anthropogenic processes such as fuel combustion and biomass
burning. Aerosols affect radiative  forcing differently than
greenhouse gases, and their radiative effects occur through
direct and indirect mechanisms: directly by scattering and
absorbing solar radiation; and indirectly by increasing droplet
counts that modify the formation, precipitation efficiency, and
radiative properties of clouds. Aerosols are removed from
the atmosphere relatively rapidly by precipitation. Because
aerosols generally have  short atmospheric lifetimes, and
have concentrations and compositions that vary regionally,
spatially, and temporally, their contributions to radiative
forcing are difficult to quantify (IPCC 2001).
    The indirect radiative forcing from aerosols is typically
divided into two effects. The first effect involves decreased
droplet size and increased droplet concentration  resulting
from an increase in airborne aerosols. The second effect
"Article 5 of the Montreal Protocol covers several groups of countries,
especially developing countries, with low consumption rates of ozone
depleting substances. Developing countries with per capita consumption
of less than 0.3 kg of certain ozone depleting substances (weighted by their
ozone depleting potential) receive financial assistance and a grace period of
ten additional years in the phase-out of ozone depleting substances.
12 NOX emissions injected higher in the stratosphere, primarily from fuel
combustion emissions from high altitude supersonic aircraft, can lead to
stratospheric ozone depletion.
                                                                                               Introduction   1-5

-------
involves an increase in the water content and lifetime
of clouds due to  the effect of reduced droplet size on
precipitation efficiency (IPCC 2001). Recent research has
placed a greater focus on the second indirect radiative forcing
effect of aerosols.
    Various categories of aerosols exist,  including
naturally produced aerosols such as soil dust, sea salt,
biogenic aerosols, sulfates, and volcanic aerosols, and
anthropogenically manufactured aerosols such as industrial
dust and carbonaceous13 aerosols (e.g., black carbon, organic
carbon) from transportation,  coal combustion, cement
manufacturing, waste incineration, and biomass burning.
    The net effect of aerosols on radiative forcing is believed
to be negative (i.e., net cooling effect on the climate),
although because they remain in the atmosphere for only days
to weeks, their concentrations respond rapidly to changes in
emissions.14 Locally, the negative radiative forcing effects
of aerosols can offset the positive forcing of greenhouse
gases (IPCC  1996). "However, the aerosol effects do not
cancel the global-scale effects of the much longer-lived
greenhouse gases,  and significant climate changes can still
result" (IPCC 1996).
    The IPCC's Third Assessment Report notes that "the
indirect radiative effect of aerosols is now understood to also
encompass effects on ice and mixed-phase clouds, but the
magnitude of any such indirect effect is not known, although
it is likely to be positive" (IPCC 2001). Additionally, current
research suggests that another constituent of aerosols, black
carbon, may have a positive radiative forcing (Jacobson
2001). The primary anthropogenic emission sources of black
carbon include diesel exhaust and open biomass burning.

Global Warming Potentials
    A global warming potential is a quantified  measure of
the globally averaged relative radiative forcing impacts  of
a particular greenhouse gas (see Table 1-2). It is defined as
the ratio of the time-integrated radiative forcing from the
instantaneous release of 1 kilogram (kg) of a trace substance
relative to that of 1 kg of a reference gas (IPCC 2001).
Direct radiative effects occur when the gas itself absorbs
13 Carbonaceous aerosols are aerosols that are comprised mainly of organic
substances and forms of black carbon (or soot) (IPCC 2001).
14 Volcanic activity can inject significant quantities of aerosol-producing
SO2 and other sulfur compounds into the stratosphere, which can result in
a longer negative forcing effect (i.e., a few years) (IPCC 1996).
radiation. Indirect radiative forcing occurs when chemical
transformations involving the original gas produce a gas or
gases that are greenhouse gases, or when a gas influences
other radiatively important processes such as the atmospheric
lifetimes of other gases. The reference gas used is CO2,
and therefore GWP weighted emissions are measured in
teragrams of CO2 equivalent (Tg CO2 Eq.).15 The relationship
between gigagrams (Gg) of a gas and Tg CO2 Eq. can be
expressed as follows:
                                           Tg
   Tg CO2 Eq. = (Gg of gas) x (GWP) x
                                        1,000 Gg
where,
    Tg CO2 Eq.
    Gg
    GWP
    Tg
Teragrams of CO2 Equivalents
Gigagrams (equivalent to a
thousand metric tons)
Global Warming Potential
Teragrams
    GWP values allow for a comparison of the impacts of
emissions and reductions of different gases. According to the
IPCC, GWPs typically have an uncertainty  of +35 percent.
The parties to the UNFCCC have also agreed to use GWPs
based upon a 100-year time horizon although other time
horizon values are available.

    Greenhouse gas emissions and removals should
    be presented on a gas-by-gas basis in units of
    mass... In  addition, consistent with decision 21
    CP.3, Parties should report aggregate emissions
    and removals of greenhouse gases,  expressed in
    CO2 equivalent terms at summary inventory level,
    using GWP values provided by  the IPCC in its
    Second Assessment Report... based on the effects of
    greenhouse gases over a 100-year time horizon.16

    Greenhouse gases with relatively long atmospheric
lifetimes (e.g., CO2, CH4, N2O, HFCs, PFCs, and SF6)
tend to  be  evenly  distributed  throughout the atmosphere,
and consequently global average concentrations can be
15 Carbon comprises 12/44'hs of carbon dioxide by weight.
16 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).
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Table 1-2: Global Warming Potentials and Atmospheric
Lifetimes (Years) Used in this Report
Gas
C02
CH4b
N20
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4Fio
CeF-|4
SF6
Atmospheric
Lifetime
50-200
12+3
120
264
5.6
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
GWPa
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
  a 100-year time horizon
  b The GWP of CH4 includes the direct effects and those indirect effects
   due to the production of tropospheric ozone and stratospheric water
   vapor. The indirect effect due to the production of C02 is not included.
  Source: (IPCC 1996)
determined. The short-lived gases such as water vapor,
carbon monoxide,  tropospheric ozone, ozone precursors
(e.g., NOX, and NMVOCs),  and tropospheric aerosols
(e.g., SO2 products and carbonaceous particles), however,
vary regionally, and consequently it is difficult to quantify
their global radiative forcing impacts. No GWP values are
attributed to these gases that are short-lived and spatially
inhomogeneous in the atmosphere.

1.2.  Institutional Arrangements

    The U.S. Environmental Protection Agency (EPA), in
cooperation with other U.S. government agencies, prepares
the Inventory of U.S. Greenhouse Gas Emissions and Sinks.
A wide range of agencies  and individuals are involved in
supplying data to, reviewing, or preparing portions of the
U.S. Inventory—including federal and state government
authorities, research and academic institutions, industry
associations, and private consultants.
    Within EPA, the Office of Atmospheric Programs (OAP)
is the lead office responsible for the emission calculations
provided in the Inventory, as well as the completion of the
National Inventory Report and the Common Reporting
Format tables. The Office of Transportation and Air Quality
(OTAQ) is also involved in calculating emissions for the
Inventory. While  the U.S. Department of State  officially
submits the annual Inventory to the UNFCCC, EPA's
OAP serves as the focal point for technical questions and
comments on the U.S. Inventory. The staff of OAP and
OTAQ coordinates the annual methodological choice,
activity data collection, and emission calculations at the
individual source category level. Within OAP, an inventory
coordinator compiles the entire Inventory into the proper
reporting format for submission to the UNFCCC, and is
responsible for the collection  and consistency  of cross-
cutting issues in the Inventory.
    Several other government agencies contribute to the
collection and analysis of the underlying activity data
used in the Inventory calculations. Formal relationships
exist between EPA and other U.S. agencies that provide
official data for use in the Inventory. The U.S. Department
of Energy's Energy Information Administration provides
national fuel consumption data and the U.S. Department of
Defense provides military fuel consumption and bunker fuels.
Informal relationships also exist with other U.S. agencies to
provide activity data for use in EPA's emission calculations.
These include: the U.S. Department of Agriculture, the U.S.
Geological Survey, the Federal Highway Administration, the
Department of Transportation, the Bureau of Transportation
Statistics, the Department of Commerce, the  National
Agricultural Statistics Service, and the Federal Aviation
Administration. Academic and research centers also provide
activity data and calculations to EPA, as well as individual
companies participating in voluntary outreach efforts with
EPA. Finally, the U.S. Department of State officially submits
the Inventory  to the UNFCCC each April.

1.3.  Inventory Process

    EPA has a decentralized approach to preparing the annual
U.S. Inventory, which  consists of a National Inventory
Report (NIR) and Common Reporting  Format  (CRF)
tables. The Inventory coordinator at EPA is responsible for
compiling all  emission estimates, and ensuring consistency
and quality throughout the NIR and CRF tables.  Emission
calculations for individual sources are the responsibility of
individual source  leads, who are most familiar with each
                                                                                            Introduction  1-7

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Box 1-1: The IPCC Fourth Assessment Report and Global Warming Potentials

      In 2007, the IPCC published its Fourth Assessment Report (AR4), which provided an updated and more comprehensive scientific
  assessment of climate change. Within this report, the GWPs of several gases were revised  relative to the SAR and the IPCC's Third
  Assessment Report (TAR) (IPCC 2001). Thus the GWPs used in this report have been updated twice by the IPCC; although the SAR GWPs
  are used throughout this report, it is interesting to review the changes to the GWPs and the impact such improved understanding has on the
  total GWP-weighted emissions of the United States. Since the SAR and TAR, the IPCC has applied an improved calculation of C02 radiative
  forcing and an improved C02 response function. The GWPs are drawn from IPCC/TEAP (2005) and the TAR, with updates for those cases
  where new laboratory or  radiative transfer results have been published. Additionally, the atmospheric lifetimes of some gases have been
  recalculated. In addition, the values for radiative forcing  and lifetimes have been recalculated for a variety of halocarbons, which were not
  presented in the SAR. Table 1-3 presents the new GWPs, relative to those presented in the SAR.

                   Table 1-3: Comparison of 100-Year GWPs
Gas

C02
CH4a
N20
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4Fio
C6F14
SF6
SAR

1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
TAR

1
23
296
12,000
550
3,400
1,300
4,300
120
3,500
9,400
1,500
5,700
11,900
8,600
9,000
22,200
AR4

1
25
298
14,800
675
3,500
1,430
4,470
124
3,220
9,810
1,640
7,390
12,200
8,860
9,300
22,800
Change
TAR
NC
2
(14)
300
(100)
600
NC
500
(20)
600
3,100
200
(800)
2,700
1,600
1,600
(1,700)
from SAR
AR4
0
4
(12)
3,100
25
700
130
670
(16)
320
3,510
340
890
3,000
1,860
1,900
(1,100)
                   NC (No Change)
                   aThe GWP of CH4 includes the direct effects and those indirect effects due to the production of tropospheric
                    ozone and stratospheric water vapor. The indirect effect due to the production of C02 is not included.
                   Note: Parentheses indicate negative values.
                   Source: IPCC (2001, 2007)
      To comply with international reporting standards under the UNFCCC, official emission estimates are reported by the United States using
  SAR GWP values. The UNFCCC reporting guidelines for national inventories17 were updated in 2002 but continue to require the use of GWPs
  from the SAR so that current estimates of aggregate greenhouse gas emissions for 1990 through 2006 are consistent and comparable with
  estimates developed prior to the publication of the TAR and AR4. For informational purposes, emission estimates that use the updated GWPs
  are presented in detail in Annex 6.1 of this report. All estimates provided throughout this report are also presented in unweighted units.
  17 See .


source category and the unique characteristics of  its   coordinating  with researchers and contractors familiar
emissions profile. The individual source leads determine   with the sources. A multi-stage process for collecting
the most appropriate methodology and collect the best   information  from the individual source leads  and
activity data to use in the emission calculations, based   producing the Inventory is undertaken annually to compile
upon their expertise in the source category,  as  well as   all information and data.


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Methodology Development, Data
Collection, and Emissions and Sink
Estimation
    Source leads at EPA collect input data and, as necessary,
evaluate or develop the estimation methodology for the
individual source categories. For most source categories,
the methodology for the previous year is applied to the
new "current" year of the Inventory, and inventory analysts
collect any new data or update data that have changed from
the previous year. If estimates for a new source category are
being developed  for the first time, or if the methodology is
changing for  an existing source category (e.g., the United
States is implementing a higher tiered approach for that
source category), then the source category lead will develop
a new methodology, gather the most appropriate activity
data and emission factors (or in some cases direct emission
measurements) for the entire time series, and conduct a
special source-specific peer review process involving relevant
experts from industry, government, and universities.
    Once the methodology is in place and the data are
collected, the individual source leads calculate emissions and
sink estimates. The source leads then update or create the
relevant text and accompanying annexes for the Inventory.
Source leads are also responsible for completing the
relevant sectoral background tables of the CRF, conducting
quality assurance and quality control (QA/QC) checks, and
uncertainty analyses.

Summary Spreadsheet Compilation and
Data Storage
    The inventory coordinator at EPA collects the  source
categories' descriptive text and Annexes, and also aggregates
the emission estimates into a summary spreadsheet that
links the individual source category spreadsheets together.
This summary sheet contains all of the essential  data in
one central location, in formats commonly  used in the
Inventory document. In addition to the data from each source
category, national trend and related data are also gathered
in the summary  sheet for use in the Executive Summary,
Introduction,  and Recent Trends sections of the Inventory
report. Electronic copies of each year's summary spreadsheet,
which contains all the emission and sink estimates for the
United States, are kept on a central server at EPA under the
jurisdiction of the inventory coordinator.
National Inventory Report Preparation
    The NIR is compiled from the sections developed
by each individual source lead. In addition, the inventory
coordinator prepares a brief overview of each chapter that
summarizes the emissions from all sources discussed in the
chapters. The inventory coordinator then carries out a key
category analysis for the Inventory, consistent with the IPCC
Good Practice Guidance, IPCC Good Practice Guidance for
Land Use, Land Use Change and Forestry, and in accordance
with the reporting requirements of the UNFCCC. Also at
this time, the Introduction, Executive Summary, and Recent
Trends sections are drafted, to reflect the trends for the most
recent year of the current Inventory. The analysis of trends
necessitates gathering supplemental data, including weather
and temperature conditions, economic activity and gross
domestic product, population, atmospheric conditions, and
the annual consumption of electricity, energy, and fossil
fuels. Changes  in these data are used to explain the trends
observed in greenhouse gas emissions in the United States.
Furthermore, specific factors that affect individual sectors
are researched and discussed. Many of the factors that affect
emissions are included in the inventory document as separate
analyses or side discussions in boxes within the text. Text
boxes are also  created to examine the data aggregated in
different ways than in the remainder of the document, such
as a focus on transportation activities or emissions  from
electricity generation. The document is prepared to match
the specification of the UNFCCC reporting guidelines for
National Inventory Reports.

Common  Reporting Format Table
Compilation
    The CRF tables are compiled from individual tables
completed by each individual  source lead, which contain
source emissions and activity data. The inventory coordinator
integrates the source data into  the UNFCCC's "CRF
Reporter" for the United States, assuring consistency across
all sectoral tables. The summary reports  for emissions,
methods, and emission factors used, the overview tables
for completeness and quality of estimates, the recalculation
tables, the notation key completion tables, and the emission
trends tables are then completed by the inventory coordinator.
Internal automated quality checks on the  CRF Reporter, as
well as reviews by the source leads, are completed for the
entire time series of CRF tables before submission.
                                                                                           Introduction  1-9

-------
QA/QC and Uncertainty
    QA/QC and uncertainty analyses are supervised by the
QA/QC and Uncertainty coordinators, who have general
oversight over the implementation of the QA/QC plan and
the overall uncertainty analysis for the Inventory (see sections
on QA/QC and Uncertainty, below). These coordinators work
closely with the source leads to ensure that a consistent QA/
QC plan and uncertainty analysis is implemented across all
inventory sources. The inventory  QA/QC plan, detailed in
a following section, is consistent with the quality assurance
procedures outlined by EPA and IPCC.

Expert and Public Review Periods
    During the Expert Review period, a first draft of the
document is sent to a select list of technical experts outside
of EPA. The purpose of the Expert Review is to encourage
feedback on the methodological and data sources used in
the current Inventory, especially for sources which have
experienced any changes since the previous Inventory.
    Once comments are received and addressed, a second
draft of the document is released for public review by
publishing a notice in the U.S. Federal Register and posting
the document on  the  EPA Web site. The Public Review
period allows for a 30 day comment period and is open to
the entire U.S. public.

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

1.4.   Methodology and Data Sources

    Emissions of greenhouse gases from various source and
sink categories  have been estimated using methodologies
that are  consistent with the Revised 1996 IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997). In addition, the United States references
the additional guidance provided in the IPCC Good Practice
Guidance and  Uncertainty Management  in National
Greenhouse Gas Inventories (IPCC 2000), the IPCC Good
Practice Guidance for Land Use, Land- Use Change, and
Forestry (IPCC 2003), and  the 2006 IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC 2006). To the
extent possible, the present report relies on published activity
and emission factor data. Depending on the emission source
category, activity data can include fuel consumption or
deliveries, vehicle-miles traveled, raw material processed,
etc. Emission factors are factors that relate quantities of
emissions to an activity.
    The IPCC methodologies provided in the Revised
1996 IPCC Guidelines represent baseline methodologies
for a variety  of source categories, and many of these
methodologies continue to be improved and refined as new
research and data become available. This report uses the
IPCC methodologies when applicable, and supplements them
with other available methodologies and data where possible.
Choices made regarding the methodologies and data sources
used are provided in conjunction with the discussion of each
source category in the main body of the report. Complete
documentation is provided in the annexes on the detailed
methodologies and data  sources utilized in the calculation
of each source category.

Box 1-2: IPCC Reference Approach
      The UNFCCC reporting  guidelines require countries to
  complete a "top-down" reference approach for estimating C02
  emissions from fossil fuel combustion in addition to their "bottom-
  up" sectoral methodology. This estimation method uses alternative
  methodologies and different data sources than those contained
  in that section of the  Energy  chapter. The reference approach
  estimates fossil fuel consumption by adjusting national aggregate
  fuel production data for imports, exports, and stock changes rather
  than relying on end-user consumption surveys (see Annex 4 of
  this report). The reference  approach assumes that once carbon-
  based fuels are brought into a national economy, they are either
  saved in some way (e.g., stored in products, kept in fuel stocks,
  or left unoxidized in ash) or combusted, and therefore the carbon
  in them is oxidized and released into the atmosphere. Accounting
  for actual consumption of fuels at the  sectoral or sub-national
  level is not required.
1-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
1.5.  Key Categories
    The IPCC's Good Practice Guidance (IPCC 2000)
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."18 By
definition, key categories include those sources that have
the greatest contribution to the absolute level of national
emissions. In addition, when an entire time series of
emission estimates is prepared, a thorough investigation of
key categories must also account for the influence of trends
and uncertainties of individual source and sink categories.
This analysis culls out source and sink categories  that
diverge from the overall trend in national emissions. Finally,
a qualitative evaluation of key categories is performed to
capture  any categories that were not identified in either of
the quantitative analyses.
    A Tier 1 approach, as defined in the IPCC's Good
Practice Guidance (IPCC 2000), was implemented to identify
the key  categories for the United States. This analysis was
performed twice; one analysis included sources and sinks from
the Land Use, Land-Use Change, and Forestry (LULUCF)
sector, the other analysis did not  include the LULUCF
categories. Following the Tier 1 approach, a Tier 2 approach,
as defined in the IPCC's Good Practice Guidance  (IPCC
2000), was then implemented to identify any additional key
categories not already identified in the Tier 1 assessment. This
analysis, which includes each source cateogory's uncertainty
assessments in its calculations, was also performed twice to
include or exclude LULUCF sources.
    In addition to conducting Tier 1 and 2 level and trend
assessments, a qualitative assessment of the source categories,
as described in the IPCC's Good Practice Guidance (IPCC
2000), was conducted to capture any key categories that were
not identified by either quantitative method. One additional
key category, international bunker fuels, was identified
using this qualitative assessment. International bunker fuels
are fuels consumed for aviation or marine international
transport activities, and emissions from these fuels are
reported separately from totals in accordance with IPCC
guidelines. If these emissions were included in the totals,
bunker fuels would qualify as a key category according to
the Tier 1 approach. The amount of uncertainty associated
with estimation of emissions from international bunker fuels
also supports the qualification of this source category as key,
which would qualify it as a key category according to the
Tier 2 approach.
    Table 1-4 presents the key categories for the United
States (including and excluding LULUCF categories) using
emissions and uncertainty data in this report,  and ranked
according to their sector and global warming potential-
weighted emissions in 2007.  The  table also indicates the
criteria used in identifying these categories (i.e., level, trend,
Tier 1, Tier 2, and/or qualitative assessments). Annex 1 of
this report provides additional information regarding the key
categories in the United States and the methodologies used
to identify them.

1.6.  Quality Assurance and Quality
Control (QA/QC)

    As part of efforts to achieve its stated goals for inventory
quality, transparency, and credibility, the United States has
developed a  quality assurance and quality control plan
designed to check, document and improve the quality of
its Inventory over time. QA/QC activities on the Inventory
are undertaken within the framework of the U.S. QA/QC
plan, Quality Assurance/Quality Control and Uncertainty
Management Plan for the U.S. Greenhouse Gas Inventory:
Procedures Manual for QA/QC and Uncertainty Analysis.
    In particular, key attributes of the  QA/QC plan
include:
•   specific detailed procedures and forms that  serve to
    standardize the process  of documenting and archiving
    information, as well as to guide the  implementation
    of QA/QC and the analysis of the uncertainty of the
    inventory estimates;
•   expert review as well as  QC—for both the inventory
    estimates and the Inventory  (which is the  primary
    vehicle for disseminating the  results of the inventory
    development process). In addition, the plan provides
    for public review of the Inventory;
18 See Chapter 7 "Methodological Choice and Recalculation" in IPCC
(2000). 
                                                                                           Introduction  1-11

-------
Table 1-4: Key Categories for the United States (1990-2007)
IPCC Source Categories



Energy
C02 Emissions from Stationary Combustion-Coal
C02 Emissions from Mobile Combustion:
Road & Other
C02 Emissions from Stationary Combustion-Gas
C02 Emissions from Stationary Combustion-Oil
C02 Emissions from Mobile Combustion: Aviation
C02 Emissions from Non-Energy Use of Fuels
C02 Emissions from Mobile Combustion: Marine
C02 Emissions from Natural Gas Systems
C02 Emissions from Incineration of Waste
Fugitive CH4 Emissions from Natural Gas Systems
Fugitive CH4 Emissions from Coal Mining
Fugitive CH4 Emissions from Petroleum Systems
Non-C02 Emissions from Stationary Combustion
N20 Emissions from Mobile Combustion:
Road & Other
Non-C02 Emissions from Stationary Combustion
International Bunker Fuels"
Industrial Processes
C02 Emissions from Iron and Steel Production &
Metallurgical Coke Production
C02 Emissions from Cement Production
C02 Emissions from Ammonia Production and
Urea Consumption
N20 Emissions from Adipic Acid Production
Emissions from Substitutes for Ozone
Depleting Substances
HFC-23 Emissions from HCFC-22 Production
SF6 Emissions from Electrical Transmission
and Distribution
PFC Emissions from Aluminum Production
Agriculture
CH4 Emissions from Enteric Fermentation
CH4 Emissions from Manure Management
CH4 Emissions from Rice Cultivation
Direct N20 Emissions from Agricultural
Soil Management
Indirect N20 Emissions from Applied Nitrogen
Waste
CH4 Emissions from Landfills
CH4 Emissions from Wastewater Treatment
Gas




C02

C02
C02
C02
C02
C02
C02
C02
C02
CH4
CH4
CH4
CH4

N20
N20
Several

r*n
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C02
rn
L*U2
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MFCs

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PFCs

CH4
CH4
CH4

N20
N20

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CH4

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1-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 1-4: Key Categories for the United States (1990-2007)  (continued)
IPCC Source Categories



Land Use, Land Use Change, and Forestry
C02 from Changes in Forest Carbon Stocks
C02 Emissions from Urban Trees
C02 Emissions from Cropland Remaining Cropland
C02 Emissions from Landfilled Yard Trimmings
and Food Scraps
C02 Emissions from Grassland Remaining Grassland
CH4 Emissions from Forest Fires
N20 Emissions from Forest Fires
Subtotal Without LULUCF
Total Emissions Without LULUCF
Percent of Total Without LULUCF
Subtotal With LULUCF
Total Emissions With LULUCF
Percent of Total With LULUCF
Gas




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  3 Qualitative criteria.
  b Emissions from this source not included in totals.
•   both Tier 1 (general) and Tier 2 (source-specific) quality
    controls and checks, as recommended by IPCC Good
    Practice Guidance;
•   consideration of secondary data quality and source-
    specific quality checks (Tier  2 QC) in parallel and
    coordination with the uncertainty assessment;  the
    development of protocols and templates provides for
    more  structured communication and integration with
    the suppliers of secondary information;
•   record-keeping provisions to track which procedures
    have  been followed, and the  results of the  QA/QC
    and uncertainty  analysis, and contains feedback
    mechanisms for corrective action based on the results
    of the investigations, thereby providing for continual
    data quality improvement and guided research efforts;
•   implementation of QA/QC procedures throughout the
    whole inventory development process—from initial
    data collection, through  preparation of the emission
    estimates, to publication of the Inventory;
•   a schedule for multi-year implementation; and
•   promotion of coordination and interaction within the EPA,
    across Federal agencies and departments, state government
    programs, and research institutions and consulting firms
    involved in supplying data or preparing estimates for the
    inventory. The QA/QC plan itself is intended to be revised
    and reflect new information that becomes available as the
    program develops, methods  are improved, or additional
    supporting documents become necessary.
    In addition, based on the  national QA/QC plan for
the Inventory,  source-specific  QA/QC plans have been
developed for a number of sources. These plans follow the
procedures outlined in the national QA/QC plan, tailoring
the procedures to the specific text and spreadsheets of the
individual sources. For each greenhouse gas emissions source
or sink included in this Inventory, a minimum of a Tier 1 QA/
QC analysis has been undertaken. Where QA/QC activities
for a particular source go beyond the minimum Tier 1 level,
further explanation is provided within the respective source
category text.
                                                                                            Introduction  1-13

-------
    The quality control activities described in the U.S. QA/
QC plan occur throughout the inventory process; QA/QC
is not separate from, but is  an integral  part of, preparing
the Inventory. Quality control—in the form of both good
practices (such as documentation procedures) and checks on
whether good practices and procedures are being followed—
is applied at every stage of inventory  development  and
document preparation. In addition, quality assurance occurs
at two stages —an expert review and a public review. While
both phases can significantly contribute to inventory quality,
the public review phase is also essential for promoting the
openness of the inventory development process and the
transparency of the inventory data and methods.
    The QA/QC plan guides the process of ensuring
inventory quality by describing data and methodology
checks, developing processes governing peer  review  and
public comments, and developing guidance on conducting
an analysis  of the uncertainty  surrounding the emission
estimates. The QA/QC procedures also include feedback
loops and provide for corrective actions that are designed
to improve the inventory estimates over time.

1.7.   Uncertainty Analysis of
Emission Estimates
    Uncertainty estimates are an essential element of a
complete and transparent emissions inventory. Uncertainty
information is not intended to  dispute the validity of
the inventory estimates, but to help prioritize efforts to
improve the accuracy  of future inventories and  guide
future decisions on methodological choice. While the U.S.
Inventory calculates its emission estimates with the highest
possible accuracy, uncertainties are associated to a varying
degree with the development of emission estimates for any
inventory. Some of the current estimates, such as those for
CO2 emissions from energy-related activities and cement
processing, are considered  to have  minimal uncertainty
associated with them. For some other categories of emissions,
however, a lack of data or  an incomplete understanding
of how emissions are generated increases the uncertainty
surrounding  the estimates presented.  Despite  these
uncertainties, the UNFCCC reporting guidelines follow the
recommendation in the 7996IPCC Guidelines (IPCC/UNEP/
OECD/IEA 1997) and require that countries provide  single
point estimates of uncertainty for each gas and emission
or removal source category.  Within the discussion of each
emission source,  specific factors affecting the uncertainty
associated with the estimates are discussed.
    Additional research in the following areas could help
reduce uncertainty in the U.S. Inventory:
•   Incorporating excluded emission sources. Quantitative
    estimates for some of the sources and sinks of greenhouse
    gas emissions are not available at this time. In particular,
    emissions from some land-use activities and industrial
    processes are not  included in the Inventory  either
    because data are incomplete or because methodologies
Table 1-5: Estimated Overall Inventory Quantitative Uncertainty (Tg C02 Eq. and Percent)
2007 Emission
Estimate
Gas (Tg C02 Eq.)

C02
CH4
N20
PFCs, HFCs&SF6d
Total
Net Emissions
(Sources and Sinks)

6,103.4
585.3
311.9
149.5
7,150.1
6,087.5
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Bound0
5,974.9
527.0
278.7
141.6
7,047.8
5,917.7
Upper Bound0
6,390.0
689.0
440.6
160.3
7,525.1
6,503.9
Lower Bound0
-2%
-10%
-11%
-5%
-1%
-3%
Upper Bound0
+5%
+ 18%
+41%
+7%
+5%
+7%
Standard
Mean" Deviation
(Tg C02 Eq.)

6,181.5
599.3
352.4
148.1
7,281.3
6,205.6

106.8
41.3
42.8
4.7
121.9
150.1
  aThe emission estimates correspond to a 95 percent confidence interval.
  b Mean value indicates the arithmetic average of the simulated emission estimates; standard deviation indicates the extent of deviation of the simulated
   values from the mean.
  cThe low and high estimates for total emissions were separately calculated through simulations and, hence, the low and high emission estimates for the
   sub-source categories do not sum to total emissions.
  11 The overall uncertainty estimate did not take into account the uncertainty in the GWP values for CH4, N20 and high GWP gases used in the inventory
   emission calculations for 2007.
1-14   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
    do not exist for estimating emissions from these source
    categories. See Annex 5 of this report for a discussion
    of the sources of greenhouse gas emissions and sinks
    excluded from this report.
•   Improving the accuracy of emission factors. Further
    research is needed in some cases to improve the accuracy
    of emission factors used to calculate  emissions from a
    variety of sources. For example, the accuracy of current
    emission factors applied to CH4 and N2O emissions from
    stationary and mobile combustion is highly uncertain.
•   Collecting detailed activity data. Although methodologies
    exist for estimating emissions for some  sources,
    problems arise in obtaining activity data at a level
    of detail in which aggregate emission factors  can be
    applied. For example, the ability to estimate emissions
    of SF6 from electrical transmission and distribution is
    limited due to a lack of activity data regarding national
    SF6 consumption or average equipment leak rates.
    The overall uncertainty estimate for the U. S. Greenhouse
Gas Emissions Inventory was developed using the IPCC
Tier 2 uncertainty estimation methodology. An estimate of
the overall quantitative uncertainty is shown in Table 1-5.
    The  IPCC provides  good practice guidance on two
approaches—Tier 1 and Tier 2—to estimating uncertainty
for individual source categories. Tier 2 uncertainty analysis,
employing the Monte Carlo Stochastic Simulation technique,
was applied wherever data and resources permitted; further
explanation is provided within the respective source category
text.  Consistent with the  IPCC Good Practice Guidance,
over a multi-year timeframe, the United  States expects to
continue  to improve the uncertainty estimates presented in
this report.
    Emissions calculated for the U.S. Inventory reflect current
best estimates; in some cases, however, estimates are based
on approximate methodologies, assumptions, and incomplete
data. As new information becomes available in the future, the
United States will continue to improve and revise its emission
estimates. See Annex 7 of this report for  further details on
the U.S. process for estimating uncertainties associated with
emission estimates and for a more detailed discussion of the
limitations of the current analysis and plans for improvement.
Annex 7 also includes details on the uncertainty analysis
performed for selected source categories.
1.8.   Completeness
    This report, along with its accompanying CRE Reporter,
serves as a thorough assessment of the anthropogenic sources
and sinks of greenhouse gas emissions for the United States
for the time series 1990 through 2007. Although this report
is intended to be comprehensive, certain sources have been
identified yet excluded from the estimates presented for
various reasons. Generally speaking, sources not accounted
for in this Inventory are excluded due to data limitations or
a lack of thorough understanding of the emission process.
The United States is continually working to improve upon
the understanding of such sources and seeking to find the data
required to estimate related emissions. As such improvements
are made, new emission sources  are quantified and included
in the Inventory. For a complete list of sources excluded, see
Annex 5 of this report.

1.9.  Organization of  Report

    In accordance with the Revised 1996 IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997), and the 2003 UNFCCC Guidelines on
Reporting and Review (UNFCCC 2003), this Inventory of
U.S. Greenhouse Gas Emissions and Sinks is segregated
into six sector-specific chapters, listed below in Table 1-6. In
addition, chapters on Trends in Greenhouse Gas Emissions
and Other information to be considered as part of the U.S.
Inventory submission are included.
    Within each chapter, emissions are identified by the
anthropogenic activity that is  the source or sink of the
greenhouse gas emissions being estimated (e.g., coal mining).
Overall, the foil owing organizational structure is consistently
applied throughout this report:
Chapter/IPCC Sector: Overview of emission trends for each
IPCC defined sector.
    Source Category: Description of source pathway and
    emission trends.
       Methodology: Description of analytical methods
       employed to produce  emission estimates and
       identification of data references, primarily for
       activity data and emission factors.
       Uncertainty: A discussion and quantification of the
       uncertainty in emission  estimates and a discussion
       of time-series consistency.
                                                                                           Introduction  1-15

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Table 1-6: IPCC Sector Descriptions
  Chapter/IPCC Sector
Activities Included
  Energy
  Industrial Processes
  Solvent and Other Product Use
  Agriculture
  Land Use, Land-Use Change, and Forestry
  Waste
Emissions of all greenhouse gases resulting from stationary and mobile energy activities
including fuel combustion and fugitive fuel emissions.
Byproduct or fugitive emissions of greenhouse gases from industrial processes not
directly related  to energy activities such as fossil fuel combustion.
Emissions, of primarily NMVOCs, resulting from the use of solvents and N20 from
product uses.
Anthropogenic  emissions from agricultural activities except fuel combustion, which is
addressed under Energy.
Emissions and  removals of C02, CH4, and N20 from forest management, other land-use
activities, and land-use change.
Emissions from waste management activities.
  Source: IPCC/UNEP/OECD/IEA (1997)
        QA/QC and Verification: A discussion on steps taken
        to QA/QC and verify the emission estimates, where
        beyond the overall U.S. QA/QC plan, and any key
        findings.
        Recalculations: A discussion of  any  data or
        methodological changes that necessitate a recalculation
        of previous years' emission estimates, and the impact
        of the recalculation on the emission  estimates, if
        applicable.
        Planned Improvements: A discussion on any source-
        specific planned improvements, if applicable.
                       Special attention is given to CO2 from fossil fuel
                   combustion relative to other sources because of its share of
                   emissions and its dominant influence on emission trends.
                   For example, each energy-consuming end-use sector (i.e.,
                   residential, commercial, industrial, and transportation),
                   as  well as the electricity generation sector, is described
                   individually. Additional information for certain source
                   categories and other topics is also provided in  several
                   Annexes listed in Table 1-7.
1-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 1-7: List of Annexes

  ANNEX 1    Key Category Analysis
  ANNEX 2    Methodology and Data for Estimating C02 Emissions from Fossil Fuel Combustion
             2.1.   Methodology for Estimating Emissions of C02 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, N20, and Indirect Greenhouse Gases from Stationary Combustion
             3.2.   Methodology for Estimating Emissions of CH4, N20, 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 C02 Emissions from Petroleum Systems
             3.6.   Methodology for Estimating C02 and N20 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 RFC Emissions from Substitution of Ozone Depleting Substances
             3.9.   Methodology for Estimating CH4 Emissions from Enteric Fermentation
             3.10.  Methodology for Estimating CH4 and N20 Emissions from Manure Management
             3.11.  Methodology for Estimating N20 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 C02 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
             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  1-17

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

      In 2007, total U.S. greenhouse gas emissions were 7,150.1 teragrams of carbon dioxide equivalents (Tg CO2 Eq.).1
      Overall, total U.S. emissions have risen by 17 percent from 1990 to 2007. Emissions increased from 2006 to 2007
      by 1.4 percent (99.0 Tg  CO2 Eq.). The following factors were primary contributors to this increase: (1) cooler
winter and warmer summer conditions in 2007 than in 2006 increased the demand for heating fuels and contributed to the
increase in the demand for electricity; (2) increased consumption of fossil fuels to generate electricity; and (3) a significant
decrease (14.2 percent) in hydropower generation used to meet this demand.  Figure 2-1 through Figure 2-3 illustrate the
overall trends in total U.S. emissions by gas,2 annual changes, and absolute changes since 1990.
    As the largest source of U.S. greenhouse gas emissions, carbon dioxide (CO2) from fossil fuel combustion has accounted
for approximately 79 percent of global warming potential (GWP) weighted emissions since 1990, growing slowly from 77
percent of total GWP-weighted emissions in 1990 to 80 percent in 2007. Emissions from this source category grew by 21.8
                                                  percent (1,026.9 Tg CO2 Eq.) from 1990 to 2007 and were
Figure 2-1
        U.S. Greenhouse Gas Emissions by Gas
              MFCs, PFCs, & SFt
              Nitrous Oxide
     8,000 -
     7,000 -
     6,000 -
   S 5,000 -
   o
   m 4,000 -
     3,000 -
     2,000 -
     1,000-
        o-
 Methane
I Carbon Dioxide
      in °> T- °
 <° 3!  5 E = £ ^
 S S.  "- S- E- S- C-
responsible for most of the increase in national emissions
during this period.  From 2006 to 2007, these emissions
increased by 1.8 percent (100.4 Tg CO2 Eq.). Historically,
changes in emissions from fossil fuel combustion have been
the dominant factor  affecting U.S. emission trends.
    Changes in CO2 emissions from fossil fuel combustion
are influenced by many long-term and short-term factors,
including population and economic growth, energy
price fluctuations,  technological changes,  and seasonal
temperatures. On an annual basis, the overall consumption
of fossil fuels in the United States generally fluctuates in
response to changes  in general economic conditions, energy
prices, weather, and the availability of non-fossil alternatives.
For example, in a year with increased consumption of goods
and services, low fuel prices, severe summer and winter
1 Estimates are presented in units of teragrams of carbon dioxide equivalent (Tg CO2 Eq.), which weight each gas by its global warming potential, or GWP,
value. (See section on global warming potentials, Executive Summary.)
2 See the following section for an analysis of emission trends by general U.S. economic sector.
                                                              Trends in Greenhouse Gas Emissions 2-1

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Figure 2-2
               Annual Percent Change in
            U.S. Greenhouse Gas Emissions
   4%-,
   -1%
   -2%
                 "li'iil   lili   •

                       -1.6%
                       i— CM co  ^ m  co r-
Figure 2-3
    Cumulative Change in Annual U.S. Greenhouse Gas
              Emissions Relative to 1990
    1,100
    1,000
     900
     800
     700
   ~ 600
     500
     400
     300
     200
     100
      0
    -100
                                       1051
                                966
                                     952
-45
weather conditions, nuclear plant closures, and lower
precipitation feeding hydroelectric dams, there would likely
be proportionally greater fossil fuel consumption than in
a year with poor economic performance, high fuel prices,
mild temperatures, and increased output from nuclear and
hydroelectric plants.
    In the longer-term, energy consumption patterns
respond to changes that affect the scale of consumption (e.g.,
population, number of cars, and size of houses), the efficiency
with which energy is used in equipment (e.g., cars, power
plants, steel mills, and light bulbs) and consumer behavior
(e.g., walking, bicycling, or telecommuting to  work instead
of driving).
    Energy-related CO2 emissions also depend on the type
of fuel or energy consumed and its carbon (C) intensity.
Producing a unit of heat or electricity using natural gas
instead of coal, for example, can reduce the CO2 emissions
because of the lower C content of natural gas.
    Emissions from fuel combustion increased in 2003 at
about the average annual growth rate since 1990 (1.4 percent).
A number of factors played a major role in the magnitude
of this increase. The U.S. economy experienced moderate
growth from 2002, causing an increase in the demand for
fuels. The price of natural gas escalated dramatically, causing
some  electric power producers to  switch to coal, which
remained at relatively stable prices. Colder winter conditions
brought on more demand for heating fuels, primarily in
the residential sector. Though  a cooler summer partially
offset demand for electricity as the use of air-conditioners
decreased, electricity consumption continued to increase in
2003. The primary drivers behind this trend were the growing
economy and the increase in U.S. housing stock. Nuclear
capacity decreased slightly, for the first time since 1997. Use
of renewable fuels rose slightly due to increases in the use
of hydroelectric power and biofuels.
    From 2003  to 2004, these  emissions continued to
increase at about the average annual growth rate since 1990.
A primary reason behind this trend was strong growth in
the U.S.  economy and industrial production, particularly
in energy-intensive industries,  causing an increase in the
demand for electricity and fossil fuels. Demand for travel was
also higher, causing an increase in petroleum consumed for
transportation. In contrast, the warmer winter conditions led
to decreases in demand for heating fuels, principally natural
gas, in both the residential and commercial sectors. Moreover,
much of the increased electricity demanded was generated by
natural gas combustion and nuclear power, which moderated
the increase in CO2 emissions from electricity generation.
Use of renewable fuels rose very slightly due to increases
in the use biofuels.
    Emissions from fuel combustion increased from 2004
to 2005 at a rate slightly lower  than the  average annual
growth rate since 1990. A number of factors played a role
in this slight increase. This small increase is primarily
2-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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a result of the restraint on fuel consumption, primarily
in the transportation sector, caused by rising fuel prices.
Although electricity prices increased slightly, there was
a significant increase in electricity consumption in the
residential and commercial sectors due to warmer summer
weather conditions. This led  to an increase in emissions
in these sectors with the increased use of air-conditioners.
As electricity emissions increased among all  end-use
sectors, the fuels used to generate electricity increased as
well. Despite a slight decrease in industrial energy-related
emissions, industrial production and manufacturing output
actually increased. The price  of natural gas escalated
dramatically, causing a decrease in consumption of natural
gas in the industrial sector. Use of renewable fuels decreased
slightly due to decreased use of biofuels and decreased
electricity output by hydroelectric power plants.
    From 2005 to 2006, emissions from fuel combustion
decreased for the first time since 2000 to 2001. This
decrease occurred primarily in the electricity generation,
transportation, residential, and commercial sectors due
to a number of factors. The decrease in emissions from
electricity generation is a result of a  smaller share of
electricity generated by coal and a greater share generated by
natural gas. Coal and natural gas consumption for electricity
generation increased by 1.3 percent and 5.9 percent in 2006,
respectively, and nuclear power increased by less  than 1
percent. The transportation decrease is primarily a result
of the restraint on fuel consumption caused by rising fuel
prices, which directly resulted in a decrease of petroleum
consumption within this sector of less than one percent in
2006. The decrease in emissions from the residential sector
is primarily  a result of decreased electricity consumption
due to increases in the price of electricity, and warmer
winter weather conditions. The increase in emissions in the
industrial sector is a result of a increased emissions from
fossil fuel combustion for this sector. A moderate increase
in the industrial sector is a result of growth in industrial
output and growth in the U.S. economy. Renewable fuels
used to generate  electricity increased in 2006, with the
greatest growth occurring in wind.
    After experiencing a decrease from 2005 to 2006,
emissions from fuel combustion grew from 2006 to 2007
at a rate slightly higher than the average growth rate since
1990. There were a number of factors contributing to this
increase. Unfavorable weather conditions in both the winter
and summer resulted in an increase in consumption of heating
fuels, as well as an increase in the demand for electricity.
This demand for electricity was met with an increase in coal
consumption of 1.8 percent, and with an increase in natural
gas consumption  of 10.3 percent. This increase  in fossil
fuel  consumption, combined with a 14.2 percent  decrease
in hydropower generation from 2006 to 2007, resulted in an
increase in emissions in 2007. The increase in emissions from
the residential and commercial sectors is a result of increased
electricity consumption due to warmer summer conditions
and cooler winter  conditions compared to 2006. In addition
to these unfavorable weather conditions, electricity prices
remained relatively stable  compared to 2006, and natural
gas prices decreased slightly. Emissions from the industrial
sector increased slightly compared to 2006 as a result of a 1.7
percent increase in industrial production and the increase in
fossil fuels used for electricity generation. Despite an overall
decrease in electricity generation from renewable energy in
2007 driven by decreases in hydropower generation, wind
and solar generation increased significantly.
    Overall, from 1990 to 2007, total emissions of CO2
increased by 1,026.7 Tg CO2 Eq. (20.2  percent), while
CtLj and N2O emissions decreased by 31.2  Tg  CO2 Eq.
(5.1  percent) and  3.1 Tg CO2 Eq. (1 percent) respectively.
During the same period, aggregate weighted  emissions of
HFCs, PFCs, and SF6 rose by 59 Tg CO2 Eq. (65.2  percent).
Despite being  emitted in smaller quantities relative to  the
other principal greenhouse gases, emissions of HFCs,
PFCs, and SF6 are significant because many of them have
extremely high GWPs and, in the cases of PFCs  and SF6,
long atmospheric lifetimes. Conversely, U.S. greenhouse gas
emissions were partly offset by C sequestration in managed
forests, trees in urban areas, agricultural soils, and landfilled
yard trimmings, which was estimated to be 14.9 percent of
total emissions in  2007.
    Table 2-1 summarizes emissions and sinks from all U.S.
anthropogenic sources in weighted units of Tg CO2 Eq., while
unweighted gas emissions and sinks in gigagrams  (Gg)  are
provided in Table  2-2.
                                                                      Trends in Greenhouse Gas Emissions  2-3

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Table 2-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
  Gas/Source
1990
1995
2000
2005
2006
2007
  C02                                           5,076.7        5,407.9        5,955.2        6,090.8    6,014.9    6,103.4
    Fossil Fuel Combustion                        4,708.9        5,013.9        5,561.51      5,723.5    5,635.4    5,735.8
       Electricity Generation                        1,809.7        1,938.9        2,283.21      2,381.0    2,327.3    2,397.2
       Transportation                             1,484.51      1,598.7        1,800.3        1,881.5    1,880.9    1,887.4
       Industrial                                    834.2          862.6          844.6          828.0      844.5      845.4
       Residential                                  337.7          354.4          370.4          358.0      321.9      340.6
       Commercial                                 214.5          224.4          226.9          221.8      206.0      214.4
       U.S. Territories                                28.3           35.0           36.2           53.2       54.8       50.8
    Non-Energy Use of Fuels                         117.0          137.5          144.5          138.1      145.1      133.9
    Iron and Steel Production & Metallurgical
     Coke Production                               109.8          103.1           95.1           73.2       76.1       77.4
    Cement Production                               33.3           36.8           41.2           45.9       46.6       44.5
    Natural Gas Systems                             33.7           33.8           29.4           29.5       29.5       28.7
    Incineration of Waste                             10.9           15.7           17.5           19.5       19.8       20.8
    Lime Production                                 11.5           13.3           14.1           14.4       15.1       14.6
    Ammonia Production and Urea Consumption         16.8           17.8           16.4           12.8       12.3       13.8
    Cropland Remaining Cropland                      7.11          7.01         7.51          7.9        7.9        8.0
    Limestone and Dolomite Use                       5.11          6.71         5.11          6.8        8.0        6.2
    Aluminum  Production                              6.81          5.71         6.11          4.1        3.8        4.3
    Soda Ash Production and Consumption              4.11          4.31         4.21          4.2        4.2        4.1
    Petrochemical Production                          2.2            2.8            3.01          2.8        2.6        2.6
    Titanium Dioxide Production                        1.2            1.51         1.81          1.8        1.9        1.9
    Carbon Dioxide Consumption                       1.4            1.4            1.4            1.3        1.7        1.9
    Ferroalloy Production                              2.2            2.01         1.91          1.4        1.5        1.6
    Phosphoric Acid Production                        1.51          1.51         1.4            1.4        1.2        1.2
    Wetlands Remaining Wetlands                      1.01          1.01         1.2            1.1        0.9        1.0
    Zinc Production                                  O.gl          1.0            1.11          0.5        0.5        0.5
    Petroleum Systems                               0.4l          0.31         0.31          0.3        0.3        0.3
    Lead Production                                  0.31          0.31         0.31          0.3        0.3        0.3
    Silicon Carbide Production and Consumption          0.4!          0.31         0.2!          0.2        0.2        0.2
    Land Use, Land-Use Change, and
     Forestry (Sink)3                             (841.4)        (851.0)        (717.5)       (1,122.7)   (1,050.5)   (1,062.6)
    Biomass—Woodb                              215.2          229.1          218.1          208.9      209.9      209.8
    International Bunker Fuels"                       114.3          101.6           99.0          111.5      110.5      108.8
    Biomass—Ethanol"                               4.2U          7.71         9.2!         22.6       30.5       38.0
  CH4                                             616.6          615.8          591.1          561.7      582.0      585.3
    Enteric Fermentation                             133.2          143.6          134.4          136.0      138.2      139.0
    Landfills                                       149.2          144.3          122.3          127.8      130.4      132.9
    Natural Gas Systems                            129.6          132.6          130.8          106.3      104.8      104.7
    Coal Mining                                     84.1           67.1           60.5           57.1       58.4       57.6
    Manure Management                             30.4           34.5           37.9           41.8       41.9       44.0
    Forest Land Remaining Forest Land                  4.el          6.11        20.6           14.2       31.3       29.0
    Petroleum Systems                              33.9           32.0           30.3           28.3       28.3       28.8
    Wastewater Treatment                            23.5           24.8           25.2           24.3       24.5       24.4
    Stationary  Combustion                            7.4l          7.11         6.61          6.7        6.3        6.6
    Rice Cultivation                                  7.11          7.61         7.51          6.8        5.9        6.2
    Abandoned Underground Coal Mines                6.0            8.2            7.41          5.6        5.5        5.7
    Mobile Combustion                               4.71          4.31         3.41          2.5        2.4        2.3
    Composting                                      O.sl          0.71         1.3            1.6        1.6        1.7
2-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 2-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.) (continued)
  Gas/Source
  1990
  1995
  2000
  2005
2006
  Total
6,098.7
6,463.3
7,008.2
2007
    Petrochemical Production                          0.91         1.1|         1.2            1.1         1.0        1.0
    Field Burning of Agricultural Residues                0.71         0.71         0.81          0.9        0.8        0.9
    Iron and Steel Production & Metallurgical             1 Q            1 Q           Q g            Q7        Q7        Q7

    Ferroalloy Production                               +1          +1          +1           +          +         +
    Silicon Carbide Production and Consumption           +1          +1          +1           +          +         +
    International Bunker Fuels6                         0.2!         0.71         0.71          0.1         0.1        0.1
  N20                                            315.0          334.1         329.2          315.9      312.1     311.9
    Agricultural Soil Management                    200.3          202.3         204.5          210.6      208.4     207.9
    Mobile Combustion                             43.7           53.7          52.8           36.7       33.5       30.1
    Nitric Acid Production                            20.0           22.3          21.9           18.6       18.2       21.7
    Manure Management                            12.1           12.9          14.0           14.2        14.6       14.7
    Stationary Combustion                           12.8           13.3          14.5           14.8       14.5       14.7
    Adipic Acid Production                           15.3           17.3           6.2            5.9        5.9        5.9
    Wastewater Treatment                             3.71         4.01         4.51          4.8        4.8        4.9
    N20 from Product Uses                            4.41         4.61         4.91          4.4        4.4        4.4
    Forest Land Remaining Forest Land                  0.51         0.81         2.4l          1.8        3.5        3.3
    Composting                                     0.4l         0.81         1.41          1.7        1.8        1.8
    Settlements Remaining Settlements                  1.0            1.2           1.2            1.5        1.5        1.6
    Field Burning of Agricultural Residues                0.4l         0.4l         0.51          0.5        0.5        0.5
    Incineration of Waste                              0.51         0.51         0.4l          0.4        0.4        0.4
    Wetlands Remaining Wetlands                       +1          +1          +1           +          +         +
    International Bunker Fuels6                         7.71         0.91         0.91          1.0        1.0        1.0
  MFCs                                           36.9           61.8         100.1          116.1       119.1     125.5
    Substitution of Ozone Depleting Substances0          0.31        28.5          71.2          100.0      105.0     108.3
    HCFC-22 Production                             36.4           33.0          28.6           15.8       13.8       17.0
    Semiconductor Manufacture                        0.2!         0.31         0.31          0.2         0.3        0.3
  PFCs                                           20.8           15.6          13.5            6.2        6.0        7.5
    Aluminum Production                            18.5           11.8           8.61          3.0        2.5        3.8
    Semiconductor Manufacture                        2.2            3.81         4.91          3.2         3.5        3.6
  SF6                                             32.8           28.1          19.2           17.9       17.0       16.5
    Electrical Transmission and Distribution             26.8           21.6          15.1           14.0       13.2       12.7
    Magnesium Production and Processing               5.41         5.61         3.0            2.9        2.9        3.0
    Semiconductor Manufacture                        0.51         0.91         1.1            1.0        1.0        0.8
7,108.6    7,051.1     7,150.1
  Net Emissions (Sources and Sinks)
5,257.3
5,612.3
6,290.7
5,985.9    6,000.6     6,087.5
  + Does not exceed 0.05 Tg C02 Eq.
  aThe net C02 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 International Bunker Fuels and Wood Biomass and Ethanol Consumption are not included in totals.
  c 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 (see Table 2-3 and Figure 2-4). Over the
eighteen-year period of 1990 to 2007, total emissions in
the Energy, Industrial Processes,  and Agriculture sectors
grew by 976.7 Tg CO2 Eq. (19 percent), 28.5 Tg  CO2 Eq.
(9 percent), and 28.9 Tg CO2 Eq. (8 percent), respectively.
               Emissions decreased in the Waste and Solvent and Other
               Product Use sectors by 11.5 Tg CO2 Eq. (6 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 192.5 Tg CO2 Eq. (23 percent).
                                                                              Trends in Greenhouse Gas Emissions  2-5

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Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
  Gas/Source
1990
    1995
    2000
     2005
     2006
     2007
  C02                                       5,076,694
    Fossil Fuel Combustion                     4,708,918
      Electricity Generation                     1,809,685
      Transportation                          1,484,485
      Industrial                                 834,204
      Residential                               337,715
      Commercial                              214,544
      U.S. Territories                             28,285
    Non-Energy Use of Fuels                      116,977
    Iron and Steel Production  & Metallurgical
     Coke Production                            109,760
    Cement Production                           33,278
    Natural Gas Systems                          33,733
    Incineration of Waste                          10,950
    Lime Production                              11,533
    Ammonia Production and Urea Consumption      16,831
    Cropland Remaining Cropland                   7,084
    Limestone and Dolomite Use                    5,127
    Aluminum Production                          6,831
    Soda Ash Production and Consumption           4,141
    Petrochemical Production                       2,221
    Titanium Dioxide Production                     1,195
    Carbon Dioxide Consumption                    1,416
    Ferroalloy Production                           2,152
    Phosphoric Acid Production                     1,529
    Wetlands Remaining Wetlands                   1,033
    Zinc Production                                 949
    Petroleum Systems                              376
    Lead Production                                 285
    Silicon Carbide Production and Consumption         375
    Land Use, Land-Use Change, and
     Forestry (Sink)3                          (841,430)
    Biomass—Wooo*                           215,186
    International Bunker Fuels"                    114,330
    Biomass—Ethanolb                            4,155
  CH4                                          29,360
    Enteric Fermentation                            6,342
    Landfills                                      7,105
    Natural Gas Systems                           6,171
    Coal Mining                                   4,003
    Manure Management                           1,447
    Forest Land Remaining Forest Land                 218
    Petroleum Systems                            1,613
    Wastewater Treatment                          1,120
    Stationary Combustion                           352
          5,407,885
          5,013,910
          1,938,862
          1,598,668
           862,5571
           354,4431
I           224,4001
            34,978
           137,4601
5,407,885
5,013,910
1,938,862
1,598,668
  862,557
  354,443
  224,400
   34,978
  137,460

  103,116
   36,847
   33,810
   15,712
   13,325
   17,796
    7,049
    6,651
    5,659
    4,304
    2,750
    1,526
    1,422
    2,036
    1,513
    1,018
    1,013
      341
      298
      329

(850,952)
  229,091
  101,620
    7,683
   29,325
    6,837
    6,871
    6,314
    3,193
    1,642
      293
    1,524
    1,183
      340
5,955,177
5,561,515
2,283,177
1,800,305
  844,554
  370,352
  226,932
   36,195
  144,473

   95,062
   41,190
   29,394
   17,485
   14,088
   16,402
    7,541
    5,056
    6,086
    4,181
    3,004
    1,752
    1,421
    1,893
    1,382
    1,227
    1,140
      325
      311
      248

(717,506)
  218,088
   98,966
    9,188
   28,148
    6,398
    5,825
    6,231
    2,881
    1,804
      983
    1,441
    1,200
      315
 6,090,838
 5,723,477
 2,381,002
 1,881,470
   828,008
   358,036
   221,761
    53,201
   138,070

    73,190
    45,910
    29,463
    19,532
    14,379
    12,849
     7,854
     6,768
     4,142
     4,228
     2,804
     1,755
     1,321
     1,392
     1,386
     1,079
      465
      287
      266
      219

(1,122,745)
   208,927
   111,487
    22,554
    26,748
     6,474
     6,088
     5,062
     2,719
     1,991
      676
     1,346
     1,159
      318
 6,014,871
 5,635,418
 2,327,313
 1,880,874
   844,505
   321,852
   206,049
    54,824
   145,137

    76,100
    46,562
    29,540
    19,824
    15,100
    12,300
     7,889
     8,035
     3,801
     4,162
     2,573
     1,876
     1,709
     1,505
     1,167
      879
      529
      288
      270
      207

(1,050,541)
   209,926
   110,520
    30,459
    27,713
     6,580
     6,211
     4,991
     2,780
     1,993
     1,489
     1,346
     1,165
      300
 6,103,408
 5,735,789
 2,397,191
 1,887,403
   845,416
   340,625
   214,351
    50,803
   133,910

    77,370
    44,525
    28,680
    20,786
    14,595
    13,786
     8,007
     6,182
     4,251
     4,140
     2,636
     1,876
     1,867
     1,552
     1,166
     1,010
      530
      287
      267
      196

(1,062,566)
   209,785
   108,756
    38,044
    27,872
     6,618
     6,327
     4,985
     2,744
     2,093
     1,381
     1,370
     1,160
      315
2-6   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) (continued)
  Gas/Source
1990
1995
2000
2005
2006
2007
    Rice Cultivation                                   339            363            357            326        282        293
    Abandoned Underground Coal Mines                2881         3921         3501          265        263        273
    Mobile Combustion                               22sl         2071         16sl          121        115        109
    Composting                                      151          351          601           75         75         79
    Petrochemical Production                          411          52             591           51         48         48
    Field Burning of Agricultural Residues                331          321          38             41         39         42
    Iron and Steel Production & Metallurgical
     Coke Production                                  46             471          441           34         35         33
    Ferroalloy Production
    Silicon Carbide Production and Consumption
    International Bunker Fuels'3
  N20
    Agricultural Soil Management
    Mobile Combustion
    Nitric Acid Production
    Manure Management
    Stationary Combustion
    Adipic Acid Production
    Wastewater Treatment
    N20 from Product Uses
    Forest Land Remaining Forest Land
    Composting
    Settlements Remaining Settlements
    Field Burning of Agricultural Residues
    Incineration of Waste
    Wetlands Remaining Wetlands
    International Bunker Fuels'3
  MFCs
    Substitution of Ozone  Depleting Substances0
    HCFC-22 Production
    Semiconductor Manufacture
  PFCs
    Aluminum Production
    Semiconductor Manufacture
  SF6
    Electrical Transmission and Distribution
    Magnesium Production and Processing
    Semiconductor Manufacture	
  + Does not exceed 0.5 Gg.
  M Mixture of multiple gases
  aThe net C02 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 International Bunker Fuels and Wood Biomass and Ethanol Consumption are not included in totals.
  c Small amounts of PFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
                                                           7
                                                       1,007
                                                         672
                                                         108
                                                          59
                                                          47
                                                          47
                                                          19
                                                          15
                                                          14
                                                          11
                                                           6
                                                           5
                                                           2
                                                           1

                                                           3
                                                           M
                                                           M
                                                           1

                                                           M
                                                           M
                                                           M
                                                           1
                                                           1
                                                        7
                                                    1,006
                                                     671
                                                      97
                                                      70
                                                      47
                                                      47
                                                      19
                                                      16
                                                      14
                                                      11
                                                        6
                                                        5
                                                        2
                                                        1

                                                        3
                                                       M
                                                       M
                                                        1

                                                       M
                                                       M
                                                       M
                                                        1
                                                        1
                                                                                Trends in Greenhouse Gas Emissions  2-7

-------
Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg C02 Eq.)
  Chapter/IPCC Sector
                                    1990
                        1995
             2000
  2005
  2006
  2007
  Energy
  Industrial Processes
  Solvent and Other Product Use
  Agriculture
  Land Use, Land-Use Change, and
   Forestry (Emissions)
  Waste
                                                5,520.1
                                                  345.8
                                                    4.6
                                                  402.0

                                                   16.2
                                                  174.7
                                    6,059.9
                                     356.3
                                        4.9
                                     399.4
             1399.41

     _       33.0
             154.6
6,169.2
  337.6
    4.4
  410.8

   26.4
  160.2
6,084.4
  343.9
    4.4
  410.3

   45.1
  163.0
6,170.3
  353.8
    4.4
  413.1

   42.9
  165.6
  Total Emissions
                                  6,098.7
                      6,463.3
           7,008.2
7,108.6     7,051.1    7,150.1
  Net C02 Flux from Land Use, Land-Use Change,
   and Forestry (Sinks)3                           (841.4)
                                                (851.0)
                                    (717.5)
                        (1,122.7)   (1,050.5)   (1,062.6)
  Net Emissions (Sources and Sinks)
                                  5,257.3
                      5,612.3
           6,290.7
5,985.9     6,000.6    6,087.5
  aThe net C02 flux total includes both emissions and sequestration, and constitutes a sink in the United States.
   Sinks are only included in net emissions total.
  Note: Totals may not sum  due to independent rounding.
  Note: Parentheses indicate negative values or sequestration.
Figure 2-4
                                                Figure 2-5
         U.S. Greenhouse Gas Emissions and Sinks
                  by Chapter/IPCC Sector
       7,500 -|
       7,000 -
       6,500 -
       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)-I
   Industrial Processes

Agriculture
                                Waste
LULUCF (sources)

 _1L_
      Land Use, Land-Use Change and Forestry (sinks)
                                         CM co -^  in to r-
   Note: Relatively smaller amounts of GWP-weighted emissions are also emitted from the Solvent and
   Other Product Use sector.
Energy

    Energy-related activities,  primarily fossil  fuel

combustion, accounted for the vast majority of U.S.  CO2

emissions  for the period of 1990  through 2007. In 2007,

approximately 85 percent of the energy consumed in the

United States (on a Btu basis) was produced through the

combustion of fossil fuels. The remaining 15 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
                                                       2007 Energy Chapter Greenhouse Gas Sources
                                                                                                               5,735.8
 Fossil Fuel Combustion

Non-Energy Use of Fuels

   Natural Gas Systems

         Coal Mining

    Mobile Combustion

    Petroleum Systems

 Stationary Combustion

   Incineration of Waste

Abandoned Underground
         Coal Mines
                                                                                        Energy as a Portion
                                                                                         of all Emissions
                                                                                       25
                                                                                            50   75   100

                                                                                               Tg C02 Eq.
                                                                                                            125   150
                                                also responsible for CH4 and N2O emissions (35 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.

                                                     CO2 emissions from fossil fuel combustion are presented

                                                in Table 2-5 based on the underlying U.S. energy consumer

                                                data collected by EIA. Estimates  of  CO2  emissions from

                                                fossil fuel combustion are calculated from  these EIA "end-

                                                use  sectors" based on total consumption  and appropriate

                                                fuel properties  (any additional  analysis  and refinement of

                                                the EIA data is further explained in the  Energy chapter of

                                                this  report). EIA's fuel consumption data for the electric
2-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Figure 2-6
                                       2007 U.S. Fossil Carbon Flows (Tg C02 Eq.)
                                            Fossil Fuel
                                            Energy Exports
                                            340
                                                                                                         NEU Emissions 122
                                                                                                       Non-Energy Use
                                                                                                       Carbon Seguestered
                                                                                                       227
                                                 Fossil Fuel   Stock
                                         Non-Energy  Consumption   Changes
                                         Use Imports    U.S.      ^
                                           55    Territories
                                                   51
25
     Non-Energy
      Use U.S.
     Territories
                                                                              Note: Totals may not sum dueto independent rounding.
                       The "Balancing Item" above accounts for the statistical imbalances
                       and unknowns in the reported data sets combined here.
                                                                                  NEU = Non-Energy Use
                                                                                  NG = Natural Gas
power sector comprises electricity-only and combined-heat-
and-power (CHP) plants within the NAICS 22 category
whose primary business is to sell electricity, or electricity
and heat, to the public (nonutility power producers can be
included in this sector as long as they meet the electric power
sector definition). EIA statistics for the industrial sector
include fossil fuel consumption that occurs in the fields of
manufacturing, agriculture, mining, and construction. EIA's
fuel consumption data for the transportation sector consists
of all vehicles whose primary purpose is transporting people
and/or goods from one physical location to another. EIA's
fuel consumption data for the industrial sector consists of
all facilities and equipment used for producing, processing,
or assembling goods (EIA includes generators that produce
electricity and/or useful thermal output primarily to support
on-site industrial activities in this sector). EIA's  fuel
consumption data for the residential sector consists of living
quarters for private households. EIA's fuel consumption
data for the  commercial sector consists  of service-
providing facilities and equipment from private and public
organizations and businesses (EIA includes generators that
produce electricity and/or useful thermal output primarily to
support the activities at commercial establishments in this
   sector). Table 2-5, Figure 2-7, and Figure 2-8 summarize CO2
   emissions from fossil fuel combustion by end-use sector.
       The main driver of emissions in the energy sector is
   CO2 from fossil fuel combustion. The transportation end-
   Figure 2-7
      2,500 -i
      2,000 -
       1,500 -
    3
       1,000 -
        500 -
         0 -1
              2007 C02 Emissions from Fossil Fuel
              Combustion by Sector and Fuel Type
                   Natural Gas
                   Petroleum
                  I Coal
Relative Contribution
   by Fuel Type
               ij
     Note: Electricity generation also includes emissions of less than 0.5 Tg C02 Eq. from geothermal-based
     electricity generation.
                                                                            Trends in Greenhouse Gas Emissions  2-9

-------
Table 2-4: Emissions from Energy (Tg C02 Eq.)
  Gas/Source
  1990
  1995
  2000
  2005
2006
  Total
5,193.6
5,520.1
6,059.9
2007
  C02                                          4,871.0        5,201.2        5,753.2        5,910.8    5,830.2     5,919.5
    Fossil Fuel Combustion                       4,708.9        5,013.91     5,561.5        5,723.5    5,635.4     5,735.8
      Electricity Generation                       1,809.7        1,938.9        2,283.21      2,381.0    2,327.3     2,397.2
      Transportation                             1,484.5        1,598.7        1,800.3        1,881.5    1,880.9     1,887.4
      Industrial                                   834.2          862.6          844.6          828.0      844.5      845.4
      Residential                                  337.7          354.4          370.4          358.0      321.9      340.6
      Commercial                                 214.5          224.4          226.9          221.8      206.0      214.4
      U.S. Territories                                28.3           35.0           36.2           53.2       54.8       50.8
    Non-Energy Use of Fuels                        117.0          137.5          144.5          138.1      145.1      133.9
    Natural Gas Systems                            33.7           33.8           29.4           29.5       29.5       28.7
    Incineration of Waste                            10.9           15.7           17.5           19.5       19.8       20.8
    Petroleum Systems                               0.41          0.31         0.31          0.3        0.3         0.3
    Wood Biomass and Ethanol Consumption3         219.3          236.8          227.3          231.5      240.4      247.8
    International Bunker Fuels*                      114.3          101.6           99.0          111.5      110.5      108.8
  CH4                                            265.7          251.4          239.0          206.5      205.7      205.7
    Natural Gas Systems                           129.6          132.6          130.8          106.3      104.8      104.7
    Coal Mining                                    84.1           67.1           60.5           57.1       58.4       57.6
    Petroleum Systems                              33.9           32.0           30.3           28.3       28.3       28.8
    Stationary Combustion                           7.4l          7.11         6.6            6.7        6.3         6.6
    Abandoned Underground Coal Mines                6.0            8.2            7.41          5.6        5.5         5.7
    Mobile Combustion                               4.71          4.31         3.41          2.5        2.4         2.3
    International Bunker Fuels3                        0.2 H          0.71         0.71          0.7        0.7         0.7
  N20                                             57.0           67.5           67.7           51.9       48.5       45.2
    Mobile Combustion                              43.7           53.7           52.8           36.7       33.5       30.1
    Stationary Combustion                          12.8           13.3           14.5           14.8       14.5       14.7
    Incineration of Waste                             0.51          0.51         0.4l          0.4        0.4         0.4
    International Bunker Fuels3                        1.1            0.9U         0.9U          1.0        1.0         1.0
6,169.2    6,084.4     6,170.3
  a These values are presented for informational purposes only and are not included in totals or are already accounted for in other source categories.
  Note: Totals may not sum due to independent rounding.
use sector accounted for 1,892.2 Tg CO2 Eq. in 2007, or
approximately 33 percent of total CO2 emissions from fossil
fuel combustion, the largest share of any end-use economic
sector.3 The industrial end-use sector accounted for 27 percent
of CO2 emissions from fossil fuel combustion. The residential
and commercial end-use sectors accounted for an average 21
and 18 percent, respectively, of CO2 emissions from fossil
fuel combustion. Both end-use sectors were heavily reliant
on  electricity for meeting energy needs, with electricity
consumption for lighting, heating,  air conditioning, and
operating appliances contributing to about 72 and 79 percent
of emissions from the residential and commercial end-use
sectors, respectively. Significant trends in emissions from
3 Note that electricity generation is the largest emitter of CO2 when electricity
is not distributed among end-use sectors.
               Figure 2-8
                   2,500 -i
                   2,000 -
                 S
                   1,500 -
                   1,000 -
                    500 -
                                                                      0 J
                             2007 End-Use Sector Emissions
                              from Fossil Fuel Combustion
                                 From Electricity
                                 Consumption
                                | From Direct Fossil
                                 Fuel Combustion
                                                                           U.S.    Commercial Residential
                                                                         Territories
                                                      Industrial Transportation
2-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-5: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1990
1,487,
1,484,
3,
1,516,
834,
682
927,
337,
589,
749,
214,
534,
28,
4,708,
1,809,
.5
.5
.0
.8
.2
.6
.1
.7
.4
.2
.5
.7
.3
.9
.7











1995
1,601,
1,598,
3,
1,575,
862
712,
993,
354,
638
808,
224,
584,
35,
5,013,
1,938,
.7
.7
.0
.5
.6
.9
.3
.4
.8
.5
.4
.1
.0
.9
.9











2000
1,803,
1,800,
3,
1,629,
844,
785,
1,128,
370,
757,
963,
226
736,
36,
5,561,
2,283,
.7
.3
.4
.6
.6
.0
.2
i
.2
.5
.2
2005
1,886.2
1,881.5
4.7
1,558.5
828.0
730.5
1,207.2
358.0
849.2
1,018.4
221.8
796.6
53.2
5,723.5
2,381.0
2006
1,885.4
1,880.9
4.5
1,550.7
844.5
706.2
1,145.9
321.9
824.1
998.6
206.0
792.5
54.8
5,635.4
2,327.3
2007
1,892.2
1,887.4
4.8
1,553.4
845.4
708.0
1,198.0
340.6
857.4
1,041.4
214.4
827.1
50.8
5,735.8
2,397.2
  Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated based on aggregate
  national electricity consumption by each end-use sector.
energy source categories over the eighteen-year period from
1990 through 2007 included the following:
•   Total CO2 emissions from fossil fuel  combustion
    increased from 4,708.9 Tg CO2 Eq. to 5,735.8 Tg CO2
    Eq. —a 22 percent total increase over the eighteen-year
    period. From 2006 to 2007, these emissions increased
    by 100.4 Tg CO2 Eq. (1.8 percent).
•   CO2 emissions from non-energy use of fossil fuels have
    increased 16.9 Tg CO2 Eq.  (14.5 percent) from 1990
    through 2007. Emissions from non-energy uses of fossil
    fuels were 133.9 Tg CO2 Eq. in 2007, which constituted
    2.2 percent of total national CO2 emissions.
•   CH4 emissions from natural gas  systems were 104.7
    Tg CO2 Eq. in 2007; emissions have declined by 24.9
    Tg CO2 Eq. (19 percent) since  1990. This decline
    has been due  to  improvements  in technology and
    management practices, as well as some replacement of
    old equipment.
•   CH4 emissions from coal mining were 57.6 Tg CO2
    Eq. This decline of 26.4 Tg CO2 Eq. (31  percent)
    from 1990 results from the  mining of less gassy coal
    from underground mines and the increased use of CH4
    collected from degasification systems.
•   In 2007, N2O emissions from mobile combustion were
    30.1 Tg CO2 Eq. (approximately 10 percent of U.S. N2O
    emissions). From 1990 to 2007, N2O emissions from
    mobile combustion decreased by 31 percent. However,
    from 1990 to 1998 emissions increased by 26 percent,
    due to control technologies that reduced NOX emissions
    while increasing N2O emissions.  Since 1998, newer
    control technologies have led to a steady decline in N2O
    from this source.
•   CO2 emissions from incineration of waste (20.8 Tg CO2
    Eq. in 2007) increased by 9.8 Tg CO2 Eq. (90 percent)
    from 1990 through 2007, as the volume of plastics and
    other fossil carbon-containing materials in municipal
    solid waste grew.

Industrial  Processes
    Emissions are produced as a byproduct of many non-
energy-related industrial process activities. For example,
industrial processes can chemically transform raw materials,
which often release waste gases such as CO2, CH4, and
N2O. These processes include iron and steel production and
metallurgical coke production, cement production, ammonia
production and urea application, lime manufacture, limestone
and dolomite use (e.g., flux stone, flue gas desulfurization, and
glass manufacturing), soda ash manufacture and use, titanium
dioxide production, phosphoric acid production, ferroalloy
production, CO2 consumption, silicon carbide production
and consumption, aluminum production, petrochemical
production, nitric acid production, adipic acid production,
lead production, and zinc production (see Figure 2-9).
                                                                    Trends in Greenhouse Gas Emissions  2-11

-------
Figure 2-9
            2007 Industrial Processes Chapter
                Greenhouse Gas Sources
   Substitution of Ozone Depleting Substances
            Iron and Steel Production &
          Metallurgical Coke Production
                 Cement Production
               Nitric Acid Production f
                HCFC-22 Production f
                  Lime Production |
  Ammonia Production and Urea Consumption |
     Electrical Transmission and Distribution |
               Aluminum Production |
           Limestone and Dolomite Use |
               Adipic Acid Production |
           Semiconductor Manufacture |
      Soda Asb Production and Consumption
             Petrocbemical Production
      Magnesium Production and Processing
           Titanium Dioxide Production
           Carbon Dioxide Consumption
               Ferroalloy Production
            Pbospboric Acid Production
                  Zinc Production
                  Lead Production | <0.5
  Silicon Carbide Production and Consumption I <0.5
Industrial Processes
  as a Portion of
  all Emissions
                            0
                                25
                                    50   75   100
                                     Tg CO, Eq.
                                                 125
Additionally, emissions from industrial processes release
HFCs, PFCs and SF6. Table 2-6 presents  greenhouse gas
emissions from industrial processes by source category.
    Overall, emissions from industrial processes increased
by 8.8 percent from 1990 to 2007 despite decreases in
emissions from several industrial processes, such as iron
and steel production and metallurgical coke production,
aluminum production, HCFC-22 production, and electrical
transmission  and distribution. The increase  in overall
emissions was driven by a rise in the emissions originating
from  cement manufacture  and, primarily, the emissions
from the use of substitutes  for ozone depleting substances.
Significant trends in emissions from industrial processes
source categories over the eighteen-year period from 1990
through 2007 included the following:
•   HFC emissions from ODS substitutes  have been
    increasing from small amounts in 1990 to 108.3 Tg CO2
    Eq. in 2007. This increase results from 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
    phased out under the provisions of  the Copenhagen
    Amendments to the Montreal Protocol.
•   Carbon dioxide and CH4 emissions from iron and steel
    production and metallurgical coke production increased
    by  1.6 percent to 78.1 Tg CO2 Eq. in 2007, but have
    declined overall by 32.6 Tg CO2 Eq.  (29.5 percent)
    from 1990 through 2007, due to restructuring of the
    industry, technological improvements, and increased
    scrap utilization.
•   PFC emissions from aluminum production decreased by
    79 percent (14.7 Tg CO2 Eq.) from 1990 to 2007, due
    to both industry emission reduction efforts and lower
    domestic aluminum production.
•   Nitrous oxide emissions from adipic acid production
    were 5.9  Tg CO2  Eq.  in 2007,  and have decreased
    significantly in recent years from the widespread
    installation of pollution control  measures. Emissions
    from adipic acid production have decreased 61 percent
    since 1990, and emissions from adipic acid production
    have fluctuated by  less than 1.2 Tg CO2 Eq. annually
    since 1998.
•   Carbon dioxide emissions from  ammonia production
    and urea application  (13.8 Tg CO2 Eq. in 2007) have
    decreased by 3.0 Tg CO2 Eq. (18 percent) since 1990,
    due to a decrease  in domestic ammonia production.
    This decrease in ammonia production can be attributed
    to market fluctuations and high natural gas prices.

Solvent and  Other Product Use
    Greenhouse gas emissions are produced as a byproduct
of various solvent and  other  product uses. In the United
States, N2O Emissions from Product Uses, the only source of
greenhouse gas emissions from this sector, accounted for 4.4
Tg CO2 Eq., or less than 0.1 percent of total U.S. emissions
in 2007 (see Table 2-7).
    In 2007, N2O emissions from product uses constituted
1 percent of US.N2O emissions. From 1990 to 2007, emissions
from this source category decreased by less than 0.5 percent,
though slight increases occurred in intermediate years.
2-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 2-6: Emissions from Industrial Processes (Tg C02 Eq.)
  Gas/Source
 1990
 1995
 2000
 2005
  Total
325.2
345.8
356.3
337.6
 2006
343.9
 2007
  C02                                             197.6          198.6         193.2           171.1      175.9      174.9
    Iron and Steel Production & Metallurgical
     Coke Production                               109.8          103.1          95.1            73.2        76.1        77.4
    Cement Manufacture                             33.3           36.8          41.2            45.9        46.6        44.5
    Lime Manufacture                                11.5           13.3          14.1            14.4        15.1        14.6
    Ammonia Production & Urea Application            16.8           17.8          16.4            12.8        12.3        13.8
    Limestone and Dolomite Use                       5.11          6.71          5.11           6.8         8.0         6.2
    Aluminum Production                             6.8            5.71          6.11           4.1         3.8         4.3
    Soda Ash Manufacture and Consumption             4.11          4.sB          4.2!           4.2         4.2         4.1
    Petrochemical Production                          2.2            2.8            3.01           2.8         2.6         2.6
    Titanium Dioxide Production                        1.2            1.51          1.81           1.8         1.9         1.9
    Carbon Dioxide Consumption                       1.4            1.4            1.4             1.3         1.7         1.9
    Ferroalloy Production                              2.2            2.01          1.91           1.4         1.5         1.6
    Phosphoric Acid Production                        1.51          1.51          1.4             1.4         1.2         1.2
    Zinc Production                                  0.91          1.01          1.11           0.5         0.5         0.5
    Lead Production                                  0.31          0.31          0.31           0.3         0.3         0.3
    Silicon  Carbide Production and Consumption         0.4!          0.31          0.2!           0.2         0.2         0.2

    Petrochemical Production                          0.91          1.11          1.2             1.1         1.0         1.0
    Iron and Steel Production & Metallurgical
     Coke Production                                 1.0            1.0            0.9             0.7         0.7         0.7
    Ferroalloy Production                               +1           +1           +1            +          +          +
    Silicon  Carbide Production and Consumption          +1           +1           +1            +          +          +
  N20                                              35.3           39.6          28.1            24.6        24.2        27.6
    Nitric Acid Production                            20.0           22.3          21.9            18.6        18.2        21.7
    Adipic Acid Production                           15.3           17.3            6.2             5.9         5.9         5.9
  MFCs                                             36.9           61.8         100.1           116.1      119.1      125.5
    Substitution of Ozone Depleting Substances3         0.31         28.5          71.2           100.0      105.0      108.3
    HCFC-22 Production                             36.4           33.0          28.6            15.8        13.8        17.0
    Semiconductor Manufacture                       0.2!          0.31          0.31           0.2         0.3         0.3
  PFCs                                             20.8           15.6          13.5             6.2         6.0         7.5
    Aluminum Production                            18.5           11.8            8.6             3.0         2.5         3.8
    Semiconductor Manufacture                       2.2            3.8            4.91           3.2         3.5         3.6
  SF6                                              32.8           28.1          19.2            17.9        17.0        16.5
    Electrical Transmission and Distribution             26.8           21.6          15.1            14.0        13.2        12.7
    Magnesium Production and Processing              5.41          5.eB          3.0             2.9         2.9         3.0
    Semiconductor Manufacture                       0.51          0.91          1.1             1.0         1.0         0.8
353.8
  + Does not exceed 0.05 Tg C02 Eq.
  a Small amounts of RFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
Table 2-7: N20 Emissions from Solvent and Other Product Use (Tg C02 Eq.)
Gas/Source
N20
N20 from Product Uses
Total
1990
4.4
4.4
4.4
1995
4.6
4.6
4.6
2000
4.9
4.9
4.9
2005
4.4
4.4
4.4
2006
4.4
4.4
4.4
2007
4.4
4.4
4.4
                                                                              Trends in Greenhouse Gas Emissions  2-13

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Agriculture
    Agricultural activities contribute directly to emissions of
greenhouse gases through a variety of processes, including
the following source categories:  enteric fermentation in
domestic livestock, livestock manure management, rice
cultivation, agricultural soil management, and field burning
of agricultural residues (see Figure 2-10).
    In 2007, agricultural  activities were responsible for
emissions of 413.1 Tg CO2 Eq., or 5.8 percent of total U.S.
greenhouse gas emissions (see Table 2-8). Methane and N2O
were the primary greenhouse gases emitted by agricultural
activities. Methane emissions from enteric fermentation
and manure management represented about 24 percent
and 8 percent of total CH4 emissions from anthropogenic
activities, respectively, in 2007. Agricultural soil management
activities, such as fertilizer application and other cropping

Figure 2-10
        2007 Agriculture Chapter Greenhouse Gas
                   Emision Sources
                                              207.9
   Agricultural Soil Management

         Enteric Fermentation

         Manure Management

            Rice Cultivation

            Field Burning of
        Agricultural Residues
 Agriculture
as a Portion of
all Emissions
                              50       100
                                 Tg C02 Eq.
                                              150
practices, were the largest source of U.S. N2O emissions in
2007, accounting for 67 percent.
    Some  significant trends in U.S. emissions  from
agriculture include the following:
•   Agricultural soils produced approximately 67 percent of
    N2O emissions in the United States in 2007. Estimated
    emissions from this source in 2007 were 207.9 Tg
    CO2 Eq. Annual N2O emissions from agricultural soils
    fluctuated between 1990 and 2007, although overall
    emissions were 3.8 percent higher in 2007 than in
    1990. N2O emissions from this source have not shown
    any  significant long-term trend, as they are highly
    sensitive to the amount of N applied to soils, which has
    not changed significantly over the time-period, and to
    weather patterns and crop type.
•   Enteric fermentation was the largest source of CH4
    emissions in 2007, at 139.0 Tg CO2 Eq. Although
    emissions from enteric fermentation have increased by
    4 percent between 1990 and 2007, emissions increased
    about 8 percent between 1990 and 1995 and decreased
    about 7 percent from 1995 to 2004, mainly due to
    decreasing  populations of both beef and dairy  cattle
    and improved feed quality for feedlot cattle. The  last
    three years have shown an increase in emissions. During
    this timeframe, populations  of sheep have decreased
    46 percent since 1990 while horse populations have
    increased over 80 percent, mostly over the last 6 years.
    Goat and swine populations have increased 1 percent
    and 21 percent, respectively, during this timeframe.
•   Overall, emissions from manure management increased
    38 percent between 1990 and 2007. This encompassed
Table 2-8: Emissions from Agriculture (Tg C02 Eq.)
  Gas/Source
       1990
  CH4
    Enteric Fermentation
    Manure Management
    Rice Cultivation
    Field Burning of Agricultural Residues
  N20
    Agricultural Soil Management
    Manure Management
    Field Burning of Agricultural Residues
  1995
 2000
 2005
                                              185.5
                                              136.0
                                               41.8
                                                6.8
                                                0.9
                                              225.3
                                              210.6
                                               14.2
                                                0.5
 2006
                                     186.8
                                     138.2
                                      41.9
                                        5.9
                                        0.8
                                     223.5
                                     208.4
                                      14.6
                                        0.5
 2007
                                 190.0
                                 139.0
                                  44.0
                                   6.2
                                   0.9
                                 223.1
                                 207.9
                                  14.7
                                   0.5
  Total
       384.2
 402.0
399.4
410.8
410.3
413.1
  Note: Totals may not sum due to independent rounding.
2-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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    an increase of 45 percent for CH4, from 30.4 Tg
    CO2 Eq. in 1990 to 44.0 Tg CO2 Eq. in 2007; and an
    increase of 22 percent for N2O, from 12.1 Tg CO2 Eq.
    in 1990 to 14.7 Tg CO2 Eq. in 2007. The majority of
    this increase was from swine and dairy cow manure,
    since the general trend in manure management is one
    of increasing  use  of liquid systems, which tends to
    produce greater CR4 emissions.

Land Use,  Land-Use Change, and Forestry
    When humans alter the terrestrial biosphere through land
use, changes in land use, and land management practices,
they also alter the background carbon fluxes between
biomass, soils, and the atmosphere. Forest management
practices, tree planting in urban areas, the management of
agricultural soils, and the landfilling of yard trimmings and
food scraps  have resulted in an uptake (sequestration) of
carbon in the United States, which offset about 14.9 percent
of total U.S. greenhouse gas emissions in 2007. Forests
(including vegetation, soils, and harvested wood) accounted
for approximately  86 percent of total 2007 net CO2 flux,
urban trees accounted for 9 percent, mineral and organic soil
carbon stock changes accounted for 4 percent, and landfilled
yard trimmings and food scraps accounted for 1  percent of
the total net flux in 2007. The net forest sequestration is a
result of net forest growth, increasing forest area, and a net
accumulation  of carbon stocks in harvested wood pools.
The net sequestration in urban forests is a result  of net tree
growth and increased urban forest size. In agricultural soils,
mineral and organic soils sequester approximately 70 percent
more C than is emitted from these soils through liming, urea
fertilization, or both. The mineral soil C sequestration is
largely due to the conversion of cropland to hay production
             fields, the limited use of bare-summer fallow areas in semi-
             arid areas, and an increase in the adoption of conservation
             tillage practices. The landfilled yard trimmings  and food
             scraps net sequestration is due to the long-term accumulation
             of yard trimming carbon and food scraps in landfills.
                 Land use, land-use change, and forestry activities in
             2007  resulted in a net C sequestration of 1,062.6 Tg CO2
             Eq. (Table 2-9). This represents an offset of approximately
             17.4 percent of total U.S. CO2 emissions, or 14.9 percent of
             total greenhouse gas emissions in 2007. Between  1990 and
             2007, total land use, land-use change, and forestry net C flux
             resulted in a 26.3 percent increase in CO2 sequestration.
                 Land use, land-use change, and forestry source categories
             also resulted in emissions of CO2, CFL,, and N2O that are
             not included in the net flux estimates presented in Table
             2-10.  The application of crushed limestone and  dolomite
             to managed land (i.e., soil liming) and urea fertilization
             resulted in CO2 emissions of 8.0 Tg CO2 Eq. in  2007, an
             increase of 13 percent relative to  1990. Lands undergoing
             peat extraction resulted in CO2 emissions of 1.0 Tg CO2 Eq.
             (1,010 Gg), andN2O emissions of less than 0.01 Tg CO2Eq.
             N2O emissions from the application of synthetic fertilizers
             to forest soils have increased from 1990 to 0.3 Tg CO2 Eq.
             in 2007.  Settlement soils in 2007 resulted in direct N2O
             emissions of 1.6 Tg CO2 Eq., a 61 percent increase relative to
             1990. Non-CO2 emissions from forest fires in 2007 resulted
             in CH4 emissions of 29 Tg CO2 Eq., and in N2O emissions
             of 2.9 Tg CO2 Eq.
                 Other significant trends from 1990 to 2007 in land use,
             land-use change, and forestry emissions include:
             •   Net C sequestration by forest land has increased 38
                 percent. This is  primarily due to increased forest
Table 2-9: Net C02 Flux from Land Use, Land-Use Change, and Forestry (Tg C02 Eq.)
  Sink Category
  1990
  1995
  2000
   2005
2006
2007
  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)
 (23.5)
 (13.9)
 (11.3)
                                        (975.7)
                                         (18.3)
                                           5.9
                                          (4.6)
                                         (26.7)
                                         (93.3)
                                     (900.3)
                                      (19.1)
                                        5.9
                                       (4.6)
                                      (26.7)
                                      (95.5)
   (10.2)     (10.4)
        (910.1)
         (19.7)
           5.9
          (4.7)
         (26.7)
         (97.6)
          (9.8)
  Total
(841.4)
(851.0)
(717.5)
(1,122.7)   (1,050.5)   (1,062.6)
  Note: Totals may not sum due to independent rounding. Parentheses indicate net sequestration.
                                                                      Trends in Greenhouse Gas Emissions  2-15

-------
Table 2-10: Emissions from Land Use, Land-Use Change, and Forestry (Tg C02 Eq.)
  Gas/Source
1990
1995
2000
2005
2006
2007
  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
  N20
    Forest Land Remaining Forest Land:
     Forest Fires
    Forest Land Remaining Forest Land:
     Forest Soils
    Wetlands Remaining Wetlands:
     Peatlands Remaining Peatlands
    Settlements Remaining Settlements:
     Settlement Soils
  8.1
  4.7
  2.4
  1.0
  4.61
  4.6
  1.51
  0.5
  0.0
  8.1
  4.4
  2.7
  1.0
  6.1
  6.1
  2.01
  0.6


  1
  1.2
  8.8
  4.3
  3.2
  1.2
20.6
20.6
  3.6
  2.1
  0.3
  8.9
  4.3

  3.5

  1.1
14.2
14.2
  3.3
  1.4
  0.3
   +

  1.5
  8.8
  4.2

  3.7

  0.9
31.3
31.3
  5.0
  3.2

  0.3
   +

  1.5
  9.0
  4.1
  4.0
  1.0
29.0
29.0
  4.9
  2.9
  0.3
   +
  1.6
  Total
14.2
16.2
33.0
26.4
45.1
42.9
  + Less than 0.05 TgC02Eq.
  Note: Totals may not sum due to independent rounding.
    management and the effects of previous reforestation.
    The increase in intensive forest management resulted in
    higher growth rates and higher biomass density. The tree
    planting and conservation efforts of the 1970s and 1980s
    continue to have a significant impact on sequestration
    rates. Finally, the  forested area in the United States
    increased over the past  18 years, although only at an
    average rate of 0.25 percent per year.
•   Net sequestration of C by urban trees has increased by
    61 percent over the period from 1990 to 2007. This is
    primarily due to an increase in urbanized land area in
    the United States.
•   Annual C sequestration in landfilled yard trimmings
    and food scraps has decreased by 58 percent since 1990.
    This is due in part to a decrease in the amount of yard
    trimmings and food scraps generated. In addition, the
    proportion of yard trimmings and food scraps landfilled
    has decreased, as there  has been a significant rise in
    the number of municipal composting facilities in the
    United States.
            Waste
                Waste management and treatment activities are sources
            of greenhouse gas emissions (see Figure 2-11). In 2007,
            landfills were the second largest source of anthropogenic
            CH4 emissions, accounting for 23 percent of total U.S. CH4
            emissions.4 Additionally, wastewater treatment accounts
            for 4 percent of U.S. CH4 emissions, and 2 percent of N2O

            Figure 2-11
              2007 Waste Chapter Greenhouse Gas Emission Sources
                 Landfills
               Composting
                       0     20
                                  40
                                       60    80    100
                                        Tg C02 Eq.
                                                        120
                                                             140
                                                           4 Landfills also store carbon, due to incomplete degradation of organic
                                                           materials such as wood products and yard trimmings, as described in the
                                                           Land Use, Land-Use Change, and Forestry chapter.
2-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 2-11: Emissions from Waste (Tg C02 Eq.)
  Gas/Source
1990
1995
2000
2005
2006
2007
  CH4
    Landfills
    Wastewater Treatment
    Composting
  N20
    Wastewater Treatment
    Composting
                                       153.8
                                       127.8
                                        24.3
                                         1.6
                                         6.5
                                         4.8
                                         1.7
                                    156.5
                                    130.4
                                     24.5
                                      1.6
                                      6.6
                                      4.8
                                      1.8
                                 158.9
                                 132.9
                                  24.4
                                   1.7
                                   6.7
                                   4.9
                                   1.8
  Total
177.1
174.7
154.6
160.2
163.0
165.6
  Note: Totals may not sum due to independent rounding.
emissions. Emissions of CH4 and N2O from composting grew
from 1990 to 2007, and resulted in emissions of 3.5 Tg CO2
Eq. in 2007. A summary of greenhouse gas emissions from
the Waste chapter is presented in Table 2-11.
    Overall, in 2007, waste activities generated emissions
of 165.6 Tg CO2 Eq., or 2.3 percent of total U.S. greenhouse
gas emissions.
    Some significant trends in U.S. emissions from waste
include the following:
•   From 1990 to 2007, net CFL, emissions from landfills
    decreased by 16.3 Tg CO2 Eq. (11 percent), with small
    increases occurring in interim years. This  downward
    trend in overall emissions is the result of increases in
    the amount of landfill gas collected and combusted,5
    which has more than offset the additional CH4 emissions
    resulting from an increase in the amount of municipal
    solid waste landfilled.
•   From 1990  to 2007, CH4 and N2O emissions from
    wastewater treatment increased by 0.8 Tg CO2 Eq. (4
    percent) and 1.2 Tg CO2 Eq. (32 percent), respectively.
•   Methane and N2O emissions from  composting each
    increased by less than 0.1 Tg CO2 Eq. (4 percent) from
    2006 to 2007. Emissions from composting have been
    continually increasing since 1990, from 0.7 Tg CO2
    Eq. to 3.5 Tg  CO2 Eq. in 2007, a four-fold increase
    over the time series.
5 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.
            2.2.  Emissions by  Economic Sector

                Throughout this report, emission estimates are grouped
            into six sectors (i.e., chapters) defined by the IPCC and
            detailed above: Energy; Industrial Processes; Solvent and
            Other Product Use;  Agriculture; Land Use, Land-Use
            Change, and Forestry; and Waste. While it is important to
            use this characterization for consistency  with UNFCCC
            reporting guidelines, it is also useful to allocate emissions
            into more commonly used sectoral categories. This section
            reports emissions by the following U.S.  economic sectors:
            residential, commercial, industry, transportation, electricity
            generation, and agriculture, as well as U.S. territories.
                Using this categorization, emissions from electricity
            generation accounted for the largest portion (34 percent)
            of U.S. greenhouse gas emissions in 2007. Transportation
            activities, in aggregate, accounted for the second largest
            portion (28 percent). Emissions from industry accounted for
            about 20 percent of U.S. greenhouse gas emissions in 2007. In
            contrast to electricity generation and transportation, emissions
            from industry have in general declined over the past decade.
            The long-term decline in these emissions has been due to
            structural changes in the U.S. economy (i.e., shifts from
            a manufacturing-based to a service-based economy), fuel
            switching, and efficiency improvements. The remaining  18
            percent of U.S. greenhouse gas emissions were contributed
            by the residential, agriculture, and commercial  sectors,
            plus emissions from U.S. territories. The residential sector
            accounted for 5 percent, and primarily consisted of CO2
            emissions from fossil  fuel combustion. Activities related to
            agriculture accounted for roughly 7 percent of U.S. emissions;
                                                                     Trends in Greenhouse Gas Emissions  2-17

-------
unlike other economic sectors, agricultural sector emissions
were dominated by N2O emissions from agricultural soil
management and CH4 emissions from enteric fermentation,
rather than CO2 from fossil fuel combustion. The commercial
sector accounted for roughly 6 percent of emissions, while
U.S. territories accounted for about 1 percent.
    Carbon dioxide was also emitted and sequestered by a
variety of activities related to forest management practices,
tree planting in urban areas, the management of agricultural
soils, and landfilling of yard trimmings.
    Table 2-12 presents a detailed breakdown of emissions
from each of these economic sectors by source category, as
they are defined in this report. Figure 2-12 shows the trend
in emissions by sector from  1990 to 2007.
                       Figure 2-12
                               Emissions Allocated to Economic Sectors
                           2,500 -i
                           2,000 -
                           1,500-
                           1,000-
                             500-
                                               Electricity Generation

                                                    Transportation


                                                        Industry
                                                                    Agriculture
                                                                  'Commercial
                                                                    Residential
                                                              Note: Does not include U.S. Territories.
Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors
(Tg C02 Eq. and Percent of Total in 2007)
  Sector/Source
1990
1995
2000
2005
2006
2007    Percent3
Electric Power Industry
C02from Fossil Fuel Combustion
Incineration of Waste
1,859.1
1, 809.7 1
11.4
11,989.0
1,938.9
16.2
2,329.3
2,283.2
17.9
2,429.4
2,381.0
19.9
2,375.5
2,327.3
20.2
2,445.1
2,397.2
21.2
34.2%
33.5%
0.3%
    Electrical Transmission and
     Distribution                        26.8
    Stationary Combustion                8.6
    Limestone and Dolomite Use            2.6
  Transportation                     1,543.6
    C02 from Fossil Fuel Combustion    1,484.5
    Substitution of Ozone Depleting
     Substances                          +
    Mobile Combustion                  47.3
    Non-Energy Use of Fuels              11.9
  Industry                          1,496.0
    C02 from Fossil Fuel Combustion      803.4
    Natural Gas Systems                163.3
    Non-Energy Use of Fuels              99.4
    Iron and Steel & Metallurgical
     Coke Production                   110.7
    Coal Mining                         84.1
    Cement Production                  33.3
    Petroleum Systems                  34.2
    Nitric Acid Production                 20.0
    HCFC-22 Production                  36.4
    Lime Production                     11.5
    Ammonia Production and Urea
     Consumption                      16.81
    Aluminum Production                 25.4
    Substitution of Ozone Depleting
     Substances
    Adipic Acid Production               15.3

             104.1
              67.1
              36.8
              32.3
              22.3
              33.0
              13.3

              17.8
              17.5
                1.2
              17.3
              96.0
              60.5
              41.2
              30.6
              21.9
              28.6
              14.1

              16.4
              14.7
               3.1
               6.2
               73.9
               57.1
               45.9
               28.6
               18.6
               15.8
               14.4

               12.8
                7.1
                5.2
                5.9
           76.8
           58.4
           46.6
           28.6
           18.2
           13.8
           15.1

           12.3
            6.3
            5.7
            5.9
           78.1
           57.6
           44.5
           29.1
           21.7
           17.0
           14.6

           13.8
            8.1
            6.1
            5.9
          0.2%
          0.2%
             +
         27.9%
         26.4%

          0.9%
          0.4%
          0.1%
         19.4%
         11.2%
          1.9%
          1.6%

          1.1%
          0.8%
          0.6%
          0.4%
          0.3%
          0.2%
          0.2%

          0.2%
          0.1%
          0.1%
          0.1%
2-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors  (continued)
(Tg C02 Eq. and  Percent of Total in 2007)
  Sector/Source
 1990
 1995
 2000
 2005
 2006
 2007    Percent3
    Abandoned Underground Coal
     Mines
    Semiconductor Manufacture
    Stationary Combustion
    N20 from Product Uses
    Soda Ash Production and
     Consumption
    Petrochemical Production
    Limestone and Dolomite Use
    Magnesium Production and
     Processing
    Titanium Dioxide Production
    Carbon Dioxide Consumption
    Ferroalloy Production
    Mobile Combustion
    Phosphoric Acid Production
    Zinc Production
    Lead Production
    Silicon Carbide Production and
     Consumption
  Agriculture
    N20 from Agricultural Soil
     Management
    Enteric Fermentation
    Manure Management
    C02from Fossil Fuel Combustion
    CH4 and N20 from  Forest Fires
    Rice Cultivation
    Liming of Agricultural Soils
    Urea Fertilization
    Field Burning of Agricultural
     Residues
    C02 and N20 from  Managed
     Peatlands
    Mobile Combustion
    N20 from Forest Soils
    Stationary Combustion
  Commercial
    C02from Fossil Fuel Combustion
    Landfills
    Substitution of Ozone Depleting
     Substances
    Wastewater Treatment
    Human Sewage
    Composting
    Stationary Combustion
  Residential
    C02from Fossil Fuel Combustion
    Substitution of Ozone Depleting
     Substances
  6.0
  2.9
  4.7
  4.4
  4.1
  3.1
  2.6

  5.4
  1.2
  1.4
  2.2
  0.9
  1.5
  0.9
  0.3

  0.4
428.5

200.3
133.2
 42.4
 30.8
  5.1
  7.1
  4.7
  2.4

  1.1
  8.2
  4.9
  4.9
  4.6
  4.3
  3.8
  3.3

  5.6
  1.5
  1.4
  2.0
  1.0
  1.5
  1.0
  0.3

  0.3
453.7

202.3
143.6
 47.4
 36.3
  6.8
  7.6
  4.4
  2.7

  1.0
  7.4
  6.2
  4.8
  4.9
  4.2
  4.2
  2.5

  3.0
  1.8
  1.4
  1.9
  1.1
  1.4
  1.1
  0.3

  0.3
470.2

204.5
134.4
 51.9
 38.4
 22.7
  7.5
  4.3
  3.2

  1.3

  1.2
  0.4
  0.3
   +
388.2
226.9
122.3

  5.5
 25.2
  4.5
  2.6
  1.2
386.0
370.4

 10.1
  5.6
  4.4
  4.5
  4.4
  4.2
  3.9
  3.4

  2.9
  1.8
  1.3
  1.4
  1.3
  1.4
  0.5
  0.3

  0.2
482.6

210.6
136.0
 56.0
 46.4
 15.6
  6.8
  4.3
  3.5

  1.4

  1.1
  0.5
  0.3
   +
401.8
221.8
127.8

 18.5
 24.3
  4.8
  3.3
  1.2
370.5
358.0

  6.5
  5.5
  4.7
  4.6
  4.4
  4.2
  3.6
  4.0

  2.9
  1.9
  1.7
  1.5
  1.3
  1.2
  0.5
  0.3

  0.2
502.9

208.4
138.2
 56.4
 48.6
 34.4
  5.9
  4.2
  3.7

  1.3

  0.9
  0.5
  0.3
   +
392.6
206.0
130.4

 22.4
 24.5
  4.8
  3.3
  1.1
334.9
321.9

  7.5
  5.7
  4.7
  4.5
  4.4
  4.1
  3.7
  3.1

  3.0
  1.9
  1.9
  1.6
  1.3
  1.2
  0.5
  0.3

  0.2
502.8

207.9
139.0
 58.7
 47.9
 31.9
  6.2
  4.1
  4.0

  1.4

  1.0
  0.5
  0.3
   +
407.6
214.4
132.9

 26.6
 24.4
  4.9
  3.5
  1.2
355.3
340.6

  8.6
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
7.0%

2.9%
1.9%
0.8%
0.7%
0.4%
0.1%
0.1%
0.1%
                                                                              5.7%
                                                                              3.0%
                                                                              1.9%

                                                                              0.4%
                                                                              0.3%
                                                                              0.1%
                                                                              5.0%
                                                                              4.8%

                                                                              0.1%
                                                                             Trends in Greenhouse Gas Emissions  2-19

-------
Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors
(Tg C02 Eq. and Percent of Total in 2007) (continued)
Sector/Source
Stationary Combustion
Settlement Soil Fertilization
U.S. Territories
C02from Fossil Fuel Combustion
Non-Energy Use of Fuels
Stationary Combustion
Total Emissions
Sinks
C02 Flux from Forests
Urban Trees
C02 Flux from Agricultural Soil
Carbon Stocks
Landfilled Yard Trimmings and
Food Scraps
Net Emissions
(Sources and Sinks)
1990
5.5

6,098.7
(841.4)
(661.1)
(60.6)
(96.3)

(23.5)

5,257.3
1995
5.0
41.1
35.0
6.0
0.1
6,463.3
(851.0)
(686.6)
(71.5)
(78.9)

(13.9)

5,612.3
2000
4.3
47.3
36.2
10.9
0.1
7,008.2
(717.5)
(512.6)
(82.4)
(111.2)

(11.3)

6,290.7
2005
4.5
1.5
60.5
53.2
7.1
0.2
7,108.6
(1,122.7)
(975.7)
(93.3)
(43.6)

(10.2)

5,985.9
2006
4.0
1.5
62.3
54.8
7.3
0.2
7,051.1
(1,050.5)
(900.3)
(95.5)
(44.5)

(10.4)

6,000.6
2007
4.4
1.6
57.7
50.8
6.7
0.2
7,150.1
(1,062.6)
(910.1)
(97.6)
(45.1)

(9.8)

6,087.5
Percent3
0.1%
+
0.8%
0.7%
0.1%
0.0%
100.0%
(14.9)%
(12.7)%
(1.4)%
(0.6)%

(0.1)%

85.1%
  + Does not exceed 0.05 Tg C02 Eq. or 0.05 percent.
  'Percent of total emissions for year 2007.
  Note: Includes all emissions of C02, CH4, N20, MFCs, PFCs, and SFe. Parentheses indicate negative values or sequestration. Totals may not sum due to
  independent rounding.
Emissions with Electricity Distributed  to
Economic Sectors
    It can also be useful to view greenhouse gas emissions
from economic sectors with emissions related to electricity
generation distributed into end-use categories (i.e., emissions
from  electricity generation  are allocated to the economic
sectors in which the electricity is consumed). The generation,
transmission, and  distribution of electricity, which is the
largest economic sector in the United States, accounted for
34 percent of total U.S. greenhouse gas emissions in 2007.
Emissions increased by 28 percent since 1990, as electricity
demand grew  and fossil fuels remained the dominant
energy source for generation. Electricity generation-related
emissions increased from 2006 to 2007 by 3 percent,
primarily due to increased CO2 emissions  from fossil fuel
combustion. The electricity generation sector in the United
States is composed of traditional electric utilities as  well as
other entities, such as power marketers and non-utility power
producers. The majority of electricity generated by these
entities was through the combustion of coal in boilers to
produce high-pressure steam that is passed through a turbine.
Table 2-13 provides a detailed summary of emissions from
electricity generation-related activities.
    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 (ElA 2008a 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.6
    When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of U.S.
greenhouse gas emissions (30 percent), followed closely by
emissions from transportation activities, which account for
28 percent of total emissions. Emissions from the residential
6Emissions 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.
2-20  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-13: Electricity Generation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
  Gas/Fuel Type or Source
  1990
                                                       1995
  2000
  2005
2006
  Total
1,859.1
                                                     1,989.0
2,329.3
2007
  C02                                        1,823.2        1,957.9       2,303.2        2,403.9    2,351.2    2,421.1
    C02 from Fossil Fuel Combustion               1,809.7        1,938.9       2,283.21      2,381.0    2,327.3    2,397.2
      Coal                                   1,531.1        1,648.6       1,909.5        1,958.4    1,932.4    1,967.6
      Natural Gas                                176.5         229.2         281.8         319.9     338.9      373.8
      Petroleum                                 101.8          60.7          91.5         102.3       55.6       55.3
      Geottiermal                                  0.4U         0.31         0.41         0.4        0.4        0.4
    Incineration of Waste                           10.9          15.7          17.5          19.5       19.8       20.8
    Limestone and Dolomite Use                      2.6            3.31         2.51         3.4        4.0        3.1
  CH4                                            0.61         0.61         0.7           0.7        0.7        0.7
    Stationary Combustion3                          0.61         0.61         0.71         0.7        0.7        0.7
  N20                                            8.5            9.01        10.4          10.7       10.5       10.7
    Stationary Combustion3                          8.11         8.61        10.0          10.3       10.1       10.3
    Incineration of Waste                            0.51         0.51         0.4l         0.4        0.4        0.4
  SF6                                           26.8          21.6          15.1          14.0       13.2       12.7
    Electrical Transmission and Distribution             26.8          21.6          15.1          14.0       13.2       12.7
2,429.4    2,375.5    2,445.1
  'Includes only stationary combustion emissions related to the generation of electricity.
  Note: Totals may not sum due to independent rounding.
and commercial sectors also increase substantially when
emissions from electricity are included, due to their relatively
large share of electricity consumption. 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 2007.

Figure 2-13
  Emissions with Electricity Distributed to Economic Sectors
              Industry
2,500 -

2,000 -

1,500-

1,000-

 500-

   0-
                                              Industrial
                                          Transportation
                                             Residential
                                             	•
                                            Commercial
                                             Agriculture
            O)O)O)O)O)O)O)O)O)O)OOOOOOOO

   Note: Does not include U.S. Territories.
                  The industrial end-use sector includes CO2 emissions
              from fossil fuel combustion from all manufacturing facilities,
              in aggregate. This sector also includes emissions  that are
              produced as a byproduct of the non-energy-related industrial
              process activities. The variety of activities producing these
              non-energy-related emissions,  includes,  among others,
              fugitive CtLj emissions from coal mining,  byproduct CO2
              emissions from  cement manufacture, and HFC, PFC, and
              SF6 byproduct emissions from semiconductor manufacture.
              Overall, direct  industry  sector  emissions have declined
              since 1990, while electricity-related emissions have risen. In
              theory, emissions from the industrial end-use sector should
              be highly correlated with economic growth and industrial
              output, but heating of industrial  buildings and agricultural
              energy consumption are also affected by weather conditions.
              In addition, structural  changes within the U.S. economy
              that lead to shifts in industrial output away from energy-
              intensive manufacturing products to less energy-intensive
              products (e.g., from steel to computer equipment) also have
              a significant affect on industrial emissions.

              Transportation
                  When electricity-related emissions are distributed
              to economic end-use sectors,  transportation activities
                                                                         Trends in Greenhouse Gas Emissions   2-21

-------
Table 2-14: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related
Emissions Distributed (Tg C02 Eq.) and Percent of Total in 2007
Sector/Gas
Industry
Direct Emissions
C02
CH4
N20
MFCs, PFCs, and SF6
Electricity-Related
C02
CH4
N20
SF6
Transportation
Direct Emissions
C02
CH4
N20
HFCsb
Electricity-Related
C02
CH4
N20
SF6
Commercial
Direct Emissions
C02
CH4
N20
MFCs
Electricity-Related
C02
CH4
N20
SF6
Residential
Direct Emissions
C02
CH4
N20
MFCs
Electricity-Related
C02
CH4
N20
SF6
1990
2,166.5
1,496.0
1,097.9
291.1
43.6
63.3
670.6
657.6
0.2
3.1 1
9.7
1,546.7
1,543.6
1,496.3
4.5
42.7
::
+
942.2
392.9
214.5
173.9
4.4
+
549.3
538.7
0.2
£
950.0
344.5
337.7
4.4
2.1 1
0.3
605.5
593.8
0.2l
2.8
8.7
1995
2,219.8
1,524.5
1,141.7
277.8
48.4
56.6
695.3
684.4
0.2l
3.2
7.5
1,688.3
1,685.2
1,610.0
4.1 1
52.5
18.6
I
+
1,000.2
401.0
224.4
170.8
5.2
0.7
599.2
589.8
0.2
2.7
6.5
1,024.2
368.8
354.4
4.0
2.2l
655.4
645.1
0.2l
3.0
7.1
2000
2,235.5
1,467.5
1,118.3
262.5
37.2
49.6
767.9
759.3
0.2
3.4 1
5.0 1
1,923.2









_._
5.5
751.7
743.3
0.2l
3.3
4.9 1
1,159.2
386.0
370.4
3.4
10.1
773.2
764.5
0.2
3.4
5.0
2005
2,081.2
1,364.9
1,070.1
230.4
33.1
31.3
716.3
708.8
0.2
3.2
4.1
2,003.6
1,998.9
1,891.7
2.2
35.2
69.7
4.8
4.7
+
+
+
1,214.6
401.8
221.8
154.6
6.8
18.5
812.8
804.3
0.2
3.6
4.7
1,237.0
370.5
358.0
3.5
2.4
6.5
866.5
857.4
0.3
3.8
5.0
2006
2,082.3
1,388.4
1,095.8
230.2
32.8
29.6
693.8
686.7
0.2
3.1
3.9
1,999.0
1,994.4
1,890.8
2.1
32.0
69.5
4.6
4.5
+
+
+
1,201.5
392.6
206.0
157.3
6.9
22.4
808.9
800.6
0.2
3.6
4.5
1,176.1
334.9
321.9
3.2
2.4
7.5
841.2
832.5
0.3
3.7
4.7
2007
2,081.2
1,386.3
1,086.4
229.1
36.2
34.7
694.9
688.0
0.2
3.0
3.6
2,000.1
1,995.2
1,897.6
2.0
28.6
67.0
4.9
4.8
+
+
+
1,251.2
407.6
214.4
159.7
7.0
26.6
843.6
835.3
0.3
3.7
4.4
1,229.8
355.3
340.6
3.5
2.5
8.6
874.5
865.9
0.3
3.8
4.5
Percent3
29.1%
19.4%
15.2%
3.2%
0.5%
0.5%
9.7%
9.6%
+
+
0.1%
28.0%
27.9%
26.5%
+
0.4%
0.9%
0.1%
0.1%
+
+
+
17.5%
5.7%
3.0%
2.2%
0.1%
0.4%
11.8%
11.7%
+
0.1%
0.1%
17.2%
5.0%
4.8%
+
+
0.1%
12.2%
12.1%
+
0.1%
0.1%

2-22  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-14: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related
Emissions Distributed (Tg C02 Eq.) and Percent of Total in 2007 (continued)
  Sector/Gas
  1990
  1995
  2000
  2005
2006
2007   Percent3
  Agriculture
    Direct Emissions
      C02
      CH4
      N20
    Electricity-Related
      C02
      CH4
      N20
      SF6
  U.S. Territories
                             47.3
                            511.7
                            482.6
                             55.3
                            199.8
                            227.5
                             29.0
                             28.7
                               +
                              0.1
                              0.2
                             60.5
                         530.0
                         502.9
                          57.3
                         218.2
                         227.4
                          27.0
                          26.8
                            +
                           0.1
                           0.2
                          62.3
                     530.1
                     502.8
                      56.9
                     219.2
                     226.7
                      27.3
                      27.0
                        +
                       0.1
                       0.1
                      57.7
                                                                        7.4%
                                                                        7.0%
                                                                        0.8%
                                                                        3.1%
                                                                        3.2%
                                                                        0.4%
                                                                        0.4%
                    0.8%
  Total
6,098.7
6,463.3
7,008.2
7,108.6    7,051.1    7,150.1    100.0%
  + Does not exceed 0.05 Tg C02 Eq. or 0.05 percent.
  'Percent of total emissions for year 2007.
  b Includes primarily HFC-134a.
  Note: Emissions from electricity generation are allocated based on aggregate electricity consumption in each end-use sector.
  Totals may not sum due to independent rounding.
accounted for 28 percent of U.S. greenhouse gas emissions
in 2007. The largest sources of transportation GHGs in 2007
were passenger cars (33 percent), light duty trucks, which
include sport utility vehicles, pickup trucks, and minivans
(28 percent), freight trucks  (21 percent) and commercial
aircraft (8 percent). These figures include direct emissions
from fossil fuel combustion, as well as HFC emissions from
mobile air conditioners and refrigerated transport allocated
to these vehicle types. Table 2-15 provides a detailed
summary of greenhouse gas emissions from transportation-
related activities with electricity-related emissions included
in the totals.
    From 1990 to 2007, transportation emissions rose by 29
percent due, in large part, to increased demand for travel and
the stagnation of fuel efficiency across the U.S. vehicle fleet.
The number of vehicle miles traveled by light-duty motor
vehicles (passenger cars and light-duty trucks)  increased
40 percent from 1990 to 2007, as a result of a confluence
of factors including population growth,  economic growth,
urban sprawl, and low fuel prices over much of this period.
A similar set of social and  economic trends has led to a
significant increase in air travel and freight transportation
by both air and road modes during the time series.
    Although average fuel economy over this period
increased slightly due primarily to the retirement of  older
                       vehicles, average fuel economy among new vehicles sold
                       annually gradually declined from 1990 to 2004. The decline
                       in new vehicle fuel economy between  1990 and 2004
                       reflected the increasing market share of light duty trucks,
                       which grew from about one-fifth of new vehicle sales in the
                       1970s to slightly over half of the market by 2004. Increasing
                       fuel prices  have since decreased the momentum of light
                       duty truck sales, and average new vehicle fuel economy has
                       improved since 2005 as the market share of passenger cars
                       increased. VMT growth among all passenger vehicles has
                       also been impacted, growing an average annual rate of 0.6
                       percent from 2004  to 2007, compared to an annual rate of
                       2.6 percent over the period 1990 to 2004.
                           Almost all of the energy consumed for transportation
                       was supplied by petroleum-based products, with more than
                       half being related to gasoline consumption in automobiles
                       and other highway vehicles. Other fuel uses, especially diesel
                       fuel for freight trucks and jet fuel for aircraft, accounted for
                       the remainder. The  primary driver of transportation-related
                       emissions was CO2 from  fossil fuel combustion,  which
                       increased by 29 percent from  1990 to 2007. This rise in
                       CO2 emissions, combined  with an increase in HFCs from
                       virtually no emissions in 1990 to 67.0 Tg CO2 Eq. in 2007,
                       led to an increase in overall emissions from transportation
                       activities of 28 percent.
                                                                      Trends in Greenhouse Gas Emissions  2-23

-------
Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
  Vehicle Type/Gas
1990
1995
2000
2005
2006
2007
  Passenger Cars                                 656.9         644.1          694.6         705.8      678.3     664.6
    C02                                         628.8         604.9          643.5         658.4      634.4     625.0

    N20                                          25.4          26.9           25.2           17.8       15.7       13.7
    MFCs                                           +1        10.1           24.3           28.5       27.2       24.9
  Light-Duty Trucks                               336.2         434.7          508.3         544.8      557.1     561.7
    C02                                         320.7         405.0          466.2         502.8      515.5     522.0



  Medium- and Heavy-Duty Trucks                  228.8         272.7          344.2         395.1      404.5     410.8
    C02                                         227.8         271.2          341.3         391.6      401.1     407.4



  Buses                                           8.3           9.11        11.1           12.1       12.4       12.4




  Motorcycles                                      1.81         1.81         1.9            1.6        1.9        2.1



  Commercial Aircraft"                            136.9         143.1          167.8         159.8      155.5     155.2
    C02                                         135.5         141.6          166.0         158.2      153.9     153.6


  Other Aircraft"                                   44.4          32.3           32.9           34.5       33.8       34.2
    C02                                          43.9          32.0           32.5           34.1       33.4       33.9


  Ships and Boats0                                 46.9          56.6           65.1           50.7       54.1       56.3
    C02                                          46.5          55.5           61.0           45.4       48.7       50.8



  Rail                                            38.6          44.1           50.1           56.7       58.9       58.0
    C02                                          38.1          42.2           45.1           49.8       51.8       50.8


    MFCs                                           +1         1.4l         4.61          6.4        6.5        6.6
    Other Emissions from Electricity Generation          0.11         0.11         0.11          0.1        0.1        0.1
2-24  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.) (continued)
Vehicle Type/Gas
Pipelines6
C02
Lubricants
C02
Total Transportation
International Bunker Fuels'
1990
36.2
36.2
11.9
11.9
1,546.7
115.6
1995
38.5
38.5
11.3
11.3
1,688.3
102.7
2000
35.2
35.2
12.1
12.1
1,923.2
100.0
2005
32.4
32.4
10.2
10.2
2,003.6
112.7
2006
32.6
32.6
9.9
9.9
1,999.0
111.7
2007
34.6
34.6
10.2
10.2
2,000.1
109.9
  + Does not exceed 0.05 Tg C02 Eq.
  'Consists of emissions from jet fuel consumed by domestic operations of commercial aircraft (no bunkers).
  b Consists of emissions from jet fuel and aviation gasoline consumption by general aviation and military aircraft.
  c Fluctuations in emission estimates are associated with fluctuations in reported fuel consumption, and may reflect data collection problems.
  11 Other emissions from electricity generation are a result of waste incineration (as the majority of municipal solid waste is combusted in "trash-to-
   steam" electricity generation plants), electrical transmission and distribution, and a portion of limestone and dolomite use (from pollution control
   equipment installed in electricity generation plants).
  e C02 estimates reflect natural gas used to power pipelines, but not electricity. While the operation of pipelines produces CH4 and N20, these emissions
   are not directly attributed to pipelines in the US Inventory.
  'Emissions from International Bunker Fuels include emissions from both civilian and military activities; these emissions are not included in the
  transportation totals.
  Note: Totals may not sum due to independent rounding. Passenger cars and light-duty trucks include vehicles typically used for personal travel and less
  than 8500 Ibs; medium- and heavy-duty trucks include vehicles 8501 Ibs and above.
  HFC emissions primarily reflect HFC-134a.
Commercial
    The commercial sector is heavily reliant on electricity
for meeting energy needs, with electricity consumption for
lighting, heating, air conditioning, and operating appliances.
The remaining emissions  were largely due to the direct
consumption of natural gas and petroleum products, primarily
for heating and cooking needs. Energy-related emissions from
the residential and commercial sectors have generally been
increasing since 1990, and are often correlated with short-
term fluctuations in energy  consumption caused by weather
conditions, rather than prevailing economic conditions.
Landfills and wastewater  treatment are included in  this
sector, with landfill emissions decreasing since 1990, while
wastewater treatment emissions have increased slightly.

Residential
    The residential sector  is heavily reliant on electricity
for meeting energy needs, with electricity consumption for
lighting, heating, air conditioning, and operating appliances.
The remaining emissions  were largely due to the direct
consumption of natural gas and petroleum products, primarily
for heating and cooking needs. Emissions from the residential
sectors have generally been increasing  since 1990,  and
are often correlated with short-term fluctuations in energy
consumption caused by weather conditions, rather than
prevailing economic conditions. In the long-term, this sector
is  also affected by population growth, regional migration
trends, and changes in housing and building attributes (e.g.,
size and insulation).

Agriculture
    The agricultural sector includes a variety of processes,
including enteric fermentation in domestic livestock,
livestock manure  management,  and agricultural soil
management. In 2007, enteric fermentation was the largest
source of CH^ emissions in the United States, and agricultural
soil management was the largest source of N2O emissions in
the United States. This sector also includes small amounts
of CO2 emissions from fossil fuel combustion by motorized
farm equipment such as  tractors.

Electricity  Generation
    The process of generating electricity, for consumption in
the above sectors, is the  single largest source of greenhouse
gas emissions in the United States, representing 34 percent
of total U.S. emissions. Electricity generation also accounted
for the largest share of CO2 emissions from fossil fuel
combustion, approximately 42 percent in 2007. Electricity
was consumed primarily in the residential, commercial,
and industrial end-use sectors  for lighting, heating, electric
motors, appliances, electronics, and air-conditioning.
                                                                          Trends in Greenhouse Gas Emissions   2-25

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Box 2-1: Methodology for Aggregating Emissions by Economic Sector

       In presenting the Economic Sectors in the annual Inventory of U.S.  Greenhouse Gas Emissions and Sinks, EPA expands upon the
  standard IPCC sectors common for UNFCCC reporting. EPA believes that discussing greenhouse gas emissions relevant to U.S.-specific
  sectors improves communication of the report's findings.
       Electricity Generation: Carbon dioxide emissions from the combustion of fossil fuels included in the EIA electric-utility fuel-consuming
  sector are apportioned to this economic sector. Stationary combustion emissions of CH4 and N20 are also based on the EIA electric-utility
  sector.  Additional sources include C02 and N20 from waste incineration, as the majority of municipal  solid waste is combusted in "trash-to-
  steam" electricity generation plants. The Electricity Generation economic sector also includes SF6 from  electrical transmission and distribution,
  and a portion  of C02 from limestone and dolomite use (from pollution control equipment installed in  electricity generation  plants).
       Transportation: Carbon dioxide emissions from the combustion of fossil fuels included in the EIA transportation fuel-consuming sector
  are apportioned to this economic sector (additional analyses and refinement of the EIA data is further explained in the Energy chapter of this
  report). Additional emissions are apportioned from CH4 and N20 from mobile combustion, based on the EIA transportation sector. Substitutes
  for ozone depleting substances are apportioned to this economic sector based on their specific end-uses within the source category, along
  with emissions from transportation refrigeration/air-conditioning systems. Finally, C02 emissions from non-energy uses of fossil fuels identified
  as lubricants for transportation vehicles are included in the Transportation economic sector.
       Industry: Carbon dioxide emissions from the combustion of fossil fuels included in the EIA industrial fuel-consuming  sector, minus the
  agricultural use of fuel explained below,  are apportioned to this economic sector. Stationary and mobile combustion emissions of CH4 and
  N20 are also based on the EIA industrial sector, minus emissions apportioned to the Agriculture economic sector described below. Substitutes
  for ozone depleting substances are apportioned based on their specific end-uses within  the source category,  with most  emissions falling
  within the Industry economic sector (emissions from the other economic sectors are subtracted to avoid double-counting). Additionally, all
  process-related emissions from sources with methods considered  within the IPCC Industrial Process guidance  have been apportioned to
  this economic sector. This includes the process-related emissions (i.e., emissions resulting from the processes used to make materials, and
  not from burning fuels to provide power or heat) from such activities as cement production, iron and steel production and metallurgical coke
  production, and ammonia production. Additionally, fugitive emissions from energy production sources, such as  natural gas systems, coal
  mining, and petroleum systems are included in the Industry economic sector. A portion of C02 emissions from limestone and dolomite use
  (from pollution control equipment installed in large industrial facilities) are also included in the Industry economic sector. Finally, all remaining
  C02 emissions from  non-energy uses of fossil fuels are assumed to be industrial in nature (besides the lubricants for transportation vehicles
  specified above), and are attributed to the Industry economic sector.
       Agriculture: As agricultural equipment is included in  ElA's industrial fuel-consuming sector surveys,  additional data is used to separate
  out the  fuel used by agricultural equipment, to allow for accurate reporting in the Agriculture economic sector from all sources of emissions,
  such as motorized farming equipment. Energy consumption estimates are obtained from Department of Agriculture survey data, in combination
  with separate  EIA fuel sales reports. This supplementary data is used to apportion C02 emissions from fossil fuel combustion and CH4 and
  N20 emissions from  stationary and mobile combustion (this data is subtracted from the Industry economic sector to avoid double-counting).
  The other emission sources included in this economic  sector are non-combustion sources of emissions that are  included  in the Agriculture
  and Land Use, Land-Use Change and Forestry chapters: N20 emissions from agricultural soils, CH4from enteric fermentation (i.e., exhalation
  from the digestive tracts of domesticated animals), CH4 and N20 from manure management, CH4 from rice cultivation,  C02 emissions from
  liming of agricultural soils and urea application, and CH4 and N20 from forest fires. Nitrous oxide emissions from the application of fertilizers
  to tree plantations (termed "forest  land" by the IPCC) are also included in the Agriculture economic sector.
       Residential: This economic sector includes the C02 emissions from the combustion of fossil fuels reported forthe EIA residential sector.
  Stationary combustion emissions of CH4 and N20 are also based on the EIA residential fuel-consuming sector. Substitutes for ozone depleting
  substances are apportioned based on their specific end-uses within the source category, with emissions from residential air-conditioning
  systems distributed to this economic sector. Nitrous oxide emissions from the application of fertilizers to developed land (termed "settlements"
  by the IPCC) are also included in the Residential economic sector.
       Commercial: This economic sector includes the C02 emissions from the combustion of fossil fuels reported in the EIA commercial
  fuel-consuming sector data. Stationary combustion emissions of CH4 and N20 are also based on the EIA commercial sector. Substitutes for
  ozone depleting substances are apportioned based on their specific end-uses within the source category, with emissions from commercial
  refrigeration/air-conditioning systems distributed to this economic sector. Public works sources including direct CH4 from landfills and CH4
  and N20 from  wastewater treatment and composting are included in this economic  sector.
2-26  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Box 2-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data

      Total emissions can be compared to other economic and social indices to highlight changes over time. These comparisons include: (1)
  emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; (2)  emissions
  per unit of fossil fuel consumption, because almost all energy-related emissions involve the combustion of fossil fuels; (3) emissions per
  unit of electricity consumption, because the electric power industry—utilities and non-utilities combined—was the largest source of U.S.
  greenhouse gas emissions in 2007; (4) emissions per unit of total gross domestic product as a measure of national economic  activity; or
  (5) emissions per capita.
      Table 2-16 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year. Greenhouse
  gas emissions in the United States have grown at an average annual rate of 0.9 percent since 1990. This rate is slightly slower than that for
  total energy or fossil fuel consumption and much slower than that for either electricity consumption or overall gross domestic product. Total
  U.S. greenhouse gas emissions have also grown slightly slower than national population since 1990 (see Figure 2-14).
  Table 2-16: Recent Trends in Various U.S. Data (Index 1990 = 100)
                                                                                                                   Growth
  Variable                              1990          1995          2000           2005       2006      2007       Rate"
  GDPb
  Electricity Consumption0
  Fossil Fuel Consumption0
  Energy Consumption0
  Populationd
  Greenhouse Gas Emissions6
  'Average annual growth rate
  b Gross Domestic Product in chained 2000 dollars (BEA 2008)
  c Energy content-weighted values (EIA 2008a)
  11 U.S. Census Bureau (2008)
  e GWP-weighted values
155
134
119
119
118
117
159
135
117
118
119
115
162
137
119
120
120
117
2.9%
1.9%
1.1%
1.1%
1.1%
0.9%
                            Figure 2-14
                                      U.S. Greenhouse Gas Emissions Per Capita and
                                           Per Dollar of Gross Domestic Product
                                                                                      Real GDP
                                                                                      Population
                                                                                      Emissions
                                                                                      per capita

                                                                                      Emissions
                                                                                      per $GDP
                              Source: BEA (2008), U.S. Census Bureau (2008), and emission estimates in the this report.
                                                                             Trends in Greenhouse Gas Emissions  2-27

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2.3.   Indirect Greenhouse  Gas
Emissions (CO,  NOX, NMVOCs,
and  S02)

    The reporting requirements of the UNFCCC7 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 CH^ 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
2005) ,8 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.
Box 2-3: Sources and Effects of Sulfur Dioxide
      Sulfur dioxide (S02) emitted into the atmosphere through natural and anthropogenic processes affects the earth's radiative budget
  through its photochemical transformation into sulfate aerosols that can (1) scatter radiation from the sun back to space, thereby reducing
  the radiation reaching the earth's surface; (2) affect cloud formation; and (3) affect atmospheric chemical composition (e.g., by providing
  surfaces for heterogeneous chemical reactions). The indirect effect of sulfur-derived aerosols on radiative forcing can be considered in
  two parts. The first indirect effect is the aerosols' tendency to decrease water droplet size and increase water droplet concentration in the
  atmosphere. The second indirect effect is the tendency of the reduction in cloud droplet size to affect precipitation by increasing cloud lifetime
  and thickness. Although still highly uncertain, the radiative forcing estimates from both the first and the second indirect effect are believed
  to be negative, as is the combined radiative forcing of the two (IPCC 2001). However, because S02 is short-lived and unevenly distributed
  in the atmosphere, its radiative forcing impacts are highly uncertain.
      Sulfur dioxide is also a major contributor to the formation of regional haze, which can cause significant increases in acute and chronic
  respiratory diseases. Once S02 is emitted, it is chemically transformed in the atmosphere and returns to the earth as the primary source of
  acid rain. Because of these harmful effects, the United States  has regulated S02 emissions in the Clean Air Act.
      Electricity generation is the largest anthropogenic source of S02 emissions  in the United States, accounting for 87  percent in
  2007. Coal combustion contributes  nearly all of those emissions (approximately 92 percent). Sulfur dioxide emissions have  decreased
  in recent years,  primarily as a result of electric power generators switching from high-sulfur to  low-sulfur coal and installing flue gas
  desulfurization equipment.
7 See .
8 NO,, and CO emission estimates from field burning of agricultural residues
were estimated separately, and therefore not taken from EPA (2008).
2-28  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 2-17: Emissions of NOX, CO, NMVOCs, and S02 (Gg)
  Gas/Activity
1990
1995
2000
2005
2006
2007
  NO,
    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
  S02
    Stationary Fossil Fuel Combustion
    Industrial Processes
    Mobile Fossil Fuel Combustion
    Oil and Gas Activities
    Incineration of Waste
    Waste
    Solvent Use
    Agricultural Burning
  NA
                NA
             15,612
              8,757
              5,857
                534
                321
                 98
                 39
                  5
                  2
             71,672
             62,519
              4,778
              1,744
              1,439
                860
                324
                  7
                  2
             14,562
              6,292
              3,881
              2,035
              1,450
                545
                243
                115
                 NA
             13,348
             11,641
                852
                600
                233
                 22
                  1
                  0
                 NA
         14,701
          8,271
          5,445
            527
            316
             98
             38
              5
              2
         67,453
         58,322
          4,792
          1,743
          1,438
            825
            323
              7
              2
         14,129
          5,954
          3,867
          1,950
          1,470
            535
            239
            113
             NA
         12,259
         10,650
            845
            520
            221
             22
              1
              0
             NA
         14,250
          7,831
          5,445
            520
            314
             97
             37
              5
              2
         63,875
         54,678
          4,792
          1,743
          1,438
            892
            323
              7
              2
         13,747
          5,672
          3,855
          1,878
          1,470
            526
            234
            111
             NA
         11,725
         10,211
            839
            442
            210
             22
              1
              0
             NA
  NA (Not Available)
  Note: Totals may not sum due to independent rounding.
  Source: EPA (2005) except for estimates from field burning of agricultural residues.
                                                                            Trends in Greenhouse Gas Emissions  2-29

-------
3.    Energy
          Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting
          for 86.3 percent of total emissions on a carbon dioxide (CO2) equivalent basis in 2007. This included 97,
          35, and 14 percent of the nation's CO2, methane (CFL,), and nitrous oxide (N2O) emissions, respectively.
Energy-related CO2 emissions alone constituted 83 percent of national emissions from all sources on a CO2 equivalent
basis, while the non-CO2 emissions from energy-related activities represented a much smaller portion of total national
emissions (4 percent collectively).
    Emissions from fossil fuel combustion comprise the vast majority of energy-related emissions, with CO2 being the
primary gas emitted (see Figure 3-1). Globally, approximately 29,195 teragrams (Tg) of CO2 were added to the atmosphere
through the combustion of fossil fuels in 2006, of which the United States accounted for about 20 percent.1 Due to their
relative importance, fossil fuel combustion-related CO2 emissions are considered separately, and in more detail than other
energy-related emissions (see Figure 3-2). Fossil fuel combustion also emits CH4 and N2O, as well as indirect greenhouse
gases such as nitrogen oxides (NOX), carbon monoxide (CO), and non-CH4 volatile organic compounds (NMVOCs). Mobile
fossil fuel combustion was the second largest source of N2O emissions in the United States, and overall energy-related
activities were collectively the largest source of these indirect greenhouse gas emissions.
    Energy-related activities other than fuel combustion,
such as the production, transmission, storage, and distribution
of fossil fuels, also emit greenhouse gases. These emissions
consist primarily of fugitive CH4 from natural gas systems,
petroleum systems, and coal mining.  Smaller quantities of
CO2, CO, NMVOCs, and NOX are also emitted.
    The combustion of biomass and biomass-based fuels also
emits greenhouse gases. Carbon dioxide emissions from these
activities, however, are not included in national emis sions totals
because biomass fuels are of biogenic origin. It is assumed that
the C released during the consumption of biomass is recycled
as U.S. forests and crops regenerate, causing no net addition
of CO2 to the atmosphere. The net impacts of land-use and
forestry activities on the C cycle are accounted for separately
within the Land Use, Land-Use Change, and Forestry chapter.
Emissions of other greenhouse gases from the combustion
Figure 3-1
 2007 Energy Chapter Greenhouse Gas Emission Sources
                                              5,735.8
    Fossil Fuel Combustion
   Non-Energy Use of Fuels
     Natural Gas Systems
           Coal Mining
      Mobile Combustion
      Petroleum Systems
    Stationary Combustion
     Incineration of Waste
Energy as a Portion
 of all Emissions
  Abandoned Underground
           Coal Mines
                       25
                            50   75   100
                               Tg CO, Eq.
                                           125   150
1 Global CO2 emissions from fossil fuel combustion were taken from Energy Information Administration International Energy Annual 2006
 EIA (2008).
                                                                                                  Energy 3-1

-------
Figure 3-2
                                        2007 U.S. Fossil Carbon Flows (Tg C02 Eq.)
                                                                                               NED Emissions
                                                                                               3
                                                                                                         Coal Emissions
                                                                                                         2,090
                                                                                                            Natural Gas Emissions
                                                                                                            1,225
                                                                                                            NEU Emissions 122
                                                                                                          Non-Energy Use
                                                                                                          Carbon Sequestered
                                                                                                          227
                                                  Fossil Fuel    Stock   Non-Energy
                                          Non-Enerav Consumption  Changes   Use U.S.
                                          Use Imports    U.S.      25    Territories
                                            55     Territories            8
                                                    51
                                                                                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.
                                                                                    NEU = Non-Energy Use
                                                                                    NG = Natural Gas
of biomass and biomass-based fuels are included in national
totals under stationary and mobile combustion.
    Table  3-1 summarizes emissions  from the Energy
sector in units of Tg of CO2 equivalents (Tg CO2 Eq.), while
             unweighted gas emissions in gigagrams (Gg) are provided in
             Table 3-2. Overall, emissions due to energy-related activities
             were 6,170.3 Tg CO2 Eq. in 2007, an increase of 19 percent
             since 1990.
Table 3-1: C02, CH4, and N20 Emissions from Energy (Tg C02 Eq.)
  Gas/Source
1990
1995
2000
2005
2006
2007
  C02                                           4,871.0        5,201.2
    Fossil Fuel Combustion                        4,708.9        5,013.9
       Electricity Generation                        1,809.7        1,938.9
       Transportation                             1,484.5        1,598.7
       Industrial                                    834.2          862.6
       Residential                                   337.7          354.4
       Commercial                                 214.5          224.4
       U.S. Territories                                28.3           35.0
    Non-Energy Use of Fuels                         117.0          137.5
    Natural Gas Systems                             33.7           33.8
    Incineration of Waste                             10.9           15.7
    Petroleum Systems                               0.41         0.3
    Wood Biomass and Ethanol Consumption3         219.3          236.8
    International Bunker Fuels3                       114.3          101.6

                           5,753.2
                           5,561.5
                           2,283.2
                           1,800.3
                             844.6
                             370.4
                             226.9
                              36.2
                             144.5
                              29.4
                              17.5
                               0.3
                             227.3
                              99.0
                           5,910.8
                           5,723.5
                           2,381.0
                           1,881.5
                             828.0
                             358.0
                             221.8
                              53.2
                             138.1
                              29.5
                              19.5
                                0.3
                             23?. 5
                             111.5
                        5,830.2
                        5,635.4
                        2,327.3
                        1,880.9
                          844.5
                          321.9
                          206.0
                           54.8
                          145.1
                           29.5
                           19.8
                            0.3
                          240.4
                          110.5
                    5,919.5
                    5,735.8
                    2,397.2
                    1,887.4
                     845.4
                     340.6
                     214.4
                       50.8
                     133.9
                       28.7
                       20.8
                        0.3
                     247.8
                     108.8
3-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-1: C02, CH4, and N20 Emissions from Energy (Tg C02 Eq.)  (continued)
  Gas/Source
  1990
  1995
  2000
  2005
 2006
 2007
  CH4
    Natural Gas Systems
    Coal Mining
    Petroleum Systems
    Stationary Combustion
    Abandoned  Underground Coal Mines
    Mobile Combustion
    International Bunker Fuels3
  N20
    Mobile Combustion
    Stationary Combustion
    Incineration of Waste
    International Bunker Fuels3
  265.7
  129.6
   84.1
   33.9
    7.4
    6.0
    4.7
    0.2
   57.0
   43.7
   12.8
    0.5
    1.1
  251.4
  132.6
   67.1
   32.0
    7.1
    8.2
    4.3
    0.1
   67.5
   53.7
   13.3
    0.5
    0.9
  239.0
  130.8
   60.5
   30.3
    6.6
    7.4
    3.4
    0.1
   67.7
   52.8
   14.5
    0.4
    0.9
  206.5
  106.3
   57.1
   28.3
    6.7
    5.6
    2.5
    0.1
   51.9
   36.7
   14.8
    0.4
    1.0
205.7
104.8
 58.4
 28.3
  6.3
  5.5
  2.4
  0.1
 48.5
 33.5
 14.5
  0.4
  1.0
205.7
104.7
 57.6
 28.8
  6.6
  5.7
  2.3
  0.1
 45.2
 30.1
 14.7
  0.4
  1.0
  Total
5,193.6
5,520.1
6,059.9
6,169.2    6,084.4     6,170.3
  a These values are presented for informational purposes only and are not included or are already accounted for in totals.
  Note: Totals may not sum due to independent rounding.
Table 3-2: C02, CH4, and N20 Emissions from Energy (Gg)
  Gas/Source
  1990
  1995
  2000
  2005
 2006
 2007
  C02                                        4,870,953      5,201,233      5,753,192
    Fossil Fuel Combustion                     4,708,918      5,013,910      5,561,515
    Non-Energy Use of Fuels                      116,9771    137,4601     144,473
    Natural Gas Systems                          33,733         33,810         29,394
    Incineration of Waste                          10,950         15,712         17,485
    Petroleum Systems                               3761        341            325
    Wood Biomass and Ethanol Consumption3       219,341U    236J75U     227,276
    International Bunker Fuels3                    114,330       101,620         98,966
  CH4                                           12,651         11,970         11,381
    Natural Gas Systems                           6,171          6,314          6,231
    Coal Mining                                   4,003          3,193          2,881
    Petroleum Systems                             1,613          1,524          1,441
    Stationary Combustion                           3521        3401         315
    Abandoned Underground Coal Mines                2881        3921         350
    Mobile Combustion                               2251        2071         163
    International Bunker Fuels3                          8              6              6\
  N20                                              184           218            219
    Mobile Combustion                               141           1731         170
    Stationary Combustion                            411         431          47
    Incineration of Waste                               2              11           1
    International Bunker Fuels3                          333

                                         5,910,830
                                         5,723,477
                                           138,070
                                            29,463
                                            19,532
                                               287
                                           231,481
                                           111,487
                                             9,832
                                             5,062
                                             2,719
                                             1,346
                                               318
                                               265
                                               121
                                                 7
                                               167
                                               118
                                                48
                                                 1
                                                 3
                                      5,830,206
                                      5,635,418
                                        145,137
                                         29,540
                                         19,824
                                            288
                                        240,386
                                        110,520
                                          9,795
                                          4,991
                                          2,780
                                          1,346
                                            300
                                            263
                                            115
                                              7
                                            156
                                            108
                                             47
                                              1
                                              3
                                  5,919,452
                                  5,735,789
                                    133,910
                                     28,680
                                     20,786
                                        287
                                    247,829
                                    108,756
                                      9,796
                                      4,985
                                      2,744
                                      1,370
                                        315
                                        273
                                        109
                                          7
                                        146
                                         97
                                         47
                                          1
                                          3
  a These values are presented for informational purposes only and are not included or are already accounted for in totals.
  Note: Totals may not sum due to independent rounding.
                                                                                                             Energy   3-3

-------
3.1.  Fossil Fuel Combustion (IPCC
Source  Category 1 A)

    Emissions from the combustion of fossil fuels for energy
include the gases CO2, CH4, and N2O. Given that CO2 is
the primary gas emitted from  fossil fuel combustion and
represents the largest share of U.S. total emissions, CO2
emissions from fossil fuel combustion are discussed at the
beginning of this section. Following that is a discussion of
emissions of  all three  gases from fossil fuel combustion
presented by sectoral breakdowns. Methodologies for
estimating CO2 from fossil fuel combustion also differ from
the estimation of CH4 and N2O emissions from stationary
combustion and mobile combustion. Thus, three  separate
descriptions of methodologies, uncertainties, recalculations,
and planned improvements are provided at the end of this
section. Total CO2, CH4, and N2O emissions from fossil fuel
combustion are presented in Table 3-3 and Table 3-4.

CO2 from Fossil Fuel Combustion

    Carbon dioxide is the primary gas emitted from fossil
fuel combustion and represents the largest share of U.S.
total greenhouse gas emissions. Carbon dioxide emissions
from fossil fuel combustion are presented in Table 3-5.
               In 2007, CO2 emissions from fossil fuel combustion
               increased by 1.8 percent relative to the previous year. This
               increase is primarily a result of an increase in electricity
               demand, combined with a significant decrease (14.2
               percent)  in hydropower generation used to meet this
               demand. Additionally, cooler winter and warmer summer
               conditions in 2007 increased the demand for heating fuels
               and contributed to the increase in the demand for electricity.
               In 2007, CO2 emissions from fossil fuel combustion were
               5,735.8 Tg CO2 Eq., or 22 percent above emissions in 1990
               (see Table 3-5).2
                   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.
Table 3-3: C02, CH4, and N20 Emissions from Fossil Fuel Combustion (Tg C02 Eq.)
Gas
C02
CH4
N20
Total
1990
4,708.9
12.1
56.5
4,777.6
1995
5,013.9
11.5
67.0
5,092.4
2000
5,561.5
10.0
67.4
5,638.9
2005
5,723.5
9.2
51.5
5,784.2
2006
5,635.4
8.7
48.1
5,692.2
2007
5,735.8
8.9
44.8
5,789.5
  Note: Totals may not sum due to independent rounding.
Table 3-4: C02, CH4, and N20 Emissions from Fossil Fuel Combustion (Gg)
  Gas
    1990
1995
2000
2005
2006
2007
  C02
  CH4
  N20
4,708,918     5,013,910     5,561,515     5,723,477  5,635,418  5,735,789
     578          5471        478          439       415       424
     182          2161        2171        166       155       145
  Note: Totals may not sum due to independent rounding.
                                                       2 An additional discussion of fossil fuel emission trends is presented in the
                                                       Trends in U.S. Greenhouse Gas Emissions chapter.
3-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-5: C02 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg C02 Eq.)
  Fuel/Sector
  1990
  1995
  2000
                 2005
             2006
             2007
  Coal
    Residential
    Commercial
    Industrial
    Transportation
    Electricity Generation
    U.S. Territories
   Natural Gas
    Residential
    Commercial
    Industrial
    Transportation
    Electricity Generation
    U.S. Territories
  Petroleum
    Residential
    Commercial
    Industrial
    Transportation
    Electricity Generation
    U.S. Territories
   Geothermal3
1,695.9
    2.9
   11.8
  149.5
    NE
1,531.1
    0.6
1,001.7
  237.4
  141.5
  410.1
   36.2
  176.5
    NO
2,010.9
   97.4
   61.2
  274.6
1,448.3
  101.8
   27.6
   0.40

1,801.9
    1.7
   11.1
  139.6
    NE
1,648.6
    0.9
1,159.1
  262.3
  164.0
  465.0
   38.6
  229.2
    NO
2,052.6
   90.5
   49.3
  257.9
1,560.1
   60.7
   34.0
   0.34
12,046.4
        I
  126.8
2,046.4
    1.0
    8.2
  126.8
    NE
1,909.5
    0.9
1,210.8
  268.8
  171.6
  452.3
   35.6
  281.8
    0.7
2,303.9
  100.5
   47.2
  265.5
1,764.7
   91.5
   34.6
   0.36
2,088.2
    0.8
    9.1
  116.2
    NE
1,958.4
    3.7
1,161.4
  262.0
  163.1
  381.8
   33.2
  319.9
    1.3
2,473.5
   95.2
   49.6
  330.0
1,848.2
  102.3
   48.2
   0.38
2,057.2
    0.5
    6.2
  114.1
    NE
1,932.4
    4.0
1,140.7
  236.8
  153.8
  376.2
   33.5
  338.9
    1.4
2,437.2
   84.5
   46.0
  354.2
1,847.4
   55.6
   49.4
   0.37
2,086.5
    0.6
    6.8
  107.4
    NE
1,967.6
    4.1
1,216.5
  256.9
  163.4
  385.6
   35.4
  373.8
    1.4
2,432.4
   83.2
   44.2
  352.5
1,852.0
   55.3
   45.3
   0.38
  Total
4,708.9
5,013.9
5,561.5
              5,723.5    5,635.4    5,735.8
  NE (Not Estimated)
  NO (Not Occurring)
  'Although not technically a fossil fuel, geothermal energy-related C02 emissions are included for reporting purposes.
  Note: Totals may not sum due to independent rounding.
    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).
    Carbon dioxide 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 as much C per unit of energy as coal,
and natural gas has only about 55 percent.3 Producing a unit of
heat or electricity using natural gas instead of coal can reduce
the CO2 emissions associated with energy consumption, and
3 Based on national aggregate carbon content of all coal, natural gas, and
petroleum fuels combusted in the United States.
              using nuclear or renewable energy sources (e.g., wind) can
              essentially eliminate emissions (see Box 3-2). Table 3-6 shows
              annual changes in emissions during the last five years for coal,
              petroleum, and natural gas in selected sectors.
                   In the United States, 85 percent of the energy consumed
              in 2007 was produced through the combustion of fossil fuels
              such as coal, natural gas, and petroleum (see Figure 3-3 and
              Figure 3-4). The remaining portion was supplied by nuclear
              electric power (8 percent) and by a variety of renewable energy
              sources (7 percent), primarily hydroelectric power and biofuels
              (FJA 2008a). Specifically, petroleum supplied the largest share
              of domestic energy demands, accounting for an average of 42
              percent of total fossil-fuel-based energy consumption in 2007.
              Natural gas and coal followed in order of importance, accounting
              for 30 and  28 percent of total consumption, respectively.
              Petroleum was consumed primarily in the transportation end-
              use  sector, the vast  majority  of coal was used in electricity
              generation, and natural gas was broadly consumed in all end-use
              sectors except transportation (see Figure 3-5) (ElA 2008a).
                                                                                                         Energy  3-5

-------
Table 3-6: Annual Change in C02 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors
(Tg C02 Eq. and Percent)
Sector
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors"
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels"
2003 to 2004
11.4
18.4
2.0
51.1
-13.7
-5.1
1.2
-17.8
64.4
0.6%
6.6%
2.0%
2.9%
-4.9%
-2.9%
1.0%
-4.2%
1.1%
2004 to 2005
40.8
22.7
2.2
19.9
-0.5
-5.7
-2.4
-28.3
54.2
2.1%
7.6%
2.2%
1.1%
-0.2%
-3.4%
-2.0%
-6.9%
1.0%
2005 to 2006
-26.0
19.0
-46.7
-0.8
-25.2
-9.3
-2.1
-5.6
-88.1
-1.3%
5.9%
-45.6%
0.0%
-9.6%
-5.7%
-1.8%
-1.5%
-1.5%
2006(02007
35.3
34.9
-0.3
4.6
20.1
9.6
-6.7
9.4
100.4
1.8%
10.3%
-0.6%
0.2%
8.5%
6.2%
-5.9%
2.5%
1.8%
  a Excludes emissions from International Bunker Fuels.
  b Includes fuels and sectors not shown in table.
Figure 3-3
     2007 U.S. Energy Consumption by Energy Source
               Renewable
                 Nuclear

              Natural Gas


                   Coal
               Petroleum
                                      7%
22%
                                      22%
                                      39%
Figure 3-4
        U.S. Energy Consumption (Quadrillion Btu)
       120-1
       100-
     .2
     S
        60-
        20-
         O-1
                                            Total Energy
                                            Fossil Fuels
                                      Renewable & Nuclear

           Note: Expressed as gross calorific values.
                       Figure 3-5
                                  2007 C02 Emissions from Fossil Fuel
                                  Combustion by Sector and Fuel Type
                          2,500 -|
                          2,000 -
                          1,500 -
                                                              3
                                                                ' 1,000 -
                                                                  500 -
                                                                   0 -1
                   Natural Gas
                   Petroleum
                  I Coal
Relative Contribution
   by Fuel Type
                                                                                                 •=
                                                                                                 1
                                                                      Note: Electricity generation also includes emissions of less than 0.5 Tg C02 Eq. from
                                                                      geothermal-based electricity generation.
                           Fossil fuels are generally combusted for the purpose
                       of producing energy for useful heat and work. During the
                       combustion process, the C stored in the fuels is oxidized and
                       emitted as CO2 and smaller amounts of other gases, including
                       CH4,  CO, and NMVOCs.4 These other C containing non-
                       CO2 gases are emitted as a by-product of incomplete fuel
                       combustion, but are, for the most part,  eventually oxidized
                       to CO2 in the atmosphere. Therefore, it is assumed that all
                       of the C in fossil fuels used to produce energy is eventually
                       converted to atmospheric CO2.
                       4 See the sections entitled Stationary Combustion and Mobile Combustion
                       in this chapter for information on non-CO2 gas emissions from fossil fuel
                       combustion.
3-6   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Box 3-1: Weather and Non-Fossil Energy Effects on C02 from Fossil Fuel Combustion Trends

       In 2007, weather conditions became much cooler in the winter and slightly warmer in the summer, compared to 2006. Although winter
  conditions were cooler in 2007 compared to 2006, the winter was warmer than normal, with heating degree days in the United States 6
  percent below normal (see Figure 3-6). Cooler winter conditions compared to 2006 led to  an increase in demand for heating fuels. Although
  summer conditions were slightly warmer in 2007  compared to  2006, summer temperatures were substantially warmer than usual, with
  cooling degree days 13 percent above normal (see  Figure 3-7) (EIA 2008f).5 As a result, the demand for electricity increased due to warmer
  summer conditions compared to 2006.
  Figure 3-6
                  Annual Deviations from Normal Heating Degree Days for the United States (1950-2007)
     15 -i
Si  10-
;i   5-
»E
it   o
*l  -5 -
IS -10 -
  o^
    -15 -
                  Normal (4,524 Heating Degree Days)
                             •  I  ••  _•-••
                                                                99% Confidence
nn ™
                                                                                                    CO  CO  O   CM
              Note: Climatological normal data are highlighted. Statistical confidence interval for "normal" climatology period of 1971 through 1990.
  Figure 3-7
                  Annual Deviations from Normal Cooling Degree Days for the United States (1950-2007)
                                                                99% Confidence
      11 '' I      Normal (1,242 Cooling Degree Days)


              Note: Climatological normal data are highlighted. Statistical confidence interval for "normal" climatology period of 1971 through 1990.
                                                                                                          s   s   s  s
      Although no  new  U.S.  nuclear power plants  have been
  constructed in recent years, the utilization (i.e., capacity factors6)
  of existing plants in 2007 remained high at just over  90  percent.
  Electricity output by hydroelectric power plants decreased in 2007
  by approximately 14 percent. Electricity generated by nuclear plants
  in 2007 provided almost  3 times as much of the energy consumed
  in the United States as hydroelectric plants (EIA 2008a). Aggregate
  nuclear and hydroelectric power plant capacity factors since 1973
  are shown in Figure 3-8.
                                                                 Figure 3-8
                                                                Aggregate Nuclear and Hydroelectric Power Plant
                                                                Capacity Factors in the United States (1974-2007)
                                                                 80-1
                                                                 60-
                                                                 40-
                                                                       20-
                                                                        0J

                                                                                                               § s s  s
                                                                                                               & & &  &
  5 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature below 65° F, while
  cooling degree days are deviations of the mean daily temperature above 65° F. Heating degree days have a considerably greater effect on energy demand
  and related emissions than do cooling degree days. Excludes Alaska and Hawaii. Normals are based on data from 1971 through 2000. The variation in these
  normals during this time period was ±10 percent and ±14 percent for heating and cooling degree days, respectively (99 percent confidence interval).
  6 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the electrical energy that could
  have been produced at continuous full-power operation during the same period (EIA 2008a).
                                                                                                                  Energy  3-7

-------
Fossil Fuel Combustion Emissions
by Sector

    In addition to the CO2 emitted from fossil fuel
combustion, CK4 and N2O are emitted from stationary and
mobile combustion as well. Table 3-7 provides an overview
of the CO2,  CH4, and N2O emissions from fossil fuel
combustion by sector.
    Other than CO2, gases emitted from stationary combustion
include the greenhouse gases CtLj and N2O and the indirect
greenhouse gases NOX, CO, and NMVOCs.7 CJ^ 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. Nitrous oxide 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. Methane emissions from
              stationary combustion are primarily a function of the CH^
              content of the fuel and combustion efficiency.
                  Mobile combustion produces greenhouse gases other
              than CO2, including CH4, N2O, and indirect greenhouse
              gases including NOX, CO, and NMVOCs. As with stationary
              combustion, N2O and NOX emissions from mobile combustion
              are closely related to fuel characteristics,  air-fuel mixes,
              combustion temperatures, and the use of pollution control
              equipment. Nitrous oxide from mobile sources, in particular,
              can be formed by the  catalytic processes used  to control
              NOX, CO, and hydrocarbon emissions. Carbon monoxide
              emissions from mobile combustion are significantly affected
              by combustion efficiency and the presence of post-combustion
              emission controls. Carbon monoxide emissions are highest
              when air-fuel mixtures  have less oxygen than required for
              complete combustion.  These emissions occur especially
              in idle, low  speed, and cold start conditions. Methane and
Table 3-7: C02, CH4, and N20 Emissions from Fossil Fuel Combustion by Sector (Tg C02 Eq.)
  End-Use Sector/Gas
  1990
  1995
               2000
                2005
            2006
            2007
  Electricity Generation
    C02
    CH4
    N20
  Transportation
    C02
    CH4
    N20
  Industrial
    C02
    CH4
    N20
  Residential
    C02
    CH4
    N20
  Commercial
    C02
    CH4
    N20
  U.S. Territories3
1,818.3
1,809.7
    0.6
    8.1
1,532.9
1,484.5
    4.7
   43.7
  838.9
  834.2
    1.5
    3.2
  343.2
  337.7
    4.4
    1.1
  215.8
  214.5
    0.9
    0.4
   28.4
1,938.9       2,283.2
    0.61         0.71
    Rfi          mn
1,948.0
1,938.9
    0.6
    8.6
1,656.7
1,598.7
    4.3
   53.7
  867.5
  862.6
    1.6
    3.3
  359.4
  354.4
    4.0
    1.0
  225.7
  224.4
    0.9
    0.4
   35.1
2,293.8
2,283.2
    0.7
   10.0
1,856.5
1,800.3
    3.4
   52.8
  849.4
  844.6
    1.6
    3.2
  374.7
  370.4
    3.4
    0.9
  228.2
  226.9
    0.9
    0.3
   36.3
2,392.1
2,381.0
    0.7
   10.3
1,920.7
1,881.5
    2.5
   36.7
  832.5
  828.0
    1.5
    3.1
  362.5
  358.0
    3.5
    0.9
  223.0
  221.8
    0.9
    0.3
   53.4
2,338.1
2,327.3
    0.7
   10.1
1,916.8
1,880.9
    2.4
   33.5
  849.2
  844.5
    1.5
    3.2
  325.9
  321.9
    3.2
    0.8
  207.2
  206.0
    0.8
    0.3
   55.0
2,408.2
2,397.2
    0.7
   10.3
1,919.8
1,887.4
    2.3
   30.1
  849.9
  845.4
    1.5
    3.1
  345.1
  340.6
    3.5
    0.9
  215.5
  214.4
    0.8
    0.3
   51.0
  Total
4,777.6
5,092.4
             5,638.9
              5,784.2    5,692.2    5,789.5
  aU.S. Territories are not apportioned by sector, and emissions are total greenhouse gas emissions from all fuel combustion sources.
  Note: Totals may not sum due to independent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based on aggregate
  national electricity consumption by each end-use sector.
7 Sulfur dioxide (SO2) emissions from stationary combustion are addressed
in Annex 6.3.
3-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
NMVOC emissions from motor vehicles are a function of the
CtLj content of the motor fuel, the amount of hydrocarbons
passing uncombusted through the engine, and any post-
combustion control of hydrocarbon  emissions (such as
catalytic converters).
    An alternative method of presenting combustion
emissions is to allocate emissions associated with electricity
generation to the sectors in which it is used.  Four end-use
sectors were defined: industrial, transportation, residential,
and commercial. In Table 3-8, electricity generation emissions
have been distributed to each end-use sector based upon the
sector's share of national electricity consumption, with the
exception of CH4 and N2O from transportation.8 Emissions
from U.S. territories are also calculated separately due to a
lack of end-use-specific consumption data. This method of
distributing emissions  assumes that each sector consumes
electricity generated from an equally carbon-intensive mix
of fuels and other energy sources. Table 3-7 and Table 3-8
summarize CO2, CH4, and N2O emissions from  direct fossil
fuel combustion and pro-rated electricity generation emissions
from electricity consumption by end-use sector. The following
discussions for stationary combustion sources focus on direct
emissions, as presented in Table 3-7, while the discussion of
transportation and mobile combustion sources focuses on the
alternative method as presented in Table 3-8.

Stationary Combustion

    The direct combustion of fuels by stationary sources
in the electricity generation, industrial, commercial, and
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. Methane and N2O emissions from  stationary
Table 3-8: C02, CH4, and N20 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)a
End-Use Sector/Gas
Transportation
C02
CH4
N20
Industrial
C02
CH4
N20
Residential
C02
CH4
N20
Commercial
C02
CH4
N20
U.S. Territories"
Total
1990
1,536.0
1,487.5
;l
43.7
1,524.7
1,516.8
1.7
6.2!
935.4
927.1
4.6
3.7
753.0
749.2
1
2.8
28.4
4,777.6
1995
1,659.7
1,601.7
4.3
53.7
1,583.8
1,575.5
1.8
6.5l
1,001.3
993.3
4.2
3.8
812.5
808.5
1.ll
2.9 1
35.1
5,092.4
2000
1,860.0
1,803.7
3.4
52.8
1,638.1
1,629.6
1.8
6.7
1,136.1
1,128.2
3.6 1
42|
968.5
963.8
1.ll
3.6 1
36.3
5,638.9
2005
1,925.4
1,886.2
2.5
36.7
1,566.4
1,558.5
1.7
6.2
1,215.6
1,207.2
3.8
4.6
1,023.3
1,018.4
1.1
3.8
53.4
5,784.2
2006
1,921.3
1,885.4
2.4
33.6
1,558.7
1,550.7
1.7
6.2
1,153.8
1,145.9
3.4
4.4
1,003.4
998.6
1.1
3.7
55.0
5,692.2
2007
1,924.6
1,892.2
2.3
30.1
1,561.2
1,553.4
1.7
6.1
1,206.4
1,198.0
3.8
4.6
1,046.4
1,041.4
1.1
3.9
51.0
5,789.5
  'Electricity generation emissions have been distributed to each end-use sector based upon the sector's share of national electricity consumption.
  bU.S. Territories are not apportioned by sector, and emissions are total greenhouse gas emissions from all fuel combustion sources.
  Note: Totals may not sum due to independent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based on aggregate
  national electricity consumption by each end-use sector.
8 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  3-9

-------
Table 3-9: C02 Emissions from Stationary Combustion (Tg C02 Eq.)
  Sector/Fuel Type
  1990
  1995
  2000
  2005
  2006
  2007
  Electricity Generation
    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. Territories3
    Coal
    Natural Gas
    Fuel Oil
1,809.7
1,531.1
  176.5
  101.8
    0.4
  834.2
  149.5
  410.1
  274.6
  214.5
   11.8
  141.5
   61.2
  337.7
    2.9
  237.4
   97.4
   28.3
    0.6
    NO
   27.6
1,938.9
1,648.6
  229.2
   60.7
    0.3
  862.6
  139.6
  465.0
  257.9
  224.4
   11.1
  164.0
   49.3
  354.4
    1.7
  262.3
   90.5
   35.0
    0.9
    NO
   34.0
2,283.2
1,909.5
  281.8
   91.5
    0.4
  844.6
  126.8
  452.3
  265.5
  226.9
    8.2
  171.6
   47.2
  370.4
    1.0
  268.8
  100.5
   36.2
    0.9
    0.7
   34.6
2,381.0
1,958.4
  319.9
  102.3
    0.4
  828.0
  116.2
  381.8
  330.0
  221.8
    9.1
  163.1
   49.6
  358.0
    0.8
  262.0
   95.2
   53.2
    3.7
    1.3
   48.2
2,327.3
1,932.4
  338.9
   55.6
    0.4
  844.5
  114.1
  376.2
  354.2
  206.0
    6.2
  153.8
   46.0
  321.9
    0.5
  236.8
   84.5
   54.8
    4.0
    1.4
   49.4
2,397.2
1,967.6
  373.8
   55.3
    0.4
  845.4
  107.4
  385.6
  352.5
  214.4
    6.8
  163.4
   44.2
  340.6
    0.6
  256.9
   83.2
   50.8
    4.1
    1.4
   45.3
  Total
4,708.9
5,013.9
5,561.5
5,723.5    5,635.4    5,735.8
  NO (Not Occurring)
  aU.S. Territories are not apportioned by sector, and emissions from all fuel combustion sources are presented in this table.
  Note: Totals may not sum due to independent rounding.
combustion sources depend upon fuel characteristics, size
and vintage, along with combustion technology, pollution
control equipment, ambient environmental conditions,
and operation and maintenance practices.  Nitrous oxide
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. Methane emissions from stationary combustion
are primarily a function of the CK4 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.

Electricity Generation
    The process of generating electricity is the single
largest source of CO2 emissions in the United  States,
representing 39 percent of total CO2 emissions from  all
CO2 emissions sources across the United States. Methane
and N2O accounted for a small portion of emissions from
electricity generation, representing less than 0.1 percent
              and 0.4 percent, respectively. Electricity generation also
              accounted for the largest share of CO2 emissions from
              fossil fuel combustion, approximately 42 percent in 2007.
              Methane and N2O from electricity generation represented 8
              and 23 percent of emissions from fossil fuel combustion in
              2007. Electricity was consumed primarily in the residential,
              commercial, and industrial end-use sectors for lighting,
              heating, electric motors,  appliances, electronics, and air
              conditioning (see Figure 3-9).
                  The electric  power industry includes  all  power
              producers,  consisting of both regulated utilities and
              nonutilities (e.g. independent power producers, qualifying
              cogenerators, and  other small power producers).  For the
              underlying energy data used in this chapter, the Energy
              Information Administration (EIA) places electric power
              generation into three functional categories:  the  electric
              power sector, the  commercial  sector, and the industrial
              sector. The electric power sector consists of electric utilities
              and independent power producers whose primary business is
3-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 3-10: CH4 Emissions from Stationary Combustion (Tg C02 Eq.)
  Sector/Fuel Type
1990
1995
2000
2005
2006
2007
  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
  0.6
  0.3
  0.1
  0.1
  0.1
  1.5
  0.3
  0.2
  0.2
  0.9
  0.91

  0.2
  0.3
  0.4
  4.4
  0.2
  0.3
  0.4
  3.5
  7.4
                               6.7
                                          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
                                          3.2
                                           +
                                          0.3
                                          0.4
                                          2.5
                                          0.1
                                           +
                                          0.1
                           6.3
                                      0.7
                                      0.4
                                       +
                                      0.1
                                      0.1
                                      1.5
                                      0.2
                                      0.2
                                      0.1
                                      0.9
                                      0.8
                                       +
                                      0.1
                                      0.3
                                      0.4
                                      3.5
                                       +
                                      0.3
                                      0.5
                                      2.8
                                      0.1
                                       +
                                      0.1
                       6.6
  + Less than 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
the production of electricity,9 while the other sectors consist
of those producers that indicate their primary business is
something other than the production of electricity.
    The industrial, residential, and commercial end-use
sectors, as presented in Table 3 -8, were reliant on electricity for
meeting energy needs. The residential and commercial end-use
sectors were especially reliant on electricity consumption for
lighting, heating, air conditioning, and operating appliances.
Electricity sales to the residential  and commercial end-use
sectors in  2007 increased about 3  percent in the residential
and 3.3 percent in the commercial sectors. The trend in the
commercial  sector can largely be attributed to the growing
economy (2.0 percent), which led to  increased demand for
electricity. The increase is also attributed to an increase in air
9 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).
            conditioning-related electricity consumption in the residential
            and commercial sectors that occurred as a result of the warmer
            summer compared to 2006. In 2007, the amount of electricity
             Figure 3-9
                        Electricity Generation Retail Sales by
                            End-Use Sector (1974-2007)
                  1,600 -i

                  1,400 -

                  1,200 -

                  1,000 -

                   800-

                   600-

                   400-
                                          Residential
             Industrial
                                                                          r-r-r-ooooooooooo>
                                                      a>a>oooo
                                                      0>0>OOOO
                        Note: The transportation end-use sector consumes minor qualities of electricity.
                                                                                                           Energy  3-11

-------
Table 3-11: N20 Emissions from Stationary Combustion (Tg C02 Eq.)
  Sector/Fuel Type
1990
1995
2000
2005
2006
2007
  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
  8.1
  7.6
  0.2
  0.1
  0.2
  3.2
  0.7
  0.5
  0.2
  1.7
  0.4
  0.1
  0.2

  a!
  0.3
  8.6
  8.1
  0.1
  0.1
  0.1
  3.31
  0.7
  0.4
  0.3
  1.9
  0.4
  0.1
  0.1

  a!


  "
  0.2
  0.1
  0.6
10.0
  9.4
  0.2
  0.2
  0.2
  3.2
  0.6
  0.4
  0.3
  1.9
  0.3

  ,1

  a!
  0.9

  0.3
  0.1
  0.5
10.3
  9.7
  0.2
  0.2
  0.2
  3.1
  0.6
  0.6
  0.2
  1.7
  0.3
  +
  0.1
  0.1
  0.1
  0.9
  +
  0.3
  0.1
  0.5
  0.1
  +
  0.1
10.1
  9.5
  0.1
  0.2
  0.2
  3.2
  0.6
  0.6
  0.2
  1.8
  0.3
  +
  0.1
  0.1
  0.1
  0.8
  +
  0.2
  0.1
  0.5
  0.1
  +
  0.1
10.3
  9.7
  0.1
  0.2
  0.2
  3.1
  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
  +
  0.1
  Total
              13.3
              14.5
              14.8
           14.5
           14.7
  + Less than 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
generated (in kWh) increased by 2.1 percent from the previous
year. This growth is due to the growing economy, expanding
industrial production, and warmer summer conditions
compared to 2006. As a result, CO2 emissions from the electric
power sector increased by 3.0 percent as the consumption
of coal and  natural gas for electricity generation increased.
Coal and natural gas consumption for electricity generation
increased by 1.8 percent and 10.3 percent, respectively, in
2007, and nuclear power increased by just over 2 percent. As
a result of the significant increase in natural gas consumption,
C  intensity  from direct fossil fuel combustion decreased
slightly overall in 2007 (see Table 3-15). Coal  is consumed
primarily by the electric power sector in the United States,
which accounted for 94 percent of total coal consumption for
energy purposes in 2007. Spurred by a 14.2-percent decrease
in hydropower, total renewable electricity generation fell by
8.9 percent  in 2007. However non-hydropower renewable
            generation grew by 6.8 percent, thus preventing an even greater
            increase in emissions.

            Industrial End-Use Sector
                The industrial sector accounted for 15 percent of CO2
            emissions from fossil fuel combustion,  17 percent of CH^
            emissions from fossil fuel combustion, and 7 percent of N2O
            emissions from fossil fuel combustion. Carbon dioxide, CH4,
            and N2O emissions resulted from the direct consumption of
            fossil fuels for steam and process heat production.

                The industrial  sector, per the underlying energy
            consumption data from EIA, includes activities such as
            manufacturing, construction, mining, and agriculture. The
            largest of these activities in terms  of energy consumption
            is manufacturing, of which  six industries—petroleum
            refineries, chemicals, primary metals, paper, food, and
            nonmetallic mineral products—represent the vast majority
            of the energy use (EIA 2008a and EIA 2005).
3-12   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
    In theory, emissions from the industrial sector should be
highly correlated with economic growth and industrial output,
but heating of industrial buildings and agricultural energy
consumption are also affected by weather conditions.10 In
addition, structural changes within the U.S. economy
that lead to shifts  in industrial output away from energy-
intensive manufacturing products to less  energy-intensive
products (e.g., from steel to computer equipment) also have
a significant affect on industrial emissions.
    From 2006 to 2007, total industrial production and
manufacturing output increased by 1.7 and 1.8 percent,
respectively (FRB  2007). Over this period, output increased
for chemicals, and food, but decreased for petroleum
refineries, paper, primary metals, and nonmetallic mineral
products (see Figure 3-10).
    Despite the growth in industrial output (60 percent)
and the overall U.S. economy (62  percent) from 1990 to
2007, CO2 emissions from the industrial  sector increased


Figure 3-10
     Industrial Production Indices (Index 2002=100)
      120
      110
      100
      70
      60

      120
      110
      100
      90
      120-,
      110-
      100-
      70-1

      120-|
      110-
      100-
      90-
               Total
             Industrial
               Incli
Paper
            Total excluding Computers,
            Communications Equipment,
              and Semiconductors
Stone, Clay & Glass Products
                              Chemicals
Primary Metals
                S  S S
                              Petroleum Refineries

                                 S 5  S S  S S
10 Some commercial customers are large enough to obtain an industrial price
for natural gas and/or electricity and are consequently grouped with the
industrial end-use sector in U. S. energy statistics. These misclassifications
of large commercial customers likely cause the industrial end-use sector to
appear to be more sensitive to weather conditions.
by only 1.3 percent over that time. A number of factors are
believed to have caused this disparity between rapid growth
in industrial  output and only minor growth in industrial
emissions, including: (1) more rapid growth in output
from less energy-intensive industries relative to traditional
manufacturing industries, and (2) improvements in energy
efficiency. In 2007, CO2, CH4, and N2O emissions from fossil
fuel combustion and electricity use within the industrial
end-use sectors totaled 1,561.2 Tg CO2 Eq., or 0.2 percent
above 2006 emissions.

Residential and Commercial End-Use Sectors
    The residential and commercial sectors accounted for
an average 6 and 4 percent of CO2 emissions from fossil
fuel combustion, 40 and 9 percent of CH4 emissions from
fossil fuel combustion, and 2 and 1 percent of N2O emissions
from fossil fuel combustion, respectively. Emissions from
these sectors  were largely due to the direct consumption of
natural gas and petroleum products, primarily for heating and
cooking needs. Coal consumption was  a minor component
of energy use in both of these end-use sectors. In 2007, CO2,
CH4, and N2O emissions  from fossil fuel combustion and
electricity use within the  residential and commercial end-
use sectors were 1,206.4 Tg CO2 Eq. and 1,046.4 Tg CO2
Eq., respectively. Total CO2, CH4, and N2O emissions from
the residential sector increased by 4.4 percent in 2007, with
emissions in  2007 from the commercial sector 4.1 percent
higher than in 2006.
    Emissions from the residential and commercial
sectors have generally been  increasing since 1990, and
are often correlated with short-term fluctuations in energy
consumption caused by weather conditions, rather than
prevailing economic conditions. In the  long-term,  both
sectors are also affected by population growth, regional
migration trends, and changes  in housing and building
attributes (e.g., size and insulation).
    Emissions from natural gas consumption represent over
75 and 76 percent of the direct fossil fuel CO2 emissions from
the residential and commercial sectors, respectively. In 2007,
natural gas CO2 emissions increased by 8.5 percent and 6
percent, respectively, in each of these sectors. The increase
in emissions in both sectors  is  a result of cooler winter
conditions in the United States compared to 2006.
                                                                                                    Energy  3-13

-------
U.S. Territories
    Emissions from U.S. territories are based on the fuel
consumption in American Samoa, Guam, Puerto Rico, U.S.
Virgin Islands, Wake Island, and other U.S. Pacific Islands.
As described in the Methodology section for CO2 from fossil
fuel combustion, this data is collected separately from the
sectoral-level data available for the general calculations. As
sectoral information is not available for U.S. Territories, CO2,
CH4, and N2O emissions are presented in Table 3-7 through
3-11, though the emissions will include some transportation
and mobile combustion sources.

Transportation and Mobile  Combustion

    This discussion of transportation emissions follows the
alternative method of presenting combustion emissions by
allocating emissions associated with electricity generation to
the transportation end-use sector, as presented in Table 3-8.
For direct emissions from transportation (i.e., not including
electricity consumption), please see Table 3-7.

Transportation End-Use Sector
    The transportation end-use sector accounted for 1,924.6
Tg CO2 Eq. in 2007, which represented 33 percent of CO2
emissions from fossil fuel combustion, 26 percent of CH4
emissions from fossil fuel combustion, and 67 percent of N2O
emissions from fossil fuel combustion, respectively. Fuel
purchased in the U.S. for international aircraft and marine
travel accounted for an additional 108.8 Tg CO2 in 2007;
these emissions are recorded as international bunkers and are
not included in U.S. totals according to UNFCCC reporting
protocols. Among domestic transportation sources, light duty
vehicles  (including passenger cars and light-duty trucks)
represented 61 percent of CO2 emissions, medium- and
heavy-duty trucks 22 percent, commercial aircraft 8 percent,
and other sources 10 percent. See Table 3-12 for a detailed
breakdown of CO2 emissions by mode and fuel type.
    From 1990 to 2007, transportation emissions rose by 29
percent due, in large part, to increased demand for travel and
the stagnation of fuel efficiency across the U.S. vehicle fleet.
The number of vehicle miles traveled by light-duty motor
vehicles (passenger cars and light-duty trucks) increased
40 percent from 1990 to 2007, as a result of a confluence
of factors including population growth, economic growth,
urban sprawl, and low fuel prices over much of this period.
A similar set of social  and economic trends has  led to a
significant increase in air travel and freight transportation
by both air and road modes during the time series.
    Almost all  of the energy consumed for transportation
was supplied by petroleum-based products, with more than
half being related to gasoline consumption in automobiles
and other highway vehicles. Other fuel uses, especially diesel
fuel for freight trucks and jet fuel for aircraft, accounted for
the remainder. The primary driver of transportation-related
emissions was  CO2 from fossil fuel combustion, which
increased by  29 percent from  1990 to 2007. This rise in
CO2 emissions, combined with an increase in HFCs from
virtually no emissions in 1990 to 67.0 Tg CO2 Eq.  in 2007,
led to an increase in overall emissions from transportation
activities of 28 percent.

    Fossil Fuel  Combustion C02 Emissions
    from Transportation
    Domestic transportation CO2 emissions increased by
27 percent (404.7 Tg CO2 Eq.) between 1990 and 2007, an
annualized increase of 1.5 percent. Since 2005, the growth
rate of emissions has slowed considerably; transportation
CO2 emissions increased by just 0.3 percent in total between
2005 and 2007. Almost all of the energy consumed by the
transportation sector is  petroleum-based, including motor
gasoline, diesel fuel, jet fuel, and residual oil. Transportation
sources also produce CFLj and N2O;  these emissions are
included in Table 3-13 and Table 3-14  in the "Mobile
Combustion" section. Annex 3.2 presents total emissions
from all transportation and mobile sources, including CO2,
N20, CFl4, and HFCs.
    Carbon dioxide emissions from passenger cars and light-
duty trucks totaled 1,147.0 Tg CO2 Eq. in 2007, an increase
of 21 percent (197.5 Tg CO2  Eq.) from 1990. CO2 emissions
from passenger cars and light-duty trucks peaked at 1,181.3 Tg
CO2 Eq.in 2004, and since then have declined about 3 percent.
Over the 1990s through  early this decade, growth in vehicle
3-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 3-12: C02 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg C02 Eq.)a
  Fuel/Vehicle Type
  1990
  1995
  2000
  2005
  2006
  2007
  Gasoline
    Passenger Cars
    Light-Duty Trucks
    Medium- and Heavy-Duty Trucks"
    Buses
    Motorcycles
    Recreational Boats
  Distillate Fuel Oil (Diesel)
    Passenger Cars
    Light-Duty Trucks
    Medium- and Heavy-Duty Trucks"
    Buses
    Rail
    Recreational Boats
    Ships and Other Boats
    International Bunker Fuels0
  Jet Fuel
    Commercial Aircraft
    Military Aircraft
    General Aviation Aircraft
    International Bunker Fuels0
  Aviation Gasoline
    General Aviation Aircraft
  Residual Fuel Oil
    Ships and Other Boatsd
    International Bunker Fuels0-"
  Natural Gas
    Passenger Cars
    Light-Duty Trucks
    Buses
    Pipelines
  LPG
    Light-Duty Trucks
    Medium- and Heavy-Duty Trucks"
    Buses
  Electricity
    Rail
  982.7
  621.0
  308.9
   38.7
    0.3
    1.7
   12.1
  261.2
    7.8
   11.3
  188.3
    7.9
   35.1
    1.9
    8.8
   11.6
  176.2
  135.5
   34.4
    6.4
   46.4
    3.1
    3.1
   23.7
   23.7
   56.4
   36.2
   36.2
    1.4
    0.5
    0.8

    3.0
    3.0
1,038.9
  597.0
  389.9
   35.8
    0.4
    1.8
   14.1
  315.9
    7.7
   14.7
  234.9
    8.6
   39.2
    2.3
    8.6
    9.2
  170.9
  141.6
   23.9
    5.4
   51.2
    2.7
    2.7
   30.5
   30.5
   41.2
   38.6

    "
    0.1
   38.5
    1.1
    0.5
    0.5

    3.0
    3.0
1,135.7
  639.9
  446.0
   36.0
    0.4
    1.8
   11.6
  394.7
    3.6
   19.8
  305.1
   10.1
   41.7
    2.7
   11.7
    6.3
  196.1
  166.0
   20.7
    9.3
   57.7
    2.5
    2.5
   34.9
   34.9
   35.0
   35.6


    0.4
   35.2
    0.7
    0.4
    0.2
    3.4
 1181.1
  654.2
  476.0
   34.7
    0.4
    1.6
   14.2
  453.0
    4.2
   25.5
  356.5
   10.6
   45.1
    3.1
    8.0
    9.3
  189.9
  158.2
   17.8
   13.9
   56.4
    2.4
    2.4
   20.2
   20.2
   45.8
   33.2
    0.8
   32.4
    1.7
    1.3
    0.4
     +
    4.7
    4.7
1,169.7
  630.3
  487.9
   35.3
    0.4
    1.9
   14.0
  464.7
    4.1
   26.4
  365.4
   10.9
   47.3
    3.2
    7.4
    8.7
  185.0
  153.9
   16.1
   15.0
   54.6
    2.3
    2.3
   24.1
   24.1
   47.2
   33.5
    0.8
   32.6
    1.6
    1.2
    0.5
     +
    4.5
    4.5
1,166.7
  620.9
  493.9
   35.6
    0.4
    2.0
   13.8
  470.6
    4.1
   26.9
  371.3
   10.9
   46.0
    3.3
    8.1
    8.1
  185.3
  153.6
   15.8
   15.8
   52.7
    2.2
    2.2
   25.6
   25.6
   47.9
   35.4
    0.8
   34.6
    1.6
    1.2
    0.5
     +
    4.8
    4.8
  Total
  Total (Including Bunkers)0
1,487.5
1,601.7
1,703.3
1,803.7
                               1,902.7
1,886.2     1,885.4     1,892.2
                1,997.6    1,995.9     2,000.9
  + Less than 0.05 Tg C02 Eq.
  aThis table does not include emissions from non-transportation mobile sources, such as agricultural equipment and construction/mining equipment;
   it also does not include emissions associated with electricity consumption by pipelines or lubricants used in transportation.
  b Includes medium- and heavy-duty trucks over 8,500 Ibs.
  c Official estimates exclude emissions from the combustion of both aviation and marine international bunker fuels; however, estimates including
   international bunker fuel-related emissions are presented for informational purposes.
  11 Fluctuations in emission estimates from the combustion of residual fuel oil are associated with fluctuations in reported fuel consumption and may reflect
   data collection problems.
  Note: Totals may not sum due to independent rounding.
                                                                                                                   Energy  3-15

-------
travel substantially outweighed improvements in vehicle fuel
economy; however, the rate of Vehicle Miles Traveled (VMT)
growth slowed considerably starting in 2005 while average
vehicle fuel economy increased. Among new vehicles sold
annually, average fuel economy gradually declined from 1990
to 2004 (Figure 3-11), reflecting substantial growth in sales of
light-duty trucks—in particular, growth in the market share
of sport utility vehicles—relative to passenger cars (Figure
3-12). New vehicle fuel economy improved beginning in 2005,
largely due to higher light-duty truck fuel economy standards,
which have risen each year since 2005. The overall increase in
fuel economy is also due to a slightly lower light-duty truck
market share, which peaked in 2004 at 52 percent and declined
to 48 percent in 2007.
    Medium- and heavy-duty truck11 CO2 emissions
increased by 79 percent (179.9 Tg  CO2 Eq.) from 1990 to
2007, representing the largest percentage increase of any
major transportation mode. This increase was largely due to
a substantial increase in truck freight movement, as medium-

Figure 3-11
   Sales-Weighted Fuel Economy of New Passenger Cars
           and Light-Duty Trucks, 1990-2007
    25-
    24-
    23-
  = 22-
  _o
  I 21-
  » 20'

    18-
    17-
    16-
    15-
Figure3-12
            Sales of New Passenger Cars and
              Light-Duty Trucks, 1990-2007
and heavy-duty truck VMT increased by 55 percent. Carbon
dioxide from the domestic operation of commercial aircraft
increased by 13  percent (18.2 Tg CO2  Eq.) from 1990 to
2007, well below the growth in travel activity. The operational
efficiency of commercial aircraft improved substantially
because of a growing percentage of seats occupied per flight,
improvements in the fuel efficiency of new aircraft, and the
accelerated retirement of older, less fuel  efficient aircraft.
Across all categories of aviation,12 CO2 emissions increased
by 5.1  percent (9.0 Tg CO2 Eq.) between 1990 and 2007.
This overall increase includes a 57 percent (18.6 Tg CO2 Eq.)
decrease in emissions from domestic military operations. For
further information on all greenhouse gas emissions from
transportation sources, please refer to Annex 3.2.

    Fossil Fuel Combustion CH4 and N20 Emissions
    from Mobile Sources
    Mobile combustion  includes emissions of CH4 and
N2O from all transportation  sources identified in the U.S.
Inventory with the exception of pipelines,  which are
stationary; mobile sources also include non-transportation
sources such as construction/mining equipment, agricultural
equipment, vehicles used off-road, and other sources (e.g.,
snowmobiles, lawnmowers, etc.). Annex 3.2 includes a
11 Includes "medium- and heavy-duty trucks" fueled by gasoline, diesel
and LPG.
12 Includes consumption of jet fuel and aviation gasoline. Does not include
aircraft bunkers, which are not accounted for in national emission totals.
3-16   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
Table 3-13: CH4 Emissions from Mobile Combustion (Tg C02 Eq.)
  Fuel/Vehicle Type3
1990
1995
2000
2005
2006
2007
  Gasoline On-Road                                  4.2
    Passenger Cars                                  2.6
    Light-Duty Trucks                                1.4
    Medium- and Heavy-Duty Trucks and Buses          0.2
    Motorcycles                                      +
  Diesel On-Road                                     +
    Passenger Cars                                   +
    Light-Duty Trucks                                 +
    Medium- and Heavy-Duty Trucks and Buses           +
  Alternative Fuel On-Road                            +
  Non-Road                                         0.5
    Ships and Other Boats                            0.1
    Rail                                            0.1
    Agricultural Equipment"                           0.1
    Construction/Mining Equipment0                     +
    Aircraft                                         0.2
    Otherd                                          0.1
                3.8
                2.1
                1.4
                0.2


                 j


                0.51
                0.1
                0.1
                0.1
                0.1
                0.1
                0.1
                2.8
                1.6
                1.1
                0.6 1
                0.1
                0.1
                0.1
                0.1
                0.2
                0.1
                1.9
                1.1
                0.7
                0.1
                0.1
                0.6
                0.1
                0.1
                0.1
                0.1
                0.2
                0.1
            1.7
            1.0
            0.6
            0.1
            0.1
            0.6
            0.1
            0.1
            0.1
            0.1
            0.1
            0.1
            1.6
            0.9
            0.6
            0.1
            0.1
            0.6
            0.1
            0.1
            0.1
            0.1
            0.1
            0.1
  Total
  4.7
  4.3
  3.4
  2.5
  2.4
  2.3
  + Less than 0.05 Tg C0? Eq.
  aSee 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.
  c Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from trucks that are used off-road in construction.
  11 "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.
summary of all emissions from both transportation  and
mobile sources. Table 3-13 and Table 3-14 provide CK4 and
N2O emission estimates in Tg CO2 Eq.13

    Mobile combustion was responsible for a small portion
of national CH4 emissions (0.4 percent) but was the second
largest source of U.S. N2O emissions (10 percent). From 1990
to 2007, mobile source CFLj emissions declined by 52 percent,
to 2.3 Tg CO2 Eq. (109 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 31 percent, to 30.1 Tg CO2
Eq. (97 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 45 percent decrease in mobile source N2O emissions from
             Figure 3-13
                       Mobile Source CH,, and N,0 Emissions
                 60-

                 50-

                 40-

                 30-

                 20-

                 10-

                  0-
                            CH4
                                                  i—  CM eo
             1998 to 2007 (Figure 3-13). Overall, CFLj and N2O emissions
             were predominantly from gasoline-fueled passenger cars and
             light-duty trucks.
13 See Annex 3.2 for a complete time series of emission estimates for 1990
through 2007.
                                                                                                          Energy  3-17

-------
Table 3-14: N20 Emissions from Mobile Combustion (Tg C02 Eq.)
  Fuel/Vehicle Type3
1990
1995
2000
2005
2006
2007
  Gasoline On-Road                               40.1           49.8          48.4
    Passenger Cars                               25.4           26.9          25.2
    Light-Duty Trucks                              14.1           22.1          22.4
    Medium-and Heavy-Duty Trucks and Buses          0.6            0.71         0.9

  Diesel On-Road                                  0.2            0.3           0.3
    Passenger Cars                                 +1          +1          +
    Light-Duty Trucks                                +1          +1          +
    Medium-and Heavy-Duty Trucks and Buses          0.2            0.2           0.3
  Alternative Fuel On-Road                          0.11         0.11         0.1
  Non-Road                                       3.4            3.61         4.0
    Ships and Other Boats                           0.4!         0.4!         0.5

    Agricultural Equipment"                          0.2!         0.31         0.3
    Construction/Mining Equipment0                   0.3            0.41         0.4

    Otherd                                        0.4l         O.sl         0.5
                                          32.1
                                          17.7
                                          13.6
                                           0.8
                                            +
                                           0.3
                                           0.3
                                           0.2
                                           4.1
                                           0.4
                                           0.4
                                           0.4
                                           0.5
                                           1.9
                                           0.6
                                       29.0
                                       15.7
                                       12.5
                                        0.7
                                         +
                                        0.3
                                        0.3
                                        0.2
                                        4.1
                                        0.4
                                        0.4
                                        0.4
                                        0.5
                                        1.8
                                        0.6
                                   25.5
                                   13.7
                                   11.1
                                    0.7
                                     +
                                    0.3
                                    0.3
                                    0.2
                                    4.1
                                    0.4
                                    0.4
                                    0.4
                                    0.5
                                    1.8
                                    0.6
  Total
43.7
53.7
52.8
36.7
33.5
30.1
  + Less than 0.05 Tg C0? Eq.
  aSee 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.
  c Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from trucks that are used off-road in construction.
  11 "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.
CO2 from Fossil Fuel Combustion


Methodology
    The methodology used by the United States for
estimating CO2 emissions from fossil fuel  combustion is
conceptually similar to the approach recommended by the
IPCC for countries that intend to develop detailed, sectoral-
based emission estimates (IPCC 2006). A detailed description
of the U.S. methodology is presented in Annex 2.1, and is
characterized by the following steps:
1.   Determine total fuel consumption by fuel type and sector.
    Total fossil fuel consumption for each year is estimated
    by aggregating consumption data by end-use sector (e.g.,
    commercial, industrial,  etc.), primary fuel type  (e.g.,
    coal, petroleum, gas), and secondary fuel category (e.g.,
    motor gasoline, distillate fuel oil, etc.). Fuel consumption
    data for the United States were obtained directly from
    the Energy Information Administration (EIA) of the
    U.S. Department of Energy (DOE), primarily from the
    Monthly Energy Review and published supplemental
    tables on petroleum product detail (EIA 2008b). The
                EIA does not include territories in its national energy
                statistics, so fuel consumption data for territories were
                collected separately from Grillot (2008).14

                For consistency of reporting, the IPCC has recommended
                that countries report energy data using the International
                Energy Agency (IEA) reporting convention and/or IEA
                data. Data in the IEA format are presented "top down"—
                that is, energy consumption for fuel types and categories
                are estimated from energy production data (accounting for
                imports, exports, stock changes, andlosses). The resulting
                quantities are referred to as "apparent consumption."
                The data collected in the United  States  by EIA on an
                annual basis and used in this Inventory are predominantly
                from mid-stream  or conversion energy  consumers
                such as refiners and  electric power generators. These
                annual surveys are supplemented with end-use energy
                consumption surveys, such as the Manufacturing Energy
                Consumption Survey, that are conducted on a  periodic
            14Fuel 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 51 Tg CO2
            Eq. in 2007.
3-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
    basis (every 4 years). These consumption data sets help
    inform the annual surveys to arrive at the national total
    and sectoral breakdowns for that total.15
    It is  also important to note that U.S. fossil fuel energy
    statistics are generally presented using  gross calorific
    values  (GCV)  (i.e., higher heating  values). Fuel
    consumption activity data presented here have not been
    adjusted to correspond to international standards, which
    are to report energy statistics in terms of net calorific
    values (NCV) (i.e., lower heating values).16
2.  Subtract uses accounted for in the  Industrial
    Processes chapter. Portions  of the fuel consumption
    data for seven fuel categories—coking  coal, distillate
    fuel, industrial  other coal, petroleum coke, natural
    gas,  residual fuel oil, and other oil —were reallocated
    to the Industrial Processes chapter,  as they were
    consumed  during non-energy related industrial
    activity. To make these adjustments, additional data
    were collected from AISI (1995 through 2008), CVR
    Energy (2008), Corathers (2008), U.S. Census Bureau
    (2008), EIA (2008g), EIA (2001), Smith, G. (2007),
    USGS  (2008),  USGS  (1995,  1998, 2000 through
    2002), USGS (1995), USGS (1991a through 2007a),
    USGS (1991b through 2007b), USGS (1991 through
    2005), and USGS (1995 through 2006).17
3.  Adjust for biofuels, conversion offossilfuels, and exports
    ofCO2. Fossil fuel consumption estimates are adjusted
    downward to exclude (1) fuels with biogenic origins,
    (2) fuels created from other fossil fuels, and (3) exports
    of CO2. Fuels with biogenic origins are  assumed to
    result in no net CO2 emissions, and must be subtracted
    from fuel consumption estimates. These fuels include
    ethanol added to motor gasoline and biomass gas used
    as natural gas. Synthetic natural gas is created from
    industrial coal, and is currently included in EIA statistics
    for both coal and natural gas. Therefore, synthetic natural
15 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.
16 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.
17 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.
    gas is subtracted from energy consumption statistics.18
    Since October 2000, the Dakota Gasification Plant has
    been exporting CO2 to Canada by pipeline. Since this
    CO2 is  not emitted to the atmosphere in the United
    States, energy used to produce this CO2 is subtracted
    from  energy consumption statistics. To make these
    adjustments, additional data for ethanol and biogas were
    collected from EIA (2008b) and data for synthetic natural
    gas were collected from EIA (2008e), and data for CO2
    exports were collected from the Dakota Gasification
    Company (2006), Fitzpatrick (2002), Erickson (2003),
    and EIA (2006).
4.   Adjust Sectoral Allocation of Distillate Fuel Oil  and
    Motor Gasoline. EPA had conducted a separate bottom-up
    analysis of transportation fuel consumption based on the
    Federal Highway Administration's (FHWA) VMT  that
    indicated that the amount of distillate and motor gasoline
    consumption allocated to the transportation sector in the EIA
    statistics should be adjusted. Therefore, for these estimates,
    the transportation sector's distillate fuel and motor gasoline
    consumption was adjusted upward to match the value
    obtained from the  bottom-up analysis based on VMT.
    As the total distillate consumption estimate from EIA is
    considered to be accurate at the national level, the distillate
    consumption totals for the residential, commercial, and
    industrial sectors were adjusted downward proportionately.
    Similarly, as the total motor gasoline consumption estimate
    is considered to be accurate at the national level, the motor
    gasoline consumption totals for commercial and industrial
    sectors were adjusted downward proportionately. The data
    sources  used in the bottom-up analysis of transportation
    fuel consumption include AAR (2008), Benson (2002
    through 2004), DOE (1993 through 2008), HA (2008a),
    EIA (1991 through 2005), EPA (2006), and FHWA (1996
    through 2008).
5.   Adjust for fuels consumed for non-energy uses.  U.S.
    aggregate energy statistics include consumption of fossil
    fuels  for non-energy purposes. These are fossil fuels
    that are manufactured into plastics, asphalt, lubricants,
    or other products. Depending  on the end-use, this can
    result in storage of some or all  of the C contained in the
    fuel for a period of time. As the emission pathways of
    C used for non-energy purposes are vastly different than
    fuel combustion (since the C in these fuels ends up in
18 These adjustments are explained in greater detail in Annex 2.1.
                                                                                                    Energy  3-19

-------
    products instead of being combusted), these emissions
    are estimated separately in the Carbon Emitted and
    Stored in Products from Non-Energy Uses of Fossil
    Fuels section in this chapter. Therefore, the amount of
    fuels used for non-energy purposes was subtracted from
    total fuel consumption. Data on non-fuel consumption
    was provided by El A (2008b).
6.   Subtract consumption of international bunker fuels.
    According to the UNFCCC reporting  guidelines
    emissions  from international transport activities, or
    bunker fuels, should not be included in national totals.
    U.S. energy consumption statistics include these bunker
    fuels (e.g., distillate fuel oil, residual fuel oil, and jet fuel)
    as part of consumption by the transportation end-use
    sector, however, so emissions from international transport
    activities were calculated separately following the same
    procedures  used  for emissions from consumption of
    all  fossil fuels (i.e., estimation of consumption, and
    determination of C content).19 The Office of the Under
    Secretary of Defense (Installations and Environment) and
    the Defense Energy Support Center (Defense Logistics
    Agency) of the U.S. Department of Defense  (DoD)
    (DESC 2008) supplied data on military jet fuel and marine
    fuel use. Commercial jet fuel use was obtained from FAA
    (2006); residual and distillate fuel use for civilian marine
    bunkers was obtained from DOC (1991 through 2008) for
    1990 through 2001, and 2007, and DHS (2008) for 2003
    through 2006. Consumption of these fuels was subtracted
    from the corresponding fuels in the transportation end-use
    sector. Estimates of international bunker fuel emissions
    for the United States are discussed in detail later in the
    International Bunker Fuels section of this chapter.
7.   Determine the total C content of fuels consumed. Total C
    was estimated by multiplying the amount of fuel consumed
    by  the amount of C in each fuel. This total C estimate
    defines the maximum amount of C that could potentially
    be released to the atmosphere if all of the C in each fuel
    was converted to  CO2.  The C content coefficients used
    by the United States were obtained from EIA's Emissions
    of Greenhouse Gases in  the United States 2007 (EIA
    2008c) and EIA's Monthly Energy Review and published
    supplemental tables on petroleum product detail EIA (EIA
    2008b). They are presented in Annexes 2.1 and 2.2.
8.   Estimate CO2 Emissions. Total CO2 emissions are the
    product of the adjusted energy consumption (from the
    previous methodology steps 1 through 6), the C content
    of the fuels consumed, and the fraction of C that is
    oxidized. The fraction oxidized was assumed to be 100
    percent for petroleum, coal, and natural gas based on
    guidance in IPCC (2006) (see Annex 2.1).
9.   Allocate transportation emissions  by vehicle type. This
    report provides a more detailed accounting of emissions
    from  transportation because it is such a large consumer
    of fossil fuels in the United States. For fuel types other
    than jet fuel, fuel  consumption data by vehicle type and
    transportation mode were used to allocate emissions by
    fuel type calculated for the transportation end-use sector.
•   For on-road vehicles, annual estimates of combined
    motor gasoline and diesel fuel consumption by vehicle
    category were obtained from FHWA (1996  through
    2008); for  each vehicle category, the percent gasoline,
    diesel, and other (e.g., CNG, LPG) fuel consumption are
    estimated using data from DOE (1993 through 2008).
•   For non-road vehicles, activity data were obtained from
    AAR (2008), APTA (2007 through 2008), BEA (1991
    through 2008), Benson (2002 through 2004), DOE
    (1993 through 2008), DESC (2008), DOC (1991 through
    2008), DOT (1991 through 2007), EIA (2008a), EIA
    (2008d), EIA (2007), EIA (2002), EIA  (1991  through
    2005), EPA (2006), FAA (2008), and Gaffney (2007).
•   For jet fuel used by aircraft, CO2 emissions  were calculated
    directly based on reported consumption of fuel as reported
    by EIA, and allocated to commercial aircraft using flight-
    specific fuel consumption data from the Federal  Aviation
    Administration's (FAA) System for assessing Aviation's
    Global Emission (SAGE) model.20 Allocation to domestic
    general aviation was made using FAA Aerospace Forecast
    data, and allocation to domestic military uses was made
    using DoD data (see Annex 3.7)
    Heat  contents and densities were obtained from EIA
(2008a) and USAF (1998).21
19 See International Bunker Fuels section in this chapter for a more detailed
discussion.
20FAA's System for assessing Aviation's Global Emissions (SAGE)
model develops aircraft fuel burn and emissions for all commercial flights
globally in a given year. The SAGE model dynamically models aircraft
performance, fuel burn, and emissions, and is based on actual flight-by-
flight aircraft  movements. See .
21 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.
3-20  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Box 3-2: Carbon Intensity of U.S. Energy Consumption

       Fossil fuels are the dominant source of energy in the United States, and C02 is emitted as a product from their combustion. Useful
  energy, however, is generated in the United States from many other sources that do not emit C02 in the energy conversion process, such as
  renewable (i.e.,  hydropower, biofuels, geothermal, solar, and wind) and nuclear sources.22
       Energy-related C02 emissions can  be reduced by not only lowering total energy consumption (e.g., through conservation measures)
  but also by lowering the C intensity of the energy sources employed (e.g., fuel switching from coal to natural gas). The amount of C emitted
  from the combustion of fossil fuels is dependent upon the C content of the fuel and the fraction of that C that is oxidized. Fossil fuels vary in
  their average C content, ranging from about 53 Tg C02 Eq./QBtu for natural gas to upwards of 95 Tg C02 Eq./QBtu for coal and petroleum
  coke.23 In general, the C content per unit of energy of fossil fuels is the highest for coal products, followed by petroleum, and then natural gas.
  Other sources of energy, however, may be directly or indirectly C neutral (i.e., 0 Tg C02 Eq./Btu).  Energy generated from nuclear and many
  renewable sources do not result in direct emissions of C02. Biofuels such as wood and ethanol are also considered to be C neutral; although
  these fuels do emit C02, in the long run  the C02 emitted from biomass consumption does not increase atmospheric C02  concentrations if
  the biogenic  C emitted is offset by the growth  of new  biomass.24 The overall C intensity of the U.S. economy is thus dependent upon the
  quantity and  combination of fuels and other energy sources employed to meet demand.
       Table 3-15 provides a time series of the C intensity for each sector of the U.S. economy. The time series incorporates only the energy
  consumed from the direct combustion of fossil fuels in each  sector. For example,  the C intensity for the residential sector does not include
  the energy from or emissions related to the consumption of electricity for lighting or wood for heat. Looking only at this direct consumption
  of fossil fuels, the residential sector exhibited the lowest C intensity, which is related to the large percentage of its energy derived from natural
  gas for heating. The C intensity of the commercial sector has predominantly declined  since 1990 as commercial businesses shift away
  from petroleum  to natural gas. The industrial sector was more dependent on petroleum and coal than either the  residential or commercial
  sectors, and thus had higher C intensities over this period. The C intensity of the transportation sector was closely related to the C content
  of petroleum products  (e.g., motor gasoline and jet fuel, both around 70 Tg C02 Eq./EJ), which were the primary  sources  of energy. Lastly,
  the electricity generation sector had the highest C intensity due to its heavy reliance on coal for generating electricity.


  Table 3-15: Carbon Intensity from Direct  Fossil Fuel Combustion by Sector (Tg  C02 Eq./QBtu)
  Sector	1990	1995	2000	2005       2006       2007
  Residential3                                          57.4           56.7           56.7            56.6        56.6       56.3
  Commercial3                                         59.3           57.8           57.1            57.6        57.2       57.0
  Industrial3                                           63.7           62.7           62.5            64.0        64.2       63.9
  Transportation3                                       71.0           71.0           71.0            71.1        71.1       71.1
  Electricity Generation"                                86.7           86.0           85.6            85.0        84.6       84.0
  U.S. Territories0	74J	74J	73.2	74.6        74.6       74.7
  All Sectors0	72J	72.2	72J	73.1        73.1       72.8
  aDoes not include electricity or renewable energy consumption.
  b Does not include electricity produced using nuclear or renewable energy.
  c Does not include nuclear or renewable energy consumption.
  Note: Excludes non-energy fuel use emissions and consumption.

       In contrast to Table 3-15, Table 3-16 presents C intensity values that incorporate energy consumed from all sources (i.e., fossil fuels,
  renewables, and nuclear). In addition, the emissions related to the generation of electricity have been attributed to both electricity generation
  and the end-use sectors in which that electricity was eventually consumed.25 This table, therefore, provides a more complete picture of
  22 Small quantities of C02, however, are released from some geologic formations tapped for geothermal energy. These emissions are included with fossil fuel
  combustion emissions from the electricity generation. Carbon dioxide emissions may also be generated from upstream activities (e.g., manufacture of the
  equipment) associated with fossil fuel and renewable energy activities, but are not accounted for here.
  23 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.
  24 Net carbon fluxes from changes in biogenic carbon reservoirs in wooded or croplands are accounted for in the estimates for Land  Use, Land-Use Change,
  and Forestry.
  25 In other words, the emissions from the generation of electricity are intentionally double counted by attributing them both to electricity generation and the
  end-use sector in which electricity consumption occurred.
                                                                                                                   Energy  3-21

-------
Box 3-2: Carbon Intensity of U.S. Energy Consumption (continued)
  the actual C intensity of each end-use sector per unit of energy consumed. The transportation end-use sector in Table 3-16 emerges as the
  most C intensive when all sources of energy are included, due to its almost complete reliance on petroleum products and relatively minor
  amount of biomass-based fuels used, such as ethanol. The "other end-use sectors" (i.e., residential, commercial, and industrial) use significant
  quantities of biofuels such as wood, thereby lowering the overall C intensity. The C intensity of the electricity generation sector differs greatly
  Table 3-16: Carbon Intensity from All Energy Consumption by Sector (Tg C02 Eq./QBtu)
  Sector
              1995
              2000
              2005
          2006
          2007
  Transportation3
  Other End-Use Sectors3'1
  Electricity Generation0
  All Sectors"
                            70.6
                            57.7
                            59.9

                             70.1
                             58.1
                             59.9
                         69.8
                         57.5
                         58.9
                     69.4
                     57.5
                     59.3
61.1
60.3
61.4
61.6
61.1
61.0
  'Includes electricity (from fossil fuel, nuclear, and renewable sources) and direct renewable energy consumption.
  b Other End-Use Sectors includes the residential, commercial, and industrial sectors.
  c Includes electricity generation from nuclear and renewable sources.
  11 Includes nuclear and renewable energy consumption.
  Note: Excludes non-energy fuel use emissions and consumption.
  from the scenario in Table 3-15, where only the energy consumed from the
  direct combustion of fossil fuels was included. This difference is due almost
  entirely to the inclusion of electricity generation from nuclear and hydropower
  sources, which do not emit C02.
      By comparing the  values in Table 3-15 and Table 3-16,  a few
  observations can be made. The use of renewable and nuclear energy sources
  has resulted in a significantly lower C intensity of the U.S. economy. Over the
  eighteen-year period of 1990 through 2007, however, the C intensity of U.S.
  energy consumption has been fairly constant, as the proportion of renewable
  and nuclear energy technologies have not changed significantly. Per capita
  energy consumption has fluctuated, but is now roughly equivalent to levels
  in 1990 (see Figure 3-14). Due to a  general shift from a manufacturing-
  based economy to a service-based economy, as well as overall increases
  in efficiency, energy consumption and energy-related C02  emissions per
  dollar of gross domestic product (GDP) have both declined since 1990
  (BEA 2008).
                  Figure 3-14
                   U.S. Energy Consumption and Energy-Related C02
                       Emissions Per Capita and Per Dollar GDP
                            Energy
                            Consumption/
                            Capita
     Uncertainty
    For estimates of CO2 from fossil fuel combustion, the
amount of CO2 emitted is directly related to the amount of
fuel consumed, the fraction of the fuel that is oxidized, and
the carbon content of the fuel. Therefore, a careful accounting
of fossil fuel consumption by fuel  type, average carbon
contents of fossil fuels consumed, and production of fossil
fuel-based products with long-term carbon storage should
yield an accurate estimate of CO2 emissions.
    Nevertheless, there are uncertainties in the consumption
data, carbon content of fuels and products, and carbon oxidation
efficiencies. For example, given the same primary fuel type
(e.g., coal, petroleum, or natural gas), the amount of carbon
contained in the fuel per unit of useful energy can vary. For
            the United States, however, the impact of these uncertainties
            on overall CO2 emission estimates is believed to be relatively
            small. See, for example, Marland and Pippin (1990).
                Although statistics of total fossil fuel and other energy
            consumption  are relatively accurate, the allocation of this
            consumption to individual end-use sectors (i.e., residential,
            commercial, industrial, and transportation) is less certain. For
            example, for some fuels the sectoral allocations are based on
            price rates (i.e., tariffs), but a commercial establishment may
            be able to negotiate an industrial rate or a small industrial
            establishment may end up paying an industrial rate, leading
            to a misallocation  of  emissions. Also,  the deregulation of
            the natural gas industry and the more recent deregulation of
            the electric  power  industry have likely led to some minor
3-22  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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problems in collecting accurate energy statistics as firms in
these industries have undergone significant restructuring.
    To calculate the total CO2 emission estimate from energy-
related fossil fuel combustion, the amount of fuel used in these
non-energy production processes were subtracted from the
total fossil fuel consumption for 2007.  The amount of CO2
emissions resulting from non-energy related fossil fuel use
has been calculated separately and reported in  the Carbon
Emitted  from Non-Energy Uses of Fossil Fuels section of
this report. These factors all contribute  to the uncertainty in
the CO2  estimates. Detailed discussions on the uncertainties
associated with C emitted from Non-Energy Uses of Fossil
Fuels can be found within that section of this chapter.
    Various sources of uncertainty surround the estimation
of emissions  from international bunker fuels, which  are
subtracted from the U.S. totals (see the detailed  discussions
on these uncertainties provided in the International Bunker
Fuels section of this chapter). Another source of uncertainty
is fuel consumption by U.S. territories. The United  States
does not collect energy statistics for its territories  at  the
same level of detail as for the fifty states and the District of
Columbia. Therefore, estimating both emissions and bunker
fuel consumption by these territories is difficult.
    Uncertainties in the emission estimates presented above
also result from the data used to allocate CO2 emissions from
the transportation end-use sector to individual vehicle types
and transport modes. In many cases, bottom-up estimates of
fuel consumption by vehicle type do not match aggregate
fuel-type estimates from EIA. Further research is planned to
improve the allocation into detailed transportation end-use
sector  emissions. In particular, residual fuel consumption
data for marine vessels are highly uncertain, as shown by the
large fluctuations in emissions that do not mimic changes in
other variables such as shipping ton miles.
    The uncertainty analysis was performed by primary fuel
type for each end-use sector, using the IPCC-recommended
Tier 2 uncertainty estimation methodology, Monte Carlo
Simulation technique, with @RISK software. For  this
uncertainty estimation, the inventory estimation model for
CO2 from  fossil  fuel combustion was integrated with  the
relevant  variables from the inventory estimation model for
International Bunker Fuels, to realistically characterize the
interaction (or endogenous correlation) between the variables
of these two models. About 150 input variables were modeled
for CO2 from energy-related Fossil Fuel Combustion
(including about 10 for non-energy fuel consumption and
about 20 for International Bunker Fuels).
    In developing the uncertainty estimation model, uniform
distributions were assumed for all activity-related input
variables and emission factors, based on the SAIC/EIA
(2001) report.26 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 (2001) and on
conversations with various agency personnel.27
    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).28 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 3-17. Fossil fuel combustion CO2
emissions in 2007 were estimated to be between 5,622.3 and
6,029.3 Tg CO2 Eq. at a 95 percent confidence level. This
indicates a range of 2 percent below to 6 percent above the
2007 emission estimate of 5,735.8 Tg CO2 Eq.
26 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.
27 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.
28 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  3-23

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Table 3-17: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from
Energy-related Fossil Fuel Combustion by Fuel Type and Sector (Tg C02 Eq. and Percent)
  Fuel/Sector
2007 Emission Estimate
     (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                      (%)

Coal"
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas"
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum"
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Total (excluding Geothermal)"
Geothermal
Total (including Geothermal)"'"

2,086.5
0.6
6.8
107.4
NE
1,967.6
4.1
1,216.5
256.9
163.4
385.6
35.4
373.8
1.4
2,432.4
83.2
44.2
352.5
1,852.0
55.3
45.3
5,735.4
0.4
5,735.8
Lower Bound
2,015.7
0.5
6.4
103.3
NE
1,890.6
3.6
1,226.2
249.7
158.9
396.1
34.4
363.1
1.2
2,279.1
78.8
42.1
306.4
1,710.8
53.3
41.8
5,621.9
NE
5,622.3
Upper Bound
2,284.1
0.7
7.8
125.4
NE
2,157.3
4.9
1,295.9
275.0
174.9
436.0
37.9
393.0
1.7
2,553.7
87.4
46.0
411.5
1,947.9
58.8
50.4
6,028.9
NE
6,029.3
Lower Bound
-3%
-6%
-5%
-4%
NA
-4%
-12%
+ 1%
-3%
-3%
+ 3%
-3%
-3%
-12%
-6%
-5%
-5%
-13%
-8%
-4%
-8%
-2%
NE
-2%
Upper Bound
+9%
+ 15%
+ 15%
+ 17%
NA
+ 10%
+ 19%
+7%
+7%
+7%
+ 13%
+7%
+5%
+ 17%
+5%
+5%
+4%
+ 17%
+5%
+6%
+ 11%
+5%
NE
+6%
  NA (Not Applicable)
  NE (Not Estimated)
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
  b The low and high estimates for total emissions were calculated separately through simulations and, hence, the low and high emission estimates for the
  sub-source categories do not sum to total emissions.
  c Geothermal emissions added for reporting purposes, but an uncertainty analysis was not performed for C02 emissions from geothermal production.
  Note: Totals may not sum due to independent rounding.
QA/QC and Verification
    A source-specific QA/QC plan for CO2 from fossil fuel
combustion was developed and implemented. This  effort
included a Tier 1 analysis, as well as portions of a Tier 2
analysis. The Tier 2 procedures that  were implemented
involved checks specifically focusing on the activity data and
methodology used for estimating CO2 emissions from fossil
fuel combustion in the United States. Emission totals for the
different sectors and fuels were compared and trends were
investigated to determine whether any corrective actions
were needed. Minor corrective actions were taken.
                         Recalculations Discussion
                             Estimates  of CO2 from  the industrial sector have
                         been revised for the years 1990 through 2006 to subtract
                         non-energy related consumption of coal, distillate fuel,
                         and natural gas used in iron and steel and metallurgical
                         coke production. A discussion of the methodology used
                         to estimate non-energy related consumption is contained
                         in the Iron and Steel Production and Metallurgical Coke
                         Production section of the Industrial Processes chapter. In
                         addition,  the Energy Information Administration (EIA
                         2008b)  updated energy consumption data for all years.
3-24  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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These revisions primarily impacted the emission estimates
for 2006. Overall, these changes resulted in an average
annual decrease of 17 Tg CO2 Eq. (0.3 percent) in CO2
emissions from fossil fuel combustion for the period 1990
through 2006.

Planned Improvements
    An analysis is being undertaken to update the carbon
content factors for fossil fuels, as presented in the annexes
of this report. To reduce uncertainty of CO2 from fossil fuel
combustion estimates,  efforts will be taken to work with
El A and other agencies to improve the quality of the U.S.
territories data.  This improvement is not all-inclusive, and
is  part of an ongoing analysis and efforts to continually
improve the CO2 from fossil fuel combustion estimates. In
addition, further expert elicitation may be conducted to better
quantify the total uncertainty associated with emissions from
this source.

CH4 and N20 from Stationary
Combustion

Methodology
    CH4 and N2O emissions  from stationary  combustion
were  estimated by multiplying fossil fuel and  wood
consumption data by emission factors  (by sector and
fuel type). National coal, natural gas, fuel oil, and wood
consumption data were grouped by sector: industrial,
commercial, residential, electricity generation, and
U.S. territories. For  the CH4 and N2O  estimates, fuel
consumption data for coal, natural gas, and fuel oil for the
United States were obtained from EIA's Monthly Energy
Review and unpublished supplemental tables on petroleum
product detail (ElA 2008a). Wood consumption data for
the United States was obtained from EIA's Annual Energy
Review (EIA 2008b). Because the United States does not
include territories in  its national  energy statistics, fuel
consumption data for territories were provided separately
by Grillot (2008).29 Fuel consumption for the industrial
sector was adjusted  to subtract  out  construction and
agricultural use, which is reported under mobile sources.30
Construction and agricultural fuel use was obtained from EPA
(2006). Estimates for wood biomass consumption for fuel
combustion do not include wood wastes, liquors, municipal
solid waste, tires, etc. that are reported as biomass by EIA.
    Emission factors for the four end-use sectors were provided
by the 2006IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC 2006). U.S. territories' emission factors
were estimated using the U.S. emission factors for the primary
sector in which each fuel was combusted.
    More detailed information on  the methodology for
calculating emissions from stationary combustion, including
emission factors and activity data, is provided in Annex 3.1.

Uncertainty
    CH4 emission estimates from stationary sources exhibit
high uncertainty, primarily due to difficulties in calculating
emissions from wood combustion (i.e., fireplaces and wood
stoves). The estimates of CH4 and N2O emissions presented
are based on broad indicators of emissions (i.e., fuel use
multiplied by an  aggregate emission factor  for different
sectors), rather than  specific emission processes (i.e., by
combustion technology and type of emission control).
    An uncertainty analysis  was performed by primary fuel
type for each end-use sector, using the IPCC-recommended
Tier 2 uncertainty estimation methodology, Monte Carlo
Simulation technique, with @RISK software.
    The  uncertainty estimation model for this  source
category  was developed by integrating the CH4 and N2O
stationary source inventory estimation models with the
model for CO2 from fossil fuel combustion to realistically
characterize the interaction (or endogenous  correlation)
between the variables of these three models. A total of 115
input variables were simulated for the uncertainty analysis of
this source category (85 from the CO2 emissions from fossil
fuel combustion inventory estimation model and 30 from the
stationary source inventory models).
    In developing the uncertainty estimation model, uniform
distribution was  assumed  for all activity-related input
variables and N2O emission factors, based on the SAIC/
29U.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.
30 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.
                                                                                                Energy  3-25

-------
EIA (2001) report.31 For these variables, the uncertainty        The uncertainties  associated with the emission
ranges were assigned to the input variables based on the   estimates of CH4 and N2O are greater than those associated
data reported in SAIC/EIA (2001).32 However, the CH4   with estimates of CO2 from fossil fuel combustion, which
emission factors differ from those used by EIA. Since these   mainly rely on the carbon content of the fuel combusted.
factors were obtained from IPCC/UNEP/OECD/IEA (1997),   Uncertainties in both CH4 and N2O estimates are due to the
uncertainty ranges were assigned based on IPCC default   fact that emissions are estimated based on emission factors
uncertainty estimates (IPCC 2000).                          representing only a limited subset of combustion conditions.
    Theresultsof the Tier 2 quantitative uncertainty analysis   For the indirect greenhouse gases, uncertainties are partly
are summarized in Table 3-18. Stationary combustion CH4   due to assumptions concerning combustion technology
emissions in 2007 (including biomass) were estimated to be   ^P68' a§e of equipment, emission factors used, and activity
between 4.3 and 15.1 Tg CO2 Eq. at a 95 percent confidence   ^^ projections.
level. This indicates a range of 34 percent below  to  128
percent above the 2007 emission estimate of 6.6 TgCO2Eq.33   QA/QC 311(1  Verification
Stationary combustion N2O emissions in 2007 (including        A source-specific QA/QC plan for stationary combustion
biomass) were estimated to be between  11.2 and 42.1 Tg   was developed and implemented. This effort included a
CO2 Eq. at a 95 percent confidence level. This indicates a   Tier 1 analysis, as well as portions of a Tier 2 analysis. The
range of 24 percent below to 187 percent above the 2007   Tier 2 procedures that were implemented involved checks
emissions estimate of 14.7 Tg CO2 Eq.                      specifically focusing on the activity data and emission factor
                                                           sources and methodology used for estimating CH4, N2O, and


Table 3-18: Tier 2 Quantitative Uncertainty Estimates for CH4 and N20 Emissions from Energy-Related Stationary
Combustion, Including Biomass (Tg C02 Eq. and Percent)

                                 2007 Emission Estimate           Uncertainty Range Relative to Emission Estimate3
  Source                  Gas          (Tg C02 Eq.)                 (Tg C02 Eq.)                       (%)

Stationary Combustion
Stationary Combustion

CH4
N20

6.6
14.7
Lower Bound
4.3
11.2
Upper Bound
15.1
42.1
Lower Bound
-34%
-24%
Upper Bound
+ 128%
+ 187%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
31 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.
32 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.
33 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.
3-26  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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the indirect greenhouse gases from stationary combustion in
the United States. Emission totals for the different sectors and
fuels were compared and trends were investigated.

Recalculations Discussion
    Historical CH4 and N2O emissions from stationary
sources (excluding CO2) were revised due to a couple of
changes. Slight changes to emission estimates for sectors
are due to revised data from EIA (2008a). This revision is
explained in greater detail in the section on CO2 Emissions
from Fossil Fuel Combustion within this sector. Wood
consumption data from EIA (2008b) were revised for the
residential,  industrial, and electric power sectors. The
combination of the methodological and historical data
changes resulted in an average annual increase of less than
0.1 Tg CO2 Eq. (less than 0.1 percent) in CFLj emissions from
stationary combustion and an average annual decrease of less
than 0.1 Tg CO2 Eq. (0.2 percent) in N2O emissions from
stationary combustion for the period 1990 through 2006.

Planned Improvements
    Several items are being evaluated to improve the CH4
and N2O emission estimates from stationary combustion
and to reduce uncertainty. Efforts will be made to work with
EIA and other  agencies to improve the quality of the U.S.
territories data. Because these data are not broken out by
stationary and mobile uses, further research will be aimed at
trying to allocate consumption appropriately. In addition, the
uncertainty of biomass emissions will be further investigated
since it was expected that the exclusion of biomass from the
uncertainty estimates would reduce the uncertainty; and in
actuality the exclusion of biomass increases the uncertainty.
These improvements are not all-inclusive, but are part of an
ongoing analysis and efforts to continually improve these
stationary estimates.

CH4 and N20  from Mobile Combustion


Methodology
    Estimates  of CH4  and N2O emissions from mobile
combustion were calculated by multiplying emission factors
by measures of activity  for each fuel and vehicle type
(e.g., light-duty gasoline trucks).  Activity data included
vehicle miles traveled (VMT) for on-road vehicles and fuel
consumption for non-road mobile sources. The activity data
and emission factors used are described in the subsections
that follow. A complete discussion of the methodology used
to estimate CH4 and N2O emissions from mobile combustion
and the emission factors used in the calculations is provided
in Annex 3.2.

On-Road Vehicles
    Estimates  of CH4 and N2O emissions from gasoline
and diesel on-road vehicles are based on VMT and emission
factors by vehicle type, fuel type, model year, and emission
control technology. Emission estimates for alternative fuel
vehicles (AFVs)34 are based on VMT and emission factors
by vehicle and fuel type.
    Emission factors for gasoline and diesel on-road
vehicles utilizing Tier 2 and Low Emission Vehicle (LEV)
technologies were  developed by ICF (2006b); all other
gasoline and diesel on-road vehicle emissions factors were
developed by ICF (2004). These factors were derived
from EPA, California Air Resources Board (CARB) and
Environment Canada laboratory test results of different
vehicle and control technology types. The EPA, CARB and
Environment Canada tests  were designed following the
Federal Test Procedure (FTP), which covers three separate
driving segments, since vehicles emit varying amounts of
GHGs depending on the driving segment. These driving
segments are:  (1) a transient driving cycle that includes
cold start and running emissions; (2) a cycle that represents
running emissions only; and (3) a transient driving cycle that
includes hot start and running emissions. For each test run, a
bag was affixed to the tailpipe of the vehicle and the exhaust
was collected; the content of this bag was then analyzed
to determine quantities of gases present. The emission
characteristics  of segment 2 were used to define running
emissions, and subtracted from the total FTP emissions to
determine start emissions. These were then recombined based
upon the ratio of start to running emissions for each vehicle
class from MOBILE6.2, an EPA emission factor model that
predicts gram per mile emissions of CO2, CO, HC, NOX, and
PM from vehicles under various conditions, to approximate
average driving characteristics.35
34Alternative 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.
35 Additional information regarding the model can be found online at http: //
www.epa.gov/OMS/m6.htm.
                                                                                                Energy  3-27

-------
    Emission factors for AFVs were developed by ICF
(2006a) after examining Argonne National Laboratory's
GREET 1.7-Transportation Fuel Cycle Model (ANL 2006)
and Lipman and Delucchi (2002). These sources describe
AFV emission factors in terms of ratios to conventional
vehicle emission factors.  Ratios of AFV to conventional
vehicle emissions factors were then applied to estimated
Tier 1 emissions factors from light-duty gasoline vehicles
to estimate light-duty AFVs.  Emissions factors for heavy-
duty AFVs were developed in relation to gasoline heavy-
duty vehicles. A complete discussion of the data source and
methodology used to determine emission factors from AFVs
is provided in Annex 3.2.
    Annual VMT data for 1990 through 2007 were obtained
from the Federal  Highway Administration's (FHWA)
Highway Performance Monitoring System database as
reported in Highway Statistics (FHWA 1996 through 2008).
VMT estimates were then allocated from FHWA's vehicle
categories  to fuel-specific vehicle categories  using the
calculated shares of vehicle fuel use for each vehicle category
by fuel type reported in DOE (1993 through 2008) and
information on total motor vehicle fuel consumption by fuel
type from FHWA (1996 through 2008). VMT for AFVs were
taken from Browning (2003). The age distributions of the
U.S. vehicle fleet were obtained from EPA (2007c, 2000), and
the average annual age-specific vehicle mileage accumulation
of U.S. vehicles were obtained from EPA (2000).
    Control technology and standards  data for on-road
vehicles were obtained from EPA's Office of Transportation
and Air Quality (EPA 2007a, 2007b, 2000,1998, and 1997) and
Browning (2005). These technologies and standards are defined
in Annex 3.2, and were compiled from EPA (1993, 1994a,
1994b, 1998,1999a) and IPCC/UNEP/OECD/IEA (1997).

Non-Road Vehicles
    To estimate emissions from  non-road vehicles, fuel
consumption data were employed as a measure of activity,
and multiplied by fuel-specific emission factors (in grams
of N2O and CH4 per kilogram of fuel consumed).36 Activity
data were obtained from AAR (2008), APTA (2007 through
2008), APTA (2006), BEA (1991 through 2005), Benson
(2002 through 2004), DHS (2008), DOC (1991 through
36 The consumption of international bunker fuels is not included in these
activity data, but is estimated separately under the International Bunker
Fuels source category.
2008), DOE (1993 through 2008), DESC (2008), DOT
(1991 through 2008), EIA (2008b, 2007a, 2007b, 2002),
EIA (2007 through 2008), EIA (1991 through 2007), EPA
(2006b), Esser (2003 through 2004), FAA (2008 and 2006),
Gaffney (2007), and Whorton (2006 through 2007). Emission
factors for non-road modes were taken from IPCC/UNEP/
OECD/IEA(1997).

Uncertainty
    A quantitative  uncertainty analysis was  conducted
for the on-road portion of the mobile source sector using
the IPCC-recommended Tier 2 uncertainty estimation
methodology, Monte Carlo simulation technique, using @
RISK software. The uncertainty analysis was performed on
2007 estimates of CH4 and N2O emissions, incorporating
probability distribution functions associated with the
major input variables. For the purposes of this analysis, the
uncertainty was modeled for the following two major sets
of input variables: (1) vehicle miles traveled (VMT) data,
by vehicle and fuel type and (2) emission factor data, by
vehicle, fuel, and control technology type.
    Uncertainty analyses were not conducted for NOX, CO,
or NMVOC emissions. Emission factors for these gases have
been extensively researched since emissions of these gases
from motor vehicles are regulated in the United States, and
the uncertainty in these emission estimates is believed to be
relatively low. However, a much higher level of uncertainty
is associated with CIL, and N2O emission factors, because
emissions of these gases are not regulated in the United States
(and, therefore, there are not adequate emission test data),
and because, unlike CO2 emissions, the emission pathways
of CH4 and N2O are highly complex.
    The results of the Tier 2 quantitative uncertainty analysis
for the mobile source CIL, and N2O emissions from on-road
vehicles are summarized in Table 3-19. As noted above, an
uncertainty analysis was not performed for CIL, and N2O
emissions from non-road vehicles. Mobile combustion CH4
emissions (from on-road vehicles) in 2007 were estimated to
be between 1.5 and 1.8 Tg CO2 Eq. at a 95 percent confidence
level. This indicates a range of 8 percent below to 8 percent
above the corresponding 2007 emission estimate of 1.7
Tg CO2 Eq. Also at a 95 percent confidence level, mobile
combustion N2O emissions from on-road vehicles in 2007
were estimated to be between 21.1 and 30.8 Tg CO2 Eq.,
3-28  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-19: Tier 2 Quantitative Uncertainty Estimates for CH4 and N20 Emissions from Mobile Combustion
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas          (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3'"
  (Tg C02 Eq.)                      (%)

Mobile Combustion
Mobile Combustion

CH4
N20

1.7
26.0
Lower Bound
1.5
21.1
Upper Bound
1.8
30.8
Lower Bound
-8%
-19%
Upper Bound
+ 8%
+ 19%
  a 2007 Emission estimates and the uncertainty range presented in this table correspond to on-road vehicles, comprising conventional and alternative fuel
   vehicles. Because the uncertainty associated with the emissions from non-road vehicles were not estimated, they were excluded in the estimates reported
   in this table.
  b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
indicating a range of 19 percent below to 19 percent above the
corresponding 2007 emission estimate of 26.0 Tg CO2 Eq.
    This uncertainty analysis is a continuation of a multi-
year process for developing quantitative uncertainty estimates
for this source category using the IPCC Tier 2 approach to
uncertainty analysis. As a result, as new information becomes
available, uncertainty  characterization of input variables
may be improved and  revised. For additional information
regarding uncertainty in emission estimates for CH4 and N2O
please refer to the Uncertainty Annex.

QA/QC and Verification
    A source-specific QA/QC plan for mobile combustion
was developed and implemented. This plan is based on the
IPCC-recommended  QA/QC Plan. The specific plan used
for mobile combustion was updated prior to collection  and
analysis of this current year of data. This effort included
a Tier 1 analysis, as  well as portions of a Tier 2 analysis.
The Tier 2 procedures  focused on the emission factor  and
activity data sources, as well as the methodology used for
estimating emissions.  These procedures included a qualitative
assessment of the emissions estimates to determine whether
they appear consistent with the most recent activity data
and emission factors  available. A comparison of historical
emissions between the current Inventory and the previous
Inventory was also conducted to ensure that the changes in
estimates were consistent with the changes in activity data
and emission factors.
                                 Recalculations  Discussion
                                     In order to ensure that these estimates are continuously
                                 improved, the calculation methodology is revised annually
                                 based on comments from internal and external reviewers. A
                                 number of adjustments were made to the methodologies used
                                 in calculating emissions in the current Inventory relative to
                                 the previous Inventory report.
                                     New estimates of VMT by alternative fueled vehicles
                                 are now calculated using an updated method. The original
                                 VMT for alternative fuels was determined from energy use
                                 data obtained from EIA and projected. The new update uses
                                 actual energy use for 2005 through 2007 and improved
                                 estimations for future years.
                                      Several changes were  also made in the calculation
                                 of emissions from non-road vehicles. Commercial aircraft
                                 activity data for 1990 through  1999 is now calculated as
                                 the result of estimating DOT (1991 through 2008) data
                                 based upon the average difference between FAA (2006)
                                 and DOT (1991 through 2008) datasets for the years 2000
                                 through 2005. For 2006 and 2007 commercial aircraft
                                 activity data, DOT (1991 through 2008) data is multiplied
                                 by the percentage difference between 2005 (the most recent
                                 available SAGE datapoint) and the respective year.
                                     International jet fuel bunkers are now calculated by
                                 assigning the difference between the sum of domestic activity
                                 data (in TBtu) and the EIA transportation jet fuel allotment
                                 to the jet fuel bunkers category. Previously, international jet
                                                                                                  Energy  3-29

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fuel bunkers were calculated based upon DOT (1991 through
2008) and BEA (1991 through 2005) data for the years 1990
through 1999 and 2006 through 2007 and estimated by FAA
(2006) for 2000 through 2005.
    Categories of non-road sources for which activity data
are supplied from EPA's NONROAD model (EPA 2006) now
include all Source Classification Codes available within the
model, rather than a subset of all sources. This change results
in an increase in emissions estimates from farm equipment,
construction equipment, and other non-road sources.
    As a result of these changes, average estimates of CH4
and N2O emissions from mobile combustion were slightly
higher relative to  the previous Inventory—showing an
increase of no more than 2.5 percent in a given year—for the
period 1990 through 2007. The greatest increase in absolute
terms, 0.48 Tg CO2 Eq. (1.4 percent), occurs with the 2006
N,O estimate.
Planned Improvements
    While the data used for this report represent the most
accurate information available, six areas have been identified
that could potentially be improved in the short-term given
available resources.
1.   Develop updated emissions factors for diesel vehicles,
    motorcycles, and biodiesel vehicles. Previous emission
    factors were based upon extrapolations from other
    vehicle classes and new test data from  Environment
    Canada will allow for better estimation of emission
    factors for these vehicles.
2.   Develop updated emissions factors for ships and boats.
    Prior emission factors were derived from AP-42 for
    combustion of diesel and residual fuel. The new factors
    will take into account new data obtained from the
    Swedish Methodology for Environmental Data.
3.   Develop new emis sion factors for non-road equipment.
    The current Inventory estimates for non-CO2 emissions
    from non-road sources are based on emission factors
    from IPCC guidelines published in 1996. Recent data
    on non-road sources from Environment Canada and the
    California Air Resources Board will be investigated in
    order to assess the feasibility of developing new N2O and
    CH4 emissions factors for non-road equipment.
4.   Examine the feasibility of estimating aircraft N2O
    and  CH4 emissions by the number of takeoffs and
    landings, instead of total fuel consumption.  Various
    studies have indicated  that aircraft N2O and CH4
    emissions are more  dependent on aircraft takeoffs
    and landings than on total aircraft fuel consumption;
    however, aircraft emissions are currently estimated
    from fuel consumption data. FAA's SAGE database
    contains detailed data on takeoffs and landings for each
    calendar year starting in 1999, and could potentially be
    used to conduct a Tier II analysis of aircraft emissions.
    This methodology will require a detailed analysis of
    the number of takeoffs and landings by aircraft type
    on domestic trips and development of procedures to
    develop comparable estimates for years prior to 1999.
    The feasibility of this approach will be explored.
5.   Develop improved estimates of domestic  waterborne
    fuel consumption. The Inventory estimates  for residual
    fuel used by  ships and boats is based in part on data on
    bunker fuel use from the U.S. Department of Commerce.
    The Department of Homeland Security (DHS) maintains
    an electronic reporting system that automatically registers
    monthly sales  of bunker fuel at ports, which should
    provide a more accurate and comprehensive estimate
    of residual bunker fuel use by reducing the amount of
    non-reporting. This system has been used to collect data
    since 2002, and these data could be incorporated into the
    development of inventory figures. The DHS figures will
    need to be reconciled with figures from the current sources
    of data and a methodology will need to be developed to
    produce updated estimates for prior years.
6.   Continue to examine the use of EPA's MOVES model
    in the development of the inventory estimates, including
    use for uncertainty analysis. Although the inventory
    uses some of the underlying data from MOVES, such as
    vehicle age distributions by model year, MOVES is not
    used directly in calculating mobile source emissions. As
    MOVES goes through additional testing and refinement,
    the use of MOVES will be further explored.
3-30  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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

    In addition to being combusted for energy, fossil fuels are
also consumed for non-energy uses (NEU) in the United States.
The fuels used for these purposes are diverse, including natural
gas, liquefied petroleum gases  (LPG), asphalt (a viscous
liquid mixture of heavy crude oil distillates), petroleum coke
(manufactured from heavy oil), and coal coke (manufactured
from coking coal). The non-energy applications are equally
diverse, and include feedstocks for the manufacture of plastics,
rubber, synthetic fibers and other materials; reducing agents
for the production of various metals and inorganic products;
and non-energy products such as lubricants, waxes, and asphalt
(IPCC 2006).
    Carbon dioxide emissions arise from non-energy
uses via several pathways. Emissions may occur during
the manufacture of a product, as is the case in producing
plastics or rubber from fuel-derived feedstocks. Additionally,
emissions may occur during the product's lifetime, such as
during solvent use. Overall, throughout the time series and
across all uses, about 63 percent of the total C consumed for
non-energy purposes was stored in products, and not released
to the atmosphere; the remaining 37 percent was emitted.
    There are several areas in which non-energy uses of
fossil fuels are closely related to other parts of the Inventory.
For example, some of the NEU products release CO2 at the
end of their commercial life when they are combusted after
disposal; these emissions are reported separately within the
Energy chapter  in the Municipal Solid Waste Combustion
source category. In addition, there is some overlap between
fossil fuels consumed for non-energy uses and the fossil-
derived CO2 emissions accounted for in the Industrial
Processes chapter, especially for fuels  used as reducing
agents. To avoid double-counting, the "raw" non-energy fuel
consumption data reported by EIA are modified to account for
these overlaps. There are also net exports of petrochemicals
that are not completely accounted for in the EIA data, and
these affect the mass of C in non-energy applications.
    As shown in Table 3-20, fossil fuel emissions in 2007
from the non-energy uses of fossil fuels were 133.9 Tg CO2
Eq., which constituted approximately 2 percent of overall
fossil fuel emissions. In  2007, the consumption of fuels for
non-energy uses (after the adjustments described above) was
5,219.2 TBtu, an increase of 16 percent since 1990(see Table
3-21). About 62.0 Tg of the C (227.2 Tg CO2 Eq.) in these
fuels was stored, while the remaining 36.5 Tg C (133.9 Tg
CO2 Eq.) was emitted. The proportion of C emitted as CO2
has remained about constant since 1990, at about 37 to 40
percent of total non-energy consumption (see Table 3-20).

Methodology
    The first step in estimating C stored in products was to
determine the aggregate quantity of fossil fuels consumed
for non-energy uses. The C content of these feedstock
fuels is equivalent to potential emissions, or  the product of
consumption and the fuel-specific C content values. Both
the non-energy fuel consumption and C  content data were
supplied by the EIA (2007) (see Annex 2.1). Consumption
of natural gas, LPG, pentanes plus, naphthas, other oils, and
special naphtha were adjusted to account for net exports of
these products that are not reflected in the raw data from EIA.
Consumption values for industrial coking coal, petroleum
coke, other oils, and natural gas in Table 3-21 and Table
Table 3-20: C02 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg C02 Eq.)
  Type
  Potential Emissions
  C Stored
  Emissions as a % of Potential
  Emissions
  1995
 137.5
 2000
 2005
 2006
 2007
                           375.9
                           237.8
                            37%
                       383.4
                       238.3
                        38%
                   361.1
                   227.2
                    37%
144.5
138.1
145.1
133.9
                                                                                               Energy  3-31

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Table 3-21: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)
  Sector/Fuel Type
  1990
  1995
  2000
  2005
2006
                                                                                                              2007
Industry                                      4,222.3
  Industrial Coking Coal                             +
  Industrial Other Coal                             8.2
  Natural Gas to Chemical Plants, Other Uses        276.0
  Asphalt & Road Oil                           1,170.2
  LPG                                        1,119.0
  Lubricants                                   186.3
  Pentanes Plus                                 77.3
  Naphtha (<401°F)                            325.7
  Other Oil (>401°F)                            677.2
  Still Gas                                      21.3
  Petroleum Coke                                82.1
  Special Naphtha                               100.9
  Distillate Fuel Oil                                 7.0
  Waxes                                        33.3
  Miscellaneous Products                        137.8
Transportation                                  176.0
  Lubricants                                   176.0
U.S. Territories                                  86.7
  Lubricants                                     0.7
  Other Petroleum (Misc. Prod.)	86.0

                                                            4,804.4
                                                               75.0
                                                               11.3
                                                              330.4
                                                            1,178.2
                                                            1,484.7
                                                              177.8
                                                              285.3
                                                              350.6
                                                              612.7
                                                               40.1
                                                               45.5
                                                               66.9
                                                                8.0
                                                               40.6
                                                               97.1
                                                              167.9
                                                              167.9
                                                               90.8
                                                                2.0
                            15,278.9
                               82.2
                     	      194!
              5,278.9
                 82.2
                 12.4
                420.7
              1,275.7
              1,603.1
                189.9
                228.5
                592.3
                553.8
                 12.6
                 49.4
                 94.3
                 11.7
                 33.1
                119.2
                179.4
                179.4
                165.5
                 16.4
                149.1
               5,153.4
                 53.3
                 11.9
                390.0
               1,323.2
               1,440.9
                160.2
                145.9
                678.2
                518.3
                 67.7
                147.2
                 60.8
                 11.7
                 31.4
                112.8
                151.3
                151.3
                107.7
                  5.2
                102.4
          5,245.8
             74.7
             12.4
            403.2
          1,261.2
          1,492.0
            156.1
            105.7
            619.4
            572.9
            123.9
            181.5
             69.1
             11.7
             26.1
            136.0
            147.4
            147.4
            110.3
              5.4
            105.0
        4,966.4
           33.0
           12.4
          396.0
        1,197.0
        1,483.2
          161.0
          132.4
          543.3
          511.7
           88.4
          165.4
           75.6
           11.7
           21.9
          133.5
          152.0
          152.0
          100.9
            4.9
           96.0
  Total
4,485.0
5,063.1
5,623.7
5,412.4    5,503.6    5,219.2
  + Less than 0.05 TBtu.
  Note: To avoid double-counting, coal coke, petroleum coke, natural gas consumption, and other oils are adjusted for industrial process consumption
  reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha, and Other Oils are adjusted to account for
  exports of chemical intermediates derived from these fuels. For residual oil (not shown in the table), all non-energy use is assumed to be consumed in C
  black production, which is also reported in the Industrial Processes chapter.
  Note: Totals may not sum due to independent rounding.
3-22 have been adjusted to subtract non-energy uses that are
included in the source categories of the Industrial Processes
chapter.37 Consumption values were also adjusted to subtract
exports of intermediary chemicals.
    For the remaining non-energy uses, the quantity of C
stored was estimated by multiplying the potential emissions
by a storage factor. For several fuel types—petrochemical
feedstocks (including natural gas for non-fertilizer uses, LPG,
pentanes plus, naphthas, other oils, still gas, special naphtha,
and industrial other coal), asphalt and road oil, lubricants,
and waxes—U.S. data on C stocks and flows were used to
develop C storage factors, calculated as the ratio  of (a) the
C stored by the fuel's non-energy products to (b) the total
C content of the fuel consumed. A lifecycle approach was
37 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.
              used in the development of these factors in order to account
              for losses in the production process and during use. Because
              losses associated with municipal solid waste management
              are handled separately in this sector under the Incineration
              of Waste source category, the storage factors do not account
              for losses at the disposal end of the life cycle. For industrial
              coking coal and distillate fuel oil, storage factors were taken
              from IPCC/UNEP/OECD/IEA (1997), which in turn draws
              from Marland and Rotty (1984). For the remaining fuel
              types (petroleum coke, miscellaneous products,  and other
              petroleum), IPCC does not provide  guidance on storage
              factors, and assumptions were made based on the potential
              fate of C in the respective NEU products.
                   Lastly, emissions were estimated by subtracting the
              C stored from the potential emissions (see Table 3-20).
              More detail on the methodology for calculating storage
              and emissions from each of these sources  is provided in
              Annex 2.3.
3-32  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-22: 2007 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions
Adjusted Carbon
Non-Energy Content
Usea Coefficient
Sector/Fuel Type (TBtu) (Tg C/QBtu)
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
4,966.4
33.0
12.4
396.0
1,197.0
1,483.2
161.0
132.4
543.3
511.7
88.4
165.4
75.6
11.7
21.9
133.5
152.0
152.0
100.9
4.9
96.0
5,219.2
-
31.00
25.63
14.47
20.62
16.76
20.24
18.24
18.14
19.95
17.51
27.85
19.86
19.95
19.81
20.33
-
20.24
-
20.24
20.00

Potential
Carbon
(TgC)
93.4
1.0
0.3
5.7
24.7
24.9
3.3
2.4
9.9
10.2
1.5
4.6
1.5
0.2
0.4
2.7
3.1
3.1
2.0
0.1
1.9
98.5
Storage
Factor
-
0.10
0.61
0.61
1.00
0.61
0.09
0.61
0.61
0.61
0.61
0.30
0.61
0.50
0.58
0.00
-
0.09
-
0.09
0.10

Carbon Carbon Carbon
Stored Emissions Emissions
(TgC) (TgC) (Tg C02 Eq.)
61.5
0.1
0.2
3.5
24.7
15.3
0.3
1.5
6.0
6.3
1.0
1.4
0.9
0.1
0.3
0.0
0.3
0.3
0.2
0.0
0.2
62.0
31.9
0.9
0.1
2.2
+
9.6
3.0
0.9
3.8
3.9
0.6
3.2
0.6
0.1
0.2
2.7
2.8
2.8
1.8
0.1
1.73
36.5
117.0
3.4
0.4
8.1
+
35.2
10.8
3.4
14.0
14.5
2.2
11.8
2.1
0.4
0.7
9.9
10.2
10.2
6.7
0.3
6.3
133.9
  + Less than 0.05 TBtu.
  - Not applicable.
  aTo avoid double counting, exports have been deducted.
  Note: Totals may not sum due to independent rounding.
    Where storage factors were calculated specifically for
the United States, data were obtained on (1) products such as
asphalt, plastics, synthetic rubber, synthetic fibers, cleansers
(soaps and detergents), pesticides, food additives, antifreeze
and deicers (glycols),  and silicones; and (2) industrial
releases including volatile organic compound, solvent, and
non-combustion CO emissions, Toxics Release Inventory
(TRI) releases, hazardous waste incineration,  and energy
recovery. Data were taken from a variety of industry sources,
government reports, and expert communications.  Sources
include EPA reports and databases such as compilations of
air emission factors (EPA 1995, 2001), National Emissions
Inventory (NEI) Air Pollutant Emissions Trends Data (EPA
2008), Toxics Release Inventory, 1998 (2000a), Biennial
Reporting System (EPA 2004a, 2006b, 2007), and pesticide
sales and use estimates (EPA 1998, 1999,2002,2004b); the
EIA Manufacturer's Energy Consumption Survey (MECS)
(EIA 1994, 1997, 2001, 2005); the National Petrochemical
& Refiners Association (NPRA 2001); the National Asphalt
Pavement Association (Connolly 2000); the Emissions
Inventory Improvement Program (EIIP 1998, 1999); the
U.S. Census Bureau (1999, 2003, 2004); the American
Plastics Council (APC 2000,  2001, 2003, 2005, 2006;
Eldredge-Roebuck 2000); the Society of the Plastics Industry
(SPI 2000); Bank of Canada (2006); Financial  Planning
Association (2006); INEGI (2006);  Statistics Canada
(2006); the United States International Trade Commission
(2006 through 2008); the Pesticide Action Network (PAN
2002); Gosselin, Smith, and Hodge (1984); the Rubber
Manufacturers'Association (RMA 2002,2006; STMC 2003);
the International Institute  of Synthetic Rubber  Products
(IISRP 2000,2003); the Fiber Economics Bureau (FEE 2001,
2003, 2005 through 2007); the Material Safety Data Sheets
(Miller 1999); the Chemical Manufacturer's Association
                                                                                               Energy 3-33

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(CMA 1999); and the American Chemistry Council (ACC
2005 through 2008) Specific data sources are listed in full
detail in Annex 2.3.

Uncertainty
    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), 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 3-23 (emissions) and Table 3-24
(storage factors). Carbon emitted  from non-energy uses of
fossil fuels in 2007 was estimated to be between 107.0 and
144.6 Tg CO2 Eq. at a 95 percent confidence level. This
indicates a range of 20 percent below to 8 percent above the
2007 emission estimate of 133.9 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.
    In Table 3-24, feedstocks and asphalt contribute least
to overall storage factor uncertainty on a percentage basis.
Although the feedstocks category—the largest use category
in terms of total carbon flows —appears to have tight
confidence limits, this is to some extent an artifact of the
way the uncertainty analysis was  structured. As discussed
in Annex 2.3, the storage factor for feedstocks is based on
an analysis of six fates that result in long-term storage (e.g.,
plastics production), and eleven that result in emissions (e.g.,
volatile organic compound emissions). Rather than modeling
the total uncertainty around all of these fate processes, the
current analysis addresses only the storage fates, and assumes
that all C that is not stored is emitted. As the production
statistics  that drive the storage values are relatively well-
characterized, this approach yields a result that is probably
biased toward understating uncertainty.
    As is the case with the other uncertainty analyses
discussed  throughout  this document,  the uncertainty
results above address only those factors that can be readily
quantified. More details on the uncertainty analysis  are
provided in Annex 2.3.

QA/QC and Verification
    A source-specific QA/QC plan for non-energy uses of
fossil fuels was  developed and implemented. This  effort
included a Tier  1 analysis, as well as portions of a Tier
2 analysis  for non-energy uses involving petrochemical
feedstocks and for imports and exports. The Tier 2 procedures
that were implemented involved checks specifically focusing
on the activity data and methodology for estimating the fate
of C (in terms of storage and emissions) across the various
end-uses  of fossil C. Emission  and storage  totals for the
different  subcategories were compared, and trends across
the time  series were analyzed to determine whether any
corrective actions were needed. Corrective actions were taken
to rectify minor errors and to improve the transparency of
the calculations, facilitating future QA/QC.
    For petrochemical import and export  data, special
attention was paid to NAICS numbers and titles to verify
that none had changed or been removed. Import and export
totals were compared for 2007 as well as their trends across
the time series.
3-34  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-23: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Non-Energy Uses of Fossil Fuels
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas          (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                      (%)

Feedstocks
Asphalt
Lubricants
Waxes
Other
Total

C02
C02
C02
C02
C02
C02

79.9
0.0
21.4
0.7
31.9
133.9
Lower Bound
64.4
0.2
17.7
0.5
13.7
107.0
Upper Bound
95.9
0.8
24.9
1.1
33.0
144.6
Lower Bound
-19%
NA
-17%
-24%
-57%
-20%
Upper Bound
+20%
NA
+ 16%
+64%
+ 3%
+8%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
  NA (Not Applicable)
Table 3-24: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
(Percent)
  Source
          2007 Storage Factor
Gas              (%)
Uncertainty Range Relative to Emission Estimate3
     (%)                      (%, Relative)

Feedstocks
Asphalt
Lubricants
Waxes
Other

C02
C02
C02
C02
C02

61%
100%
9%
58%
17%
Lower Bound Upper Bound
59% 63%
99% 100%
4% 17%
44% 70%
17% 64%
Lower Bound
-4%
-1%
-57%
-25%
+ 2%
Upper Bound
+ 3%
+ 0%
+89%
+20%
+273%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval, as a percentage of the inventory value
  (also expressed in percent terms).
Recalculations Discussion
    Non-energy end uses for petroleum coke (other than
in the industrial processing sectors, where it is accounted
for separately) had not been identified in the past. Huurman
(2006) suggests that in the Netherlands petroleum coke is
used in some pigments, and identifies its corresponding
storage factor as 0.3. This year,itwas assumed that petroleum
coke used for non-energy purposes (and not accounted for
in the Industrial Processes chapter, viz., for production of
primary  aluminum anodes, electric arc furnace anodes,
titanium dioxide, ammonia, urea, and ferroalloys) is used in
pigments, with a storage factor of 0.3 (rather than the value
of 0.5 used previously). This resulted in an average 1.4%
increase in NEU emissions across the time series.
                                  Planned  Improvements
                                     There are several improvements planned for the
                                  future:
                                  •   Future updates in line with the 2006 IPCC Guidelines.
                                     These changes could affect both the non-energy use and
                                     industrial processes sections.
                                  •   Improving the uncertainty analysis. Most of the input
                                     parameter distributions are based on professional
                                     judgment rather than rigorous statistical characterizations
                                     of uncertainty.
                                  •   Better characterizing flows of fossil C. Additional "fates"
                                     may be researched, including the fossil C load in organic
                                     chemical wastewaters, plasticizers, adhesives, films,
                                     paints,  and coatings. There is also a need to further
                                     clarify the treatment of fuel additives and backflows
                                     (especially methyl tert-butyl ether, MTBE).
                                                                                                   Energy  3-35

-------
    Finally, although U.S.-specific storage factors have been
developed for feedstocks, asphalt, lubricants, and waxes,
default values from IPCC are still used for two of the non-
energy fuel types (industrial coking coal and distillate oil),
and broad assumptions are  being used for miscellaneous
products and other petroleum. Over the long term, there are
plans to improve these storage factors by conducting analyses
of C fate similar to those described in Annex 2.3.


3.3.  Coal  Mining  (IPCC  Source
Category 1B1 a)

    Three types of coal mining related activities release CH4
to the atmosphere: underground mining, surface mining, and
post-mining (i.e.,  coal-handling) activities. Underground
coal mines contribute the largest share of CH^ emissions. In
2007,233 coal mines, (including all 131 gassy underground
coal mines), in the United States employ ventilation systems
to ensure that CH4 levels remain within safe concentrations.
These systems can exhaust significant amounts of CH^ to the
            atmosphere in low concentrations. Additionally, 20 U. S. coal
            mines supplement ventilation systems with degasification
            systems. Degasification systems are wells drilled from the
            surface or boreholes drilled inside the mine that remove large
            volumes of CH4 before, during, or after mining. In 2007,15
            coal mines collected CH^ from degasification systems and
            utilized this gas, thus reducing emissions to the atmosphere.
            Of these mines, 13 coal mines sold CK4 to the natural gas
            pipeline, one coal mine generated electricity, and one coal
            mine used CH^ from its degasification system to heat mine
            ventilation air on site. On addition, one of the coal mines that
            sold gas to pipelines also used CK4 to fuel a thermal coal
            dryer. Surface coal mines also release CH4 as the overburden
            is removed and the coal is exposed, but the level of emissions
            is much lower than from underground mines. Finally, some
            of the CFLj retained in the coal after mining is released during
            processing, storage, and transport  of the coal.

                Total CH4 emissions in 2007 were estimated to be
            57.6 Tg CO2 Eq. (2,744 Gg), a decline of 31 percent since
            1990 (see Table 3-25 and Table 3-26). Of this amount,
Table 3-25: CH4 Emissions from Coal Mining (Tg C02 Eq.)
  Activity
 1990
       1995
 2000
 2005
2006
2007
  Underground Mining
    Liberated
    Recovered & Used
  Surface Mining
  Post-Mining (Underground)
  Post-Mining (Surface)
 62.3
 67.9
 (5.6)
 12.0
  7.7
  2.0
I      59.2          54.4
       (12.4)         (14.9)
        11.5          12.3
I       6.9           6.71
               35.2
               50.1
              (14.9)
               13.3
                6.4
                2.2
           35.8
           54.5
          (18.6)
           14.0
            6.3
            2.3
          35.5
          47.7
         (12.3)
          13.8
           6.1
           2.2
  Total
 84.1
        67.1
 60.5
 57.1
58.4
57.6
  Note: Totals may not sum due to independent rounding. Parentheses indicate negative values.
Table 3-26: CH4 Emissions from Coal Mining (Gg)
  Activity
 1990
       1995
  Underground Mining
    Liberated
    Recovered & Used
  Surface Mining
  Post-Mining (Underground)
  Post-Mining (Surface)
2,968
3,234
(266)
  574
  368
   93
I       2,817
       (592)

         330
              2005
              1,677
              2,387
              (710)
               633
               306
               103
          2006
          1,705
          2,593
          (888)
           668
           298
           109
          2007
         1,689
         2,273
          (584)
           659
           290
           107
  Total
4,003
       3,193
2,881
2,719      2,780
         2,744
  Note: Totals may not sum due to independent rounding. Parentheses indicate negative values.
3-36   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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underground mines accounted for 62 percent, surface
mines accounted for 24 percent, and post-mining emissions
accounted for 15  percent. The decline in CH4 emissions
from underground mines from 1996 to 2002 was the result
of the  reduction of overall coal production, the mining
of less gassy coal, and an increase in CH^ recovered and
used. Since that time, underground coal production and the
associated methane emissions have remained fairly level,
while surface coal production and its associated emissions
have generally increased.

Methodology
    The methodology for estimating  CH4 emissions from
coal mining consists of two parts. The first part involves
estimating CH4 emissions from underground mines. Because
of the  availability of ventilation system measurements,
underground mine emissions can be estimated on a mine-by-
mine basis and then summed to determine total emissions.
The second step involves estimating emissions from surface
mines  and post-mining activities by multiplying basin-
specific coal production by basin-specific emission factors.
    Undergro und mines. Total CFLj emitted from underground
mines  was estimated as  the sum of CH4 liberated from
ventilation systems and CH4 liberated by means of
degasification systems, minus CH4 recovered and used. The
Mine Safety and Heath Administration (MSHA) samples
CH4 emissions from ventilation systems for all mines with
detectable38 CH4 concentrations. These mine-by-mine
measurements are used to estimate  CH4 emissions from
ventilation systems.
    Some of the higher-emitting underground mines also
use degasification systems (e.g., wells or boreholes) that
remove CH4 before, during, or after mining. This CH4 can
then be collected for use or vented to the atmosphere. Various
approaches were employed to estimate the quantity of CH4
collected by each of the twenty mines using these systems,
depending on available data. For example, some mines report
to EPA the amount of CFLj liberated from their degasification
systems. For mines that sell recovered CH4 to a pipeline,
pipeline sales data published by state petroleum and natural
gas agencies were used to estimate degasification emissions.
For those mines for which no other data are available, default
recovery efficiency values were developed, depending on the
type of degasification system employed.
    Finally, the amount of CFLj recovered by degasification
systems and then used (i.e., not vented) was estimated. In
2007,13 active coal mines sold recovered CK4 into the local
gas pipeline networks, one used recovered CH4 to generate
electricity while one coal mine used recovered CFLj on site for
heating. Emissions avoided for these projects were estimated
using gas sales data reported by various state agencies. For
most  mines with recovery systems, companies and state
agencies provided individual well production information,
which was used to assign gas sales to a particular year. For
the few remaining mines, coal mine operators supplied
information regarding the number of years in advance of
mining that gas recovery occurs.
    Surface Mines and Post-Mining Emissions. Surface
mining and post-mining CFLj emissions were estimated by
multiplying basin-specific coal production, obtained from the
Energy Information Administration's Annual Coal Report
(see Table 3-27) (EIA 2006), by basin-specific emission
factors. Surface mining emission factors were developed by
assuming that surface mines emit two times as much CH4
as the average in situ CK4 content of the coal. Revised data
on in situ CH4 content and emissions factors are taken from
EPA (2005), EPA (1996), and AAPG (1984). This calculation
accounts for CH4 released from the strata surrounding the
coal seam. For post-mining emissions, the emission factor
was assumed to be 32.5 percent  of the average in situ CH4
content of coals mined in the basin.

Table 3-27: Coal Production (Thousand Metric Tons)
      Year     Underground     Surface
                          Total
                 384,250
                 ^H
                 359,477
            546,818
            577,638
             931,068
             937,115
      2000
     ^
      2005
      2006
      2007
338,173
635,592
 973,765
334,404
325,703
319,145
691,460
728,459
720,035
1,025,864
1,054,162
1,039,179
38 MSHA records coal mine CH4 readings with concentrations of greater
than 50 ppm (parts per million) CH4. Readings below this threshold are
considered non-detectable.
                                                                                                Energy  3-37

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Table 3-28: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas         (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound   Lower Bound    Upper Bound
  Coal Mining
CH,
57.6
48.6
71.2
-16%
+24%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Uncertainty
    A quantitative uncertainty analysis was conducted for the
coal mining source category using the IPCC-recommended
Tier 2 uncertainty estimation methodology. Because emission
estimates from underground ventilation systems were
based on actual measurement data, uncertainty is relatively
low. A degree of imprecision was introduced because the
measurements used were  not continuous but rather an
average of quarterly instantaneous readings. Additionally,
the measurement equipment used can be expected to have
resulted in an average of 10 percent overestimation of annual
CtLj emissions (Mutmansky and Wang 2000). Estimates of
CH4 recovered by degasification systems are relatively certain
because many coal mine operators provided information on
individual well gas sales and mined through dates. Many of
the recovery estimates use data on wells within 100 feet of
a mined area. Uncertainty also exists concerning the radius
of influence of each well. The number of wells counted, and
thus the avoided emissions,  may vary if the drainage area is
found to be larger or smaller than currently estimated.
    Compared to underground mines, there is considerably
more uncertainty associated with surface mining and post-
mining emissions because  of the difficulty in developing
accurate emission factors from field measurements. However,
since underground emissions comprise the majority of total
coal mining emissions, the uncertainty associated with
underground emissions is the primary factor that determines
overall uncertainty. The results of the Tier 2 quantitative
uncertainty analysis are summarized in Table 3-28. Coal
mining CH^ emissions in 2007 were estimated to be between
                                48.6 and 71.2 Tg CO2 Eq. at a 95 percent confidence level.
                                This indicates a range of 16 percent below to 24 percent
                                above the 2007 emission estimate of 57.6 Tg CO2 Eq.

                                Recalculations Discussion
                                   In 2007, calculations of emissions avoided at the four
                                Jim Walters Resources (JWR) coal mines in Alabama were
                                performed using the previous EPA method. This was done
                                in order to take a better documented approach and to track
                                the four coal mines individually rather than as  a group.
                                Emissions avoided calculations for any pre-drainage wells
                                at JWR coal mines are based on  publicly-available data
                                records from the Alabama State Oil & Gas Board. Emission
                                reductions are  calculated for pre-drainage wells that are
                                located inside the mine plan boundaries and are declared
                                "shut-in" by the O&G Board. The total production for a
                                well is  claimed in the year that the well was shut-in and
                                mined through.

                                3.4.  Abandoned Underground Coal
                                Mines (IPCC Source Category 1B1 a)

                                   Underground coal mines  contribute the largest share of
                                CH4 emissions, with active underground mines the leading
                                source  of underground emissions. However, mines also
                                continue to release CH4 after closure. As mines mature
                                and coal seams are mined through, mines are closed and
                                abandoned. Many are sealed and some flood through intrusion
                                of groundwater or surface water into the  void. Shafts or
                                portals  are generally filled with  gravel and capped with a
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concrete seal, while vent pipes and boreholes are plugged
in a manner similar to oil and gas wells. Some abandoned
mines are vented to the atmosphere to prevent the buildup
of CtLj that may find its way to surface structures through
overburden fractures. As work stops within the mines, the
CtLj liberation decreases but it does not stop completely.
Following an initial decline, abandoned mines can liberate
CtLj at a near-steady rate over an extended period of time,
or, if flooded, produce gas for only a few years. The gas
can migrate to the surface through  the conduits described
above, particularly if they have not been sealed adequately. In
addition, diffuse emissions can occur when CK4 migrates to
the surface through cracks and fissures in the strata overlying
the coal mine. The following factors influence abandoned
mine emissions:
•   Time since abandonment;
•   Gas content and adsorption characteristics of coal;
•   CtLj flow capacity of the mine;
•   Mine flooding;
•   Presence of vent holes; and
•   Mine seals.
    Gross abandoned mine CR4 emissions ranged from
6.0 to 9.1 Tg CO2  Eq. from 1990 through 2007, 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 2007,  with only three closures in 2007. By 2007,
gross abandoned mine emissions increased to 9.0 Tg CO2
Eq. (see Table 3-29 and Table 3-30). Gross emissions are
reduced by CFLj recovered and used at 27  mines, resulting
in net emissions in 2007 of 5.7 Tg CO2 Eq.
Methodology
    Estimating CH4 emissions from an abandoned coal mine
requires predicting the emissions of a mine from the time of
abandonment through the inventory year of interest. The flow
of CH4 from the coal to the mine void is primarily dependent
on the mine's emissions when active and the extent to which
the mine is flooded or sealed. The CH4 emission rate before
abandonment reflects the gas content of the coal, rate of coal
mining, and the flow capacity of the mine in much the same
way as the initial rate of a water-free conventional gas well
reflects the gas content of the producing formation and the
flow capacity of the well. A well or a mine which produces
gas from a coal seam and the surrounding strata will produce
less gas through time as the reservoir of gas is depleted.
Depletion of a reservoir will follow a predictable pattern
depending on the interplay of a variety of natural physical
Table 3-29: CH4 Emissions from Abandoned Underground Coal Mines (Tg C02 Eq.)
Activity
Abandoned Underground Mines
Recovered & Used
Total
1990
6.0
0.0
6.0
1995
8.9
0.7
8.2
2000
8.9
1.5
7.4
2005
7.0
1.4
5.6
2006
7.5
2.0
5.5
2007
9.0
3.3
5.7
  Note: Totals may not sum due to independent rounding.
Table 3-30: CH4 Emissions from Abandoned Underground Coal Mines (Gg)
Activity
Abandoned Underground Mines
Recovered & Used
Total
1990
288
0
288
1995
424
32
392
2000
422
72
350
2005
334
68
265
2006
359
96
263
2007
428
155
273
  Note: Totals may not sum due to independent rounding.
                                                                                                Energy  3-39

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conditions imposed on the reservoir. The depletion of a
reservoir is commonly modeled by mathematical equations
and mapped as a type curve. Type curves which are referred
to as decline curves have been developed for abandoned
coal mines. Existing data on abandoned mine emissions
through time, although sparse, appear to fit the hyperbolic
type of decline curve used in forecasting production from
natural gas wells.
    In order to estimate CH4 emissions over time for a given
mine, it is necessary to apply a decline function, initiated
upon abandonment, to that mine. In the analysis,  mines
were grouped by coal  basin with the assumption that they
will generally have the same initial pressures, permeability
and isotherm. As CR4 leaves the system, the reservoir
pressure, Pr, declines  as  described by  the isotherm. The
emission rate declines because the mine pressure (Pw) is
essentially constant at atmospheric pressure, for a vented
mine, and the PI term is essentially  constant at the pressures
of interest (atmospheric to 30 psia).  Arate-time equation can
be generated that can be used to predict future emissions.
This decline through time is hyperbolic in nature and can
be empirically expressed as:
    where,
    q  = Gas rate at time t in thousand cubic feet
          per day (mcfd)
    q;  = Initial gas rate at time zero (t0) in mcfd
    b  = The hyperbolic exponent, dimensionless
    D; = Initial decline rate, 1/yr
    t  = Elapsed time from t0 (years)

    This equation is applied to mines of various initial
emission rates that have similar initial pressures, permeability
and adsorption isotherms (EPA 2003).
    The decline  curves created to model the gas emission
rate of coal mines must account for factors that decrease
the rate of emission after mining activities cease, such as
sealing and flooding. Based on field measurement data, it
was assumed that most U.S. mines prone to flooding will
become completely flooded within eight years and therefore
no longer have any measurable CH4 emissions. Based on this
assumption, an average decline rate for flooding mines was
established by fitting a decline curve to emissions from field
measurements. An exponential equation was developed from
emissions data measured at eight abandoned mines known to
be filling with water located in two of the five basins. Using
a least squares, curve-fitting algorithm, emissions data were
matched to the exponential equation shown below. There
was not enough data to establish basin-specific equations as
was done with the vented, non-flooding mines (EPA 2003).

    where,
    q   =  Gas flow rate at time t in mcfd
    q;  =  Initial gas flow rate at time zero (t0) in mcfd
    D  =  Decline rate, 1/yr
    t   =  Elapsed time from t0 (years)

    Seals  have an inhibiting effect on the rate of flow of
CH4 into the atmosphere compared to the rate that would be
emitted if the mine had an open vent. The total volume emitted
will be the same, but will occur over a longer period. The
methodology, therefore, treats the emissions prediction from
a sealed mine similar to emissions from a vented mine, but
uses a lower initial rate depending on the degree of sealing.
The computational fluid dynamics simulator was again
used with  the conceptual abandoned mine model to predict
the decline curve for inhibited flow. The percent sealed is
defined as 100 x [1 - (initial emissions from sealed mine /
emission rate at abandonment prior to sealing)]. Significant
differences are seen between 50 percent, 80 percent, and 95
percent closure. These decline curves were therefore used as
the high, middle, and low values for emissions from sealed
mines (EPA 2003).
    For active coal mines, those mines producing over 100
mcfd account  for 98 percent of  all CK4 emissions. This
same relationship is assumed for abandoned mines. It was
determined that 448  abandoned mines closing after 1972
produced  emissions greater  than 100 mcfd when active.
Further, the status of 267 of the 448 mines (or 60 percent) is
known to be either: (1) vented to the atmosphere; (2) sealed
to  some degree (either earthen or concrete  seals); or,
(3) flooded (enough to inhibit CH4 flow to the atmosphere).
The remaining 40 percent of the mines were placed in one
of  the three categories by applying a probability distribution
analysis based on the known status of other mines located in
the same coal basin (EPA 2003).
    Inputs to  the decline equation require the average
emission rate and  the date of abandonment. Generally this
data is available for mines abandoned after 1972; however,
such data are largely unknown for mines closed before 1972.
3-40  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Information that is readily available such as coal production
by state and county is helpful, but does not provide enough
data to directly employ the methodology used to calculate
emissions from mines abandoned after 1971. It is assumed
that pre-1972 mines are governed by the same physical,
geologic, and hydrologic constraints that apply to post-1972
mines; thus, their emissions may be characterized by the
same decline curves.
    During the 1970s, 78 percent of CH4 emissions from
coal mining came from seventeen counties in seven states.
In addition, mine closure dates were obtained for two states,
Colorado and Illinois, for the hundred year period extending
from 1900 through 1999. The data were used to establish a
frequency of mine closure histogram (by decade) and applied
to the other five states with gassy mine closures. As a result,
basin-specific decline curve equations were applied to  145
gassy coal mines estimated to have closed between 1920
and 1971 in the United States, representing 78 percent of
the emissions. State-specific, initial emission rates were used
based on average coal mine CFLj emissions rates during the
1970s (EPA 2003).
    Abandoned mines emission estimates are based on all
closed mines  known to have active mine CH4 ventilation
emission rates greater than 100 mcfd at  the  time of
abandonment; a list by region is shown in Table 3-31.  For
example, for 1990 the analysis  included  145 mines  closed
before 1972 and 258 mines closed between 1972 and 1990.
Initial emission rates based on MSHA reports, time of
abandonment, and basin-specific decline curves influenced by
a number of factors were used to calculate annual emissions for
each mine in the database. Coal mine degasification data are
not available for years prior to 1990, thus the initial emission
rates used reflect ventilation emissions only for pre-1990
closures. Methane degasification amounts  were added to the
quantity of CH4 ventilated for the total CH4 liberation rate for
fifteen mines that closed between 1992 and 2007. Since the
sample of gassy mines (with active mine emissions greater
than 100 mcfd) is assumed to account for 78 percent of the
pre-1971 and 98 percent of the post-1971 abandoned mine
emissions, the modeled results were multiplied by 1.22 and
1.02 to account for all U.S. abandoned mine emissions.
    From  1993 through 2007,  emission totals were
downwardly adjusted to  reflect abandoned mine CH4
emissions avoided from those mines. The inventory totals
were not adjusted for abandoned mine reductions in 1990
through 1992, because no data was reported for abandoned
coal mining CFLj recovery projects during that time.

Uncertainty
    A quantitative  uncertainty analysis was conducted
to estimate the uncertainty surrounding the estimates
of emissions from  abandoned underground coal mines.
The uncertainty analysis  described below 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 provide
the range within which, with 95 percent certainty, emissions
from this source category are likely to fall.
    As  discussed above, the parameters for which values
must be  estimated for each mine in order to predict its decline
curve are: (1) the coal's adsorption isotherm; (2)  CH4 flow
capacity as expressed by permeability; and (3) pressure at
abandonment. Because these parameters are not available
for each mine, a methodological  approach to estimating
emissions was used that generates a probability distribution
of potential outcomes based on the most likely value and
the probable range of values for each parameter. The range
of values is not meant to capture  the extreme values, but
values that  represent the highest and lowest quartile of the
cumulative probability density function of each parameter.
Table 3-31: Number of Gassy Abandoned Mines Occurring in U.S. Basins Grouped by Class According to
Post-abandonment State
Basin
Central Appalachia
Illinois
Northern Appalachia
Warrior Basin
Western Basins
Total
Sealed
24
28
42
0
25
119
Vented
25
3
22
0
3
53
Flooded
48
14
16
15
2
95
Total Known
97
45
79
15
30
267
Unknown
115
25
32
0
9
181
Total Mines
212
70
112
15
39
448

                                                                                                Energy  3-41

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Table 3-32: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal Mines
(Tg C02 Eq. and Percent)

                                 2007 Emission Estimate          Uncertainty Range Relative to Emission Estimate3
  Source	Gas	(Tg C02 Eq.)	(Tg C02 Eq.)	(%)	
  	Lower Bound   Upper Bound    Lower Bound    Upper Bound
  Abandoned Underground
   Coal Mines	CH4	57	4.6	7J	-19%	+23%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Once the low, mid, and high values are selected, they are   35    |\|gtural G3S SySteiTIS (IPCC
applied to a probability density function.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 3-32. Abandoned coal mines CH4       The U.S. natural gas system encompasses hundreds
emissions in 2007 were estimated to be between 4.6 and 7.1   of thousands of wells,  hundreds of processing facilities,
Tg CO2 Eq. at a 95 percent confidence level. This indicates   and over a million miles  of transmission and distribution
a range of  19 percent below to 23 percent above the 2007   pipelines. Overall, natural gas systems emitted 104.7 Tg CO2
emission estimate of 5.7 Tg CO2 Eq. One of the reasons for   Eq. (4,985 Gg) of CH4 in  2007, a 19 percent decrease over
the relatively narrow range is that mine-specific data is used   1990 emissions (see Table 3-33 and Table 3-34), and 28.7
in the methodology. The largest degree of uncertainty is   Tg CO2 Eq. (28,680 Gg) of non-combustion CO2 in 2007,
associated with the unknown status mines (which account for   a 15 percent decrease over 1990 emissions  (see Table 3-35
40 percent  of the mines), with a +53 percent uncertainty.      and Table 3-36). Improvements in management practices and

Table 3-33: CH4 Emissions from Natural Gas Systems (Tg C02 Eq.)a

  Stage                                        1990          1995          2000          2005      2006      2007
  Field Production                                34.2          38.7          40.3          26.4      27.8       22.4
  Processing                                    15.0          15.1          14.5          11.6      11.6       12.3
  Transmission and Storage                         47.0          46.4          44.6          39.1      38.4       40.4
  Distribution                                    33.4          32.4          31.4          29.3      27.0       29.6
  Total                                         129.6         132.6         130.8         106.3     104.8      104.7
  'Including CH4 emission reductions achieved by the Natural Gas STAR program and NESHAP regulations.
  Note: Totals may not sum due to independent rounding.
Table 3-34: CH4 Emissions from Natural Gas Systems (Gg)a
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
1,629
7141
2,237
1,591
6,171
1995
1,842
717
2,212
1,543
6,314
2000
1,918
692
2,123
1,498
6,231
2005
1,256
550
1,862
1,393
5,062
2006
1,323
555
1,828
1,285
4,991
2007
1,066
584
1,926
1,409
4,985
  'Including CH4 emission reductions achieved by the Natural Gas STAR program and NESHAP regulations.
  Note: Totals may not sum due to independent rounding.
3-42   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-35: Non-combustion C02 Emissions from Natural Gas Systems (Tg C02 Eq.)
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
5.9
27.8
0.1 1
+
33.7
1995
24.6
0.1 1
+
33.8
2000
6.0
23.3
0.1 1
+
29.4
2005
7.6
21.7
0.1
+
29.5
2006
8.2
21.2
0.1
+
29.5
2007
7.4
21.2
0.1
+
28.7
+ Less than 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
Table 3-36: Non-combustion C02 Emissions from Natural Gas Systems (Gg)
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
5,877
27,752
59
46
33,733
1995
9,084
24,621
61
45
33,810
2000
5,956
23,332
61
44
29,394
2005
7,625
21,736
61
41
29,463
2006
8,235
21,204
60
40
29,540
2007
7,389
21,189
61
41
28,680
  Note: Totals may not sum due to independent rounding.
technology, along with the replacement of older equipment,
have helped to stabilize emissions.  Methane emissions
decreased since 2006 despite an increase in production
and production wells due to a decrease in 73 offshore
platforms and an increase of 25 percent in Natural Gas STAR
production sector emissions reductions.
    Methane and non-combustion CO2 emissions from
natural gas systems are generally process related, with normal
operations, routine maintenance,  and  system upsets being
the primary contributors. Emissions from normal operations
include: natural gas engines and turbine uncombusted
exhaust, bleed and discharge emissions from pneumatic
devices, and fugitive emissions from  system components.
Routine maintenance emissions originate from pipelines,
equipment, and wells  during repair and  maintenance
activities. Pressure surge relief systems and  accidents can
lead to system upset emissions. Below is a characterization
of the four major stages of the natural gas system. Each of
the stages is described and the different factors affecting CH4
and non-combustion CO2 emissions are discussed.
    Field Production. In this initial stage, wells are used to
withdraw raw gas from underground formations. Emissions
arise from the wells themselves, gathering pipelines,  and
well-site gas treatment facilities  such as dehydrators  and
separators. Fugitive emissions and emissions from pneumatic
devices account for the majority of CH4 emissions. Flaring
emissions account for the majority of the non-combustion
CO2 emissions. Emissions from field production accounted
for approximately 21 percent of CK4 emissions and about
26 percent of non-combustion CO2 emissions from natural
gas systems in 2007.
    Processing. In this stage, natural gas liquids and various
other constituents from the raw gas are removed, resulting in
"pipeline quality" gas, which is injected into the transmission
system. Fugitive CH4 emissions from compressors, including
compressor seals, are the primary emission source from this
stage. The majority of non-combustion CO2 emissions come
from acid gas removal units, which are designed to remove
CO2 from natural gas. Processing plants account for about 12
percent of CFLj emissions and approximately 74 percent of
non-combustion CO2 emissions from natural gas systems.
    Transmission and Storage. Natural gas transmission
involves high pressure, large diameter pipelines that transport
gas long distances from field production and processing areas
to distribution systems or large volume customers such as
powerplants or chemical plants. Compressor station facilities,
which contain large reciprocating and turbine compressors, are
used to move the gas throughout the United States transmission
system.  Fugitive CR4 emissions from these compressor
stations and from metering and regulating stations account
for the majority of the emissions from this stage. Pneumatic
                                                                                                Energy  3-43

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devices and engine uncombusted exhaust are also sources of
   j emissions from transmission facilities.
    Natural gas is also injected and stored in underground
formations, or liquefied and stored in above ground tanks,
during periods of low demand (e.g., summer), and withdrawn,
processed, and distributed during periods of high demand
(e.g., winter). Compressors and dehydrators are the primary
contributors to emissions  from these storage facilities.
Methane emissions from the transmission and storage sector
account for approximately 39 percent of emissions from
natural gas systems, while CO2 emissions from transmission
and storage  account for less than 1 percent of the non-
combustion CO2 emissions from natural gas systems.
    Distribution. Distribution pipelines  take the high-
pressure gas from the transmission system at "city gate"
stations, reduce the pressure and distribute the gas through
primarily underground mains and service lines to individual
end users. There were over 1,190,000 miles of distribution
mains in 2007, an increase from just over 944,000 miles in
1990 (OPS 2007b). Distribution system emissions, which
account for approximately 28 percent of CH4 emissions
from natural gas systems and less  than 1 percent of non-
combustion CO2 emissions, result mainly from fugitive
emissions from gate stations and pipelines. An increased use
of plastic piping, which has lower emissions than other pipe
materials, has reduced emissions from this stage. Distribution
system CH4 emissions in 2007 were 1 1 .4 percent lower than
1990 levels.

Methodology
    The primary basis for estimates of  CH4 and non-
combustion-related CO2 emissions from the U.S. natural gas
industry is a detailed study by the Gas Research Institute
(GRI) and EPA (EPA/GRI 1996). The EPA/GRI study
developed over 80 CH4 emission  and activity factors to
characterize emissions from the various components within
the operating stages of the U.S. natural gas system. The
same activity factors were used to  estimate both CK4 and
non-combustion CO2 emissions. However, the CH4 emission
factors were adjusted for CO2 content when estimating fugitive
and vented non-combustion CO2 emissions. The EPA/GRI
study  was based on a combination of  process engineering
studies and measurements at representative gas facilities.
From this analysis, a 1992 emission estimate was developed
using the emission and activity factors, except where direct
activity data was available (e.g., offshore platform counts,
processing plant counts, transmission pipeline miles, and
distribution pipelines). For other years, a set of industry
activity factor drivers was developed that can be used to
update activity factors. These drivers include statistics on
gas production, number of wells, system throughput, miles
of various kinds of pipe, and other statistics that characterize
the changes in the U.S. natural gas system infrastructure and
operations. See Annex 3.4 for more detailed information on
the methodology and data used to calculate CK4 and non-
combustion CO2 emissions from natural gas systems.
    Activity  factor data were  taken from the following
sources: American Gas Association (AGA 1991-1998);
Minerals and Management Service (MMS 2008a-d); Monthly
Energy Review (EIA 20081); Natural Gas Liquids Reserves
Report (EIA 2005); Natural Gas Monthly (EIA 2008b,c,e);
the Natural Gas STAR Program annual emissions savings
(EPA 2008); Oil and Gas Journal (OGJ 1997-2008);
Office of Pipeline Safety (OPS 2008a-b) and other Energy
Information Administration publications (EIA 2001, 2004,
2008a,d); World Oil Magazine (2008a-b). Data for estimating
emissions from hydrocarbon production tanks were
incorporated (EPA 1999). Coalbed CH4 well activity factors
were taken from the Wyoming Oil and Gas Conservation
Commission (Wyoming 2008) and the Alabama State Oil
and Gas Board (Alabama 2008). Other state well data was
taken from: American Association of Petroleum Geologists
(AAPG 2004); Brookhaven College (Brookhaven 2004);
Kansas Geological Survey (Kansas 2008); Montana Board
of Oil and Gas  Conservation (Montana 2008); Oklahoma
Geological Survey (Oklahoma 2008); Morgan Stanley
(Morgan Stanley 2005); Rocky Mountain Production Report
(Lippman (2003); New Mexico Oil Conservation Division
(New Mexico 2008a,b); Texas Railroad Commission (Texas
2008a-d); Utah Division of Oil, Gas and Mining (Utah 2008).
Emission factors were taken from EPA/GRI (1996). GTI's
Unconventional Natural Gas and Gas Composition Databases
(GTI2001) were used to adapt the CFLj emission factors into
non-combustion  related CO2 emission factors. Additional
information about CO2  content in transmission-quality
natural gas was obtained via the internet from numerous
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U.S. transmission companies to help further develop the
non-combustion CO2 emission factors.

Uncertainty
    A quantitative uncertainty analysis was conducted to
determine the level of uncertainty surrounding estimates of
emissions from natural gas systems. Performed using @RISK
software and the IPCC-recommended Tier 2 methodology
(Monte Carlo Simulation technique), this analysis 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 with 95 percent certainty the range within
which emissions from this source category are likely to
fall.
    The heterogeneous nature of the  natural gas industry
makes it difficult  to sample  facilities that are completely
representative of the entire industry. Because of this, scaling
up from model facilities introduces a degree of uncertainty.
Additionally, highly variable  emission rates were measured
among many system components, making the calculated
average emission rates uncertain. The results of the Tier 2
quantitative uncertainty analysis are summarized in Table
3-37. Natural gas  systems CH4 emissions in 2007  were
estimated to be between 79.7 and 150.2 Tg CO2 Eq. at a 95
percent confidence level. Natural gas  systems  non-energy
CO2 emissions in 2007 were estimated to be between 21.8
and 41.1 Tg CO2 Eq. at 95  percent confidence level.
                                  Recalculations Discussion
                                      In the previous Inventory, all activity factors  were
                                  estimated using base year activity factors and activity drivers
                                  even if activity data was publicly available for all years in
                                  the time series. This was done to maintain consistency of
                                  methodology across all sources. However, this resulted in
                                  discrepancy in the activity factors  in outer years. This is
                                  because activity data in the base year have been revised since
                                  the GPJ  activity factors were developed. Additionally,  the
                                  oil and gas industry has undergone  changes that do not  get
                                  reflected in the outer years, if the base year activity factors
                                  are driving the entire time series.
                                      Therefore, where direct activity data were available for
                                  activity factors, the activity factors  were replaced with  the
                                  direct data for all years to adapt the natural gas Inventory to
                                  publicly  available data and adjust the current Inventory to
                                  better reflect emissions from these  sources. Direct activity
                                  data are available for shallow water gas platforms, deep
                                  water gas platforms,  gas processing plants, transmission
                                  pipeline miles, distribution mains pipeline miles (by pipeline
                                  material), and distribution services (by pipeline material).
                                  This substitution resulted in a 3.5 to 4 percent increase in
                                  CH4 emissions in the inventory time series.
                                      The second recalculation is a result of changing several
                                  base year (1992) activity factors to re-estimated EPA/GPJ
                                  (1996). Methane Emissions from the Natural Gas Industry
                                  report base year activity factors. The GPJ study consists of
Table 3-37: Tier 2 Quantitative Uncertainty Estimates for CH4 and Non-energy C02 Emissions from Natural Gas
Systems (Tg C02 Eq. and Percent)
  Source
         2007 Emission Estimate
Gas          (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                      (%)

Natural Gas Systems
Natural Gas Systems"

CH4
C02

104.7
28.7
Lower Bound0
79.7
21.8
Upper Bound0
150.2
41.1
Lower Bound0
-24%
-24%
Upper Bound0
+43%
+43%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
  bAn uncertainty analysis for the non-energy C02 emissions was not performed. The relative uncertainty estimated (expressed as a percent) from the CH4
   uncertainty analysis was applied to the point estimate of non-energy C02 emissions.
  c All reported values are rounded after calculation. As a result, lower and upper bounds may not be duplicable from other rounded values as shown in table.
                                                                                                     Energy  3-45

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direct activity factors and derived activity factors. Direct
activity factors  refer to publicly available data, whereas
derived activity factors were obtained by extrapolating
sample data collected from the surveys to national estimates
using direct factors such as gas production, gas throughput,
etc. The base year derived activity factors were re-estimated
by updating the  1992 direct activity factor with the publicly
available data discussed in the previous paragraph.
    All other recalculations are  the result of updating the
previous Inventory activity data with revised values.

Planned Improvements
    Most of the activity factors and emission factors in the
natural gas model are from  the EPA/GRI (1996) study. A
study is currently underway to  review selected emission
factors in the natural gas industry, and as appropriate, conduct
measurement-based studies  to develop updated emission
factors to better reflect current national  circumstances.
Results from these studies  are expected in the next few
years, and will be incorporated into the Inventory, pending
a peer review.

3.6.  Petroleum Systems  (IPCC
Source Category 1B2a)
       j emissions from petroleum systems are primarily
associated with crude oil production, transportation,
and refining operations. During each of these activities,
CH4 emissions are released to the atmosphere as fugitive
emissions, vented emissions, emissions from  operational
upsets, and emissions from fuel combustion. Fugitive and
vented CO2 emissions from petroleum systems are primarily
associated with crude oil production and are negligible in
the transportation and refining operations. Combusted CO2
emissions are already accounted for in the Fossil Fuels
Combustion source category, and hence have not been taken
into account in the Petroleum Systems source category. Total
CFLj and CO2 emissions from petroleum systems in 2007
were 28.8 Tg CO2 Eq. (1,370 Gg CH4) and 0.3 Tg CO2 (287
Gg), respectively. Since 1990, CH4 emissions have declined
by 15 percent, due to industry efforts to reduce emissions
and a decline in domestic oil production (see Table 3-38 and
Table 3-39). Carbon dioxide emissions have also declined
by 24 percent since 1990 due to similar reasons (see Table
3-40 and Table 3-41).
    Production Field Operations. Production field operations
account for almost 98 percent of total CFLj emissions from
petroleum systems. Vented CF^ from field operations account
for 91.5 percent  of the emissions from  the production
sector, unburned CH4 combustion emissions account for 5.2
percent, fugitive emissions are 3.2 percent, and process upset
emissions are slightly over two-tenths of a percent. The most
dominant sources  of emissions, in order of magnitude, are
shallow water offshore oil platforms, natural-gas-powered
pneumatic devices (low bleed and high bleed), field storage
tanks, gas engines, chemical injection pumps and deep water
offshore platforms. These seven sources alone emit over 95
percent of the production field operations emissions. Offshore
platform emissions are a combination of fugitive, vented,
and unburned fuel combustion emissions from all equipment
housed on oil platforms producing oil and associated gas.
Emissions from high and low-bleed pneumatics occur when
pressurized gas that is used for control devices is bled to the
atmosphere as they cycle open and closed  to modulate the
system.  Emissions from storage tanks occur when the CFLj
entrained in crude oil under pressure  volatilizes  once the
crude oil is put into storage  tanks at atmospheric  pressure.
Emissions from gas engines are due to unburned  CH4 that
vents with the exhaust. Emissions from chemical  injection
pumps are due to  the 25 percent that use associated gas to
drive pneumatic pumps. The remaining five percent of the
emissions are  distributed among 26 additional activities
within the four categories: vented, fugitive,  combustion and
process  upset emissions. For more detailed, source-level
data on CFLj emissions in production field operations, refer
to Annex 3.5.
    Vented CO2  associated with  natural gas emissions
from field operations account for  99  percent of the  total
CO2 emissions from this source category, while fugitive
and process upsets together account for 1 percent of the
emissions. The most dominant sources of vented emissions
are field storage tanks, pneumatic devices (high bleed and low
bleed), shallow water offshore oil platforms, and  chemical
injection pumps. These five sources together account for
98.5 percent of the non-combustion CO2  emissions from
this source category, while the remaining 1.5 percent of the
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Table 3-38: CH4 Emissions from Petroleum Systems (Tg C02 Eq.)
  Stage
 1990
1995
2000
2005
2006
2007
  Production Field Operations
    Pneumatic Device Venting
    Tank Venting
    Combustion & Process Upsets
    Misc. Venting & Fugitives
    Wellhead Fugitives
  Crude Oil Transportation
  Refining
                                            27.6
                                             8.3
                                             2.8
                                             1.5
                                            14.5
                                             0.4
                                             0.1
                                             0.6
                                        27.6
                                         8.3
                                         2.8
                                         1.5
                                        14.6
                                         0.4
                                         0.1
                                         0.6
                                    28.1
                                     8.4
                                     2.8
                                     1.5
                                    15.0
                                     0.4
                                     0.1
                                     0.6
  Total
 33.9
32.0
30.3
  Note: Totals may not sum due to independent rounding.
Table 3-39: CH4 Emissions from Petroleum Systems (Gg)
 28.3
 28.3
 28.8
  Stage
 1990
              2000
  Production Field Operations
    Pneumatic Device Venting
    Tank Venting
    Combustion & Process Upsets
    Misc. Venting & Fugitives
    Wellhead Fugitives
  Crude Oil Transportation
  Refining
   25
  Total
1,613
               2005
           2006
                                       1,314
                                        396
                                        135
                                         71
                                        694
                                         17
                                          5
                                         28
                            1,346      1,346
           2007
                                   1,338
                                     398
                                     135
                                      72
                                     716
                                      18
                                       5
                                      27
                                   1,370
  Note: Totals may not sum due to independent rounding.
Table 3-40: C02 Emissions from Petroleum Systems (Tg C02 Eq.)
Stage
Production Field Operations
Pneumatic Device Venting
Tank Venting
Misc. Venting & Fugitives
Wellhead Fugitives
Total
1990
0.4
0.3
+
+
0.4
1995
0.3
0.3 1
+ 1
+
0.3
2000
0.3
0.3 1
+ 1
+
0.3
2005
0.3
+
0.2
+
+
0.3
2006
0.3
+
0.2
+
+
0.3
2007
0.3
+
0.2
+
+
0.3
+ Less than 0.05 Tg C02 Eq.
Table 3-41: C02 Emissions from Petroleum Systems (Gg)
  Stage
 1990
              2000
  Production Field Operations
      Pneumatic Device Venting
      Tank Venting
      Misc. Venting & Fugitives
      Wellhead Fugitives
               2005
                                            287
                                             22
                                            248
                                             16
                                               1
           2006
                                        288
                                         22
                                        249
                                         16
                                           1
           2007
                                     287
                                      22
                                     247
                                      16
                                       1
  Total
  376
 341
 325
 287
 288
 287
  Note: Totals may not sum due to independent rounding.
                                                                                                         Energy  3-47

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emissions is distributed among 24 additional activities within
the three categories: vented, fugitive and process upsets.
    Crude Oil Transportation. Crude oil transportation
activities account for less than one half of one percent of
total CH4 emissions from the oil industry. Venting from tanks
and marine vessel loading operations accounts for 62 percent
of CH4 emissions from crude oil  transportation. Fugitive
emissions, almost entirely from floating roof tanks, account
for 19percent. The remaining 19percentis distributed among
six additional sources within these two categories. Emissions
from pump engine drivers and heaters were not estimated
due to lack of data.
    Crude Oil Refining. Crude oil refining processes and
systems account for slightly less than two percent of total
CH4 emissions from the oil industry because most of the
CtLj in crude oil is removed or escapes before the crude oil
is delivered to the refineries. There is an insignificant amount
of CtLj in all refined products. Within refineries, vented
emissions account for about 87 percent of the emissions,
while fugitive and combustion  emissions account for
approximately six and seven percent, respectively. Refinery
system blow downs for maintenance and the process of asphalt
blowing—with air, to harden the asphalt—are the primary
venting contributors. Most  of the  fugitive CK4 emissions
from refineries are from leaks in the fuel gas system. Refinery
combustion emissions include small amounts of unburned
CH4 in process heater stack emissions and unburned CH4 in
engine exhausts and flares.

Methodology
    The methodology for estimating CH4 emissions
from petroleum  systems is a bottom-up approach, based
on comprehensive studies of CH4 emissions from U.S.
petroleum systems (EPA  1996, EPA 1999).  These studies
combined emission estimates from 64 activities occurring
in petroleum systems from the oil  wellhead through crude
oil refining, including 33 activities  for crude oil production
field operations,  11 for crude oil transportation activities,
and 20 for refining operations. Annex 3.5 provides greater
detail on the emission estimates for these 64 activities. The
estimates of CH4 emissions from petroleum systems do
not include emissions downstream  of oil refineries because
these emissions are very small compared to CH4 emissions
upstream of oil refineries.
    The methodology for estimating CH4 emissions from the
64 oil industry activities employs emission factors initially
developed by EPA (1999) and activity factors that are based
on three EPA studies (1996, 1999 and 2005). Emissions are
estimated for each activity by multiplying emission factors
(e.g., emission rate per equipment item or per activity) by
their corresponding activity factor (e.g., equipment count or
frequency of activity). The report provides emission factors
and activity factors for all activities except those related to
offshore oil production and field storage tanks. For offshore
oil production, two emission factors  were calculated using
data collected over a one-year period for all federal offshore
platforms (EPA 2005, MMS 2004). One emission factor is
for oil platforms in shallow water, and one emission factor
is for oil platforms in deep water. Emission factors are held
constant for the period 1990 through 2007. The number of
platforms in shallow water and the number of platforms in
deep water are used as activity factors and are taken from
Minerals Management Service statistics (MMS  2008a-c).
For oil storage  tanks, the emissions  factor was calculated
from API TankCalc data as the total emissions per barrel of
crude charge (EPA 1999).
    The methodology for estimating CO2 emissions from
petroleum systems combines vented, fugitive and process
upset emissions sources from 29 activities for  crude oil
production field operations. Emissions are estimated for
each activity by multiplying  emission factors by their
corresponding activity factors. The emission factors for CO2
are estimated by multiplying the CH4 emission factors by
a conversion factor, which is the ratio of CO2 content and
CH4 content in produced associated gas. The only exceptions
to this methodology are the  emission factors for crude
oil storage tanks, which are obtained from API  TankCalc
simulation runs.
    Activity factors for the years 1990 through 2007 were
collected from a wide variety of statistical resources.  For
some years, complete activity factor data were not available.
In such cases, one of three approaches was employed. Where
appropriate, the activity factor was calculated from related
statistics using ratios developed for EPA (1996). For example,
EPA (1996) found that the number of heater treaters (a source
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of CH4 emissions) is related to both number of producing
wells and annual production. To estimate the activity factor
for heater treaters, reported statistics for wells and production
were used, along with the ratios developed for EPA (1996).
In other cases, the activity factor was held constant from
1990 through 2007 based on EPA(1999). Lastly, the previous
year's data were used when data for the current year were
unavailable. The  CK4 and CO2 sources  in  the production
sector share common activity factors. See  Annex 3.5 for
additional detail.
     Nearly all emission factors were taken from EPA (1995,
1996,  1999). The remaining  emission factors were taken
from EPA default values in (EPA 2005) and the consensus
of industry peer review panels.
     Among the more important references  used to obtain
activity factors are the Energy Information Administration
annual and monthly reports (EIA 1990 through 2007, 1990
through 2008, 1995 through 2008a-b), Methane Emissions
from the Natural Gas Industry by the Gas Research Institute
and EPA (EPA/GRI 1996a-d), Estimates  of Methane
Emissions from the U.S. Oil Industry (EPA 1999), consensus
of industry peer review panels, MMS reports (MMS 2001,
2008a-c), analysis of MMS data (EPA 2005, MMS 2004),
the Oil & Gas Journal (OGJ 2008a,b), the Interstate Oil and
Gas Compact Commission (IOGCC 2008),  and the United
States Army Corps of Engineers (1995-2008).

Uncertainty
     This section describes the analysis conducted to quantify
uncertainty associated with the estimates of emissions from
petroleum systems. Performed using @RISK software and
the IPCC-recommended Tier 2 methodology (Monte Carlo
                                 Simulation technique), the method employed 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 provide
                                 the range within which, with 95 percent certainty, emissions
                                 from this source category are likely to fall.
                                     The detailed, bottom-up inventory analysis used to
                                 evaluate U.S. petroleum systems reduces the uncertainty
                                 related to the CH4  emission  estimates in comparison to
                                 a top-down approach. However, some uncertainty still
                                 remains. Emission factors and activity factors are  based on
                                 a combination of measurements, equipment design data,
                                 engineering calculations and  studies, surveys of selected
                                 facilities and statistical reporting. Statistical uncertainties
                                 arise from natural variation in measurements,  equipment
                                 types, operational variability and survey and statistical
                                 methodologies. Published activity factors are not available
                                 every year for  all 64 activities analyzed for  petroleum
                                 systems; therefore, some are estimated. Because  of the
                                 dominance of the seven major sources,  which account for
                                 93.1 percent of the total methane emissions, the uncertainty
                                 surrounding these seven sources has been estimated most
                                 rigorously, and serves as the basis for determining the overall
                                 uncertainty of petroleum systems emission estimates.
                                     The results of the Tier  2 quantitative uncertainty
                                 analysis are summarized in Table 3-42. Because the top
                                 emission sources have not changed from 2006, the relative
                                 uncertainty ranges computed for 2006 and published in the
                                 previous Inventory were taken as valid  and applied to the
                                 2007 inventory emission estimates. Petroleum systems CH^
                                 emissions in 2007 were estimated to be between  20.7 and
                                 70.2 Tg CO2 Eq., while CO2 emissions were estimated to be
Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CH4 and C02 Emissions from Petroleum Systems
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas          (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                     (%)

Petroleum Systems
Petroleum Systems

CH4
C02

28.8
0.3
Lower Bound"
20.7
0.2
Upper Bound"
70.2
0.7
Lower Bound"
-28%
-28%
Upper Bound"
+ 144%
+ 144%
  a Range of 2006 relative uncertainty predicted by Monte Carlo Stochastic Simulation, based on 1995 base year activity factors, for a 95 percent confidence
   interval.
  b All reported values are rounded after calculation. As a result, lower and upper bounds may not be duplicable from other rounded values as shown in table.
                                                                                                  Energy  3-49

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Box 3-3: Carbon Dioxide Transport, Injection, and Geological Storage

      Carbon dioxide is produced, captured, transported, and used for Enhanced Oil Recovery (EOR) as well as commercial and non-EOR
  industrial applications. This C02 is produced from both naturally-occurring C02 reservoirs and from industrial sources such as natural
  gas processing plants and ammonia plants. In the current Inventory, emissions from naturally-produced C02 are estimated based on
  the application.
      In the current Inventory, the C02 that is used in non-EOR industrial and commercial applications  (e.g., food  processing, chemical
  production)  is assumed to be emitted to the atmosphere during its  industrial use.  These  emissions are discussed in the Carbon Dioxide
  Consumption section. The naturally-occurring C02 used in EOR operations is assumed to be fully sequestered. Additionally, all anthropogenic
  C02 emitted from natural gas processing and ammonia plants is assumed to be emitted to the atmosphere, regardless of whether the C02 is
  captured or not. These emissions are currently included in the Natural Gas Systems and the Ammonia Production sections of the Inventory,
  respectively.
      IPCC (2006) includes, for the first time, methodological guidance to estimate emissions from the  capture, transport, injection, and
  geological storage of C02.  The methodology is based on the principle that the carbon capture and storage system should be  handled in a
  complete and consistent manner across the entire Energy sector. The approach accounts for C02 captured at natural  and industrial sites as
  well as emissions from capture, transport, and use. For storage specifically, a Tier 3 methodology is outlined for estimating and reporting
  emissions based on site-specific evaluations. However, IPCC (2006) notes that if a national regulatory process exists, emissions information
  available through that process may support development of C02 emissions estimates for geologic storage.
      In October 2007, the U.S. EPA announced plans to develop regulations for geologic sequestration of C02 under the EPA Underground
  Injection Control Program. Given that the regulatory process is in its early phases, and site-specific emissions estimates are not yet available,
  emissions estimates from C02 capture, transport, injection and geologic storage are not yet included in national totals.  Preliminary estimates
  indicate that the amount of C02 captured from industrial and natural sites, as well as fugitive emissions from pipelines is 40.0 Tg  C02 (40,044
  Gg C02) (see Table 3-43 and Table 3-44).  Site-specific monitoring and reporting data for C02 injection sites (i.e., EOR operations) were not
  readily available; therefore, these estimates assume all C02 is emitted.


  Table 3-43: Potential Emissions from C02 Capture and Transport (Tg C02 Eq.)
Stage
Acid Gas Removal Plants
Naturally Occurring C02
Ammonia Production Plants
Pipelines Transporting C02
Total
1990
4.8
20.8
0.0
0.0
25.6
1995
3.7
22.5
0.7 B
0.0
26.9
2000
2.3
23.2
0.7 B
0.0
26.1
2005
6.0
28.3
0.7
0.0
34.9
2006
6.4
30.2
0.7
0.0
37.3
2007
6.3
33.1
0.7
0.0
40.0
  Table 3-44: Potential Emissions from C02 Capture and Transport (Gg)
Stage
Acid Gas Removal Plants
Naturally Occurring C02
Ammonia Production Plants
Pipelines Transporting C02
Total
1990
4,832
20,811
0
8
25,643
1995
3,672
22,547
676
8
26,896
2000
2,264
23,208
676
8
26,149
2005
5,992
8,267
676
7
34,935
2006
6,417
30,224
676
8
37,318
2007
6,282
33,086
676
8
40,044
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between 0.2 and 0.7 Tg CO2 Eq. at a 95 percent confidence
level. This indicates a range of 28 percent below to 144
percent above the 2007 emission estimates of 28.8 and 0.3
Tg CO2 Eq. for CFL, and CO2, respectively.

Recalculations Discussion
    All revisions were due to updating previous years' data
with revised data from existing data sources.

Planned Improvements
    As noted above, nearly all emission factors used in the
development of the petroleum systems estimates were taken
from EPA (1995, 1996, 1999), with the remaining emission
factors taken from EPA default values (EPA 2005) and a
consensus of industry peer review panels. These emission
factors will be reviewed as part of future inventory work.
Results of this review and analysis will be incorporated into
future Inventories, as appropriate.

3.7.  Incineration of Waste (IPCC
Source Category 1A5)

    Incineration is used to manage about 7 to 19 percent of
the solid wastes generated in the United States, depending on
the source of the estimate and the scope of materials included
in the definition of solid waste (EPA 2000b, Goldstein and
Matdes 2001, Kaufman et al. 2004a,  Simmons et al. 2006,
ArSova et al. 2008). In the context of this  section, waste
includes all municipal solid waste (MSW) as well as tires. In
the United States, almost all incineration of MSW occurs at
waste-to-energy facilities where useful energy is recovered,
and thus emissions from waste incineration are  accounted
for in the Energy chapter. Similarly, tires are combusted for
energy recovery in industrial and utility boilers. Incineration
of waste results in conversion of the organic inputs to CO2.
According to IPCC guidelines, when the CO2 emitted is of
fossil origin, it is counted as a net anthropogenic emission
of CO2 to  the atmosphere. Thus, the emissions from waste
incineration are calculated by estimating the quantity of waste
combusted and the fraction of the waste that is C derived
from fossil sources.
    Most of the organic materials in municipal solid wastes
are of biogenic origin (e.g.,  paper, yard trimmings), and
have their net C flows accounted for under the Land Use,
Land-Use Change, and Forestry chapter. However,  some
components —plastics, synthetic rubber, synthetic fibers, and
carbon black—are of fossil origin. Plastics in the U.S. waste
stream are primarily in the form of containers, packaging,
and durable goods. Rubber is found in durable goods, such
as carpets, and in non-durable goods, such as clothing and
footwear. Fibers in municipal solid wastes are predominantly
from clothing and home furnishings. As noted above, tires
(which contain rubber and carbon black) are also considered
a "non-hazardous" waste and are included in the waste
incineration estimate, though waste disposal practices for
tires differ from municipal solid waste (viz., most incineration
occurs outside of MSW combustion facilities).
    Approximately 32 million metric tons of waste was
incinerated in the United States in 2007 (EPA 2008). Carbon
dioxide emissions from incineration of waste rose 91 percent
since 1990, to an estimated 20.8 Tg CO2 Eq. (20,786 Gg)
in 2007, as the volume of synthetic fibers and other  fossil
C-containing materials in waste  increased (see Table 3-45
and Table 3-46). Waste incineration is also a source of N2O
emissions (De Soete 1993). Nitrous oxide emissions from
the incineration of waste were estimated to be 0.4 Tg CO2
Eq. (1 Gg N2O) in 2007, and have not changed significantly
since 1990.

Methodology
    Emissions of CO2 from the incineration of waste include
CO2 generated by the incineration of plastics, synthetic
fibers, and synthetic rubber, as well as the incineration of
synthetic rubber and carbon black in tires. These emissions
were estimated by multiplying the amount of each material
incinerated by the C content of the material and the fraction
oxidized (98 percent). Plastics incinerated in municipal solid
wastes were categorized into seven plastic resin types, each
                                                                                               Energy  3-51

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Table 3-45: C02 and N20 Emissions from the Incineration of Waste (Tg C02 Eq.)
  Gas/Stage
1990
1995
2000
2005
2006
2007
  C02
    Plastics
    Synthetic Rubber in Tires
    Carbon Black in Tires
    Synthetic Rubber in MSW
    Synthetic Fibers
                                        19.5
                                        12.8
                                         1.2
                                         1.6
                                         1.8
                                         2.2
                                         0.4
                                     19.8
                                     12.9
                                      1.2
                                      1.6
                                      1.8
                                      2.3
                                      0.4
                                  20.8
                                  13.6
                                   1.2
                                   1.6
                                   2.0
                                   2.4
                                   0.4
  Total
              16.2
              17.9
              19.9
          20.2
          21.2
Table 3-46: C02 and N20 Emissions from the Incineration of Waste (Gg)
  Gas/Stage
1990
1995
2000
2005
2006
2007
  C02
    Plastics
    Synthetic Rubber in Tires
    Carbon Black in Tires
    Synthetic Rubber in MSW
    Synthetic Fibers
  N20
                                      19,532
                                      12,782
                                       1,207
                                       1,579
                                       1,752
                                       2,212
                                           1
                                   19,824
                                   12,920
                                    1,207
                                    1,579
                                    1,788
                                    2,330
                                        1
                                20,786
                                13,622
                                 1,207
                                 1,579
                                 2,000
                                 2,378
                                    1
material having a discrete C content. Similarly, synthetic
rubber is categorized into three product types, and synthetic
fibers were categorized into four product types, each having
a discrete C content. Scrap  tires contain several types of
synthetic rubber, as well  as carbon black. Each type of
synthetic rubber has a discrete C content, and carbon black
is 100 percent C. Emissions  of CO2 were calculated based
on the number of scrap tires used for fuel and the synthetic
rubber and carbon black content of the tires.
    More detail on the  methodology  for  calculating
emissions from each of these waste incineration sources is
provided in Annex 3.6.
    For each of the methods used to calculate CO2 emissions
from the incineration of waste, data on the quantity of product
combusted and the C content of the product are needed. For
plastics, synthetic rubber, and synthetic fibers, the amount of
material in municipal solid wastes and its portion incinerated
were taken from the Characterization of Municipal Solid
Waste in the United States (EPA2000b, 2002, 2003, 2005a,
2006b, 2007,2008) and detailed unpublished backup data for
some years not shown in the reports (Schneider 2007). For
           synthetic rubber and carbon black in scrap tires, information
           was obtained from U.S. Scrap Tire Markets in the United
           States 2005 Edition (RMA 2006) and Scrap Tires, Facts
           and Figures (STMC 2000 through 2003, 2006).  For 2006
           and 2007, synthetic rubber data is set equal to 2005 due to a
           lack of more recently available data.
                Average C contents for the "Other" plastics category,
           synthetic rubber in municipal solid wastes, and synthetic
           fibers were calculated from 1998 production statistics,
           which divide their respective markets by chemical
           compound. Information about scrap tire composition was
           taken from the Scrap Tire Management Council's Internet
           site (STMC 2006).
                The assumption that 98 percent of organic C is oxidized
           (which applies to all waste incineration categories for CO2
           emissions) was reported in EPA's life cycle analysis of
           greenhouse gas emissions and sinks from management of
           solid waste (EPA 2006a).
                Incineration of waste also results in emissions of N2O.
           These emissions were calculated as a  function of the total
           estimated mass of waste incinerated and an emission factor.
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Table 3-47: Municipal Solid Waste Generation (Metric
Tons) and Percent Combusted
Year
1990
1995
2000
2001
2002
2003
2004
2005
2006
2007
Waste Generation
266,365,714
296,390,405
^^^^^^^^^^^H
371,071,109
353,086,962a
335,102,816
343,482,645"
351,862,474
363,274,720
374,686,965
374,686,965C
Incinerated (%)
11.5
10.0
^^^^^^^^^B
^^^^^^^^^H
7.0
7.4a
7.7
7.6b
7.4
7.2
6.9
6.9C
  'Interpolated between 2000 and 2002 values.
  b Interpolated between 2002 and 2004 values.
  c Assumed equal to 2006 value.
  Source: ArSova et al. (2008).
The N2O  emission estimates are based on different data
sources than the CO2 emission estimates. As noted above,
N2O emissions are a function of total waste incinerated in
each year; for 1990 through 2006, these data were derived
from the information published in BioCycle (ArSova et al.
2008). Data on total waste incinerated was not available for
2007, so this value was assumed to equal the most recent
value available (2006). Table 3-47 provides data on municipal
solid waste generation and percentage combusted for the
total waste stream. The emission factor of N2O emissions per
quantity of municipal solid waste combusted is an average of
values from IPCC's Good Practice Guidance (2000).

Uncertainty
    ATier 2 Monte Carlo analysis was performed to determine
the level of uncertainty surrounding  the estimates of CO2
emissions  and N,O emissions from the incineration of waste.
IPCC Tier 2 analysis allows the specification of probability
density functions for key variables within a computational
structure that mirrors the calculation of the inventory
estimate. Uncertainty estimates  and distributions for waste
generation variables (i.e., plastics, synthetic rubber, and textiles
generation) were obtained through a conversation with one of
the authors  of the Municipal Solid Waste in the United States
reports. Statistical analyses or expert judgments of uncertainty
were not available directly from the information sources for the
other variables; thus, uncertainty estimates for these variables
were determined using assumptions based on source category
knowledge  and the known uncertainty estimates for the waste
generation variables.
    The uncertainties in the waste incineration emission
estimates  arise from  both the assumptions applied to
the data and from the quality of the data. Key factors
include MSW incineration rate; fraction oxidized; missing
data on waste composition; average C content of waste
components; assumptions on the synthetic/biogenic C ratio;
and combustion conditions affecting N2O emissions. The
highest levels of uncertainty surround the variables that
are based on assumptions  (e.g., percent of clothing and
footwear composed of  synthetic rubber); the lowest levels
of uncertainty surround variables that were determined by
quantitative measurements (e.g., combustion efficiency, C
content of C black).
    The results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 3-48. Waste incineration
CO2 emissions in 2007 were estimated to be between 15.2
and 25.0 Tg CO2 Eq. at a 95 percent confidence level. This
indicates a  range of 27 percent below to 20 percent above
the 2007 emission estimate of 20.8 Tg CO2 Eq. Also at a 95
percent confidence level, Waste incineration N2O emissions
in 2007 were estimated to be between 0.1 and 1.2 Tg CO2
Table 3-48: Tier 2 Quantitative Uncertainty Estimates for C02 and N20 from the Incineration of Waste
(Tg C02 Eq. and Percent)
Source

Incineration of Waste
Incineration of Waste
2007 Emission Estimate Uncertainty Range Relative to Emission Estimate3
Gas (TgC02Eq.) (Tg C02 Eq.) (%)

C02
N20

20.8
0.4
Lower Bound
15.2
0.1
Upper Bound
25.0
1.2
Lower Bound
-27%
-71%
Upper Bound
+20%
+ 191%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                                  Energy  3-53

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Eq. This indicates a range of 71 percent below to 191 percent
above the 2007 emission estimate of 0.4 Tg CO2 Eq.

QA/QC and Verification
    A source-specific QA/QC plan was  implemented for
incineration of waste. This effort included a Tier 1 analysis,
as well as portions of a Tier 2 analysis. The Tier 2 procedures
that were implemented involved checks specifically focusing
on the activity data and specifically focused on the emission
factor and activity data sources and methodology used for
estimating  emissions from incineration of waste. Trends
across the time series were analyzed to determine whether
any corrective actions were needed. Actions were taken to
streamline the activity data throughout the incineration of
waste calculations.

Recalculations Discussion
    This emissions source  was previously known  as
Municipal Solid Waste Combustion.

Planned Improvements
    Additional data sources for calculating an N2O emission
factor for U.S. incineration of waste may be investigated. In
conjunction with its efforts to develop methods for reporting
              GHG emissions from various sources, the use of new
              techniques using radiochemistry methods to directly measure
              the fossil C content of flue gas from the incineration of waste
              may also be investigated.


              3.8.  Energy  Sources of  Indirect
              Greenhouse  Gas Emissions

                 In addition to  the main greenhouse gases addressed
              above, many energy-related activities generate emissions of
              indirect greenhouse gases. Total emissions of nitrogen oxides
              (NOX), carbon monoxide (CO), and non-CH^ volatile organic
              compounds (NMVOCs) from energy-related activities from
              1990 to 2007 are reported in Table 3-49.

              Methodology
                 These emission estimates were obtained from preliminary
              data (EPA 2008), 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
Table 3-49: NOX, CO, and NMVOC Emissions from Energy-Related Activities (Gg)
  Gas/Source
   1990
 1995
2000
2005
2006
2007
  NO,
    Mobile Combustion
    Stationary Combustion
    Oil and Gas Activities
    Incineration of Waste
    International Bunker Fuels3
  CO
    Mobile Combustion
    Stationary Combustion
    Incineration of Waste
    Oil and Gas Activities
    International Bunker Fuels3
  NMVOCs
    Mobile Combustion
    Stationary Combustion
    Oil and Gas Activities
    Incineration of Waste
    International Bunker Fuels3
 20,829
 10,920
  9,689
    139
    82
  2,020
125,640
119,360
  5,000
    978
    302
    130
 12,620
 10,932
    912
    554
    222
    61

20,429
10,622
 9,619
   100
                     14,129
                      8,271
                      5,445
                        316
                         98
                      1,719
                     64,876
                     58,322
                      4,792
                      1,438
                        323
                        130
                      8,198
                      5,954
                      1,470
                        535
                        239
                         54
                  13,687
                   7,831
                   5,445
                    314
                     97
                   1,712
                  61,231
                  54,678
                   4,792
                   1,438
                    323
                    127
                   7,903
                   5,672
                   1,470
                    526
                    234
                     54
  a These values are presented for informational purposes only and are not included or are already accounted for in totals.
  Note: Totals may not sum due to independent rounding.
3-54  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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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
    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.

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
bunker fuels under the UNFCCC, are currently not included
in national  emission totals,  but are reported  separately
based upon location of fuel sales. The decision to report
emissions from international bunker fuels separately, instead
of allocating them to a particular country, was made by the
Intergovernmental Negotiating Committee in establishing the
Framework Convention on Climate Change.39 These decisions
are reflected in the Revised 1996 IPCC Guidelines, as well as
the 2006 IPCC Guidelines, in which countries are requested
to report emissions from ships or aircraft that depart from their
ports with fuel purchased within national boundaries and are
engaged in international transport separately from national
totals (IPCC/UNEP/OECD/IEA  1997).40
    Greenhouse gases  emitted from the combustion of
international bunker fuels, like other fossil fuels, include CO2,
CH4 and N2O. Two transport modes are addressed under the
IPCC definition of international bunker fuels: aviation and
marine.41 Emissions from ground transport activities (by
road vehicles and trains), even when crossing international
borders, are allocated to the country where the fuel was
loaded into the vehicle  and, therefore,  are not counted as
bunker fuel emissions.
    The IPCC Guidelines distinguish between different
modes of air traffic. Civil aviation comprises aircraft used for
the commercial transport of passengers and freight, military
aviation comprises aircraft under the control  of national
armed forces, and general aviation applies to recreational and
small  corporate aircraft. The IPCC Guidelines further define
international bunker fuel use from civil  aviation as the fuel
combusted for civil (e.g., commercial) aviation purposes by
aircraft arriving or departing on international flight segments.
However, as mentioned above, and in keeping with the IPCC
Guidelines, only the fuel purchased in the United States and
used by aircraft taking-off (i.e., departing) from the United
States are reported here. The standard fuel used for civil
aviation is kerosene-type jet fuel, while the typical fuel used
for general aviation is aviation gasoline.42
    Emissions of CO2 from aircraft are essentially a
function of fuel use. Methane  and N2O emissions also
depend upon engine characteristics,  flight conditions,
and flight phase (i.e., take-off, climb, cruise, decent, and
landing). Methane is the product of incomplete combustion
and occurs mainly during the landing and take-off phases.
In jet  engines, N2O is primarily produced by the oxidation
of atmospheric nitrogen, and the majority of emissions
occur during the cruise phase. International marine
bunkers comprise emissions from fuels burned by ocean-
going ships of all  flags that are engaged in international
transport. Ocean-going ships  are generally classified
as cargo and passenger-carrying, military (i.e.,  Navy),
fishing, and miscellaneous support ships (e.g., tugboats).
For the  purpose of estimating greenhouse gas emissions,
39 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).
40 Note that the definition of international bunker fuels used by the UNFCCC
differs from that used by the International Civil Aviation Organization.
41 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).
42 Naphtha-type jet fuel was used in the past by the military in turbojet and
turboprop aircraft engines.
                                                                                                  Energy  3-55

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international bunker fuels are solely related to cargo and
passenger carrying vessels, which is the largest of the four       Emissions of CO2 were estimated by applying  C
categories, and military vessels. Two main types of fuels   content ^ fraction oxidized factors to fuel consumption
are used on sea-going vessels: distillate diesel fuel and   actiyity data This approach is analogous to that described
residual fuel oil. Carbon dioxide is the primary greenhouse   under ^ from Fossil Fud Combustion. Carbon content
gas emitted from marine shipping.                        aad fraction oxidized factors for jet fuel, distillate fuel oil,
    Overall, aggregate greenhouse gas emissions in 2007   and residual fuel oil  were taken directly from EIA and are
from the combustion of international  bunker fuels from   presented in Annex 2.1, Annex 2.2, and Annex 3.7 of this
both aviation and marine activities were 109.9 Tg CO2 Eq.,   Inventory. Density conversions were taken from Chevron
or five percent below emissions in 1990  (see Table 3-50   (2000), ASTM (1989), and USAF (1998). Heat content
and Table 3-51). Although  emissions  from international   for distillate fuel oil  and residual fuel oil were taken from
flights departing from the United States have increased (14   EIA (2008) and USAF (1998), and heat content for jet fuel
percent), emissions from international shipping voyages   was taken from EIA (2008). A complete description of the
departing the United States have  decreased by 18 percent   methodology and a listing of the various factors employed
since  1990. The majority of these emissions were  in the   can be found in Annex 2.1.  See Annex 3.7 for a specific
form of CO2; however, small amounts of CH^ and N2O were   discussion on the methodology used for estimating emissions
also emitted.                                              from international bunker fuel use by the U.S. military.

Table 3-50: C02, CH4, and N20 Emissions from International Bunker Fuels (Tg C02  Eq.)

  Gas/Mode                                    1990         1995         2000          2005      2006      2007
  C02                                         114.3        101.6         99.0         111.5     110.5      108.8
    Aviation                                    46.4         51.2         57.7          56.4      54.6       52.7
    Marine                                     68.0         50.4         41.3          55.1      56.0       56.0
  CH4                                           0.2          0.11         0.11         0.1       0.1        0.1
    Aviation                                      +1          +1         +1          +        +         +
    Marine                                      0.11         0.11         0.11         0.1       0.1        0.1
  N20                                           1.11         0.9           0.9           1.0       1.0        1.0
    Aviation                                     0.51         0.61         0.61         0.6       0.6        0.6
    Marine	05	04	03	0.4       0.4        0.4
  Total	115.6	102.7	100.0	112.7     111.7      109.9
  + Less than 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
Table 3-51: C02, CH4, and N20 Emissions from International Bunker Fuels (Gg)
  Gas/Mode                                    1990         1995         2000          2005      2006      2007
  C02
    Aviation
    Marine
  CH4
    Aviation
    Marine
  N20
    Aviation
    Marine	
  Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
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    Emission estimates for CK4 and N2O were calculated by
multiplying emission factors by measures of fuel consumption
by fuel type and mode. Emission factors used in the
calculations of CELj and N2O emissions were obtained from
the Revisedl 996IPCC Guidelines (IPCCIUNEPIOECDIIEA
1997). For aircraft emissions, the following values, in units
of grams of pollutant per kilogram of fuel consumed (g/kg),
were employed: 0.09  for CELj and  0.1 for N2O For marine
vessels consuming either distillate diesel or residual fuel oil
the following values (g/MJ), were employed: 0.32 for CFLj and
0.08 for N2O. Activity data for aviation included solely jet fuel
consumption statistics, while the marine mode included both
distillate diesel and residual fuel oil.
    Activity data on aircraft fuel consumption were derived
from FAA's System for assessing Aviation Global Emissions
(SAGE) Model  (FAA 2006).  International aviation bunker
fuel consumption from  1990-2007 was calculated by
assigning the difference between the sum of domestic
activity data (in TBtu) from  SAGE and the reported EIA
transportation jet fuel consumption  to the international
bunker fuel category for jet fuel from EIA (2008). Data on
U.S. Department of Defense (DoD) aviation bunker fuels and
total jet fuel consumed by the U. S. military was supplied by
the Office of the Under Secretary of Defense (Installations
and Environment), DoD. Estimates of the percentage of each
Service's total operations that were international operations
were developed by DoD. Military aviation bunkers included
international operations, operations conducted from
naval vessels at sea,  and  operations conducted from U.S.
            installations principally over international water in direct
            support of military operations at sea. Military aviation
            bunker fuel emissions were estimated using military fuel
            and operations data synthesized from unpublished data by
            the Defense Energy Support Center, under DoD's Defense
            Logistics Agency (DESC 2008). Together, the data allow the
            quantity of fuel used in military international operations to
            be estimated. Densities for each jet fuel type were obtained
            from a report from the U.S. Air Force (USAF 1998). Final jet
            fuel consumption estimates are presented in Table 3-52. See
            Annex 3.7 for additional discussion of military data.
                Activity data on distillate diesel and residual fuel oil
            consumption by cargo or passenger carrying marine vessels
            departing from U.S. ports were taken from unpublished
            data collected by the Foreign Trade Division of the  U.S.
            Department of Commerce's Bureau of the Census (DOC
            1991 through 2008) for 1990 through 2001, and 2007, and
            the Department of Homeland Security's Bunker Report for
            2003 through 2006 (DHS 2008). Fuel consumption data for
            2002 was  interpolated due to inconsistencies in reported
            fuel consumption data. Activity data on distillate diesel
            consumption by military vessels departing from U.S. ports
            were provided by DESC (2008). The total amount of fuel
            provided to naval vessels was reduced by 13 percent  to
            account for fuel used while the vessels were not-underway
            (i.e., in port). Data on the percentage of steaming hours
            underway versus  not-underway were provided by the  U.S.
            Navy. These fuel consumption estimates  are presented  in
            Table 3-53.
Table 3-52: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
  Nationality
 1990
 1995
 2000
 2005
 2006
 2007
  U.S. and Foreign Carriers
  U.S. Military
4,932
  862
5,462
  581
6,158
 480
6,022
 462
5,823
 400
5,629
 410
  Total
5,794
6,043
6,638
6,484
6,223
6,039
  Note: Totals may not sum due to independent rounding.
Table 3-53: Marine Fuel Consumption for International Transport (Million Gallons)
Fuel Type
Residual Fuel Oil
Distillate Diesel Fuel & Other
U.S. Military Naval Fuels
Total
1990
4,781
61/1
522
5,920
1995
3,495
5731
334
4,402
2000
2,967
290 1
329
3,586
2005
3,881
444
471
4,796
2006
4,004
446
414
4,864
2007
4,059
358
444
4,861
Note: Totals may not sum due to independent rounding.
                                                                                                Energy  3-57

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Uncertainty
    Emission estimates related to the  consumption
of international bunker fuels are subject to the same
uncertainties as those from domestic aviation and marine
mobile combustion emissions; however, additional
uncertainties result from the difficulty in collecting accurate
fuel consumption activity data for international transport
activities separate from domestic transport activities.43
For example, smaller aircraft on shorter routes often carry
sufficient fuel to complete several flight segments without
refueling in order to minimize time spent at the airport gate or
take advantage of lower fuel prices at particular airports. This
practice, called tankering, when done on international flights,
complicates the use of fuel sales data for estimating bunker
fuel emissions. Tankering is less common with the type of
large, long-range aircraft that make many international flights
from the United States, however. Similar practices occur in
the marine shipping industry where fuel costs represent a
significant portion of overall operating costs and fuel prices
vary from port to port, leading to some tankering from ports
with low fuel costs.
    Uncertainties exist with regard to the total fuel used by
military aircraft and ships, and in the activity data on military
operations and training that were used to estimate percentages
of total fuel use reported as bunker fuel  emissions. Total
aircraft and ship fuel use estimates  were developed from
DoD records, which document fuel sold to the Navy and
Air Force from the Defense Logistics Agency. These data
may slightly over or under estimate actual total fuel use in
aircraft and ships because each Service may have procured
fuel from, and/or may have sold to, traded with, and/or given
fuel to other ships, aircraft, governments,  or other entities.
There are uncertainties  in aircraft operations and training
activity data. Estimates for the quantity of fuel actually used
in Navy and Air Force flying activities reported as bunker
fuel emissions had to be estimated based on a combination
of available data and expert judgment. Estimates of marine
bunker fuel emissions were based on Navy vessel steaming
hour data, which reports fuel used while underway and fuel
used while not underway. This approach does not  capture
some  voyages  that would be classified as domestic for a
commercial vessel. Conversely, emissions from fuel used
while not underway preceding an international voyage are
reported as domestic rather than international as would be
done for a commercial vessel. There is uncertainty associated
with ground fuel estimates for 1997 through 2001. Small fuel
quantities may have been used in vehicles or equipment other
than that which was assumed for each fuel type.
    There are also uncertainties  in fuel  end-uses by fuel-
type,  emission factors, fuel densities, diesel fuel  sulfur
content, aircraft and vessel engine characteristics and fuel
efficiencies, and the methodology used to back-calculate
the data-set to 1990 using  the original set from 1995. The
data were adjusted for trends in fuel use based on a closely
correlating, but not matching, data set. All assumptions used
to develop the estimates were based on process knowledge,
department and military service data, and expert judgments.
The magnitude of the potential errors related to the various
uncertainties has not been calculated, but is believed to be
small. The uncertainties associated with future military
bunker fuel emission estimates could  be reduced through
additional data collection.
    Although aggregate fuel consumption data have been
used to estimate emissions from aviation, the recommended
method for estimating emissions of gases other than CO2 in
the Revised 1996IPCC Guidelines is to use data by specific
aircraft type  (IPCC/UNEP/OECD/IEA  1997). The  IPCC
also recommends that cruise altitude emissions be estimated
separately using fuel consumption data, while landing and
take-off (LTO) cycle data be used to estimate near-ground
level emissions of gases other than COj.44
    There is also concern as to the reliability of the existing
DOC (1991  through 2008) data on  marine  vessel fuel
consumption reported at U.S. customs stations due  to the
significant degree of inter-annual variation.
43 See uncertainty discussions under CO2 Emissions from Fossil Fuel
Combustion.
44U.S. aviation emission estimates for CO, NO,,, and NMVOCs are reported
by EPA's National Emission Inventory (NEI) Air Pollutant Emission
Trends web site, and reported under the Mobile Combustion section. It
should be noted that these estimates are based solely upon LTO cycles and
consequently only capture near ground-level emissions, which are more
relevant for air quality evaluations. These estimates also include both
domestic and international flights. Therefore, estimates reported under the
Mobile Combustion section overestimate IPCC-defmed domestic CO, NO,,,
and NMVOC emissions by including 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  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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QA/QC and Verification
    A source-specific QA/QC plan for international bunker
fuels was developed and implemented. This effort included
a Tier 1 analysis, as well as portions of a Tier 2 analysis. The
Tier 2 procedures that were implemented involved checks
specifically focusing on the activity data and emission
factor sources and methodology used for estimating CO2,
CH4, and N2O from international bunker fuels in the United
States.  Emission totals for the different sectors and fuels
were compared and trends were investigated. No corrective
actions were necessary.

Recalculations  Discussion
    Historical activity data for aviation was revised for both
U.S. and foreign carriers. International jet fuel bunkers are
now calculated in tandem with the domestic jet fuel estimates.
EPA performs the analysis  for domestic activity data (in
TBtu), as described in the CO2 from fossil fuel combustion
section, and, using that calculated total for domestic in
comparison with EIA's total consumption activity data,
assigns the remainder to the jet fuel bunkers consumption.
The previous method for international jet fuel bunkers were
calculated based upon DOT (1991 through 2008) and BEA
(1991 through 2005) data for the years 1990-1999 and
2006-2007 and estimated by FAA (2006) for 2000-2005.
That data is still collected and used to quality assure the
new method. The new method is understood to reduce
the uncertainty of the domestic emissions calculation, as
it relies on one dataset, rather than the multiple datasets
that were used in the previous method for international jet
fuel bunkers. Distillate and residual fuel oil consumption
by cargo or passenger carrying marine vessels from 2003
through 2006 was revised using DHS (2008), and 2002
distillate and residual fuel oil consumption was interpolated
to adjust inconsistencies in reported fuel consumption data.
These historical data changes resulted in changes  to the
emission estimates for 1990 through 2006, which averaged
to an annual increase in emissions from international bunker
fuels of 6.6 Tg CO2 Eq. (7.0 percent) in CO2 emissions, an
annual increase of less than 0.1 Tg CO2 Eq. (14 percent) in
CH4 emissions, and an annual increase of 0.1 Tg CO2 Eq.
(12 percent) in N2O emissions.

3.10.  Wood Biomassand
Ethanol Consumption
(IPCC Source Category 1 A)

    The combustion of biomass fuels such as wood, charcoal,
and wood waste and biomass-based fuels such as ethanol
from corn and woody crops generates CO2. However, in the
long run the CO2 emitted from biomass consumption does not
increase atmospheric CO2 concentrations, assuming that the
biogenic C emitted is offset by the uptake of CO2 that results
from the growth of new biomass. As a result, CO2 emissions
from biomass combustion have been estimated separately
from fossil fuel-based  emissions and are not included in
the U.S. totals. Net C fluxes from changes in biogenic C
reservoirs in wooded or crop lands are accounted for in the
Land Use, Land-Use Change, and Forestry chapter.
    In 2007, total CO2 emissions from the burning of woody
biomass in the industrial,  residential, commercial, and
electricity generation sectors were approximately  209.8 Tg
CO2 Eq. (209,785 Gg) (see Table 3-54 and Table 3-55). As
the largest consumer of woody biomass, the industrial sector
was responsible for 65 percent of the CO2 emissions from this
source. The residential sector was the second largest emitter,
constituting 23 percent of the total, while the commercial and
electricity generation sectors accounted for the remainder.
    Biomass-derived fuel consumption in the United States
consisted primarily of ethanol use in the transportation
sector. Ethanol is primarily produced from corn grown
in the Midwest, and was used mostly in the Midwest and
South. Pure ethanol can be combusted, or it can be mixed
with gasoline as a supplement  or octane-enhancing agent.
The most common mixture is a 90 percent gasoline, 10
percent ethanol blend known as gasohol. Ethanol and ethanol
blends are often used to fuel public transport vehicles such
as buses, or centrally fueled fleet vehicles. These fuels burn
cleaner than gasoline (i.e., lower in NOX and hydrocarbon
                                                                                             Energy  3-59

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Table 3-54: C02 Emissions from Wood Consumption by End-Use Sector (Tg C02 Eq.)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
135.3
59.8
6.8 1
13.3
215.2
1995
155.1
53.6
7.5l
12.9
229.1
2000
153.6
43.3
7.4
13.9
218.1
2005
136.3
46.4
7.2
19.1
208.9
2006
142.2
42.3
6.7
18.7
209.9
2007
136.7
47.4
6.7
18.9
209.8
  Note: Totals may not sum due to independent rounding.
Table 3-55: C02 Emissions from Wood Consumption by End-Use Sector (Gg)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
135,
59,
6,
13,
215,
348
808
779
252
186
1995
155,
53,
7,
12,
229,
075
621
463
932
091
2000
153,
43,
7,
13,
218,
559
309
370
851
088
2005
136
,269
46,402
7
19
208
,182
,074
,927
2006
142
42
6
18
209
,226
,278
,675
,748
,926
2007
136,729
47,434
6,675
18,947
209,785
  Note: Totals may not sum due to independent rounding.


emissions), and have been employed in urban areas with poor
air quality. However, because ethanol is a hydrocarbon fuel,
its combustion emits CO2.
    In 2007, the United  States consumed an estimated
577 trillion Btu of ethanol, and as a result, produced
approximately 38.0 Tg CO2 Eq. (38,044 Gg) (seeTable 3-56
and Table 3-57) of CO2 emissions. Ethanol production and
consumption has grown steadily every year since 1990, with
the exception of 1996 due to short corn supplies and high
prices in that year.
Methodology
    Woody biomass emissions were estimated by applying
two EIA gross heat contents (Lindstrom 2006) to U.S.
consumption data (EIA 2008) (see Table 3-58), provided in
energy units for the industrial, residential, commercial, and
electric generation sectors. One heat content (16.953114
MMBtu/MT wood and wood waste) was applied to  the
industrial sector's consumption, while the other heat content
(15432359 MMBtu/MT wood and wood waste) was applied
to the consumption data for the other sectors. An EIA
Table 3-56: C02 Emissions from Ethanol Consumption (Tg C02 Eq.)
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
4.1
0.1
+
4.2
1995
7.6
0.1 1
+
7.7
2000
9.1
°l
9.2
2005
22.0
0.5
0.1
22.6
2006
29.8
0.6
0.1
30.5
2007
37.2
0.8
0.1
38.0
  + Less than 0.05 Tg C02 Eq.
Table 3-57: C02 Emissions from Ethanol Consumption (Gg)
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
4,066
55
33
4,155
1995
7,570
1041
9
7,683
2000
9,077
85 1
25
9,188
2005
22,034
460
59
22,554
2006
29,758
622
80
30,459
2007
37,168
111
100
38,044
3-60  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 3-58: Woody Biomass Consumption by Sector (Trillion Btu)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
Table 3-59: Ethanol
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
1,442
580 1
eel
129
2,216
Consumption by Sector (Trillion Btu)
1990
61.7
0.8 1
0.5
63.0
1995
1,652
520 1
72 1
125
2,370

1995
114.8
1.6
0.1
116.5
2000
1,636
420 1
134
2,262

2000
137.6
1.3
0.4
139.3
2005
1,452
450
70
185
2,156

2005
334.1
7.0
0.9
342.0
2006
1,515
410
65
182
2,172

2006
451.2
9.4
1.2
461.9
2007
1,457
460
65
184
2,165

2007
563.6
11.8
1.5
576.9
emission factor of 0.434 MT C/MT wood (Lindstrom 2006)
was then applied to the resulting quantities of woody biomass
to obtain CO2 emission estimates. It was assumed that the
woody biomass contains black liquor and other wood wastes,
has a moisture content of 12 percent, and is converted into
CO2 with 100 percent efficiency. The emissions from ethanol
consumption were calculated by applying an EIA emission
factor of 17.99 Tg C/QBtu (Lindstrom 2006) to U.S. ethanol
consumption estimates  that were provided in energy units
(EIA 2008) (see Table 3-59).

Uncertainty
    It is assumed  that the combustion  efficiency for
woody biomass is  100 percent, which is  believed to be
an overestimate of the efficiency of wood combustion
processes in the United States. Decreasing the combustion
efficiency would decrease emission estimates. Additionally,
the heat content applied to the consumption of woody
biomass in the residential,  commercial, and electric
power sectors is unlikely to be a completely accurate
representation of the heat content  for all the different
types of woody biomass consumed within these sectors.
Emission estimates from ethanol production are more
certain than estimates from woody biomass consumption
due to better activity data collection methods and uniform
combustion techniques.

Recalculations  Discussion
    Wood consumption values were revised in 2001 through
2003, and 2005 through 2006 based on updated information
from EIA's Annual Energy Review (EIA 2008). EIA (2008)
also reported minor changes in wood consumption for
all sectors in 2006. This adjustment of historical data for
wood biomass consumption resulted in an average annual
increase in emissions from wood biomass consumption
of 0.6 Tg CO2 Eq. (0.3 percent) from 1990  through 2006.
Slight adjustments were made to ethanol consumption based
on updated information from EIA (2008), which slightly
decreased estimates for ethanol consumed. As a result of
these adjustments, average annual emissions from ethanol
consumption decreased by less than 0.1 Tg CO2 Eq. (less
than 0.1 percent).
                                                                                            Energy  3-61

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4.    Industrial   Processes
          Greenhouse gas emissions are produced as the byproducts of various non-energy-related industrial activities. That
          is, these emissions are produced from an industrial process itself and are not directly a result of energy consumed
          during the process. For example, raw materials can be chemically transformed from one state to another. This
transformation can result in the release of greenhouse gases such as carbon dioxide (CO2), methane (CH4), or nitrous oxide
(N2O). The processes addressed in this chapter include iron and steel production, cement production, lime production,
ammonia production and urea consumption, limestone and dolomite  use (e.g., flux stone, flue gas desulfurization, and
glass manufacturing), soda ash production and use, aluminum production, titanium dioxide production, CO2 consumption,
ferroalloy production, phosphoric acid production, zinc production, lead production, petrochemical production, silicon
carbide production and consumption, nitric acid production,  and adipic acid production (see Figure 4-1).
    In addition to the three greenhouse gases  listed
above, there are also  industrial sources of man-made
fluorinated compounds called hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The
present contribution of these gases to the radiative forcing
effect of all anthropogenic greenhouse gases  is  small;
however, because of their extremely long lifetimes, many
of them will continue to accumulate in the atmosphere as
long as emissions continue. In addition, many of these gases
have high global warming potentials; SF6 is the most potent
greenhouse gas the Intergovernmental Panel on Climate
Change (IPCC) has evaluated.  Usage of HFCs for the
substitution of ozone depleting substances is growing rapidly,
as they  are the primary substitutes for ozone  depleting
substances (ODSs), which are being phased-out  under the
Montreal Protocol on Substances that Deplete the  Ozone
Layer. In addition to their use as ODS substitutes,  HFCs,
PFCs, SF6, and other fluorinated compounds are employed
and emitted by a number of other industrial sources in the
United States. These industries include aluminum production,
HCFC-22 production, semiconductor manufacture, electric
power transmission and distribution, and magnesium metal
production and processing.
    In 2007, industrial processes generated emissions of 353.8
teragrams of CO2 equivalent (Tg  CO2 Eq.), or 5 percent of
Figure 4-1
           2007 Industrial Processes Chapter
           Greenhouse Gas Emission Sources
   Substitution of Ozone Depleting Substances
           Iron and Steel Production &
          Metallurgical Coke Production
               Cement Production
              Nitric Acid Production  |
               HCFC-22 Production  f
                 Lime Production  |
  Ammonia Production and Urea Consumption  |
     Electrical Transmission and Distribution  |
              Aluminum Production  |
           Limestone and Dolomite Use  |
              Adipic Acid Production  |
           Semiconductor Manufacture  |
     SodaAsb Production and Consumption
            Petrocbemical Production
     Magnesium Production and Processing
           Titanium Dioxide Production
           Carbon Dioxide Consumption
              Ferroalloy Production
           Pbospboric Acid Production
                 Zinc Production
                 Lead Production  | <0.5
  Silicon Carbide Production and Consumption  I <0.5
Industrial Processes
  as a Portion of
  all Emissions
                          0
                              25
                                  50   75
                                   TgCO,Eq.
                                          100  125
                                                                                    Industrial Processes  4-1

-------
total U.S. greenhouse gas emissions. Carbon dioxide emissions
from all industrial processes were 174.9 Tg CO2 Eq. (174,939
Gg) in 2007, or 3 percent of total U.S. CO2 emissions. CH4
emissions from industrial processes resulted in emissions of
approximately 1.7 Tg CO2 Eq. (82 Gg) in 2007, which was less
than 1 percent of U.S. CFLj emissions. Nitrous oxide emissions
from adipic acid and nitric acid production were 27.6 Tg CO2
Eq. (89 Gg) in 2007, or 9 percent of total U.S. N2O emissions.
In 2007, combined emissions of HFCs, PFCs and SF6 totaled
149.5 Tg CO2 Eq. Overall, emissions from industrial processes
increased by 9 percent from 1990 to 2007 despite decreases in
emissions from several industrial processes, such as cement
production, lime production, limestone and dolomite use, soda
ash production and consumption, and electrical transmission
and distribution. The increase  in overall emissions was
driven by a rise in the emissions originating from HCFC-
22 production and, primarily, the emissions from the use of
substitutes for ozone depleting substances.
    Table 4-1 summarizes emissions for the Industrial
Processes chapter in units of Tg CO2 Eq., while unweighted
native gas emissions in Gg are provided in Table 4-2. The
source descriptions that follow in the chapter are presented
in the order as reported to  the UNFCCC in the  common
reporting format tables, corresponding generally to: mineral
products,  chemical production, metal production, and
emissions from the uses of HFCs, PFCs, and SF6.

QA/QC and Verification Procedures
    Tier 1 quality assurance and quality control procedures
have been performed for all industrial process sources. For
industrial process  sources of CO2 and CH4 emissions, a
detailed plan was developed and implemented. This plan
was based  on U.S. strategy,  but was tailored to include
specific procedures recommended for these  sources. Two
types of checks were performed using this plan: (1) general,
or Tier 1, procedures that focus on annual procedures and
checks to be used  when gathering, maintaining, handling,
documenting, checking and archiving the data, supporting
documents, and  files, and (2) source-category specific, or
Tier 2, procedures that focus on procedures and checks of the
emission factors, activity data, and methodologies used for
estimating emissions from the relevant Industrial Processes
sources. Examples of these procedures  include, among
others, checks to ensure that activity data and emission
estimates are consistent  with historical trends; that, where
possible, consistent and reputable data sources are used
across sources; that interpolation or extrapolation techniques
are consistent across sources; and that common datasets and
factors are used where applicable.
    The general method employed to estimate emissions
for industrial processes, as recommended by the IPCC,
involves multiplying production data (or activity data) for
each process by an emission factor per unit of production.
The  uncertainty in the emission  estimates is therefore
generally a function of a combination of the uncertainties
surrounding the production and emission factor variables.
Uncertainty of activity data and the associated probability
density functions for industrial processes CO2 sources were
estimated based on expert assessment of available qualitative
and quantitative information. Uncertainty estimates and
probability density functions for the emission factors used
to calculate emissions from this source were devised based
on IPCC recommendations.
    Activity datais obtained through a survey of manufacturers
conducted by various organizations (specified within each
source); the uncertainty of the activity data is a function of
the reliability of plant-level production data and is influenced
by the  completeness of the  survey response. The emission
factors used were  either derived using calculations that
assume precise and efficient chemical reactions, or were
based upon empirical data in published references. As a result,
uncertainties in the emission coefficients can be attributed
to, among other things, inefficiencies in the chemical
reactions associated with each production process or to the
use of empirically-derived emission factors that are biased;
therefore, they may not represent U.S. national averages.
Additional assumptions are described within each source.
    The uncertainty analysis performed to quantify
uncertainties associated with the 2007 inventory estimates
from industrial processes continues a multi-year  process
for developing credible quantitative uncertainty estimates
for these source categories using the IPCC Tier 2 approach.
As the process continues, the type and the characteristics
of the  actual probability density functions underlying
the input variables are identified and better characterized
(resulting in development of more reliable inputs for  the
model, including accurate characterization of correlation
between variables), based primarily on expert judgment.
Accordingly, the quantitative uncertainty estimates reported
in this section should be considered illustrative and as
4-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-1: Emissions from Industrial Processes (Tg C02 Eq.)
  Gas/Source
 1990
 1995
 2000
  Total
325.2
345.8
356.3
 2005
337.6
 2006
343.9
 2007
  C02                                             197.6         198.6          193.2          171.1       175.9      174.9
    Iron and Steel Production and Metallurgical
     Coke Production                               109.8         103.1           95.1            73.2        76.1        77.4
      Iron and Steel Production                      104.3          98.1           90.7           69.3        72.4        73.6
      Metallurgical Coke Production                    5.sl         5.ol         4.^1          3.8         3.7         3.8
    Cement  Production                               33.3          36.8           41.2           45.9        46.6        44.5
    Ammonia Production & Urea Consumption          16.8          17.8           16.4           12.8        12.3        13.8
    Lime Production                                 11.5          13.3           14.1            14.4        15.1        14.6
    Limestone and Dolomite Use                        5.11         6.71         5.11          6.8         8.0         6.2
    Aluminum Production                              6.8           5.71         6.11          4.1         3.8         4.3
    Soda Ash Production and Consumption              4.11         4.sB         4.2!          4.2         4.2         4.1
    Petrochemical Production                          2.2           2.8            3.01          2.8         2.6         2.6
    Titanium Dioxide Production                        1.2           1.51         1.81          1.8         1.9         1.9
    Carbon Dioxide Consumption                       1.4           1.4            1.4            1.3         1.7         1.9
    Ferroalloy Production                              2.2           2.01         1.91          1.4         1.5         1.6
    Phosphoric Acid Production                        1.51         1.51         1.4            1.4         1.2         1.2
    Zinc Production                                   0.91         1.01         1.11          0.5         0.5         0.5
    Lead Production                                  0.31         0.31         0.31          0.3         0.3         0.3
    Silicon Carbide Production  and Consumption          0.4!         0.31         0.2!          0.2         0.2         0.2

    Petrochemical Production                          0.91         1.11          1.2            1.1         1.0         1.0
    Iron and Steel Production and Metallurgical
     Coke Production                                 1.0           1.0            0.9            0.7         0.7         0.7
      Iron and Steel Production                        7.ol         7.ol         O.sl          0.7         0.7         0.7
      Metallurgical Coke Production                     +1           +1           +1           +          +          +
    Ferroalloy Production                               +1           +1           +1           +          +          +
    Silicon Carbide Production  and Consumption           +              +1           +1           +          +          +
  N20                                              35.3          39.6           28.1            24.6        24.2        27.6
    Nitric Acid Production                             20.0          22.3           21.9           18.6        18.2        21.7
    Adipic Acid Production                            15.3          17.3            6.2            5.9         5.9         5.9
  MFCs                                             36.9          61.8          100.1           116.1       119.1      125.5
    Substitution of Ozone Depleting Substances3          0.31        28.5           71.2          100.0       105.0       108.3
    HCFC-22 Manufacture                            36.4          33.0           28.6           15.8        13.8        17.0
    Semiconductor Manufacturing MFCs                 0.2!         0.31         0.31          0.2         0.3         0.3
  PFCs                                             20.8          15.6           13.5            6.2         6.0         7.5
    Aluminum Production                             18.5          11.8            8.6            3.0         2.5         3.8
    Semiconductor Manufacturing PFCs                 2.2           3.8            4.91          3.2         3.5         3.7
  SF6                                              32.8          28.1           19.2           17.9        17.1        16.5
    Electrical Transmission  and Distribution             26.8          21.6           15.1            14.0        13.2        12.7
    Magnesium Production  and Processing              5.41         5.eB         3.0            2.9         2.9         3.0
    Semiconductor Manufacturing SF6                   0.51         0.91         1.11          1.0         1.0         0.8
353.8
  + Does not exceed 0.05 Tg C02 Eq.
  a Small amounts of RFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
iterations of ongoing efforts to produce accurate uncertainty
estimates. The correlation among data used for estimating
emissions for different sources can influence the uncertainty
analysis of each individual source. While the uncertainty
             analysis  recognizes very significant connections  among
             sources, a more comprehensive approach that accounts for
             all linkages will be identified as the uncertainty analysis
             moves forward.
                                                                                               Industrial Processes  4-3

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Table 4-2: Emissions from Industrial Processes (Gg)
  Gas/Source
1990
1995
2000
2005
2006
2007
  C02                                          197,623
    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
    Aluminum Production
    Soda Ash Production and Consumption
    Petrochemical Production
    Titanium Dioxide Production
    Carbon Dioxide Consumption
    Ferroalloy 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
  N20
    Nitric Acid Production
    Adipic Acid Production
  MFCs
    Substitution of Ozone Depleting Substances3
    HCFC-22 Manufacture
    Semiconductor Manufacturing MFCs
  PFCs
    Aluminum Production
    Semiconductor Manufacturing PFCs
  SF6
    Electrical Transmission and Distribution
    Magnesium Production and Processing
    Semiconductor Manufacturing SF6
  + Does not exceed 0.5 Gg.
  M (Mixture of gases).
  a Small amounts of RFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
            198,584

            103,116
             98,078
              5,037
             36,847
             17,796
             13,325
              6,651
            193,217

             95,062
             90,680
              4,381
             41,190
             16,402
             14,088
              5,056
            171,075    175,897    174,939
             73,190
             69,341
              3,849
             45,910
             12,849
             14,379
              6,768
              4,142
              4,228
              2,804
              1,755
              1,321
              1,392
              1,386
                465
                266
                219
                 86
                 51

                 34
                 34
                                              79
                                              60
                                              19
                                              M
                                              M
                                               1

                                              M
                                              M
                                              M
                                               1
                                               1
         76,100
         72,418
          3,682
         46,562
         12,300
         15,100
          8,035
          3,801
          4,162
          2,573
          1,876
          1,709
          1,505
          1,167
            529
            270
            207
             83
             48

             35
             35
                                          78
                                          59
                                          19
                                           M
                                           M
                                           1

                                           M
                                           M
                                           M
                                           1
                                           1
         77,370
         73,564
          3,806
         44,525
         13,786
         14,595
          6,182
          4,251
          4,140
          2,636
          1,876
          1,867
          1,552
          1,166
            530
            267
            196
             82
             48

             33
             33
                                       89
                                       70
                                       19
                                       M
                                       M
                                        1

                                       M
                                       M
                                       M
                                        1
                                        1
4-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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4.1.  Cement Production
(IPCC Source Category  2A1)

    Cement production is an energy- and raw-material-
intensive process that results in the generation of CO2 from
both the  energy consumed in making the cement and the
chemical process itself.1 Cement is produced in 37 states
and Puerto Rico. Carbon dioxide emitted from the chemical
process of cement production is the second largest source of
industrial CO2 emissions in the United States.
    During the cement production proces s, calcium carbonate
(CaCO3) is heated in a cement kiln at a temperature of 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 calcining. A
very small amount of carbonates other than CaCO3 and non-
carbonates are also present in the raw material; however, for
calculation purposes all of the raw material is assumed to be
CaCO3. Next, the lime is combined with silica-containing
materials to produce clinker (an intermediate product), with
the earlier byproduct CO2 being released to the atmosphere.
The  clinker  is then allowed to  cool, mixed with a small
amount of gypsum, and potentially  other materials (e.g.,
slag) and used to make portland cement.2
    In 2007, U.S. clinker production—including  Puerto
Puco—totaled 86,106 thousand metric tons (van Oss 2008b).
The resulting emissions of CO2 from 2007 cement production
were estimated to be  44.5 Tg CO2 Eq. (44,525 Gg) (see
Table 4-3).
    After falling in 1991 by 2 percent  from 1990 levels,
cement production emissions grew every year through 2006,
and then decreased slightly from 2006 to 2007. Overall, from
1990 to 2007, emissions increased by 34 percent. Cement
continues to be a critical component of the construction
industry; therefore, the availability of public construction
Table 4-3: C02 Emissions from Cement Production
(Tg C02 Eq. and Gg)
1 The CO2 emissions related to the consumption of energy for cement
manufacture are accounted for under CO2 from Fossil Fuel Combustion
in the Energy chapter.
2 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. Carbon dioxide emissions that result
from the production of lime used to create masonry cement are included in
the Lime Manufacture source category (van Oss 2008c).
        Year
Tg C02 Eq.
  Gg
        1990
  33.3
33,278
        2005
        2006
        2007
                  45,910
                  46,562
                  44,525
funding, as well as overall economic growth, have had
considerable influence on cement production.

Methodology
    Carbon dioxide emissions from cement production
are created by the chemical reaction of carbon-containing
minerals (i.e., calcining limestone) in the cement kiln. While
in the kiln, limestone is broken down into CO2 and lime with
the CO2 released to the atmosphere. The quantity of CO2
emitted during cement production is directly proportional to
the lime content of the clinker. During calcination, each mole
of CaCO3 (i.e., limestone) heated in the clinker kiln forms
one mole of lime (CaO) and one mole of CO2:
              CaCO3 + heat -» CaO + CO2
    Carbon dioxide emissions were estimated by applying
an emission factor, in tons of CO2 released per ton of
clinker produced, to the total amount of clinker produced.
The emission factor used in this analysis is the product of
the average lime fraction for clinker of 65 percent (van Oss
2008c) and a constant reflecting the mass of CO2 released
per unit of lime. This calculation yields an emission factor
of 0.51 tons of CO2 per ton of clinker produced, which was
determined as follows:
                                                               EFQlnker = 0.65 CaO x
                             44.01 g/mole CO2
                             56.08 g/mole CaO
              = 0.51 tons CO2/ton clinker

    During clinker production, some of the clinker precursor
materials remain in the kiln as non-calcinated, partially
calcinated, or fully calcinated cement kiln dust (CKD). The
emissions attributable to the calcinated portion of the CKD
                                                                                     Industrial Processes  4-5

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Table 4-4: Clinker Production (Gg)
                                 Uncertainty
             Year
             Clinker
                                     88,783
                                     90,045
                                     86,106
are not accounted for by the clinker emission factor. The IPCC
recommends that these additional CKD CO2 emissions should
be estimated as 2 percent of the CO2 emissions calculated from
clinker production.3 Total cement production emissions were
calculated by adding the emissions from clinker production
to the emissions assigned to CKD (IPCC 2006)4
    The 1990 through 2007  activity data for clinker
production (see Table 4-4) were obtained through a personal
communication with Hendrik van Oss (van Oss 2008b) of the
USGS and through the USGS Minerals Yearbook: Cement
Annual Report (US Bureau of Mines 1990 through 1993,
USGS 1995  through 2006). The data were compiled by
USGS through questionnaires sent to domestic clinker and
cement manufacturing plants.
                     The uncertainties contained in these estimates are
                 primarily due to uncertainties in the lime content of clinker
                 and in the percentage of CKD recycled inside the cement
                 kiln. Uncertainty is also associated with the assumption
                 that all calcium-containing raw material is CaCO3 when a
                 small percentage likely consists of other carbonate and non-
                 carbonate raw materials. The lime content of clinker varies
                 from 60 to 67 percent (van Oss 2008b). CKD loss can range
                 from 1.5 to 8 percent depending upon plant specifications.
                 Additionally, some amount of CO2 is reabsorbed when the
                 cement is used for construction. As cement reacts with water,
                 alkaline substances such as calcium hydroxide are formed.
                 During this  curing process, these compounds may react
                 with CO2 in the atmosphere to create CaCO3. This reaction
                 only occurs in roughly the outer 0.2 inches of surface  area.
                 Because the amount of CO2 reabsorbed is thought to be
                 minimal, it was not estimated.
                     The results of the Tier 2 quantitative uncertainty analysis
                 are summarized in Table 4-5. Cement Production  CO2
                 emissions  were estimated to be between 38.8 and 50.5 Tg
                 CO2 Eq. at the 95 percent confidence level. This  indicates
                 a range of approximately 13 percent below and 13 percent
                 above the emission estimate of 44.5 Tg CO2 Eq.
Table 4-5: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Cement Production
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas          (Tg C02 Eq.)
                     Uncertainty Range Relative to Emission Estimate3
                      (Tg C02 Eq.)                     (%)
                                                       Lower Bound   Upper Bound   Lower Bound   Upper Bound
  Cement Production
CO,
44.5
38.8
50.5
-13%
+ 13%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
3 Default IPCC clinker and CKD emission factors were verified through
expert consultation with the Portland Cement Association (PCA 2008) and
van Oss (2008a).
4 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  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Recalculations
    Estimates of CO2 emissions from cement production
were revised for 2006 to reflect updates to the clinker
production data for that year.

Planned  Improvements
    Future  improvements to the cement source category
involve continued research into emission factors for clinker
production and CKD. Research has been conducted into the
accuracy and appropriateness of default emission factors
and reporting methodology used by other organizations. As
these methodologies continue to develop, the cement source
category will be updated with any improvements to IPCC
assumptions for clinker and CKD emissions.

4.2.  Lime Production
(IPCC Source  Category  2A2)

    Lime is an important manufactured product with many
industrial, chemical,  and environmental applications. Its
major uses are in steel making, flue gas desulfurization (FGD)
systems at  coal-fired electric power plants, construction,
and water  purification. For U.S. operations, the term
"lime" actually refers to a variety of chemical compounds.
These  include calcium oxide (CaO), or high-calcium
quicklime; calcium hydroxide (Ca(OH)2), or hydrated lime;
dolomitic quicklime ([CaOMgO]); and dolomitic hydrate
([Ca(OH)2»MgO] or [Ca(OH)2»Mg(OH)2]).
    Lime production involves three main processes:
stone preparation, calcination, and hydration. Carbon
dioxide is generated during the calcination stage, when
limestone—mostly calcium carbonate (CaCO3)—is roasted
at high temperatures  in a kiln to produce CaO and CO2.
The CO2 is given  off as  a gas and is normally emitted to
the atmosphere. Some of the CO2  generated during the
production process, however, is recovered at some facilities
for use in sugar refining and precipitated calcium carbonate
(PCC)  production.5 In certain additional applications, lime
reabsorbs CO2 during use.
    Lime production in the United States—including Puerto
Rico—was reported to be 20,192 thousand metric tons in 2007
Table 4-6: C02 Emissions from Lime Production
(Tg C02 Eq. and Gg)
        Year
     Tg C02 Eq.
             Gg
        1990
        11.5
            11,533
        2005
        2006
        2007
                       14,379
                       15,100
                       14,595
Table 4-7: Potential, Recovered, and Net C02 Emissions
from Lime Production (Gg)
      Year
Potential
Recovered3  Net Emissions
      1990
 12,004
   471
11,533
2005
2006
2007
15,131
15,825
15,264
752
725
669
14,379
15,100
14,595
5 PCC is 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.
  Note: Totals may not sum due to independent rounding.
  aFor sugar refining and PCC production.
(USGS 2008). This resulted in estimated CO2 emissions of 14.6
Tg CO2 Eq. (or 14,595 Gg) (see Table 4-6 and Table 4-7).
    The contemporary lime market is distributed across five
end-use categories as follows: metallurgical uses, 36 percent;
environmental uses, 29 percent; chemical and industrial uses,
22 percent; construction uses, 12 percent; and refractory
dolomite, 1 percent. In the construction sector, lime is used
to improve durability in plaster, stucco, and  mortars, as
well as to stabilize soils. In 2007, the amount of lime used
for construction decreased by 8 percent from 2006 levels.
This is most likely a result of increased prices for lime and
the downturn in new home construction; total construction
spending decreased by 3 percent and residential construction
spending decreased by nearly 18 percent compared with
2006 (USGS 2008).
    Lime production in 2007 decreased by 4 percent
compared to 2006, owing to a downturn in major markets
including construction, mining, and steel  (USGS  2008).
Overall, from 1990 to 2007, lime production has increased
by 28 percent. Annual consumption for industrial/chemical
                                                                                   Industrial Processes  4-7

-------
and environmental lime consumption decreased by  1
percent and 4 percent, respectively (USGS 2008). The
decrease in environmental production for environmental
uses is attributed to a decrease in lime consumption for
drinking water treatment, sludge treatment, and the utility
power-plant market for flue gas  desulfurization (USGS
2008). Lime production also decreased for metallurgical
consumption, owing to a shift in steel production from basic
oxygen furnaces (BOF) to electric arc furnaces (EAF). EAFs
use iron and steel scrap as their primary iron source which
contains fewer impurities  and requires  less than one-half
of the lime per ton of steel produced than pig iron used by
BOFs (USGS 2008).

Methodology
    During the calcination stage of lime production, CO2
is  given off as a gas and normally exits the system  with
the stack gas. To calculate emissions, the amounts of high-
calcium and dolomitic lime produced were multiplied by
their respective emission factors. The emission factor is the
product of a constant reflecting the mass of CO2 released per
unit of lime and the average calcium plus magnesium oxide
(CaO  + MgO)  content for lime (95 percent for both types
of lime) (IPCC 2006). The emission factors were calculated
as follows:
For high-calcium lime:
      [(44.01 g/mole CO2) •*- (56.08 g/mole CaO)] x
          (0.95 CaO/lime) = 0.75 g CO2/g lime
For dolomitic lime:
      [(88.02 g/mole CO2) •*- (96.39 g/mole CaO)] x
          (0.95 CaO/lime) = 0.87 g CO2/g lime
                                    Production was adjusted to remove the mass of
                                chemically combined water found in hydrated lime,
                                determined according to the molecular weight ratios of H2O
                                to Ca(OH)2 and [Ca(OH)2»Mg(OH)2] (IPCC 2000). These
                                factors set the chemically combined water content to 24.3
                                percent for high-calcium hydrated lime, and 27.3 percent for
                                dolomitic hydrated lime.
                                    Lime emission estimates were multiplied by a factor of
                                1.02 to account for lime kiln dust (LKD), which is produced
                                as a byproduct during the production of lime (IPCC 2006).
                                    Lime emission estimates were further adjusted to account
                                for PCC producers and sugar refineries that recover CO2
                                emitted by  lime production facilities  and use the captured
                                CO2 as an input  into production or refining  processes.
                                For CO2 recovery by sugar refineries, lime consumption
                                estimates from USGS were multiplied by a CO2 recovery
                                factor to determine the total amount of CO2 recovered from
                                lime production facilities. According to industry surveys,
                                sugar refineries use captured CO2 for 100 percent of their
                                CO2 input (Lutter 2008). Carbon dioxide recovery by PCC
                                producers was determined by multiplying estimates for the
                                percentage  CO2 of production weight for PCC  production
                                at lime plants, by a CO2 recovery factor of 93 percent for
                                2007  (Prillaman 2008). As  data were  only available for
                                2007, CO2 recovery for the period 1990 through 2006 were
                                extrapolated by determining a ratio of PCC production at
                                lime facilities  to lime consumption for PCC (USGS 2002
                                through 2007, 2008).
                                    Lime production data (high-calcium- and dolomitic-
                                quicklime, high-calcium- and dolomitic-hydrated, and dead-
                                burned dolomite) for 1990 through 2007 (see Table 4-8) were
                                obtained from USGS (1992 through 2007). Natural hydraulic
Table 4-8: High-Calcium- and Dolomitic-Quicklime, High-Calcium- and Dolomitic-Hydrated,
and Dead-Burned-Dolomite Lime Production (Gg)
        Year
High-Calcium
 Quicklime
Dolomitic
Quicklime
High-Calcium
  Hydrated
Dolomitic
Hydrated
Dead-Burned
  Dolomite
2005
2006
2007
14,100
15,000
14,700
2,990
2,950
2,700
2,220
2,370
2,240
474
409
352
200
200
200
4-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-9: Adjusted Lime Production3 (Gg)
        Year
High-Calcium       Dolomitic
        1990
        1995
        2000
   12,514
  ^H
   14,700
  ^^^^^^^^H
   15,473
 2,809

 3,207
^^^^^^^H
 3,506
2005
2006
2007
15,781
16,794
16,396
3,535
3,448
3,156
  a Minus water content of hydrated lime.

lime, which is produced from CaO and hydraulic calcium
silicates, is not produced in the United States (USGS 2008).
Total lime production was adjusted to account for the water
content of hydrated  lime by converting hydrate to oxide
equivalent, based on recommendations from the IPCC Good
Practice Guidance and is presented in Table 4-9 (USGS
1992 through 2007, IPCC 2000). The CaO and CaOMgO
contents of lime were obtained from IPCC (2006). Since data
for the individual lime types (high calcium and dolomitic)
was  not provided prior to 1997, total lime production for
1990 through  1996 was calculated according to the  three
year distribution from 1997 to 1999. Lime  consumed by
PCC producers and sugar refineries was obtained from USGS
(1992 through 2007).
Uncertainty
    The uncertainties contained in these estimates can be
attributed to slight differences in the chemical composition
of these products and recovery rates for sugar refineries and
PCC manufacturers located at lime plants. Although the
methodology accounts for various formulations of lime, it
does not account for the trace impurities found in lime, such
as iron oxide, alumina, and silica. Due to differences in the
limestone used as a raw material, a rigid specification of lime
material is impossible. As a result, few plants produce lime
with exactly the same properties.
    In addition, a portion of the CO2 emitted during lime
production will actually be reabsorbed when the lime
is consumed. As noted above,  lime has many different
chemical, industrial, environmental,  and construction
applications. In many processes, CO2 reacts with the lime
to create calcium carbonate (e.g., water softening). Carbon
dioxide reabsorption rates vary, however, depending on the
application. For example, 100 percent of the lime used to
produce PCC reacts with CO2, whereas most  of the lime
used in steel-making reacts with impurities such as silica,
sulfur, and aluminum compounds. A detailed accounting of
lime use in the United States and further research into the
associated processes are required to quantify the amount of
CO2 that is reabsorbed.6
    In some cases, lime is generated from calcium carbonate
byproducts at pulp mills and water treatment plants.7 The
lime generated by these processes is not included in the
USGS data for commercial lime consumption. In the pulping
industry, mostly using the Kraft (sulfate) pulping process,
lime is consumed in order to causticize a process liquor
(green liquor) composed of sodium carbonate  and sodium
sulfide. The green liquor results from the dilution of the smelt
created by combustion of the black liquor where biogenic
C is present from the wood. Kraft mills recover the calcium
carbonate  "mud" after the causticizing operation and calcine
it back into lime—thereby generating CO2—for reuse in
the pulping process. Although this re-generation of lime
could be considered a lime manufacturing process, the CO2
emitted during this process  is mostly biogenic in origin,
and therefore is not included in inventory totals (Miner and
Upton 2002).
    In the case of water treatment plants, lime is used in the
softening  process. Some large water treatment plants may
recover their waste calcium carbonate and calcine  it into
quicklime for reuse in the softening process. Further research
is necessary to determine the degree to which lime recycling
is practiced by water treatment plants in the United States.
    Uncertainties also remain surrounding recovery rates
used for sugar refining and PCC production. The recovery rate
for sugar refineries is based on two sugar beet processing and
refining facilities located in California that use  100 percent
recovered  CO2 from lime plants (Lutter 2008). This analysis
assumes that all sugar refineries located on-site at lime plants
                                    6 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).
                                    7 Some carbide producers may also regenerate lime from their calcium
                                    hydroxide byproducts, 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.
                                                                                       Industrial Processes  4-9

-------
Table 4-10: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Lime Production
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
Gas          (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Lime Production
CO,
14.6
13.5
15.9
+9%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
also use 100 percent recovered CO2. The recovery rate for
PCC producers located on-site at lime plants is based on the
2007 value for PCC manufactured at commercial lime plants,
given by the National Lime Association (Prillaman 2008).
    The results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-10. Lime CO2 emissions
were estimated to be between 13.5 and 15.9 Tg CO2 Eq.
at the 95 percent confidence level. This indicates a range
of approximately 8 percent below and 9 percent above the
emission estimate of 14.6 Tg CO2 Eq.

Recalculations Discussion
    Estimates of CO2 emissions from lime production were
revised for years 1990 through 2006 to include estimates of
CO2 recovery from PCC production and sugar refining. On
average, these revisions resulted in an annual decrease in
emissions of approximately 13 percent.

Planned Improvements
    Future improvements to the lime source category involve
continued research into CO2 recovery associated with lime use
during sugar refining and PCC production. Two sugar refining
facilities in California have been identified that capture CO2
produced in lime kilns located on the same site as the sugar
refinery (Lutter, 2008). Currently, data on CO2 production by
these lime facilities is unavailable. Future work will include
research to determine the number of sugar refineries that
employ the carbonation technique, the percentage of these
that use captured CO2 from lime production facilities, and the
amount of CO2 recovered per unit of lime production. Future
research will also aim to improve estimates of CO2 recovered
as part of the PCC production process using estimates of PCC
production and CO2 inputs rather than lime consumption by
PCC facilities.
                                4.3.  Limestone and  Dolomite Use
                                (IPCC  Source Category 2A3)

                                    Limestone (CaCO3) and dolomite (CaCO3MgCO3)8
                                are basic raw materials used by a wide variety of industries,
                                including construction, agriculture, chemical, metallurgy,
                                glass production, and environmental pollution control.
                                Limestone is widely distributed throughout the world
                                in deposits of varying sizes and degrees  of purity. Large
                                deposits of limestone occur in nearly every state in the United
                                States, and significant quantities are extracted for industrial
                                applications. For some of these applications, limestone is
                                sufficiently heated during the process and generates CO2 as a
                                byproduct. Examples of such applications include limestone
                                used as a flux or purifier in metallurgical furnaces, as a
                                sorbent in flue gas  desulfurization systems for utility and
                                industrial plants, or as a raw material in glass manufacturing
                                and magnesium production.
                                    In 2007, approximately 13,075 thousand metric tons of
                                limestone and 1,827 thousand metric tons of dolomite were
                                consumed during production for these applications. Overall,
                                usage of limestone and dolomite resulted in aggregate CO2
                                emissions of 6.2 Tg CO2 Eq. (6,182 Gg) (see Table 4-11 and
                                Table 4-12). Emissions in 2007 decreased 23 percent from
                                the previous year and have increased 21 percent overall from
                                1990 through 2007.

                                Methodology
                                    Carbon dioxide emissions were calculated by multiplying
                                the quantity of limestone or dolomite consumed by the
                                average C content, approximately 12.0 percent for limestone
                                8 Limestone and dolomite are collectively referred to as limestone by the
                                industry, and intermediate varieties are seldom distinguished.
4-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-11: C02 Emissions from Limestone & Dolomite Use (Tg C02 Eq.)
Activity
Flux Stone
Glass Making
Flue Gas Desulfurization
Magnesium Production
Other Miscellaneous Uses
Total
1990
1""
0.8
5.1
1995
•„„
1.2
6.7
2000
•„.
""•
0.1
0.7
5.1
2005
2.7
0.4
3.0
0.0
0.7
6.8
2006
4.5
0.7
2.1
0.0
0.7
8.0
2007
2.0
0.3
3.2
0.0
0.7
6.2
  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: C02 Emissions from Limestone & Dolomite Use (Gg)
  Activity
 1990
 1995
 2000
 2005
 2006
2007
  Flux Stone
    Limestone
    Dolomite
  Glass Making
    Limestone
    Dolomite
  Flue Gas Desulfurization
  Magnesium Production
  Other Miscellaneous Uses
2,593
2,304
  289
  217
  189
   28
1,433
   64
  819
3,198
2,027
1,171
  525
  421
  103
1,719
   41
1,168
2,104
1,374
  730
  371
  371

    °
1,787
   73
  722
2,650
1,096
1,554
  425
  405
   20
2,975
    0
  718
4,492
1,917
2,575
  747
  717
   31
2,061
    0
  735
1,959
1,270
  689
  333
  333
    0
3,179
    0
  711
  Total
5,127
6,651
5,056
6,768      8,035
          6,182
  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.
and 13.2 percent for dolomite (based on stoichiometry), and
converting this value to CO2. This methodology was used
for flux stone, glass manufacturing, flue gas desulfurization
systems,  chemical  stone, mine dusting or acid water
treatment, acid neutralization,  and sugar refining and then
converting to CO2 using a molecular weight ratio. Flux stone
used during the production of  iron and steel was deducted
from the Limestone and Dolomite Use estimate and attributed
to the Iron and Steel Production estimate.

    Traditionally, the production of magnesium metal was
the only other significant use of limestone and dolomite that
produced CO2 emissions. At the start of 2001, there were
two magnesium production plants operating in the United
States and they used different production methods. One plant
produced magnesium metal using a dolomitic process that
resulted in the  release of CO2 emissions, while the other
plant produced magnesium from magnesium chloride using
a CO2-emissions-free process called electrolytic reduction.
            However, the plant utilizing the dolomitic process ceased
            its operations prior to the end of 2001, so beginning in 2002
            there were no emissions from this particular sub-use.

                Consumption data for 1990 through 2007 of limestone
            and dolomite used for flux stone, glass manufacturing, flue
            gas desulfurization systems, chemical stone, mine dusting or
            acid water treatment, acid neutralization, and sugar refining
            (see  Table 4-13) were obtained from the USGS Minerals
            Yearbook: Crushed Stone Annual Report (USGS 1993,
            1995a through 2007a,  2008a). The production  capacity
            data for 1990 through 2007 of dolomitic magnesium metal
            (see Table 4-14) also came from the USGS (1995b through
            2007b, 2008b). The last  plant in the United States that used
            the dolomitic production process for magnesium metal
            closed in 2001. The USGS does not mention this process
            in the 2007 Minerals Yearbook: Magnesium; therefore, it
            is assumed that this process continues to be non-existent in
            the United States (USGS 2008b). During 1990 and 1992, the
                                                                                      Industrial Processes  4-11

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Table 4-13: Limestone and Dolomite Consumption (Thousand Metric Tons)
  Activity
              1990
  1995
  2000
  2005
2006
2007
  Flux Stone
    Limestone
    Dolomite
  Glass Making
    Limestone
    Dolomite
  Flue Gas Desulfurization
  Other Miscellaneous Uses
                                                      7,022
                                                      3,165
                                                      3,857
                                                        962
                                                        920
                                                        43
                                                      6,761
                                                      1,632
                                     11,030
                                      5,208
                                      5,822
                                      1,693
                                      1,629
                                         64
                                      4,683
                                      1,671
                                   5,305
                                   3,477
                                   1,827
                                    757
                                    757
                                      0
                                   7,225
                                   1,616
  Total
             12,319
16,321
12,826
16,377     19,078     14,903
  Notes: "Other miscellaneous uses" includes chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar refining. Zero values for
  limestone and dolomite consumption for glass making result during years when the USGS reports that no limestone or dolomite are consumed for this use.
Table 4-14: Dolomitic Magnesium Metal Production
Capacity (Metric Tons)
             Year
Production Capacity
            1990
     35,000
            2005
            2006
            2007
  Note: Production capacity for 2002, 2003, 2004, 2005, 2006, and 2007
  amounts to zero because the last U.S. production plant employing the
  dolomitic process shut down mid-2001 (USGS 2002b through 2008b).
USGS did not conduct a detailed survey of limestone and
dolomite consumption by end-use. Consumption for 1990
was  estimated by applying the 1991 percentages of total
limestone and dolomite use constituted by the individual
limestone and dolomite uses to 1990 total use. Similarly, the
1992 consumption figures were approximated by applying an
average of the 1991 and 1993 percentages of total limestone
and dolomite use constituted by the individual limestone and
dolomite uses to the 1992 total.
    Additionally, each  year the USGS withholds data
on certain  limestone  and  dolomite end-uses  due to
confidentiality agreements regarding company proprietary
data. For  the purposes of this analysis, emissive end-uses
that contained withheld data were estimated using one of
the following techniques: (1) the value for all the withheld
data points for limestone or dolomite use was  distributed
evenly to  all withheld end-uses; (2) the average percent of
total limestone or dolomite for the withheld end-use in the
preceding and succeeding years; or (3) the average fraction
of total limestone or dolomite for the end-use over the entire
time period.
    There is a large quantity of crushed stone reported to the
USGS under the category "unspecified uses." A portion of
this consumption is believed to be limestone or dolomite used
for  emissive end uses. The quantity listed for "unspecified
uses" was, therefore, allocated to each reported end-use
according to  each  end-use's fraction of total consumption
in that year.9

Uncertainty
    The uncertainty levels presented in this  section arise
in part due to variations in the chemical composition of
limestone. In addition to calcium carbonate, limestone may
contain smaller amounts of magnesia, silica, and  sulfur,
among other minerals. The exact specifications for limestone
or dolomite used as flux stone vary with the pyrometallurgical
process and the kind of ore processed. Similarly, the quality
of the limestone used for glass manufacturing will depend
on the type of glass being manufactured.
    The estimates below also account  for uncertainty
associated with activity data. Large fluctuations in reported
consumption exist, reflecting year-to-year changes in the
number of survey responders. The uncertainty resulting from
a shifting survey population is exacerbated by the gaps in
the  time series of reports. The accuracy of distribution by
end use is also uncertain because this value is reported by
the  manufacturer and not the end user. Additionally, there is
                                                          'This approach was recommended by USGS.
4-12   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-15: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Limestone and Dolomite Use
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
 Uncertainty Range Relative to Emission Estimate3
   (Tg C02 Eq.)                      (%)
                                                       Lower Bound   Upper Bound   Lower Bound   Upper Bound
  Limestone and Dolomite
   Use                   CO?
                6.2
5.4
7.2
-12%
+ 16%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
significant inherent uncertainty associated with estimating
withheld data points for specific end uses of limestone and
dolomite. The uncertainty of the estimates for limestone
used in glass making is especially high; however, since
glass making accounts for a small percent of consumption,
its contribution to the overall emissions estimate is low.
Lastly, much of the limestone consumed in the United
States is  reported as "other unspecified uses;" therefore, it
is difficult to accurately allocate this unspecified quantity to
the correct end-uses.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-15. Limestone and Dolomite Use
CO2 emissions were estimated to be between 5.4 and 7.2 Tg
CO2 Eq.  at the 95 percent confidence level. This indicates
a range of approximately 12 percent below and 16 percent
above the emission estimate of 6.2 Tg CO2 Eq.

Recalculations Discussion
    Estimates  of CO2 emissions from Limestone and
Dolomite Use have been revised for the entire time series to
accommodate minor revisions to the  "unspecified uses" of
limestone and dolomite identified by the USGS. On average,
these revisions resulted in an annual decrease in emissions of
0.1 percent. Additionally, limestone and dolomite consumption
data were updated to attribute emissions from limestone and
dolomite used for iron and steel production to the Iron and
Steel Production estimate. On average, this resulted in an
additional decrease in emissions of 10 percent.
Planned Improvements
    Future improvements to the limestone and dolomite
source category involve research into the availability of
limestone and dolomite end-use data. If sufficient data are
available, limestone and dolomite used as process materials
in source categories included in future Inventories (e.g., glass
                                production, other process use of carbonates) may be removed
                                from this section and will be reported under the appropriate
                                source categories.

                                4.4.  Soda Ash Production  and
                                Consumption (IPCC Source
                                Category 2A4)

                                    Soda ash (sodium carbonate,  Na2CO3) is a white
                                crystalline solid that is readily soluble in water and strongly
                                alkaline. Commercial soda ash is used as a raw material in a
                                variety of industrial processes and in many familiar consumer
                                products such as glass, soap and detergents, paper, textiles,
                                and food.  It is used primarily as an  alkali, either in glass
                                manufacturing or simply as a material that reacts with and
                                neutralizes acids or acidic substances. Internationally, two
                                types of soda ash are produced—natural and synthetic. The
                                United States produces only natural soda ash and is second
                                only to China in total soda ash-production. Trona is the
                                principal ore from which natural soda ash is made.
                                    Only  two states produce natural soda ash: Wyoming
                                and California.  Of these two states, only net emissions
                                of CO2 from Wyoming were calculated due  to specifics
                                regarding the production processes employed in the state.10
                                10 In California, soda ash is manufactured using sodium carbonate-bearing
                                brines instead of trona ore. To extract the sodium carbonate, the complex
                                brines are first treated with CO2 in carbonation towers to convert the
                                sodium carbonate into sodium bicarbonate, which then precipitates from
                                the brine solution. The precipitated sodium bicarbonate is then calcined
                                back into sodium carbonate. Although CO2 is generated as a byproduct,
                                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.
                                                                                      Industrial Processes  4-13

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Table 4-16: C02 Emissions from Soda Ash Production
and Consumption (Tg C02 Eq.)
      Year
Production   Consumption
             Total
      1990
   1.4
 2.7
      2005
      2006
      2007
   1.7
   1.6
   1.7
 2.6
 2.5
 2.5
4.2
4.2
4.1
  Note: Totals may not sum due to independent rounding.
Table 4-17: C02 Emissions from Soda Ash Production
and Consumption (Gg)
      Year
Production   Consumption      Total
      1990
  1,431
2,710
                                           4,228
                                           4,162
                                           4,140
  Note: Totals may not sum due to independent rounding.

During the production process used in Wyoming, trona ore
is treated to produce soda ash. Carbon dioxide is generated
as a byproduct of this reaction, and is  eventually emitted
into the atmosphere. In addition, CO2 may also be released
when soda ash is consumed.
    In 2007, CO2 emissions from the production of soda ash
from trona were approximately  1.7 Tg CO2 Eq. (1,675 Gg).
Soda ash consumption in the United States generated 2.5
Tg CO2 Eq. (2,465 Gg) in 2007. Total emissions from soda
ash production and consumption in 2007 were 4.1 Tg CO2
Eq. (4,140 Gg) (see Table 4-16  and Table 4-17).  Emissions
have fluctuated since 1990. These fluctuations were strongly
related to the behavior of the export market and the U.S.
economy. Emissions in 2007 decreased by approximately 0.5
percent from the previous year, and have decreased overall
by less than 0.5 percent since 1990.
    The United States represents  about one-fourth of total
world soda ash output. The approximate distribution of
soda ash by end-use in 2007 was glass making, 49 percent;
chemical production, 30 percent; soap and detergent
manufacturing, 8 percent; distributors, 5 percent; flue gas
desulfurization, 2 percent; water treatment, 2 percent; pulp
and paper production, 2 percent; and miscellaneous, 3 percent
(USGS 2008).
    Although the United States continues to  be a major
supplier  of world soda ash, China, which surpassed the
United States in soda ash production in 2003, is the world's
leading producer. While Chinese soda ash  production
appears to be stabilizing, U.S. competition in Asian markets
is expected to continue. Despite this  competition, U.S. soda
ash production is expected to increase by about 0.5 percent
annually  over the next five years (USGS 2006).

Methodology
    During the production process,  trona ore is calcined in
a rotary kiln and chemically transformed into a crude soda
ash that requires further processing.  Carbon dioxide and
water are generated as byproducts of  the calcination process.
Carbon dioxide emissions from the calcination of trona can
be estimated based on the following chemical reaction:
 2(Na3(CO3)(HCO3)»2H2O) -> 3Na2CO3 + 5H2O + CO2
            [trona]              [soda ash]
    Based on this formula, approximately 10.27 metric tons
of  trona are required to generate one metric ton of CO2, or
an emission factor of 0.097 metric tons CO2 per metric ton
trona (IPCC 2006).  Thus, the 17.2  million metric tons of
trona mined in 2007 for soda ash production  (USGS 2008)
resulted in CO2 emissions of approximately 1.7  Tg CO2 Eq.
(1,675 Gg).
    Once produced, most soda ash is consumed in glass
and chemical production, with minor amounts in soap and
detergents, pulp  and paper,  flue gas desulfurization and
water treatment. As soda ash is consumed for these purposes,
additional CO2 is usually emitted. In these applications, it
is assumed that one mole of C is released for every mole of
soda ash  used. Thus, approximately  0.113 metric tons of C
(or 0.415 metric tons of CO2) are released for every metric
ton of soda ash consumed.
    The  activity data for trona production  and soda ash
consumption (see Table 4-18) were taken from USGS (1994
through 2008). Soda ash production and consumption data
were collected by the USGS from voluntary surveys of the
U.S. soda ash industry.
4-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-18: Soda Ash Production and Consumption (Gg)    Planned  Improvements
        Year
Production3
Consumption
2005
2006
2007
17,000
16,700
17,200
6,200
6,110
5,940
  aSoda ash produced from trona ore only.


Uncertainty
    Emission estimates from soda ash production have
relatively low associated uncertainty levels  in that
reliable and accurate data sources are available for the
emission factor and activity data. The primary source of
uncertainty, however,  results from the fact that emissions
from soda ash consumption are dependent upon the type of
processing employed by each end-use.  Specific information
characterizing the emissions from each end-use is  limited.
Therefore, there is  uncertainty surrounding the emission
factors from the consumption of soda ash.
    The results of the Tier 2 quantitative uncertainty  analysis
are summarized in  Table 4-19. Soda Ash Production and
Consumption CO2 emissions were estimated to be between
3.8 and 4.4 Tg CO2 Eq. at the 95  percent confidence level.
This indicates a range of approximately 7 percent below and
7 percent above the emission estimate of 4.1 Tg CO2 Eq.
    Future inventories are anticipated to estimate emissions
from glass production and other use of carbonates. These
inventories will extract soda ash consumed for glass
production and other use of carbonates from the current
soda ash consumption emission estimates and include them
under those sources.

4.5.  Ammonia  Production (IPCC
Source Category 2B1) and  Urea
Consumption

    Emissions of CO2 occur during the production of
synthetic ammonia, primarily through the use of natural gas
as a feedstock. The natural gas-based, naphtha-based, and
petroleum coke-based processes produce CO2 and hydrogen
(H2), the latter of which is used in the production of ammonia.
One N production plant located in Kansas is producing
ammonia from petroleum coke feedstock. In some plants
the CO2 produced is captured and used to produce urea. The
brine electrolysis process for production of ammonia does
not lead to process-based CO2 emissions.
    There are five principal process steps in synthetic
ammonia production from natural gas feedstock. The primary
reforming step converts CH4 to CO2, carbon monoxide (CO),
and H2 in the presence of a catalyst. Only 30 to 40 percent
of the CH4 feedstock to the primary reformer is converted
to CO and CO2. The secondary reforming step converts the
Table 4-19: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Soda Ash Production and Consumption
(Tg C02 Eq. and Percent)
  Source
         2007 Emission Estimate
   Gas         (Tg C02 Eq.)
                     Uncertainty Range Relative to Emission Estimate3
                       (Tg C02 Eq.)                    (%)
                                                    Lower Bound   Upper Bound    Lower Bound    Upper Bound
  Soda Ash Production
   and Consumption
   CO?
   4.1
   3.8
4.4
+7%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                 Industrial Processes  4-15

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remaining CH4 feedstock to CO and CO2. The CO in the
process gas from the secondary reforming step (representing
approximately 15 percent of the process gas) is converted to
CO2 in the presence of a catalyst, water, and air in the shift
conversion step. Carbon dioxide is removed from the process
gas by the shift conversion process, and the hydrogen gas is
combined with the nitrogen (N2) gas in the process gas during
the ammonia synthesis step to produce ammonia. The CO2 is
included in a waste gas stream with other process impurities
and is absorbed by a scrubber solution. In regenerating the
scrubber solution, CO2 is released.
    The conversion process for conventional steam reforming
of CH4, including primary and secondary reforming and the
shift conversion processes, is approximately as follows:

                            (catalyst)
  0.88CH4  + 1.26Air + 1.24H2O -> 0.88CO2 + N2 + 3H2
                  N2 + 3H2 -» 2NH3
    To produce synthetic ammonia  from petroleum coke,
the petroleum coke is gasified and converted to CO2 and H2.
These gases are separated, and the H2 is used as a feedstock
to the ammonia production process, where it is reacted with
N2 to form ammonia.
    Not all of the CO2 produced  in the production of
ammonia is emitted directly  to the atmosphere. Both
ammonia and CO2 are used as raw materials in the production
of urea [CO(NH2)2], which is another type of nitrogenous
fertilizer that contains C as well as N. The chemical reaction
that produces urea is:
   2NH3 + CO2 -» NH2COONH4 -» CO(NH2)2 + H2O
    Urea is  consumed for a variety of uses, including as a
nitrogenous  fertilizer, in urea-formaldehyde resins, and as
a deicing agent (TIG 2002). The C in the consumed urea is
assumed to be released into the environment as CO2 during
use. Therefore, the CO2 produced by ammonia production
that is subsequently used in the production of urea is still
emitted during urea consumption. The majority of CO2
emissions associated with urea  consumption are those
that result from its use as a fertilizer. These emissions are
accounted for in the Cropland Remaining Cropland section
of the Land  Use, Land-Use Change, and Forestry chapter.
Carbon dioxide emissions associated with other uses of urea
are accounted for in this chapter. Net emissions of CO2 from
ammonia production in 2007 were 13.8 Tg CO2 Eq. (13,786
Gg), and are summarized in Table  4-20 and Table 4-21.
Emissions of CO2 from urea consumed for non-fertilizer
purposes in  2007 totaled 4.7 Tg CO2 Eq. (4,750 Gg), and
are summarized in Table 4-20 and Table 4-21. The decrease
in ammonia production in recent years is due to several
factors, including market fluctuations and high  natural gas
prices. Ammonia production relies on natural gas as both a
feedstock and a fuel, and as such, domestic producers are
competing with imports from countries with lower gas prices.
If natural gas prices remain high, it is likely that domestically
Table 4-20: C02 Emissions from Ammonia Production and Urea Consumption (Tg C02 Eq.)
Source
Ammonia Production
Urea Consumption3
Total
1990
13.0
3.8
16.8
1995
13.5
4.3
17.8
2000
12.2
4.2
16.4
2005
9.2
3.7
12.8
2006
8.8
3.5
12.3
2007
9.0
4.7
13.8
  allrea Consumption is for non-fertilizer purposes only. Urea consumed as a fertilizer is accounted for in the Land Use, Land-Use Change, and Forestry chapter.
  Note: Totals may not sum due to independent rounding.
Table 4-21: C02 Emissions from Ammonia Production and Urea Consumption (Gg)
Source
Ammonia Production
Urea Consumption3
Total
1990
13,047
3,784
16,831
1995
13,541
4,255
17,796
2000
12,172
4,231
16,402
2005
9,196
3,653
12,849
2006
8,781
3,519
12,300
2007
9,036
4,750
13,786
  aUrea Consumption is for non-fertilizer purposes only. Urea consumed as a fertilizer is accounted for in the Land Use, Land-Use Change, and Forestry chapter.
  Note: Totals may not sum due to independent rounding.
4-16   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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produced ammonia will continue to decrease with increasing
ammonia imports (EEA 2004).

Methodology
    The calculation methodology for non-combustion
CO2 emissions from production of nitrogenous fertilizers
from natural gas feedstock is based on a CO2 emission
factor published by the European Fertilizer Manufacturers
Association (EFMA). The selected EFMA factor is based on
ammonia production technologies that are similar to those
employed in the U.S. The CO2 emission factor (1.2 metric tons
CO2/metric ton NH3) is applied to the percent of total annual
domestic ammonia production from natural gas feedstock.
Emissions from fuels consumed for energy purposes during
the production of ammonia are accounted for in the Energy
chapter. Emissions of CO2 from ammonia production are then
adjusted to account for the use of some of the CO2 produced
from ammonia production as a raw material in the production
of urea. For each ton of urea produced, 8.8 of every 12 tons of
CO2 are consumed and 6.8 of every 12 tons of ammonia are
consumed  (European Fertilizer Manufacturers Association
2000). The CO2 emissions reported for ammonia production
are therefore reduced by a factor of 0.73 multiplied by total
annual domestic urea production. Total CO2 emissions
resulting from nitrogenous fertilizer production do not
change as a result of this calculation, but some  of the CO2
emissions are attributed to ammonia production and some of
the CO2 emissions are attributed to urea consumption. Those
CO2 emissions that result from the use of urea as a fertilizer
are accounted for in the Land Use, Land-Use Change, and
Forestry chapter.
                                    The total amount of urea consumed for non-agricultural
                                purposes is  estimated by deducting the  quantity of urea
                                fertilizer applied to agricultural lands, which is  obtained
                                directly from the Land Use, Land-Use Change, and Forestry
                                Chapter and is reported in Table 4-22, from the total U.S.
                                production. Total urea production is estimated based on the
                                amount of urea produced plus the sum of net urea imports
                                and exports CO2 emissions associated with urea that is used
                                for non-fertilizer purposes are estimated using a  factor of
                                0.73 tons of CO2 per ton of urea consumed.
                                    All ammonia production and subsequent urea
                                production are assumed to be from the same process —
                                conventional catalytic reforming of natural gas feedstock,
                                with the exception of ammonia production from petroleum
                                coke feedstock at one plant located in Kansas. The CO2
                                emission factor for production of ammonia from petroleum
                                coke is based on plant specific data, wherein all C contained
                                in the petroleum coke feedstock that is not used for urea
                                production is assumed to be emitted to the atmosphere as
                                CO2 (Bark 2004). Ammonia and urea are assumed to be
                                manufactured in the same manufacturing complex, as both
                                the raw materials needed for urea production are produced
                                by the ammonia production process. The CO2 emission
                                factor (3.57 metric tons CO2/metric ton NH3) is applied to
                                the percent of total annual domestic ammonia production
                                from petroleum coke feedstock.
                                    The emission factor of  1.2 metric ton CO2/metric ton
                                NH3 for production of ammonia from natural gas feedstock
                                was  taken from the EFMA Best Available Techniques
                                publication, Production  of Ammonia (EFMA 1995). The
Table 4-22: Ammonia Production, Urea Production, Urea Net Imports, and Urea Exports (Gg)
        Year
Ammonia
Production
Urea Production
Urea Applied
as Fertilizer
Urea Imports
Urea Exports
2005
2006
2007
10,143
9,962
10,386
5,270
5,410
5,630
4,779
4,985
5,389
5,026
5,029
6,546
536
656
310
                                                                                  Industrial Processes 4-17

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EFMA reported an emission factor range of 1.15 to 1.30
metric ton CO2/metric ton NH3, with 1.2 metric ton CO2/
metric ton NH3 as  a typical value. Technologies (e.g.,
catalytic reforming process)  associated with this factor
are found to closely resemble those employed in the
United States for use of natural gas as a feedstock. The
EFMA reference also indicates that more than 99 percent
of the CtLj feedstock to the catalytic reforming process is
ultimately converted to CO2. The emission factor of 3.57
metric ton CO2/metric ton NH3 for production of ammonia
from petroleum coke feedstock was developed from plant-
specific ammonia production data and petroleum coke
feedstock utilization data for the ammonia plant located
in Kansas (Bark 2004). As noted earlier, emissions from
fuels consumed for energy purposes during the production
of ammonia are  accounted for in the Energy chapter.
Ammonia production data (see Table 4-22) was obtained
from Coffeyville Resources (Coffeyville 2005,2006,2007a,
2007b) and the Census  Bureau of the U.S. Department of
Commerce (U.S. Census Bureau 1991 through 1994, 1998
through 2007) as reported in Current Industrial Reports
Fertilizer Materials and  Related Products annual and
quarterly reports. Urea-ammonia nitrate production was
obtained from Coffeyville Resources  (Coffeyville 2005,
2006, 2007a). Urea production data for 1990 through 2007
were obtained from the Minerals Yearbook: Nitrogen (USGS
1994 through 2007). Import data for urea were obtained from
the U. S. Census Bureau Current Industrial Reports Fertilizer
Materials and Related Products annual and quarterly reports
for 1997 through 2007 (U.S. Census Bureau 1998 through
2007), The Fertilizer Institute (TFI 2002) for 1993 through
1996, and the United States International Trade Commission
Interactive Tariff and Trade DataWeb (U.S. ITC 2002) for
1990 through 1992 (see Table 4-22). Urea export data for
1990 through 2007 were taken from U.S. Fertilizer Import/
Exports from USDA Economic Research Service Data Sets
(U.S. Department of Agriculture 2008).
                               Uncertainty
                                   The uncertainties presented in this section are primarily
                               due to how accurately the emission factor used represents
                               an average across all ammonia  plants using  natural gas
                               feedstock. Uncertainties are also associated with natural gas
                               feedstock consumption data for the U.S. ammonia industry
                               as a whole, the assumption that all ammonia production and
                               subsequent urea production was from the same process —
                               conventional catalytic reforming  of natural gas feedstock,
                               with the exception of one ammonia production plant located
                               in Kansas that is manufacturing ammonia from petroleum
                               coke feedstock. It is also assumed that ammonia and urea
                               are produced at collocated plants from the same natural gas
                               raw material.
                                   Such recovery may or may not affect the overall estimate
                               of CO2 emissions depending upon the end use to which the
                               recovered CO2 is applied. Further research is required to
                               determine whether byproduct CO2 is being recovered from
                               other ammonia production plants for application to end uses
                               that are not accounted for elsewhere.
                                   Additional uncertainty is  associated with the estimate
                               of urea consumed for non-fertilizer purposes. Emissions
                               associated with this  consumption are reported in this
                               source category, while those associated with consumption
                               as fertilizer are reported in Cropland Remaining Cropland
                               section of the  Land Use, Land-Use Change, and Forestry
                               chapter. The amount of urea used for non-fertilizer purposes
                               is estimated based on estimates of urea production, net urea
                               imports, and the amount of urea used as fertilizer. There is
                               uncertainty associated with the accuracy of these estimates
                               as well as the fact that each  estimate is obtained from a
                               different data source.
                                   The results of the Tier  2 quantitative uncertainty
                               analysis are summarized in Table 4-23. Ammonia Production
                               and Urea Consumption CO2 emissions were estimated to
                               be between 12.1 and  15.2 Tg CO2 Eq. at the 95 percent
Table 4-23: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Ammonia Production and
Urea Consumption (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                     (%)
                                                      Lower Bound   Upper Bound    Lower Bound    Upper Bound
  Ammonia Production
   and Urea Consumption
CO?
13.8
12.1
15.2
-12%
+11%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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confidence level. This indicates a range of approximately 12
percent below and 11 percent above the emission estimate
of 13.8TgC02Eq.

Recalculations Discussion
    Urea export data were revised for 1990 through 2006
using the U.S.  Department of Agriculture's Economic
Research Service Data Set for U.S. Fertilizer Exports. These
data were used because the previous data source discontinued
publication of urea export data. On average, revisions to
the exported urea dataset resulted in a decrease  in annual
emission estimates of less than one percent. Urea production
data were revised for 1990 through 2006. These  data were
used in place of estimating urea production based on quantity
of urea applied to agricultural lands and an estimated percent
of urea consumed for agricultural purposes. On average, the
new data resulted in a decrease in annual emission estimates
of less than half of one percent.

Planned  Improvements
    Planned improvements to the Ammonia Production and
Urea Consumption source category include updating emission
factors to include both fuel and feedstock CO2 emissions and
incorporating CO2 capture and storage. Methodologies  will
also be updated if additional ammonia-production  plants
are found to use hydrocarbons other than natural gas for
ammonia production. Additional efforts will be made to find
consistent data sources for urea consumption and to  report
emissions from  this  consumption appropriately as defined
by the 2006IPCC Guidelines for National Greenhouse Gas
Inventories  (IPCC 2006).

4.6.  Nitric Acid  Production (IPCC
Source  Category 2B2)

    Nitric acid  (HNO3) is an inorganic compound used
primarily to make  synthetic commercial fertilizers. It is
also a major component in the production of adipic acid—a
feedstock for nylon—and explosives. Virtually  all  of the
nitric  acid produced in the United States  is manufactured
by the catalytic oxidation of  ammonia (EPA 1997). During
this reaction, N2O is formed  as a byproduct and is released
from reactor vents into the atmosphere.
Table 4-24: N20 Emissions from Nitric Acid Production
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
Gg
        1990
  20.0
64
        2005
        2006
        2007
    Currently, the nitric acid industry controls for emissions
of NO and NO2  (i.e., NOX). As such, the industry uses a
combination of non-selective catalytic reduction (NSCR)
and selective catalytic reduction (SCR) technologies. In the
process of destroying NOX, NSCR systems are also very
effective at destroying N2O. However, NSCR units are
generally not preferred in modern plants because of high
energy costs and  associated high gas temperatures. NSCRs
were widely installed in nitric plants built between 1971 and
1977. Less than 5 percent of nitric acid plants use NSCR and
they represent 0.6 percent of estimated national production
(EPA 2008). The  remaining 95 percent of the facilities use
SCR or extended absorption, neither of which is known to
reduce N2O emissions.
    Nitrous oxide emissions from this source were estimated
to be 21.7 Tg CO2 Eq. (70 Gg) in 2007 (see Table 4-24).
Emissions from nitric acid production have increased by 8.5
percent since  1990, with the trend in the time series closely
tracking the changes in production. Emissions increased
19 percent between 2006 and 2007,  which resulted from
an increase in nitric acid production driven by increased
synthetic fertilizer demand by farmers taking advantage of
high grain prices  by expanding crop planting (ICIS 2008).
Emissions have decreased by 8.8 percent since 1997, the
highest year of production in the time series.

Methodology
    Nitrous oxide emissions were calculated by multiplying
nitric acid production by the amount of N2O emitted per unit
of nitric acid produced. The emission factor was determined
as a weighted average of 2 kg N2O / metric ton HNO3
                                                                                  Industrial Processes  4-19

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Table 4-25: Nitric Acid Production (Gg)
            Year
             Gg
produced at plants using non-selective catalytic reduction
(NSCR) systems and 9 kg N2O/metric ton HNO3 produced at
plants not equipped with NSCR (IPCC 2006). In the process
of destroying NOX, NSCR systems destroy 80 to 90 percent
of the N2O, which is accounted for in the emission factor of 2
kg N2O/metric ton HNO3. Less than 5 percent of HNO3 plants
in the United States are equipped with NSCR representing
0.6  percent of estimated national production (EPA 2008).
Hence, the emission factor is equal to (9 x 0.994) + (2 x
0.006) = 9.0 kg N2O per metric ton HNO3.
    Nitric acid production data for 1990 through 2002 were
obtained from the U.S. Census Bureau Current Industrial
Reports (2006), and for 2003 through 2007 from the U.S.
Census  Bureau Current Industrial Reports (2008) (see
Table 4-25).

Uncertainty
    The overall uncertainty associated  with  the 2007
N2O emissions estimate  from nitric  acid production
was calculated using the IPCC Guidelines for National
Greenhouse Gas Inventories (2006) Tier 2 methodology.
Uncertainty associated with the parameters used to estimate
N2O emissions included that of production data, the share
                of U.S. nitric acid production attributable to each emission
                abatement technology, and the emission factors applied to
                each abatement technology type.
                    The results of this Tier 2 quantitative uncertainty analysis
                are summarized in Table 4-26. Nitrous oxide emissions from
                nitric acid production were estimated to be between 12.7
                and 31.3  Tg CO2 Eq. at the  95 percent confidence level.
                This indicates a range of approximately 42 percent below
                to 44 percent above the 2007 emissions estimate of 21.7 Tg
                CO2 Eq.

                Recalculations Discussion
                    Changes to the weighted N2O emission factor resulted in
                an increase in emissions across the time series. The weighted
                N2O emission factor was previously based on the percentage
                of facilities equipped and not equipped with NSCR systems.
                The emission factor used for the current estimate is based
                on the percentage of HNO3 produced at plants with NCSR
                systems and HNO3 produced at plants without NSCR
                systems. Additionally, the nitric acid production value  for
                2006 has also been updated relative to the previous Inventory
                based on revised production data published by the U.S.
                Census Bureau (2008). Revised production data reduced
                emissions for 2006by 0.2TgCO2Eq. (l.Opercent). Overall,
                these changes resulted in an average annual increase in N2O
                emissions  of 3.1 Tg CO2 Eq.  (17.8 percent) for the period
                1990 through 2006 relative to the previous Inventory.

                4.7.  Adipic Acid  Production (IPCC
                Source Category 2B3)

                    Adipic acid production is an anthropogenic source of
                N2O emissions. Worldwide, few adipic acid plants exist.
                The  United  States  and Europe are the  major producers.
Table 4-26: Tier 2 Quantitative Uncertainty Estimates for N20 Emissions from Nitric Acid Production
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Nitric Acid Production
N,0
21.7
12.7
31.3
-42%
+44%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
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The United States has three companies in four locations
accounting for 34 percent of world production, and eight
European producers account for a combined 38 percent
of world production (CW 2007). Adipic  acid is  a white
crystalline solid used in the manufacture of synthetic fibers,
plastics, coatings, urethane foams, elastomers, and synthetic
lubricants.  Commercially, it is the most important of the
aliphatic dicarboxylic acids, which are used to manufacture
polyesters.  Eighty-four percent of all adipic acid produced
in the United States is used in the production of nylon 6,6;
9 percent is used in the production of polyester polyols; 4
percent is used in the production of plasticizers; and the
remaining 4 percent is accounted for by other uses, including
unsaturated polyester resins and food applications (ICIS
2007). Food grade adipic acid is used to provide some foods
with a "tangy" flavor (Thiemens and Trogler 1991).
    Adipic acid is produced through a two-stage process
during which N2O is generated in the second stage. The first
stage  of manufacturing usually involves the oxidation of
cyclohexane to form a cyclohexanone/cyclohexanol mixture.
The second stage involves oxidizing this mixture with nitric
acid to produce adipic acid. Nitrous oxide is generated as a
byproduct of the nitric acid oxidation stage and is emitted in
the waste gas stream (Thiemens and Trogler 1991). Process
emissions from the production  of adipic  acid vary with
the types of technologies and level  of emission controls
employed by a facility. In 1990, two of the three major adipic
acid-producing plants  had N2O abatement technologies in
place and, as of 1998, the three major adipic acid production
facilities had control systems in place (Reimer et al. 1999).n
Only one small plant, representing approximately two percent
of production, does not control  for N2O  (ICIS 2007; VA
DEQ 2006).
    Nitrous oxide emissions from adipic acid production
were estimated to be 5.9 Tg CO2 Eq. (19 Gg) in 2007 (see
Table 4-27). National adipic acid production has increased
by approximately 26 percent over the period of 1990 through
2007, to approximately one million metric tons. Over the
same period, emissions have been reduced by 61 percent due
to the widespread installation of pollution control measures
in the late 1990s.
Table 4-27: N20 Emissions from Adipic Acid Production
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
Gg
        1990
   15.3
49
        2005
        2006
        2007
Methodology
    For two production plants, 1990 to  2002 emission
estimates were obtained directly from the plant engineer
and account for reductions due to control systems in place at
these plants during the time series (Childs 2002,2003). These
estimates were based on continuous emissions monitoring
equipment installed at the two facilities. Reported emission
estimates for  2003 to  2007 were  unavailable. Emission
estimates for 2003 and 2004 were calculated by applying 4.4
and 4.2 percent national production growth rates, respectively.
Emission estimates for 2005 to 2007 were kept the same as
2004. National production for 2003 was calculated through
linear interpolation between 2002 and 2004 reported national
production  data. 2005 national production was  calculated
through linear interpolation between 2004 and 2006 reported
national production. 2007 national production was  kept
the same as 2006. For the other two plants, N2O emissions
were  calculated by multiplying adipic acid production by
an emission factor (i.e., N2O emitted per unit of adipic acid
produced) and adjusting for the percentage of N2O released
as a result of plant-specific emission controls. On the basis
of experiments, the overall reaction stoichiometry for N2O
production  in the preparation of adipic acid was estimated
at approximately 0.3 metric tons of N2O per metric ton of
product (IPCC 2006). Emissions are  estimated using the
following equation:
       N2O emissions = {production of adipic acid
           [metric tons (MT) of adipic acid]} x
            (0.3 MT N2O /MT adipic  acid) x
[1-(N2O destruction factor x abatement system utility factor)]
"During 1997, the N2O emission controls installed by the third plant
operated for approximately a quarter of the year.
                                                                                     Industrial Processes  4-21

-------
    The "N2O destruction factor" represents the percentage
of N2O emissions that are destroyed by the installed abatement
technology. The "abatement system utility factor" represents
the percentage of time that the abatement equipment operates
during the annual production period. Overall, in the United
States, two of the plants  employ catalytic destruction, one
plant employs thermal destruction, and the smallest plant
uses no N2O abatement equipment. For the one plant that
uses thermal destruction  and for which no reported plant-
specific emissions are available, the N2O abatement system
destruction factor is assumed to be 98.5 percent, and the
abatement system utility factor is assumed to be 97 percent
(IPCC 2006).
    For 1990 to 2003, plant-specific production data was
estimated where direct emission measurements were not
available. In  order to calculate plant-specific production
for the two plants, national adipic acid production was
allocated to the plant level using the ratio of their known plant
capacities to total national capacity for all U.S. plants. The
estimated plant production for the two plants was then used
for calculating emissions as described above. For 2004 and
2006, actual plant production data were obtained for these
two plants and used for  emission calculations. For 2005,
interpolated national production was used for calculating
emissions. For 2007, production was kept the same as 2006,
as described above.
    National  adipic acid production data (see Table 4-28)
for 1990 through 2002 were obtained from the American
Chemistry Council (ACC 2003). Production for 2003 was
estimated based on linear interpolation of 2002 and 2004
reported production. Production for 2004  and 2006 were
obtained from Chemical Week, "Product Focus: Adipic Acid"
(CW 2005, 2007). Plant  capacities for 1990 through 1994
were obtained from Chemical and Engineering News, "Facts
and Figures" and "Production of Top 50 Chemicals" (C&EN
1992 through 1995). Plant capacities for 1995 and 1996 were
kept the same as 1994 data. The 1997 plant capacities were
taken  from Chemical Market Reporter "Chemical Profile:
Adipic Acid" (CMR 1998). The 1998 plant capacities for all
four plants and 1999 plant capacities for three of the plants
were obtained from Chemical Week, "Product Focus: Adipic
Acid/Adiponitrile" (CW  1999). Plant capacities for 2000
for three of the plants were updated using Chemical Market
Table 4-28: Adipic Acid Production (Gg)
            Year
 Gg
            1990
           ^m
            1995
            2000
           ^H
            2005
            2006
            2007
 735
 830
 925
^B
1,002
1,002
1,002
Reporter, "Chemical Profile: Adipic Acid" (CMR 2001). For
2001 through 2005, the plant capacities for these three plants
were kept the same as the year 2000 capacities. Plant capacity
for 1999 to 2005 for the one remaining plant was kept the
same as 1998. For 2004 to 2007, although plant capacity data
are available (CW 1999, CMR 2001, ICIS 2007), they are
not used to calculate plant-specific production for these years
because plant-specific production data for 2004 and 2006 are
also available and are used in our calculations instead (CW
2005, CW 2007).

Uncertainty
    The overall uncertainty associated with the 2007 N2O
emission estimate from adipic acid production was calculated
using the IPCC Guidelines for National  Greenhouse
Gas  Inventories  (2006) Tier 2 methodology.  Uncertainty
associated with the parameters used to estimate N2O
emissions included that of company specific production data,
industry wide estimated production growth rates, emission
factors for abated and unabated emissions, and company-
specific historical emissions estimates.
    The results  of this Tier 2 quantitative  uncertainty
analysis are summarized in Table 4-29. Nitrous oxide
emissions from adipic acid production were estimated to be
between 4.9 and 7.1 Tg CO2 Eq. at the 95 percent confidence
level. This indicates a range of approximately 18  percent
below to 20 percent above the 2007 emission estimate of
5.9 Tg CO2 Eq.

Planned Improvements
    Improvement efforts will be focused on obtaining direct
measurement data from facilities. If they become available,
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Table 4-29: Tier 2 Quantitative Uncertainty Estimates for N20 Emissions from Adipic Acid Production
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
  Uncertainty Range Relative to Emission Estimate3
    (Tg C02 Eq.)                     (%)
                                                      Lower Bound   Upper Bound    Lower Bound    Upper Bound
  Adipic Acid Production     N20
                5.9
 4.9
  7.1
                                                                                  -18%
                                                                                                +20%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
cross verification with top-down approaches will provide a
useful Tier 2 level QC check. Also, additional information
on the actual performance of the latest catalytic and thermal
abatement equipment at plants with continuous emission
monitoring may support the re-evaluation of current default
abatement values.

4.8.  Silicon  Carbide  Production
(IPCC Source  Category 2B4)  and
Consumption

    Carbon dioxide and CtLj are emitted from the production12
of silicon carbide (SiC), a material used  as an industrial
abrasive. To make SiC, quartz (SiO2) is reacted with C in
the form of petroleum coke. A portion (about 35 percent) of
the C contained in the petroleum coke is retained in the SiC.
The remaining C is emitted as CO2, CH4, or CO.
                                   Carbon dioxide is also emitted from the consumption of
                               SiC for metallurgical and other non-abrasive applications.
                               The USGS reports that a portion (approximately 50 percent)
                               of SiC is used in metallurgical and other non-abrasive
                               applications, primarily in iron and steel production (USGS
                               2005a).

                                   Carbon dioxide emissions from SiC production and
                               consumption in 2007 were 0.2 Tg CO2 Eq. (196 Gg).
                               Approximately 47 percent of these emissions resulted
                               from SiC production while the remainder results from SiC
                               consumption. CH^ emissions from SiC production in 2007
                               were 0.01 Tg CO2 Eq. CH4 (0.4 Gg) (see Table 4-30 and
                               Table 4-31).


                               Methodology
                                   Emissions of CO2 and CH4 from the production of SiC
                               were calculated by multiplying annual SiC production by
                               the emission factors (2.62 metric tons CO2/metric ton SiC
Table 4-30: C02 and CH4 Emissions from Silicon Carbide Production and Consumption (Tg C02 Eq.)
Gas
                                            1990
                                              2000
                          2005
C02
CH4
                                              0.4
                                               0.2
                            0.2
                       2006
                                                                                                     2007
                        0.2
                                                                                                      0.2
Total
                                              0.4
                                  0.3
              0.3
               0.2
                                                                                             0.2
 0.2
  + Does not exceed 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
Table 4-31: C02 and CH4 Emissions from Silicon Carbide Production and Consumption (Gg)
  Gas
                    1990
1995
2000
                                                                                  2005
                                                                                           2006
2007
  C02
  CH4
  + Does not exceed 0.5 Gg.
12 Silicon carbide is produced for both abrasive and metallurgical applications
in the United States. Production for metallurgical applications is not available
and therefore both CH4 and CO2 estimates are based solely upon production
estimates of silicon carbide for abrasive applications.
                                                                     207
                                                                       +
                                              196
                                                +
                                                                                   Industrial Processes  4-23

-------
for CO2 and 11.6 kg CH4/metric ton SiC for CH4) provided
by the 2006IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC 2006).
    Emissions of CO2 from silicon carbide consumption
were calculated by multiplying the annual SiC consumption
(production plus net imports) by the percent used in
metallurgical and other non-abrasive uses (50 percent)
(USGS 2005a). The total SiC consumed in metallurgical and
other non-abrasive uses was multiplied by the C content of
SiC (31.5 percent), which was determined according to the
molecular weight ratio of SiC.
    Production data for 1990 through 2007 were obtained
from the Minerals Yearbook: Manufactured Abrasives (USGS
1991a through 2005a, 2006). Silicon carbide consumption
by major end use was obtained from the Minerals Yearbook:
Silicon (USGS 1991b through 2005b) (see Table 4-32) for
Table 4-32: Production and Consumption of Silicon
Carbide (Metric Tons)
        Year
Production
Consumption
        1990
       ^m
        1995
       ^^g
        2000
        2005
        2006
        2007
 105,000
 ^H
 75,400
 45,000
 ^H
 35,000
 35,000
 35,000
  172,465
 ^M
  227,395
  225,070
 ^H
  220,149
  199,937
  179,741
years 1990 through 2004 and from the USGS Minerals
Commodity Specialist for 2005 and 2006 (Corathers 2006,
2007). Silicon carbide consumption by major end use data
for 2007 are proxied using 2006 data due to unavailability
of data at time of publication. Net imports for the entire time
series were obtained from the U.S. Census Bureau (2005
through 2008).

Uncertainty
    There is uncertainty associated with the emission factors
used because they are based on stoichiometry as opposed to
monitoring of actual SiC production plants. An alternative
would be to calculate  emissions based on the quantity
of petroleum coke used during the  production process
rather than on the amount of silicon carbide produced.
However, these data were not available. For CtLj, there is
also  uncertainty associated with the hydrogen-containing
volatile  compounds in  the petroleum coke (IPCC 2006).
There is also some uncertainty associated with production,
net imports, and consumption data as well as the percent of
total consumption that is attributed to metallurgical and other
non-abrasive uses.
    The results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-33. Silicon carbide
production and consumption CO2 emissions were estimated
to be between 10 percent below and 10 percent above the
emission estimate of 0.2 Tg CO2  Eq. at the  95 percent
confidence level. Silicon carbide production CH4 emissions
Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CH4 and C02 Emissions from Silicon Carbide Production
and Consumption (Tg C02 Eq. and Percent)
  Source
         2007 Emission Estimate
  Gas         (Tg C02 Eq.)
                      Uncertainty Range Relative to Emission Estimate3
                       (Tg C02 Eq.)                     (%)

Silicon Carbide Production
and Consumption
Silicon Carbide Production

C02 0.2
CH4 +
Lower Bound Upper Bound Lower Bound
0.18 0.22 -10%
+ + -9%
Upper Bound
+10%
+ 10%
  + Does not exceed 0.05 Tg C02 Eq. or 0.5 Gg.
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4-24  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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were estimated to be between 9 percent below and 10
percent above the emission estimate of 0.01 Tg CO2 Eq. at
the 95 percent confidence level.

Recalculations Discussion
    Estimates of CO2 emissions from silicon carbide
consumption were revised for all years due to the availability
of more precise import and export data from the United
States International Trade Commission. On average, these
revisions resulted in a decrease in annual emissions of less
than 1 percent.

Planned Improvements
    Future improvements to  the carbide production source
category include continued research to determine if calcium
carbide production and consumption data are available for
the United States. If these data are available, calcium carbide
emission estimates will be included in this source category.

4.9.  Petrochemical  Production
(IPCC Source Category 2B5)

    The production of some petrochemicals  results in
the release of small amounts of CH^ and  CO2 emissions.
Petrochemicals are chemicals isolated or derived from
petroleum or natural gas. CH4 emissions are  presented
here from the production of C black, ethylene, ethylene
dichloride, and methanol, while CO2 emissions are presented
here for only C black production. The CO2 emissions from
petrochemical processes other than C black are currently
included in the Carbon Stored in Products from Non-Energy
Uses of Fossil Fuels Section of the Energy chapter. The CO2
from C black production is included here to allow for the
direct reporting of CO2 emissions from the process and direct
accounting of the feedstocks used in the process.
    Carbon black is an intense black powder generated by
the incomplete combustion of an aromatic petroleum or
coal-based feedstock. Most C black produced in the United
States is added to rubber to impart strength and abrasion
resistance, and the tire industry is by far the largest consumer.
Ethylene is consumed in the  production processes of the
plastics industry including polymers such as high, low, and
linear low density polyethylene (HOPE,  LDPE, LLDPE),
polyvinyl  chloride (PVC), ethylene dichloride, ethylene
oxide, and ethylbenzene. Ethylene dichloride is one of the
first manufactured chlorinated hydrocarbons with reported
production as early as 1795. In addition to being an important
intermediate in the synthesis of chlorinated hydrocarbons,
ethylene dichloride is used as an industrial solvent  and as a
fuel additive. Methanol is an alternative transportation fuel
as well as  a principle ingredient in windshield wiper fluid,
paints, solvents, refrigerants, and disinfectants. In addition,
methanol-based acetic acid is  used in making PET plastics
and polyester fibers.
    Emissions  of CO2 and CH4 from petrochemical
production in 2007 were 2.6 Tg CO2 Eq. (2,636 Gg) and 1.0
Tg CO2 Eq. (48 Gg), respectively (see Table 4-34 and Table
4-35), totaling 3.7 Tg CO2 Eq. Emissions of CO2 from C
Table 4-34: C02 and CH4 Emissions from Petrochemical Production (Tg C02 Eq.)
Gas
C02
CH4
Total
1990
2.2
0.9
3.1
1995
2.8
1.1
3.8
2000
3.0
1.2
4.2
2005
2.8
1.1
3.9
2006
2.6
1.0
3.6
2007
2.6
1.0
3.7
Table 4-35: C02 and CH4 Emissions from Petrochemical Production (Gg)
Gas
C02
CH4
1990
2,221
41
1995
2,750
52
2000
3,004
59 |
2005
2,804
51
2006
2,573
48
2007
2,636
48
                                                                                 Industrial Processes  4-25

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black production remained constant at 2.6 Tg CO2 Eq. (2,573
Gg) in 2006 and 2007. There has been an overall increase
in CO2 emissions from C black production of 18 percent
since 1990. CK4 emissions from petrochemical production
increased by approximately 17 percent since 1990.

Methodology
    Emissions of CH4 were calculated by multiplying
annual estimates of chemical production by the appropriate
emission factor, as follows: 11 kg CtLj/metric ton C black, 1
kg CH4/metric ton ethylene, 0.4 kg CH4/metric ton ethylene
dichloride,13 and 2 kg CELj/metric ton methanol. Although
the production of other chemicals may also result in CH4
emissions, insufficient data were available to estimate their
emissions.
    Emission factors  were taken from the Revised  1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual
production data (see Table  4-36) were obtained from the
American Chemistry Council's Guide to the Business of
Chemistry (ACC 2002, 2003, 2005 through 2008) and the
International Carbon Black Association (Johnson 2003,2005
through 2008).
    Almost all C black in  the United States is  produced
from petroleum-based or coal-based feedstocks  using the
"furnace black" process (European IPPC Bureau 2004).
The furnace black process  is a partial combustion process
in which a portion of the C black feedstock is combusted
to provide energy to the process.  C black is also produced
in the United States by the  thermal cracking of acetylene-
containing feedstocks ("acetylene black  process") and by
the thermal cracking of other hydrocarbons ("thermal black
process"). One U.S. C black plant produces C black using the
thermal black process, and one U.S. C black plant produces
C black using the acetylene black process (The Innovation
Group 2004).
    The furnace black process produces C black from "C
black feedstock" (also referred to as "C black oil"), which
is a heavy aromatic oil that may be derived as a byproduct
of either the petroleum refining process or the metallurgical
(coal) coke production process. For the production of both
petroleum-derived and coal-derived C black, the "primary
feedstock" (i.e., C black feedstock) is injected into a furnace
that is heated by a "secondary feedstock" (generally natural
gas). Both the natural gas secondary feedstock and a portion
of the C black feedstock are oxidized to provide heat to the
production process and pyrolyze the remaining C black
feedstock to C black. The "tail gas" from the furnace black
process contains CO2, carbon monoxide, sulfur compounds,
CELj, and non-CELj volatile organic compounds. A portion of
the tail gas is generally burned for energy recovery to heat
the downstream C black product dryers. The remaining tail
gas may also be burned for energy recovery, flared, or vented
uncontrolled to the atmosphere.
    The calculation of the C lost during the production
process  is the basis for determining the amount of CO2
released during the process. The C content of national C
black production is subtracted from the total amount of C
contained  in primary and secondary C black feedstock to
find the amount of C lost during the production process. It
is assumed that the C  lost in this process is  emitted to the
atmosphere as either CK4 or CO2. The C content of the CK4
emissions, estimated as described above, is subtracted from
the total C lost in the process to calculate the amount of C
emitted as CO2.  The total amount of primary and secondary
C black feedstock consumed in the process (see Table 4-37)
is estimated using a primary feedstock consumption factor
Table 4-36: Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Dichloride
Methanol
1990
1,307
16,541
6,282
3,785
1995
1,619
21,214
7,829
4,992
2000
1,769
24,970
9,866
5,221 1
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

13 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).
4-26  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-37: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
Consumption (Thousand Metric Tons)
  Activity
                    1990
           2000
  Primary Feedstock
  Secondary Feedstock
                    1,864
                     302
2005
2006
2007
                        2,353
                         381
         2,159
           350
         2,212
           358
and a secondary feedstock consumption factor estimated
from U.S. Census Bureau (1999 and 2004) data. The
average C black feedstock consumption factor for U.S. C
black production is 1.43 metric tons of C black feedstock
consumed per metric ton of C black produced. The average
natural gas consumption factor for U. S. C black production is
341 normal cubic meters of natural gas consumed per metric
ton of C black produced. The amount of C contained in the
primary and secondary feedstocks is calculated by  applying
the respective C contents of the feedstocks to the respective
levels of feedstock consumption (EIA 2003, 2004).
    For the purposes of emissions estimation, 100 percent of
the primary C black feedstock is assumed to be derived from
petroleum refining byproducts. C black feedstock derived
from metallurgical (coal) coke production (e.g.,  creosote
oil) is also used for C black production; however, no data
are available  concerning the annual consumption of coal-
derived C black feedstock. C black feedstock derived from
petroleum refining byproducts is assumed to be 89 percent
elemental C (Srivastava et al. 1999). It is assumed that 100
percent of the tail gas produced from the C black production
process is combusted and that none of the tail gas is vented
to the atmosphere uncontrolled. The furnace black process
is assumed to be the only process used for the production of
C black because of the lack of data concerning the relatively
small amount of C black produced using the acetylene black
and thermal black processes. The C black produced from the
furnace black process is assumed to be 97 percent elemental
C (Othmer et al. 1992).
                                Uncertainty
                                    The CH4 emission factors used for petrochemical
                                production are based on a limited number of studies. Using
                                plant-specific factors instead of average factors could increase
                                the accuracy of the emission estimates; however, such data
                                were not available. There may also be other significant
                                sources  of CH4 arising from petrochemical production
                                activities that have not been included in these estimates.
                                    The results of the quantitative uncertainty analysis for
                                the CO2 emissions from C black production calculation
                                are based on feedstock  consumption, import and export
                                data, and C black production data. The composition of C
                                black feedstock varies depending upon the specific refinery
                                production process, and therefore the assumption that C
                                black feedstock is 89 percent C gives rise to uncertainty.
                                Also, no data are available concerning the consumption of
                                coal-derived C black feedstock, so CO2 emissions from the
                                utilization of coal-based feedstock are not included in the
                                emission estimate. In addition, other data sources indicate
                                that the  amount of petroleum-based feedstock used in C
                                black production may be underreported by the U.S. Census
                                Bureau. Finally, the amount of C black produced from the
                                thermal black process and acetylene black process, although
                                estimated to be a small percentage of the total production, is
                                not known. Therefore, there is some uncertainty associated
                                with the assumption that all of the C black is produced using
                                the furnace black process.
                                    The results of the Tier 2 quantitative uncertainty analysis
                                are summarized in Table 4-38. Petrochemical production
Table 4-38: Tier 2 Quantitative Uncertainty Estimates for C02 and CH4 Emissions from Petrochemical Production
and C02 Emissions from Carbon Black Production (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                     (%)

Petrochemical Production
Petrochemical Production

C02
CH4

2.6
1.0
Lower Bound
1.7
0.7
Upper Bound
3.7
1.3
Lower Bound
-34%
-31%
Upper Bound
+40%
+31%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                    Industrial Processes  4-27

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CO2 emissions were estimated to be between 1.7 and 3.7 Tg
CO2 Eq. at the 95 percent confidence level. This indicates
a range of approximately 34 percent below to 40 percent
above the emission estimate of 2.6 Tg CO2 Eq. Petrochemical
production CH4 emissions were estimated to be between 0.7
and 1.3 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range of approximately 31 percent below to 31
percent above the emission estimate of 1.0 Tg CO2 Eq.

Recalculations  Discussion
    Estimates of CH4 emissions from petrochemical
production were revised to account for small changes in
ethylene, ethylene dichloride, and methanol production
for years 1990 through 2006. On average, these revisions
resulted in  an annual increase in CH4 emissions of
approximately 1.5 percent.
Table 4-39: C02 Emissions from Titanium Dioxide
(Tg C02 Eq. and Gg)
Planned Improvements
    Future improvements to the Petrochemical Production
source category include research into the use of acrylonitrile
in the United States, revisions to the C black CH4 and CO2
emission factors, and research into process and feedstock
data to obtain Tier 2 emission estimates from the production
of methanol, ethylene, propylene, ethylene dichloride, and
ethylene oxide.

4.10. Titanium  Dioxide Production
(IPCC Source  Category 2B5)

    Titanium dioxide (TiO2) is a metal oxide manufactured
from titanium ore, and  is  principally used as  a pigment.
Titanium dioxide is a principal ingredient in white paint,
and is also used as a pigment in the manufacture of white
paper, foods, and other products. There are two processes for
making TiO2: the chloride  process and the sulfate process.
The chloride process uses  petroleum coke and chlorine as
raw materials  and emits process-related CO2. The sulfate
process does not use petroleum coke or other forms of C as
a raw material and does not emit CO2.
    The chloride process is based on the following chemical
reactions:
    2FeTi03 + 7C12 + 3C -» 2TiCl4 + 2FeCl3 + 3CO2
            2TiCl4 + 202 -» 2Ti02 + 4C12
        Year
Tg C02 Eq.
 Gg
        1990
   1.2
1,195
        2005
        2006
        2007
    The C in the first chemical reaction is provided by
petroleum coke, which is oxidized in the presence of the
chlorine and FeTiO3 (the Ti-containing ore) to form CO2.
The majority of U.S. TiO2 was produced in  the United
States through the chloride process, and a special grade of
"calcined" petroleum coke is manufactured specifically for
this purpose.
    Emissions of CO2 in 2007 were 1.9 Tg CO2 Eq. (1,876
Gg), which represents an increase of 57 percent since 1990
(see Table 4-39).

Methodology
    Emissions of CO2 from TiO2 production were calculated
by multiplying annual TiO2 production by chloride-process-
specific emission factors.
    Data were  obtained for the total amount of TiO2
produced each year. For years previous to 2004, it was
assumed that TiO2 was produced using the chloride process
and the sulfate process in the same ratio as the  ratio of the
total U.S. production capacity for each process. As of 2004,
the last remaining sulfate-process plant in the United States
had closed. As a result, all U.S. current TiO2  production
results from the chloride process (USGS 2005). An emission
factor of 0.4 metric tons C/metric ton TiO2 was applied to the
estimated chloride-process production. It was assumed that
all TiO2 produced using the chloride process was produced
using  petroleum coke, although some TiO2 may have been
produced with graphite or other C inputs. The amount of
petroleum coke consumed annually in TiO2 production
was calculated based on the assumption that the calcined
petroleum coke used in the process is 98.4 percent C and 1.6
percent inert materials (Nelson 1969).
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Table 4-40: Titanium Dioxide Production (Gg)
            Year
            Gg
            1990
            1995
            2000
           ^H
            2005
            2006
            2007
            979
           •
           1,250
          ^m
           1,400
          ^m
           1,310
           1,400
           1,400
    The emission factor for the TiO2 chloride process
was taken from the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC 2006). Titanium dioxide
production data and the percentage of total TiO2 production
capacity that is chloride process for 1990 through 2006 (see
Table 4-40) were obtained through the Minerals Yearbook:
Titanium Annual Report (USGS 1991 through 2008). Because
2007 production and capacity data were unavailable, 2006
production data were used. Percentage chloride-process data
were not available for 1990 through 1993, and data from the
1994 USGS Minerals  Yearbook were used for these years.
Because a sulfate-process plant closed in September 2001,
the chloride-process percentage for 2001 was estimated based
on a discussion with Joseph Gambogi (2002). By 2002, only
one sulfate plant remained online in the United States and
this plant closed in 2004 (USGS 2005).

Uncertainty
    Although some TiO2 may be produced using graphite
or other C inputs, information and data regarding  these
practices were  not available. Titanium dioxide produced
using graphite inputs, for example, may generate differing
amounts of CO2 per unit of TiO2 produced as compared
to that generated through the use of petroleum coke in
production. While the most accurate method to estimate
emissions would be to base calculations on the amount
of reducing agent used in each process rather than on the
amount of TiO2 produced, sufficient data were not available
to do so.
    Also, annual TiO2 is not reported by USGS by the type
of production process used (chloride or sulfate). Only the
percentage of total production capacity by process is reported.
The  percent of total TiO2  production capacity that was
attributed to the chloride process was multiplied by total TiO2
production to estimate the amount of TiO2 produced using
the chloride process. As of 2004, the last remaining sulfate-
process plant in the United States closed; therefore, 100
percent of post-2004 production uses the chloride process.
This assumes that the chloride-process plants and sulfate-
process plants operate at the same level of utilization. Finally,
the emission factor was applied uniformly to all chloride-
process production, and no  data were available to account
for differences in production efficiency among  chloride-
process plants. In calculating the amount of petroleum coke
consumed in chloride-process TiO2 production,  literature
data were used for petroleum  coke composition. Certain
grades of petroleum coke are manufactured specifically for
use in the TiO2 chloride process; however, this composition
information was not available.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-41. Titanium dioxide consumption
CO2 emissions were estimated to be between 1.6 and 2.1 Tg
CO2 Eq.  at the 95 percent confidence level. This indicates
a range of approximately 12 percent below and 13 percent
above the emission estimate of  1.9 Tg CO2 Eq.
Table 4-41: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Titanium Dioxide Production
(Tg C02 Eq. and Percent)
  Source
      2007 Emission Estimate
Gas        (Tg C02 Eq.)
    Uncertainty Range Relative to Emission Estimate3
     (Tg C02 Eq.)                     (%)
                                                      Lower Bound    Upper Bound    Lower Bound   Upper Bound
  Titanium Dioxide Production  CO?
               1.9
   1.6
2.1
-12%
+13%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                    Industrial Processes  4-29

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Planned Improvements
    Future improvements to TiO2 production methodology
include researching the significance of titanium-slag
production in electric furnaces  and synthetic-rutile
production using the Becher process in the United States.
Significant use of these production processes will be included
in future estimates.

4.11.  Carbon Dioxide Consumption
(IPCC Source Category 2B5)

    Carbon dioxide is  used for a variety of commercial
applications, including food processing, chemical production,
carbonated beverage production, and refrigeration, and is
also used in petroleum production for enhanced oil recovery
(EOR). Carbon dioxide used for EOR  is injected into the
underground reservoirs to increase the reservoir pressure to
enable additional petroleum to be produced.
    For the most part, CO2 used in non-EOR applications
will eventually be  released to  the atmosphere, and for
the purposes of this analysis CO2 used in commercial
applications other than EOR is assumed to be emitted to
the atmosphere. Carbon dioxide  used in EOR applications
is discussed in the Energy Chapter under "Carbon Capture
and Storage, including Enhanced Oil Recovery" and is not
discussed in this section.
     Carbon dioxide is  produced from  naturally occurring
CO2 reservoirs, as a byproduct from energy and industrial
production processes (e.g., ammonia production, fossil
fuel combustion, ethanol production), and as a byproduct
from the production of crude oil and  natural gas, which
contain naturally occurring CO2 as a component. Only CO2
produced from naturally occurring CO2 reservoirs and used
in industrial applications other than EOR is included in this
analysis. Neither byproduct CO2 generated from energy
nor industrial production processes nor CO2 separated from
crude oil and natural gas are included in this analysis for a
number of reasons. Carbon dioxide captured from biogenic
sources (e.g., ethanol production plants) is not included in
the inventory. Carbon dioxide  captured from crude oil and
gas production is used in EOR applications and is therefore
reported in the Energy Chapter. Any CO2 captured from
industrial or energy production  processes (e.g., ammonia
plants, fossil  fuel  combustion) and  used in non-EOR
applications is assumed to be emitted  to the atmosphere.
The CO2 emissions from such capture and use are therefore
accounted for under Ammonia Production, Fossil Fuel
Combustion, or other appropriate source category.14
    Carbon dioxide is produced as a byproduct of crude oil
and natural gas production. This CO2 is separated from the
crude oil and natural gas using gas processing equipment,
and may be emitted directly to the atmosphere, or captured
and reinjected into underground formations, used for EOR,
or sold for other commercial uses. A further discussion of
CO2 used in EOR is described in the Energy Chapter under
the text box titled  "Carbon Dioxide Transport, Injection,
and Geological Storage." The  only CO2 consumption that
is  accounted for in this analysis is CO2 produced from
naturally-occurring CO2 reservoirs that is used in commercial
applications other than EOR.
    There are currently two facilities, one in Mississippi and
one in New Mexico, producing CO2 from naturally occurring
CO2 reservoirs for use in both EOR and in other commercial
applications (e.g., chemical manufacturing, food production).
There are other naturally occurring CO2 reservoirs, mostly
located in the western United States. Facilities are producing
CO2 from these natural reservoirs, but they are only producing
CO2 for EOR applications,  not for  other commercial
applications (Allis et al. 2000). Carbon dioxide production
from these facilities is discussed in the Energy chapter.
    In 2007, the amount of CO2 produced by the Mississippi
and New Mexico facilities for commercial applications and
subsequently emitted to the atmosphere was 1.9 Tg  CO2
Eq. (1,867 Gg) (see Table 4-42). This amount represents an
increase of 9 percent from the previous year and an increase

Table 4-42: C02  Emissions from C02 Consumption
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
  Gg
        2000
       ^m
        2005
        2006
        2007
   1.4
  •
   1.3
   1.7
   1.9
 1,421
M
 1,321
 1,709
 1,867
14There are currently four known electric power plants operating in the
United States 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.
4-30  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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of 32 percent since 1990. This increase was due to an increase
in production at the Mississippi facility, despite the decrease
in the percent of the facility's total reported production that
was used for commercial applications.

Methodology
    Carbon dioxide emission estimates for 1990 through 2007
were based on production data for the two facilities currently
producing CO2 from naturally-occurring CO2 reservoirs for
use in non-EOR  applications.  Some of the CO2 produced
by these facilities is used for EOR and some is used in other
commercial applications (e.g., chemical manufacturing,
food production). It is assumed that 100 percent of the CO2
production used in commercial applications other than EOR
is eventually released into the atmosphere.
    Carbon dioxide production data for the Jackson Dome,
Mississippi facility and the percentage of total production
that was used for EOR and in  non-EOR applications
were obtained from the Advanced Resources Institute
(ARI 2006, 2007) for  1990 to 2000 and from the Annual
Reports for Denbury Resources (Denbury Resources 2002
through 2007) for 2001 to 2007 (see Table 4-43). Denbury
Resources reported the average CO2 production in units of
MMCF CO2 per  day for 2001 through 2007 and reported
the percentage of the total average annual production that
                              was used for EOR. Carbon dioxide production data for the
                              Bravo Dome, New Mexico facility were obtained from the
                              Advanced Resources International, Inc. (Godec 2008). The
                              percentage of total production that was used for EOR and in
                              non-EOR applications were obtained from the New Mexico
                              Bureau of Geology and Mineral Resources (Broadhead
                              2003 and New Mexico Bureau of Geology and Mineral
                              Resources 2006).

                              Uncertainty
                                  Uncertainty is associated with the number of facilities
                              that are currently producing CO2 from naturally occurring
                              CO2 reservoirs for commercial uses other than EOR, and for
                              which the CO2 emissions are not accounted for elsewhere.
                              Research indicates that there are only two such  facilities,
                              which are in New Mexico and Mississippi; however,
                              additional facilities may exist that have not been identified. In
                              addition, it is possible that CO2 recovery exists in particular
                              production and end-use  sectors that are not accounted for
                              elsewhere. Such recovery may or may not affect the overall
                              estimate of CO2 emissions from that sector depending upon
                              the end use to which the recovered CO2 is applied. Further
                              research is required to  determine whether CO2 is  being
                              recovered from other facilities for application to end uses
                              that are not accounted for elsewhere.
Table 4-43: C02 Production (Gg C02) and the Percent Used for Non-EOR Applications for Jackson Dome
and Bravo Dome
          Year
Jackson Dome C02
 Production (Gg)
Jackson Dome % Used
    for Non-EOR
Bravo Dome C02
Production (Gg)
Bravo Dome % Used
   for Non-EOR
2005
2006
2007
4,677
6,610
9,529
27%
25%
19%
5,799
5,613
5,605
1%
1%
1%
                                                                                  Industrial Processes  4-31

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Table 4-44: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from C02 Consumption
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                   Uncertainty Range Relative to Emission Estimate3
                    (Tg C02 Eq.)                     (%)
                                                    Lower Bound    Upper Bound    Lower Bound   Upper Bound
  C02 Consumption
CO,
1.9
1.5
2.3
-18%
+22%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-44. Carbon dioxide consumption
CO2 emissions were estimated to be between 1.5 and 2.3 Tg
CO2 Eq. at the 95 percent confidence level. This indicates a
range of approximately 18 percent below to 22 percent above
the emission estimate of 1.9 Tg CO2 Eq.

Recalculations Discussion
    Estimates of CO2 emissions from CO2  Consumption
have been revised for 2006 based on revised CO2 production
data from Jackson Dome. The revision resulted in an increase
in emissions of approximately 8 percent for 2006.

Planned  Improvements
    Future improvements to the Carbon Dioxide Consumption
source category include research into CO2 capture for
industrial purposes at electric power plants. Currently,
four plants have been identified that capture CO2 for these
purposes, but insufficient data  prevents including them in
the current emission estimate.

4.12.  Phosphoric Acid Production
(IPCC  Source Category  2B5)

    Phosphoric acid (H3PO4) is a basic raw material in the
production of phosphate-based fertilizers.  Phosphate rock
is mined in Florida, North Carolina, Idaho, Utah, and other
areas of the United States and is used primarily as a raw
material for phosphoric acid production. The production of
phosphoric acid from phosphate rock produces byproduct
gypsum (CaSO4 • 2H2O), referred to as phosphogypsum.
    The  composition of natural  phosphate rock varies
depending upon the location where it is  mined. Natural
                              phosphate rock mined in the United States generally contains
                              inorganic C in the form of calcium carbonate (limestone) and
                              also may contain organic C. The chemical composition of
                              phosphate rock (francolite) mined in Florida is:
                                       Ca10_x_y Nax Mgy (PO4)6_x(CO3)xF2+0.4x
                                  The calcium carbonate component of the phosphate rock
                              is integral to the phosphate rock chemistry. Phosphate rock
                              can also contain organic C that is physically incorporated
                              into the mined rock but is not an integral component of the
                              phosphate rock chemistry. Phosphoric acid production from
                              natural phosphate rock is a source of CO2 emissions, due to
                              the chemical reaction of the inorganic C (calcium carbonate)
                              component of the phosphate rock.
                                  The  phosphoric acid production process  involves
                              chemical reaction of the calcium phosphate (Ca3(PO4)2)
                              component of the phosphate rock with sulfuric acid (H2SO4)
                              and recirculated phosphoric acid (H3PO4) (EFMA 2000). The
                              primary chemical reactions for the production of phosphoric
                              acid from phosphate rock are:
                                       Ca3(PO4)2 + 4H3PO4 -» 3Ca(H2PO4)2
                                        3Ca(H2P04)2 + 3H2S04 + 6H2O -»
                                             3CaS04 • 6H20 + 6H3PO4
                                  The limestone (CaCO3) component of the phosphate rock
                              reacts with the sulfuric acid in the phosphoric acid production
                              process to produce calcium  sulfate (phosphogypsum) and
                              CO2. The chemical reaction for the limestone-sulfuric acid
                              reaction is:
                                    CaCO,
           H2SO4 + H2O
                                            CaSO4 • 2H2O + CO2
                                  Total marketable phosphate rock production in 2007
                              was 29.7 million metric tons. Approximately 87 percent of
                              domestic phosphate rock production was mined in Florida
                              and North Carolina,  while  approximately 13 percent of
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Table 4-45: C02 Emissions from Phosphoric Acid
Production (Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
 Gg
        1990
   1.5
1,529
        2005
        2006
        2007
production was mined in Idaho and Utah. In addition, 2.7
million metric tons of crude phosphate rock was imported
for consumption in 2007. The vast majority, 99 percent, of
imported phosphate rock is sourced from Morocco (USGS
2005). Marketable phosphate  rock production, including
domestic production and imports for consumption, decreased
by less than 1 percent between 2006 and 2007. However,
over the 1990 to 2007 period, production has decreased
by 26 percent. Total CO2 emissions from phosphoric acid
production were 1.2 Tg CO2 Eq. (1,166 Gg) in 2007 (see
Table 4-45).

Methodology
    Carbon dioxide emissions from production of phosphoric
acid from phosphate rock are calculated by multiplying the
average amount of calcium carbonate contained in the natural
phosphate rock by the amount of phosphate rock that is used
annually to produce phosphoric acid, accounting for domestic
production and net imports for consumption.
    The CO2 emissions calculation methodology is based
on the assumption that all  of the inorganic C (calcium
carbonate) content of the phosphate rock reacts to CO2 in
the phosphoric acid production process and is emitted with
the stack gas. The methodology also assumes that none of
the organic C content of the phosphate rock is converted
to CO2 and that all of the organic C content remains in the
phosphoric acid product.
    From  1993 to 2004,  the USGS  Minerals  Yearbook:
Phosphate Rock  disaggregated phosphate rock mined
annually in Florida and North Carolina from  phosphate
rock mined annually in Idaho and Utah, and reported the
annual amounts of phosphate rock exported and imported
for consumption (see Table 4-46). For the years 1990,1991,
1992, 2005, 2006, and 2007 only nationally aggregated
mining data  was reported by USGS. For these years, the
breakdown of phosphate rock mined in Florida and North
Carolina, and the amount mined in Idaho and Utah, are
approximated using  1993  to 2004 data. Data for domestic
production of phosphate rock, exports of phosphate rock
(primarily from Florida and North Carolina), and imports of
phosphate rock for consumption for 1990 through 2007 were
obtained from USGS Minerals Yearbook: Phosphate Rock
(USGS 1994 through 2008). From 2004-2007,  the USGS
reported no exports of phosphate rock from U.S. producers
(USGS 2005 through 2008).
Table 4-46: Phosphate Rock Domestic Production, Exports, and Imports (Gg)
Location
U.S. Production3
Florida & North Carolina
Idaho & Utah
Exports — Florida & North Carolina
Imports— Morocco
Total U.S. Consumption
1990
49,800
42,4941
7,306 1
6,240
451
44,011
1995
43,720
38,100
5,620
2,760
1,800
42,760
2000
37,370
31,900
5,470
299
1,930
39,001
2005
36,100
31,227
4,874
2,630
38,730
2006
30,100
26,037
4,064
2,420
32,520
2007
29,700
25,691
4,010
2,670
32,370
  - Assumed equal to zero.
  aUSGS does not disaggregate production data regionally (Florida & North Carolina and Idaho & Utah) for 1990, 2005, 2006, and 2007. Data for those years are
  estimated based on the remaining time series distribution.
                                                                                  Industrial Processes  4-33

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Table 4-47: Chemical Composition of Phosphate Rock (Percent by Weight)
Composition
Total Carbon (as C)
Inorganic Carbon (as C)
Organic Carbon (as C)
Inorganic Carbon (as C02)
Central Florida
1.60
1.00
0.60
3.67
North Florida
1.76
0.93
0.83
3.43
North Carolina
(calcined)
0.76
0.41
0.35
1.50
Idaho
(calcined)
0.60
0.27
1.00
Morocco
1.56
1.46
0.10
5.00
  - Assumed equal to zero.
  Source: FIPR (2003).
    The carbonate content of phosphate rock varies
depending upon where the material is mined. Composition
data for domestically mined and imported phosphate rock
were provided by the Florida Institute of Phosphate Research
(FIPR 2003). Phosphate rock mined in Florida contains
approximately 1 percent inorganic C, and phosphate rock
imported from Morocco contains approximately 1.46 percent
inorganic C. Calcined phosphate rock mined in North
Carolina and Idaho contains approximately 0.41 percent and
0.27 percent inorganic C, respectively (see Table 4-47).
    Carbonate content data for phosphate rock mined
in Florida are used to calculate the CO2 emissions from
consumption of phosphate rock mined in Florida and North
Carolina (87 percent of domestic production) and carbonate
content data for phosphate rock mined in Morocco are used
to calculate CO2 emissions from consumption of imported
phosphate rock. The CO2 emissions calculation is based
on the assumption that all of the domestic production of
phosphate rock is used in uncalcined form. As of 2006, the
USGS noted that one phosphate rock producer in Idaho
produces calcined phosphate rock; however, no production
data were available for this single producer (USGS 2006).
Carbonate content data for uncalcined phosphate rock mined
in Idaho and Utah (13 percent of domestic production) were
not available, and carbonate content was therefore estimated
from the carbonate content data for calcined phosphate rock
mined in Idaho.

Uncertainty
    Phosphate rock production data used in the emission
calculations were developed by the USGS through monthly
and semiannual voluntary surveys of the active phosphate
rock mines during 2007. For previous years in the time
series, USGS provided the data disaggregated regionally;
however, beginning in 2006 only total U.S. phosphate rock
production was reported. Regional production for 2007 was
estimated based on regional production data from previous
years and multiplied by regionally specific emission factors.
There is  uncertainty associated with the degree to which
the estimated 2007 regional production data represents
actual production in those regions. Total U.S. phosphate
rock production data are not considered to be a significant
source of uncertainty because all the domestic phosphate
rock producers report their annual production to the USGS.
Data for  exports of phosphate rock used in the emission
calculation are reported by phosphate rock producers and
are not considered to be a significant source of uncertainty.
Data for imports for consumption are based on international
trade data collected by the U.S. Census  Bureau. These
U.S. government economic data are not considered to be a
significant source of uncertainty.
    An additional source of uncertainty in the calculation
of CO2 emissions from phosphoric  acid production is  the
carbonate composition of  phosphate rock; the composition
of phosphate rock varies depending upon where the material
is mined, and may also vary over time. Another source of
uncertainty is the disposition of the organic C content of the
phosphate rock. A representative of the FIPR indicated that
in the phosphoric acid  production process, the  organic C
content of the mined phosphate rock generally remains in the
phosphoric acid product, which is what produces the color
of the phosphoric acid product (FIPR 2003a). Organic C is
therefore not included in the calculation of CO2 emissions
from phosphoric acid production.
    A third source of uncertainty is the assumption that all
domestically-produced phosphate rock is used in phosphoric
acid production and used without first being calcined.
Calcination of the phosphate rock would result in conversion
of some of the organic  C in the phosphate rock into CO2.
However, according to the USGS, only one producer in
4-34  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-48: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Phosphoric Acid Production
(Tg C02 Eq. and Percent)
  Source
      2007 Emission Estimate
Gas        (Tg C02 Eq.)
 Uncertainty Range Relative to Emission Estimate3
  (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Phosphoric Acid Production   C02
               1.2
1.0
1.4
-18%
+18%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Idaho is currently calcining phosphate rock, and no data were
available concerning the annual production of this single
producer (USGS 2005). For available years, total production
of phosphate rock in Utah and Idaho combined amounts to
approximately 13 percent of total domestic production on
average (USGS 1994 through 2005).
    Finally, USGS indicated that approximately 7 percent
of domestically-produced phosphate rock  is used to
manufacture elemental phosphorus and other phosphorus-
based chemicals, rather than phosphoric acid (USGS 2006).
According to USGS, there is only one domestic producer of
elemental phosphorus, in Idaho, and no data were available
concerning the annual  production of this single producer.
Elemental phosphorus is produced by  reducing phosphate
rock with coal coke, and it is therefore assumed that 100
percent of the carbonate content of the  phosphate rock will
be converted to CO2 in the elemental phosphorus production
process. The calculation for CO2 emissions is based on the
assumption that phosphate rock consumption, for purposes
other than phosphoric acid  production, results  in CO2
emissions from 100 percent of the inorganic C content in
phosphate rock, but none from the organic C content.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-48. Phosphoric acid production
CO2 emissions were estimated to be between 1.0 and 1.4 Tg
CO2 Eq. at the 95 percent confidence level. This indicates
a range of approximately 18 percent below and 18 percent
above the emission estimate of 1.2 Tg CO2 Eq.

Planned Improvements
    Currently, data sources for the carbonate content of the
phosphate rock are limited. If additional data sources are found,
this information will be incorporated into future estimates.
                              4.13.  Iron  and  Steel  Production
                              (IPCC Source Category 2C1)  and
                              Metallurgical Coke Production

                                  The production of iron and steel is an energy-intensive
                              process that also generates process-related emissions of CO2
                              and CH4. Metallurgical  coke, which is manufactured using
                              coking coal  as a raw material, is used widely during the
                              production of iron and steel. According to the 2006 IPCC
                              Guidelines for National Greenhouse Gas Inventories (IPCC
                              2006), the production of metallurgical coke from coking
                              coal is considered to be an energy use of fossil fuel and
                              the use of coke in iron and steel production is considered
                              to be an industrial process source, so emissions from these
                              are reported separately. Emission estimates presented in
                              this chapter  are based on the methodologies provided by
                              the 2006 IPCC Guidelines for National Greenhouse Gas
                              Inventories (IPCC 2006), which call for a mass balance
                              accounting of the carbonaceous  inputs and outputs  during
                              the iron and steel production process and the metallurgical
                              coke production process. The methodologies also call for
                              reporting emissions from metallurgical coke production in
                              the Energy sector; however, the approaches and emission
                              estimates for both metallurgical coke production and iron and
                              steel production are presented separately here because the
                              activity data used to estimate emissions from metallurgical
                              coke production have significant overlap with activity data
                              used to estimate iron and steel production emissions. Further,
                              some byproducts (e.g., coke oven gas) of the metallurgical
                              coke production process are consumed during iron and
                              steel production, and some byproducts of the iron and steel
                              production process (e.g., blast furnace gas) are consumed
                              during metallurgical coke production. Emissions associated
                                                                                  Industrial Processes 4-35

-------
with the consumption of these byproducts are attributed
to point of consumption. As an example, CO2 emissions
associated with the combustion of coke oven gas in the blast
furnace during pig iron production are attributed to pig iron
production. Emissions  associated with fuel consumption
downstream of the iron and steelmaking furnaces, such as
natural  gas used for heating and annealing purposes, are
reported in the Energy chapter.
    The production of metallurgical coke from coking
coal occurs both on-site  at "integrated" iron and steel
plants and off-site at "merchant" coke plants. Metallurgical
coke is produced by heating coking coal in a coke oven
in a low-oxygen environment. The process drives off the
volatile components of the coking coal and produces coal
(metallurgical) coke. Carbon-containing byproducts of the
metallurgical coke manufacturing process include coke
oven gas, coal tar, coke breeze (small-grade coke oven coke
with particle size <5mm). Coke oven gas is recovered and
used for underfiring the coke ovens and within the iron and
steel mill. Small amounts of coke oven gas are also sold as
synthetic natural gas outside of the iron and steel mills and
are accounted for in the Energy chapter. Coal tar is used as a
raw material to produce anodes used for primary aluminum
production, electric arc furnace (EAF) steel production, and
other electrolytic processes, and also used in the production
of other coal tar products. Light oil is sold to petroleum
refiners who use the material as an additive for gasoline.
The metallurgical coke production process produces CO2
emissions and fugitive CH4 emissions.
    Iron is produced by first reducing iron oxide (iron ore)
with metallurgical coke in a blast furnace to produce pig iron
(impure or crude iron containing about 3 to 5 percent carbon
by weight). Inputs to the blast furnace include natural gas,
fuel oil, and coke oven gas. The carbon in the metallurgical
coke used in the blast furnace combines with oxides in the
iron ore in a reducing atmosphere to produce blast furnace
gas containing carbon monoxide (CO) and CO2. The CO is
then converted and emitted as CO2 when combusted to either
pre-heat the blast  air used in the blast furnace or for other
purposes at the steel mill. Iron may be introduced into the
blast furnace in the  form of raw iron ore, pellets (9-16mm
iron-containing spheres), briquettes, or sinter. Pig iron is used
as a raw material in the production of steel, which contains
about 1 percent carbon by weight. Pig iron is also used as a
raw material in the production of iron products in foundries.
The pig iron production process produces CO2 emissions
and fugitive CK4 emissions.
    Iron can also be produced through the direct reduction
process; wherein, iron ore is reduced to metallic iron in the
solid state at process temperatures less than 1000°C. Direct
reduced iron production results in process emissions of CO2
and emissions of CH4 through the consumption of natural
gas used during the reduction process.
    Sintering is  a thermal process by  which fine iron-
bearing particles, such as air emission control system dust,
are baked, which causes the material to agglomerate into
roughly one-inch pellets that are then recharged into the
blast furnace for pig iron production. Iron ore particles
may also  be formed into  larger pellets or briquettes by
mechanical means, and then agglomerated by heating. The
agglomerate is then crushed and screened to produce an
iron-bearing feed that is charged into the blast furnace. The
sintering process produces CO2 and fugitive CK4 emissions
through the consumption of carbonaceous inputs (e.g., coke
breeze) during the sintering process.
    Steel is produced from pig iron in a variety of specialized
steel-making furnaces, including EAFs and basic oxygen
furnaces (BOFs). Carbon inputs to steel-making furnaces
include pig iron and scrap steel as well as natural gas, fuel oil,
and fluxes (e.g., limestone, dolomite). In a BOF, the carbon
in iron and scrap steel combines with high-purity oxygen to
reduce the carbon content of the metal to the amount desired
for the specified grade of steel. EAFs use carbon electrodes,
charge carbon and other materials (e.g., natural gas) to aid in
melting metal inputs (primarily recycled scrap steel), which
are refined and alloyed to produce the desired grade of steel.
Carbon dioxide emissions occur in BOFs occur through the
reduction process. In EAFs, CO2 emissions result primarily
from the consumption of carbon electrodes and also from
the consumption of supplemental materials used to augment
the melting process.
    In addition to the production processes mentioned above,
CO2 is also generated at iron and steel  mills  through the
consumption of process byproducts (e.g., blast furnace gas,
coke oven gas) used for various purposes including heating,
4-36  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

-------
annealing, and electricity generation.15 Process byproducts
sold for use as synthetic natural gas are deducted and reported
in the Energy chapter. Emissions associated with natural gas
and fuel oil consumption for these purposes are reported in
the Energy chapter.
    The majority of CO2 emissions from the iron and steel
production process come from the use of metallurgical coke in
the production of pig iron and from the consumption of other
process byproducts at the iron and steel mill, with smaller
amounts evolving from the use of flux and from the removal
of carbon from pig iron used to produce steel. Some carbon
is also stored in the finished iron and steel products.

Metallurgical Coke Production
    Emissions of CO2 and CH4 from metallurgical coke
production in 2007 were 3.8 Tg CO2 Eq. (3,806 Gg)  and
less than 0.05 Tg CO2 Eq. (less than 0.5 Gg), respectively
(see Table 4-49 and Table 4-50), totaling 3.8 Tg CO2 Eq.
Emissions increased in 2007, but  have decreased overall
since 1990. In 2007, domestic coke production decreased
by 1.2 percent and has decreased overall since 1990. Coke
production in 2007 was 22 percent lower than in 2000 and 41
percent below 1990. Overall, emissions from metallurgical
coke production have declined by 31 percent (1.7 Tg CO2
Eq.) from 1990 to 2007.

Iron  and Steel Production
     Emissions of CO2 and CELj from iron and steel production
in 2007 were 73.6 Tg CO2 Eq. (73,564 Gg) and 0.7 Tg CO2
Eq. (33.2 Gg), respectively (seeTable 4-51, Table 4-52,Table
4-53, and Table 4-54), totaling 74.3 Tg CO2 Eq. Emissions
increased in 2007, but have decreased overall since 1990 due
to restructuring of the industry, technological improvements,
and  increased scrap utilization. Carbon dioxide  emission
estimates  include emissions from the consumption of
carbonaceous materials in the blast furnace, EAF, and BOF
as well as blast furnace gas and coke oven gas consumption
for other activities at the steel mill.
Table 4-49: C02 and CH4 Emissions from Metallurgical Coke Production (Tg C02 Eq.)
Gas
C02
CH4
Total
1990
5.5
+
5.5
1995
5.0 1
+
5.0
2000
4.4
+
4.4
2005
3.8
+
3.8
2006
3.7
+
3.7
2007
3.8
+
3.8
  + Does not exceed 0.05 Tg C02 Eq.
Table 4-50: C02 and CH4 Emissions from Metallurgical Coke Production (Gg)
  Gas
                              2005
2006
2007
  C02
  CH4
  + Does not exceed 0.5 Gg.
15 Emissions resulting from fuel consumption for the generation of electricity
are reported in the Energy chapter. Some integrated iron and steel mills have
on-site electricity generation for which fuel is used. Data are not available
concerning the amounts and types of fuels used in iron and steel mills to
generate electricity. Therefore all of the fuel consumption reported at iron and
steel mills is assumed to be used within the iron and steel mills for purposes
other than electricity consumption, and the amounts of any fuels actually
used to produce electricity at iron and steel mills are not subtracted from the
electricity production emissions value used in the Energy chapter, therefore
some double-counting of electricity-related CO2 emissions may occur.
                                                                                        Industrial Processes  4-37

-------
Table 4-51: C02 Emissions from Iron and Steel Production (Tg C02 Eq.)
Process
Sinter Production
Iron Production
Steel Production
Other Activities3
Total
1990
I"'
,-,.,
39.3
104.3
1995
I"
,„.„
40.9
98.1
2000
•""
,-,.„
39.9
90.7
2005
1.7
19.6
14.0
34.2
69.3
2006
1.4
24.0
14.4
32.6
72.4
2007
1.4
26.9
14.3
31.0
73.6
  'Includes emissions from blast furnace gas and coke oven gas combustion for activities at the steel mill other than consumption in blast furnace,
   EAFs, or BOFs.
  Note: Totals may not sum due to independent rounding.



Table 4-52: C02 Emissions from Iron and Steel Production (Gg)
Process
Sinter Production
Iron Production
Steel Production
Other Activities3
Total
1990
2,448
47,886
14,672
39,256
104,262
1995
2,512
38,791
15,925
40,850
98,078
2000
2,158
33,808
14,837
39,877
90,680
2005
1,663
19,576
13,950
34,152
69,341
2006
1,418
24,026
14,392
32,583
72,418
2007
1,383
26,948
14,270
30,964
73,564
  'Includes emissions from blast furnace gas and coke oven gas combustion for activities at the steel mill other than consumption in blast furnace,
   EAFs, or BOFs.
  Note: Totals may not sum due to independent rounding.



Table 4-53: CH4 Emissions from Iron and Steel Production (Tg C02 Eq.)
Process
Sinter Production
Iron Production
Total
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
Table 4-54: CH4 Emissions from Iron and Steel
Process
Sinter Production
Iron Production
Total
1990
+
0.9
1.0

Production
1990
0.9 1
44.7
45.6
1995
+
1.0
1.0

(Gg)
1995
0.9 1
45.8
46.7
2000
+
0.9
0.9


2000
0.7
43.1
43.8
2005
+
0.7
0.7


2005
0.6
33.5
34.1
2006
+
0.7
0.7


2006
0.5
34.1
34.6
2007
+
0.7
0.7


2007
0.5
32.7
33.2
  Note: Totals may not sum due to independent rounding.
    In 2007, domestic production of pig iron decreased by 4    M 6t h 0 d 010 Q V

percent. Overall, domestic pig iron production has declined

since the 1990s. Pig iron production in 2007 was 24 percent    Metallurgical Coke Production

lower than in 2000 and 26 percent below 1990. Carbon        Coking coal is used to manufacture metallurgical

dioxide emissions from steel production have decreased by    (coal) coke mat is used primarily as a reducing agent in

3 percent (4Tg CO2 Eq.) since  1990. Overall, CO2 emissions    the production of iron  and steel, but is also used in the

from iron and steel production have declined by 29 percent    production of other metals including lead and zinc (see Lead

(30 7 Tg CO Eq ) from 1990 to 2007                        Production  and Zinc Production in this chapter). Emissions
4-38  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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associated with producing metallurgical coke from coking
coal are estimated and reported separately from emissions
that result from the iron and steel production process. To
estimate emission from metallurgical coke production, a Tier
2 method provided by the 20051PCC Guidelines for National
Greenhouse Gas Inventories (IPCC 2006) was utilized. The
amount of carbon contained in materials produced during
the metallurgical coke production process (i.e., coke, coke
breeze, coke oven gas, and coal tar) is deducted from the
amount of carbon contained in materials consumed during
the metallurgical coke production process (i.e., natural
gas, blast furnace gas, coking coal). Light oil, which is
produced during the metallurgical coke production process,
is excluded from the deductions due to data limitations. The
amount of carbon contained in these materials is calculated
by multiplying the material-specific carbon content by the
amount of material consumed or produced (see Table 4-55).

Table 4-55: Material Carbon Contents for
Metallurgical Coke  Production
Material
Coal Tar
Coke
Coke Breeze
Coking Coal
Material
Coke Oven Gas
Blast Furnace Gas
kg C/kg
0.62
0.83
0.83
0.73
kg C/GJ
12.1
70.8
  Source: IPCC (2006), Table 4.3. Coke Oven Gas and Blast Furnace Gas,
  Table 1.3.
Table 4-56: CH4 Emission Factor for
Metallurgical Coke Production (g CH^metric ton)
  Material Produced
g CH4/metric ton
  Metallurgical Coke
     0.1
  Source: IPCC (2006), Table 4.2.
The amount of coal tar produced was approximated using a
production factor of 0.03 tons of coal tar per ton of coking
coal consumed. The amount of coke breeze produced was
approximated using a production factor of 0.075 tons of
coke breeze per ton of coking coal consumed. Data on the
consumption of carbonaceous materials (other than coking
coal) as well as coke oven gas production were available for
integrated steel mills only (i.e., steel mills with co-located
coke plants). Therefore, carbonaceous material (other than
coking coal) consumption and coke oven gas production
were excluded from emission estimates for merchant coke
plants. Carbon contained in coke oven gas used for coke-
oven underfiring was not included in the deductions to avoid
double-counting.
    The  production processes  for metallurgical  coke
production results in fugitive emissions of CH4, which are
emitted via leaks in the production equipment rather than
through the emission stacks or vents  of the production
plants. The fugitive emissions were calculated by applying
the Tier 1 emission factor (0.1 g CH4/metric ton) taken from
the 2006 IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC 2006) for metallurgical coke production
(see Table 4-56).
    Data relating to the mass of coking coal consumed
at metallurgical coke plants and the mass of  metallurgical
coke produced at coke plants were taken from the Energy
Information Administration (EIA), Quarterly Coal Report
October through December (EIA 1998  through 2004a) and
January through March (EIA 2006a, 2007,2008a) (see Table
4-57). Data on the volume of natural gas consumption, blast
furnace gas consumption, and coke oven gas production for
metallurgical coke production at integrated steel mills were
obtained from the American Iron and Steel Institute (AISI),
Annual Statistical Report (AISI 2004 through 2008a) and
through personal communications with AISI  (2008b) (see
Table 4-57: Production and Consumption Data for the Calculation of C02 and CH4 Emissions from Metallurgical
Coke Production (Thousand Metric Tons)
Source/Activity Data
Metallurgical Coke Production
Coking Coal Consumption at Coke Plants
Coke Production at Coke Plants
Coal Tar Production
Coke Breeze Production
1990

35,269
25,054
7521
1,879
1995

29,948
21,545
646 1
1,616
2000

26,254
18,877
566
1,416
2005

21,259
15,167
455
1,138
2006

20,827
14,882
446
1,116
2007

20,607
14,698
441
1,102

                                                                                    Industrial Processes  4-39

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Table 4-58: Production and Consumption Data for the Calculation of C02 Emissions from Metallurgical
Coke Production (million ft3)
Source/Activity Data
Metallurgical Coke Production
Coke Oven Gas Production3
Natural Gas Consumption
Blast Furnace Gas Consumption
1990


59gl
24,602
1995

1 66,750 1
1841
29,423
2000

149,47/1
180
26,075 |
2005

114,213
2,996
4,460
2006

114,386
3,277
5,505
2007

109,912
3,309
5,144
  'Includes coke oven gas used for purposes other than coke oven underfiring only.
Table 4-58). The factor for the quantity of coal tar produced per
ton of coking coal consumed was provided by AISI (2008b).
The factor for the quantity of coke breeze produced per ton of
coking coal consumed was obtained through Table 2-1 of the
report Energy and Environmental Profile of the U.S. Iron and
Steel Industry (DOE 2000). Data on natural gas consumption
and coke oven gas production at merchant coke plants were
not available and were excluded from the emission estimate.
Carbon contents for coking coal, metallurgical coke, coal tar,
coke oven gas, and blast furnace gas were provided by the 2006
IPCC Guidelines for  National Greenhouse Gas Inventories
(IPCC 2006). The carbon content for coke breeze was assumed
to equal the carbon content of coke.

Iron and Steel Production
    Emissions of CO2 from sinter production and direct
reduced iron production were estimated by multiplying
total national sinter production and the total  national direct
reduced iron production by Tier 1 CO2 emission factors (see
Table 4-59). Because estimates of sinter production and direct
reduced iron production were not available, production was
assumed to equal consumption.
    To estimate emissions from pig iron production in the
blast furnace, the amount of carbon contained in the produced
pig iron and blast furnace gas were deducted from the amount
of carbon contained in inputs (i.e., metallurgical coke, sinter,
natural ore, pellets, natural gas, fuel oil, coke  oven gas,
direct coal injection). The carbon contained in the pig iron,
blast furnace gas, and blast furnace inputs  was  estimated

Table 4-59: C02 Emission  Factors for Sinter Production
and Direct Reduced  Iron Production
  Material Produced
Metric Ton C02/Metric Ton
  Sinter
  Direct Reduced Iron
         0.2
         0.7
                            by multiplying the material-specific carbon content by each
                            material type (see Table 4-60). Carbon in blast furnace gas
                            used to pre-heat the blast furnace air is combusted to form
                            CO2 during this process.
                                Emissions from steel production in EAFs were estimated
                            by deducting  the carbon contained in the steel produced
                            from the carbon contained in the EAF anode, charge carbon,
                            and scrap steel added to the EAF. Small amounts of carbon
                            from direct reduced iron, pig iron, and flux additions to the
                            EAFs were also included in the EAF calculation. For BOFs,
                            estimates of carbon contained in BOF steel were deducted
                            from carbon contained in inputs such as natural gas, coke
                            oven gas, fluxes,  and pig iron. In each case, the carbon was
                            calculated by multiplying material-specific carbon contents
                            by each material type (see Table 4-60). For EAFs, the amount
                            of EAF anode consumed was approximated by multiplying
                            total EAF steel production by the amount of EAF anode
                            consumed per metric ton of steel produced (0.002 metric tons
                            EAF anode per metric ton steel produced (AISI 2008b)). The
                            amount of flux (e.g., limestone and dolomite) used during
                            Table 4-60: 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
kg C/kg
0.83
0.02
0.13
0.82
0.83
0.12
0.04
0.01
kg C/GJ
12.1
70.8
  Source: IPCC (2006), Table 4.1.
                             Source: IPCC (2006), Table 4.3. Coke Oven Gas and Blast Furnace Gas,
                             Table 1.3.
4-40  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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steel manufacture was deducted from the Limestone and
Dolomite Use source category to avoid double-counting.
    Carbon dioxide emissions from the consumption of blast
furnace gas and coke oven gas for other activities occurring
at the steel mill were estimated by multiplying the amount of
these materials consumed for these purposes by the material-
specific C content (see Table 4-60).
    Carbon  dioxide emissions associated with the  sinter
production, direct reduced  iron production,  pig iron
production, steel production, and other steel mill activities
were summed to calculate the total CO2 emissions from iron
and steel production (see Table 4-51 and Table 4-52).
    The production processes for sinter and pig iron result in
fugitive emissions of CK4, which are emitted via leaks in the
production equipment rather than through the emission stacks
or vents of the production plants. The fugitive emissions
were calculated by applying Tier 1 emission factors taken

Table 4-61: CH4  Emission Factors for Sinter and
Pig Iron Production
  Material Produced
Factor
Unit
  Pig Iron
  Sinter
 0.9
 0.07
g CHVkg
kg CH^metric ton
  Source: Sinter (IPCC 2006, Table 4.2), Pig Iron (IPCC/UNEP/OECD/IEA
  1995, Table 2.2).
from the 2006 IPCC Guidelines for National Greenhouse
Gas Inventories (IPCC 2006) for sinter production and the
1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) (see
Table 4-61) for pig iron production. The production of direct
reduced iron also results in emissions of CH4 through the
consumption of fossil fuels (e.g., natural gas); however, these
emissions estimates are excluded due to data limitations.
    Sinter consumption and direct reduced iron consumption
data were obtained from AISI' s Annual Statistical Report (AISI
2004 through 2008a) and through personal communications
withAISI (2008b) (see Table 4-62). Data on direct reduced iron
consumed in EAFs were not available for the years 1990,1991,
1999, 2006, and 2007. EAF direct reduced iron consumption
in 1990 and 1991 was assumed to equal consumption in
1992, consumption in 1999 was assumed to equal the average
of 1998 and 2000, and consumption in 2006 and 2007 was
assumed to equal consumption in 2005. Data on direct reduced
iron consumed in BOFs were not available for the years  1990
through 1994,1999,2006, and 2007. EOF direct reduced iron
consumption in 1990 through  1994 was assumed to equal
consumption in 1995, consumption in 1999 was assumed to
equal the average of 1998 and 2000, and consumption in 2006
and 2007 was assumed to equal consumption in 2005. The
Tier 1 CO2 emission factors for sinter production and direct
reduced iron production were obtained through the 2006 IPCC
Table 4-62: Production and Consumption Data for the Calculation of C02 and CH4 Emissions from
Iron and Steel 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
BOF Steel Production
Pig Iron Consumption
Scrap Steel Consumption
Flux Consumption
BOF Steel Production
1990

12,239
936 1
24,946
49,669
1,485

67 1
35,743
319
33,511

46,564
14,548
576 1
43,973
1995

12,562
989
22,198
50,891
1,509

77 1
39,010
267 1
38,472

49,896
15,967
1,259
56,721
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

104
37,558
695
52,194

32,115
11,612
582
42,705
2006

7,088
1,633
14,684
37,904
2,526

112
37,558
671
56,071

32,115
11,612
610
42,119
2007

6,914
1,633
15,039
36,337
2,734

114
37,558
567
57,004

32,115
11,612
408
41,099

                                                                                   Industrial Processes  4-41

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Guidelines for National Greenhouse Gas Inventories (IPCC
2006). Data for pig iron production, coke, natural gas, fuel
oil, sinter, and pellets consumed in the blast furnace; pig iron
production; and blast furnace gas produced at the iron and steel
mill and used in the metallurgical coke ovens and other steel
mill activities were obtained from AISI's Annual Statistical
Report (AISI 2004 through 2008a) and  through personal
communications with AISI (2008b) (see Table 4-63). Data for
EAF steel production, flux, EAF charge carbon, direct reduced
iron, pig iron, scrap steel, and natural gas consumption as well
as EAF  steel production were obtained from AISI's Annual
Statistical Report (AISI 2004  through 2008a) and through
personal communications with AISI (2008b).  The factor for
the quantity of EAF anode consumed per ton of EAF steel
produced was provided by AISI (AISI 2008b). Data for EOF
steel production, flux, direct reduced iron, pig iron, scrap steel,
natural gas, natural ore, pellet sinter consumption as well as
BOF steel production were obtained from AISI's Annual
Statistical Report (AISI 2004  through 2008a) and through
personal communications with AISI (2008b). Because data on
pig iron consumption and scrap steel consumption in BOFs
and EAFs were not available for 2006 and 2007, 2005 data
were used. Because pig iron consumption in EAFs was also
not available in 2003 and 2004, the average of 2002 and 2005
pig iron consumption data were used. Data on coke oven gas
and blast furnace gas consumed at the iron and steel mill other
than in the  EAF, BOF, or blast furnace were obtained from
AISI's Annual Statistical Report (AISI 2004 through 2008a)
and through personal communications  with AISI (2008b).
Data on blast furnace gas and coke oven gas sold for use as
synthetic natural gas were obtained through EIA's Natural
Gas Annual 2007 (EIA 2008b). C contents for direct reduced
iron, EAF carbon electrodes, EAF charge carbon, limestone,
dolomite, pig iron, and steel were provided by the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories (IPCC
2006). The C contents for natural  gas, fuel oil, and direct
injection coal as well as the heat contents for the same fuels
were provided by EIA (2008b). Heat contents for coke oven
gas and blast furnace gas were provided in Table 2-2 of the
report Energy and Environmental Profile of the U.S. Iron and
Steel Industry (DOE 2000).

Uncertainty
    The estimates of CO2 emissions from metallurgical coke
production are based on material production and consumption
data and average carbon contents. Uncertainty is associated
with the total U.S. coking coal consumption, total U.S. coke
production and materials  consumed during this process.
Data for coking coal consumption and metallurgical coke
production are from different data  sources (EIA) than data
for other carbonaceous materials consumed at coke plants
(AISI), which does not include data for merchant coke plants.
There is uncertainty associated with the fact that coal tar
and coke breeze production were estimated based on coke
Table 4-63: Production and Consumption Data for the Calculation of C02 Emissions from Iron and Steel 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 Production3
EAF Steel Production
Natural Gas Consumption
BOF Steel Production
Natural Gas Consumption
Coke Oven Gas Consumption
Other Activities
Coke Oven Gas Consumption
Blast Furnace Gas Consumption
1990

56,
163,
22,
1,439,
9,
6,
3,

224,
1,414,

,273
,397
,033
,380
,604
,301
,851

,883
,778









1995

106,
108,
10,
1,559,
11,
16,
1,

155,
1,530,

,514
,196
,097
,795
,026
,546
,284

,369
,372
2000

91,
120,

,798
,921
13,702
1,524,
13,
6,

135,
1,498,
,891


,135
,816
2005

59,
16,
16,
1,299,
14,
5,

97,
1,295,

844
170
557
980
959
026
524

132
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
  'Includes blast furnace gas used for purposes other than in the blast furnace only.
4-42  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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production because coal tar and coke breeze production data
were not available.
    The estimates of CO2 emissions from iron and steel
production are based on material production and consumption
data and average carbon contents.  There is  uncertainty
associated with the assumption that direct reduced iron
and sinter consumption are equal  to production. There is
uncertainty associated with the assumption that all coal used
for purposes other than coking coal  is for direct injection
coal. Some of this coal may be used for electricity generation.
There is also uncertainty associated with the carbon contents
for pellets, sinter, and natural ore, which are assumed to equal
the carbon contents of direct reduced iron. For EAF steel
production there is uncertainty associated with the amount of
EAF anode and charge carbon consumed due to inconsistent
data throughout the timeseries. Uncertainty is also associated
with the use of process gases  such as blast furnace gas
and coke oven gas. Data are not available to differentiate
between the use of these gases for processes at the steel
mill versus for energy generation (e.g., electricity and steam
generation); therefore, all consumption is attributed  to iron
and steel production. These data and carbon contents produce
a relatively accurate estimate of CO2 emissions. However,
there are uncertainties associated with each.
    For the purposes of the CH4 calculation it is assumed
that all of the CFLj escapes as fugitive emissions and that
none of the CH4 is captured in stacks or vents. Additionally,
the CO2 emissions calculation is  not corrected by subtracting
the C content of the CH4, which  means there may be a slight
double counting of C as both CO2 an
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-64 for iron and steel production.
Iron and Steel Production CO2 emissions were estimated
                                to be between 57.0 and 87.9 Tg CO2 Eq. at the 95 percent
                                confidence level. This indicates a range of approximately 22
                                percent below and 20 percent above the emission estimate of
                                73.6 Tg CO2 Eq. Iron and Steel  Production CK4 emissions
                                were estimated to be between 0.6 Tg CO2 Eq. and 0.8  Tg
                                CO2 Eq. at the 95 percent confidence level. This indicates a
                                range of approximately 8 percent below and 8 percent above
                                the emission estimate of 0.7 Tg CO2 Eq.

                                Recalculations Discussion
                                   Estimates of CO2 from iron and steel production have
                                been revised for the years 1990 through 2006 to adhere to the
                                methods presented in the 2006IPCC Guidelines for National
                                Greenhouse Gas Inventories (IPCC 2006). Previously the
                                estimates focused primarily on the consumption of coking
                                coal to produce metallurgical coke and the consumption of
                                metallurgical coke, carbon anodes, and scrap steel to produce
                                iron and steel. The revised estimates differentiate between
                                emissions associated with metallurgical coke production and
                                those associated with iron and steel production and include
                                CO2 emissions from the consumption of other materials such
                                as natural gas, fuel  oil,  flux (e.g.  limestone and dolomite
                                use), direction injection goal, sinter, pellets, and natural
                                ore during  the iron and steel production process as well
                                as the metallurgical coke  production process. Currently,
                                CO2 emissions from iron and steel production are reported
                                separately from CO2 emissions from metallurgical coke
                                production. On average, revisions to the Iron and Steel
                                Production  estimate resulted in  an annual increase of CO2
                                emissions of 26.1 Tg CO2 Eq. (40.7 percent).
                                   Estimates of CH4 emissions  from  iron  and steel
                                production have been revised based on revisions to the
                                CH4 emission factor from sinter production and to report
Table 4-64: Tier 2 Quantitative Uncertainty Estimates for C02 and CH4 Emissions from Iron and Steel Production
(Tg C02 Eq. and Percent)3
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                     Uncertainty Range Relative to Emission Estimate"
                      (Tg C02 Eq.)                      (%)
                                                        Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Iron and Steel Production
  Iron and Steel Production
C02
CH4
73.6
 0.7
57.0
 0.6
87.9
 0.8
-22%
+20%
 +8%
  aThe emission estimates and the uncertainty range presented in this table correspond to iron and steel production only. Uncertainty associated with
   emissions from metallurgical coke production were not estimated due to data limitations and were excluded from the uncertainty estimates presented in
   this table.
  b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                      Industrial Processes  4-43

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emissions from metallurgical coke production separately. On
average, revisions to the Iron and Steel Production estimate
resulted in an annual decrease of CH4 emissions of 0.3 Tg
CO2 Eq. (24.6 percent).

Planned Improvements
    Plans for improvements to the Iron and Steel Production
source category include attributing emissions estimates for
the production of metallurgical coke to the Energy chapter
as well as identifying the amount of carbonaceous materials,
other than coking coal, consumed at merchant coke plants.
Additional improvements include identifying the amount of
coal used for direct injection and the amount of coke breeze,
coal tar,  and light oil produced during coke production.
Efforts will also be made to identify inputs for preparing
Tier 2 estimates for sinter and direct reduced iron production,
as well as to identify information to better  characterize
emissions from the use of process gases and fuels within the
Energy and Industrial Processes chapters.

4.14  Ferroalloy Production (IPCC
Source Category  2C2)

    Carbon dioxide and CK4 are emitted from the production
of several ferroalloys. Ferroalloys are composites of iron and
other elements such as silicon, manganese, and chromium.
When incorporated in alloy steels, ferroalloys are used to alter
the material properties of the steel. Estimates from two types
of ferrosilicon (25 to 55 percent and 56 to 95 percent silicon),
           silicon metal (about 98 percent silicon), and miscellaneous
           alloys  (36 to 65 percent silicon) have been calculated.
           Emissions from the production of ferrochromium and
           ferromanganese are not included here because of the small
           number of manufacturers of these materials in the United
           States. Consequently, government information disclosure
           rules prevent the publication of production data for these
           production facilities.
               Similar to emissions from the production of iron and
           steel, CO2 is emitted when metallurgical coke is oxidized
           during a high-temperature reaction with iron and the selected
           alloying element. Due to the strong reducing environment,
           CO is initially produced, and eventually oxidized to CO2.
           A representative reaction equation for the production of 50
           percent ferrosilicon is given below:
                     Fe203 + 2Si02 + 7C -» 2FeSi + 7CO
               While most of the C contained in the process materials
           is released to the atmosphere as CO2, a percentage is also
           released as CK4 and other volatiles. The amount of CK4 that
           is released is dependent on furnace efficiency, operation
           technique, and control technology.
               Emissions of CO2 from ferroalloy production in 2007
           were 1.6 Tg CO2 Eq. (1,552 Gg) (see Table 4-65 and Table
           4-66), which is a 3  percent increase from the previous year
           and a 28 percent reduction since 1990. Emissions of CK4
           from ferroalloy production in 2007 were 0.01 Tg CO2 Eq.
           (0.448 Gg),  which is also a 3 percent increase from the
           previous year and a 28 percent decrease since 1990.
Table 4-65: C02 and CH4 Emissions from Ferroalloy Production (Tg C02 Eq.)
Gas
                                            1990
             1995
             2000
2005      2006
                                                                                                    2007
C02
CH4
                                              2.2
              2.o
              1.9
                                                                                   1.4
           1.5
  1.6
Total
                                              2.2
              2.0
              1.9
                                                                                   1.4
           1.5
 1.6
  + Does not exceed 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
Table 4-66: C02 and CH4 Emissions from Ferroalloy Production (Gg)
  Gas
1990
1995
                                                                    2000
2005
                                                                                           2006
2007
  C02
  CH4
                                                1,505
                                                   +
                                             1,552
                                               +
  + Does not exceed 0.5 Gg.
4-44  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Methodology
    Emissions of CO2 and CH4 from ferroalloy production
were calculated by multiplying annual ferroalloy production
by material-specific emission factors. Emission factors taken
from the 2006 IPCC Guidelines for National Greenhouse
Gas Inventories (IPCC 2006) were applied to  ferroalloy
production.  For ferrosilicon alloys containing 25 to 55
percent silicon and miscellaneous alloys (including primarily
magnesium-ferrosilicon, but also including other silicon
alloys) containing 32 to 65 percent silicon, an emission factor
for 45 percent silicon was applied for CO2 (2.5 metric tons
CO2/metric ton of alloy produced) and an emission factor
for 65 percent silicon was applied for CH4 (1 kg CH4/metric
ton of alloy produced). Additionally, for ferrosilicon alloys
containing 56 to 95 percent silicon, an  emission factor for
75 percent silicon ferrosilicon  was applied for both CO2
and CtLj (4 metric tons CO2/metric ton  alloy produced and
1 kg CH4/metric ton of alloy produced, respectively). The
emission factors for silicon metal equaled 5 metric tons CO2/
metric ton metal produced and 1.2 kg CH4/metric ton metal
produced. It was assumed that 100 percent of the ferroalloy
production was produced using petroleum coke using an
electric  arc furnace process (IPCC  2006), although some
ferroalloys may have been produced with coking coal, wood,
other biomas s, or graphite C inputs. The amount of petroleum
coke consumed in ferroalloy production was calculated
assuming that the petroleum coke used is  90 percent C and
10 percent inert material.
    Ferroalloy production data for 1990 through 2007 (see
Table 4-67) were obtained from the USGS through personal
                           communications with the USGS Silicon Commodity Specialist
                           (Corathers 2008) and through the Minerals Yearbook: Silicon
                           Annual Report (USGS 1991 through 2007). Because USGS
                           does not provide estimates of silicon metal production for
                           2006 and 2007,2005 production data are used. Until 1999, the
                           USGS reported production of ferrosilicon containing 25 to 55
                           percent silicon separately from production of miscellaneous
                           alloys containing 32 to 65 percent silicon; beginning in 1999,
                           the USGS reported these as a single category (see Table 4-67).
                           The composition data for petroleum coke was obtained from
                           Onder and Bagdoyan  (1993).

                           Uncertainty
                               Although some  ferroalloys may be produced using
                           wood or other biomass as a C source, information and data
                           regarding these practices were not available. Emissions from
                           ferroalloys produced with wood or other biomass would not
                           be counted under this source because wood-based C is of
                           biogenic origin.16 Even though emissions from ferroalloys
                           produced  with coking coal or graphite inputs would be
                           counted in national trends, they may be  generated with
                           varying amounts of CO2 per unit of ferroalloy produced.
                           The most accurate method for these estimates would be to
                           base calculations on the amount of reducing agent used in
                           the process, rather than the amount of ferroalloys produced.
                           These data, however,  were not available.
                               Emissions of  CH4 from ferroalloy production will
                           vary depending on furnace specifics,  such as  type,
                           operation technique, and control technology. Higher heating
                           temperatures and techniques such as sprinkle charging
Table 4-67: Production of Ferroalloys (Metric Tons)
          Year
Ferrosilicon
 25%-55%
Ferrosilicon
 56%-95%
Silicon Metal
Misc. Alloys
 32%-65%
          1990
         M
          1995
         ^
          2000
  NA (Not Available).
 321,385
 ^H
 184,000
 ^^H
 229,000
 109,566
 ^M
 128,000
 ^^m
 100,000
  145,744
 ^H
  163,000
  184,000
  72,442
  ^m
  99,500
   •
   NA
2005
2006
2007
123,000
164,000
180,000
86,100
88,700
90,600
148,000
148,000
148,000
NA
NA
NA
                                                        16 Emissions and sinks of biogenic carbon are accounted for in the Land
                                                        Use, Land-Use Change, and Forestry chapter.
                                                                                   Industrial Processes  4-45

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Table 4-68: Tier 2 Quantitative Uncertainty Estimates for C02 and CH4 Emissions from Ferroalloy Production
(Tg C02 Eq. and Percent)
  Source
      2007 Emission Estimate
Gas        (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                      (%)

Ferroalloy Production
Ferroalloy Production

C02
CH4

1.6
Lower Bound Upper Bound Lower Bound
1.4 1.7 -12%
+ + -12%
Upper Bound
+ 12%
+ 12%
  + Does not exceed 0.05 Tg C02 Eq.
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
will reduce CH4 emissions; however, specific furnace
information was not available or included in the CH4
emission estimates.
    Also, annual ferroalloy production is now reported by
the USGS in three broad categories: ferroalloys containing
25 to 55 percent silicon (including miscellaneous  alloys),
ferroalloys containing 56 to 95 percent silicon, and silicon
metal. It was assumed that the IPCC emission factors apply
to all of the ferroalloy production processes,  including
miscellaneous alloys. Finally, production data for silvery
pig iron (alloys containing less than 25 percent silicon) are
not reported by the USGS to avoid disclosing company
proprietary  data. Emissions from this production category,
therefore, were not estimated.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-68. Ferroalloy production CO2
emissions were estimated to be between 1.4 and 1.7 Tg CO2
Eq. at the 95 percent confidence level. This indicates a range
of approximately 12 percent below and 12 percent above the
emission estimate of 1.6 Tg CO2 Eq. Ferroalloy production
CFLj emissions were estimated to be  between a range of
approximately  12 percent below and 12  percent above the
emission estimate of 0.01 Tg CO2 Eq.

Planned  Improvements
    Future improvements to the ferroalloy production
source category include research into the data availability for
ferroalloys other than ferrosilicon and silicon metal. If data are
available, emissions will be estimated for those ferroalloys.
Additionally, research will be conducted to determine whether
data are available concerning raw material  consumption (e.g.,
coal coke, limestone and dolomite flux, etc.) for inclusion in
ferroalloy production emission estimates.
                              4.15  Aluminum Production
                              (IPCC Source Category 2C3)

                                  Aluminum is a light-weight, malleable, and corrosion-
                              resistant metal that is used in many manufactured products,
                              including aircraft,  automobiles, bicycles, and kitchen
                              utensils. As of last reporting, the United States was the fourth
                              largest producer of primary aluminum, with approximately
                              seven percent of the world total (USGS 2008). The  United
                              States was also a major importer of primary aluminum. The
                              production of primary aluminum—in addition to consuming
                              large quantities of electricity—results in process-related
                              emissions of CO2  and two  perfluorocarbons (PFCs):
                              perfluoromethane (CF4) and perfluoroethane (C2F6).
                                  Carbon dioxide is emitted during the aluminum smelting
                              process when alumina (aluminum oxide, A12O3) is reduced
                              to aluminum using the Hall-Heroult reduction process. The
                              reduction  of the alumina occurs through electrolysis in a
                              molten bath of natural or synthetic cryolite (Na3AlF6). The
                              reduction cells contain a C lining that serves as the cathode. C
                              is also contained in the anode, which can be a C mass of paste,
                              coke briquettes, or prebaked C  blocks from petroleum coke.
                              During reduction, most of this  C is oxidized and released to
                              the atmosphere as CO2.
                                  Process emissions of CO2 from aluminum production
                              were estimated to be 4.3 Tg CO2 Eq. (4,251 Gg) in 2007
                              (see Table 4-69). The C anodes consumed during aluminum
                              production consist of petroleum coke and, to a minor extent,
                              coal tar pitch. The petroleum coke portion of the total CO2
                              process emissions from aluminum production is considered
                              to be a non-energy use of petroleum coke, and is accounted
                              for here and not under the CO2 from Fossil Fuel Combustion
                              source category of the Energy  sector. Similarly, the coal tar
                              pitch portion of these CO2 process emissions is accounted
4-46  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-69: C02 Emissions from Aluminum Production
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
 Gg
        1990
   6.8
6,831
        2005
        2006
        2007
for here rather than in the Iron and Steel source category of
the Industrial Processes sector.
    In addition to CO2 emissions, the aluminum production
industry is also  a source of PFC  emissions. During the
smelting process, when the alumina ore content of the
electrolytic bath falls below critical levels required for
electrolysis, rapid voltage increases occur, which are termed
"anode effects." These anode effects cause carbon from the
anode and fluorine from the dissociated molten cryolite bath
to combine,  thereby producing fugitive emissions of CF4
and C2F6. In general, the magnitude of emissions for a given
smelter and level of production depends on the frequency and
duration of these anode effects. As the frequency and duration
of the anode effects increase, emissions increase.
    Since 1990, emissions of CF4 and C2F6 have declined
by 80 percent and 76 percent, respectively, to 3.2 Tg CO2
Eq. of CF4 (0.5 Gg) and 0.64 Tg CO2 Eq. of C2F6  (0.07
Gg) in 2007, as shown in Table 4-70 and Table 4-71. This
decline is due both to reductions in domestic aluminum
production and to  actions taken by aluminum smelting
companies to reduce the frequency and duration of anode
effects. (Note, however, that production and the frequency
and duration of anode effects increased in 2007 compared
to 2006.) Since 1990, aluminum production has declined by
37 percent, while the combined CF4 and C2F6 emission rate
(per metric ton of aluminum produced) has been reduced
by 67 percent.
    In 2007, U.S. primary aluminum production totaled
approximately 2.6 million metric tons, a 12 percent increase
from 2006 production levels. In December 2006, production
resumed at the 265,000-t/y smelter in Hannibal, OH, owned
by Ormet Corp (USGS 2007). In 2007, Columbia  Falls
Aluminum Co. announced it was restarting additional
                                 Table 4-70: PFC Emissions from Aluminum Production
                                 (Tg C02 Eq.)
Year
CF4
C2F6
            Total
1990
15.9
2.7
            18.5
                                       2005
                                       2006
                                       2007
                                   Note: Totals may not sum due to independent rounding.

                                 Table 4-71: PFC Emissions from Aluminum Production
                                 (Gg)
                                         Year
                                        CF4
                                   C2F6
                                         2005
                                         2006
                                         2007
                                   + Does not exceed 0.05 Gg.

                                 potlines (USAA 2007), and Alcoa Intalco Works reported
                                 increased production from a re-energized potline at their
                                 Ferndale operation (Alcoa Inc. 2007).
                                 Methodology
                                     Carbon dioxide emissions released during aluminum
                                 production were estimated using the combined application
                                 of process-specific emissions estimates modeling with
                                 individual partner reported data. These estimates are based
                                 on information gathered  by EPA's Voluntary Aluminum
                                 Industrial Partnership (VAIP) program.
                                     Most of the CO2 emissions released during aluminum
                                 production occur during the electrolysis reaction of the C
                                 anode, as described by the following reaction:
                                               2A12O3
                                     3C -» 4A1 + 3CO,
                                     For prebake smelter technologies, CO2 is also emitted
                                 during the anode baking process.  These emissions can
                                 account for approximately 10 percent of total process CO2
                                 emissions from prebake smelters.
                                                                                  Industrial Processes 4-47

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    Depending on the availability of smelter-specific data,
the CO2 emitted from  electrolysis at each smelter was
estimated from: (1) the smelter's annual anode consumption;
(2) the smelter's annual aluminum production and rate of
anode consumption (per ton of aluminum produced) for
previous and /or following years, or; (3) the smelter's annual
aluminum production and IPCC  default CO2 emission
factors. The first approach tracks the consumption and carbon
content of the anode, assuming that all carbon in the anode
is converted to CO2. Sulfur, ash, and other impurities in the
anode are subtracted from the anode consumption to arrive
at a carbon consumption figure. This approach corresponds
to  either the IPCC Tier  2 or Tier 3 method, depending on
whether smelter-specific data on anode impurities are used.
The second approach interpolates  smelter-specific  anode
consumption rates to estimate emissions during years for
which anode consumption data are not available. This
avoids substantial errors and discontinuities that could be
introduced by reverting  to Tier 1 methods for those years.
The last approach corresponds to the IPCC Tier 1 method
(2006) and is used in the absence of present or historic anode
consumption data.
    The equations used to estimate CO2 emissions in the
Tier 2 and 3 methods vary depending on smelter type (IPCC
2006). For Prebake cells, the process formula accounts for
various parameters, including net anode consumption, and
the sulfur, ash, and impurity content of the baked anode. For
anode baking emissions, the formula accounts for packing
coke consumption, the sulfur and ash content of the packing
coke, as well as the pitch content and weight of baked anodes
produced. For S0derberg cells, the process formula accounts
for the weight of paste consumed per metric ton of aluminum
produced, and pitch properties, including sulfur, hydrogen,
and ash content.
    Through the VAIP, anode  consumption (and some
anode impurity) data have been reported for 1990, 2000,
2003, 2004,  2005, 2006, and  2007. Where  available,
smelter-specific process  data reported under the VAIP were
used; however, if the data were incomplete or unavailable,
information was supplemented using industry average values
recommended by IPCC (2006). Smelter-specific CO2 process
data were provided by 18 of the 23 operating smelters in 1990
and 2000, by  14 out of  16 operating smelters in 2003 and
2004, 14 out of 15 operating smelters in 2005, and 13 out
of 14 operating smelters in 2006 and 2007. For years where
CO2 process data were not reported  by these companies,
estimates were developed through linear interpolation, and/
or assuming industry default values.
    In the absence of any smelter-specific process data (i.e.,
1 out of 14 smelters in 2007 and 2006,1 out of 15 smelters in
2005, and 5 out of 23 smelters between 1990 and 2003), CO2
emission estimates were estimated using Tier  1 S0derberg
and/or Prebake emission factors (metric ton of CO2 per metric
ton of aluminum produced) from IPCC (2006).
    Aluminum production  data for 13 out of 14 operating
smelters were reported under the VAIP in 2007. Between
1990 and 2006, production data were  provided by 21 of
the 23 U.S. smelters that operated during at least part of
that period. For the non-reporting smelters, production was
estimated based on the difference between reporting smelters
and national aluminum production levels  (US AA 2008), with
allocation to specific smelters based on reported production
capacities (USGS 2002).
    PFC emissions from  aluminum production  were
estimated using a per-unit production emission factor that
is expressed as a function of operating parameters (anode
effect frequency and duration), as follows:
         PFC (CF4 or C2F6) kg/metric ton Al =
           S x Anode Effect Minutes/Cell-Day
where,
    S        =   Slope coefficient  (kg PFC/metric ton
                  Al)/(Anode Effect Minute/Cell-Day)
    Anode Effect
    Minutes/
    Cell-Day =   Anode  Effect Frequency/Cell-Day x
                  Anode  Effect Duration (Minutes)
    This approach corresponds to either the Tier 3 or the Tier
2 approach in the 2006 IPCC Guidelines, depending upon
whether the slope-coefficient is smelter-specific (Tier 3) or
technology-specific (Tier 2). For 1990 through 2007, smelter-
specific slope coefficients were available and were used for
smelters representing between 30 and 94 percent  of U.S.
primary aluminum production. The percentage changed from
year to year as some smelters closed or changed hands and as
the production at remaining smelters fluctuated. For smelters
that did not report smelter-specific slope coefficients, IPCC
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technology-specific slope coefficients were applied (IPCC
2000, 2006). The slope  coefficients were combined with
smelter-specific anode effect data collected by aluminum
companies and reported under the VAIP, to estimate emission
factors over time. For 1990 through 2007, smelter-specific
anode effect data were available for smelters representing
between 80 and 100 percent of U.S. primary aluminum
production. Where smelter-specific anode effect data were
not available, industry averages were used.
    For all smelters, emission factors were multiplied by
annual production to estimate annual emissions at the smelter
level. For  1990 through  2007, smelter-specific production
data were available for smelters representing between 30 and
100 percent of U.S. primary aluminum production. (For the
years after 2000, this percentage was near the high end of the
range.) Production at non-reporting smelters was estimated
by calculating the difference between the production reported
under VAIP and the total U.S. production supplied by USGS
or US AA and then allocating this difference to non-reporting
smelters in proportion to their production capacity. Emissions
were then  aggregated across smelters to estimate national
emissions.
    National primary aluminum production data for 2007
were obtained via USAA (USAA 2008). For 1990 through
2001, and  2006 (see Table 4-72) data were obtained from
USGS Mineral Industry Surveys: Aluminum Annual Report
(USGS  1995, 1998, 2000, 2001, 2002, 2007). For 2002
through 2005, national  aluminum production data were

Table 4-72: Production of Primary Aluminum (Gg)
            Year
 Gg
            2005
            2006
            2007
2,478
2,284
2,560
obtained from the United States Aluminum Association's
Primary Aluminum Statistics (USAA 2004, 2005, 2006).

Uncertainty
    The overall uncertainties associated with the 2007 CO2,
CF4, and C2F6 emission estimates were calculated using
Approach 2, as defined by IPCC (2006). For CO2, uncertainty
was assigned to each of the parameters used to estimate CO2
emissions. Uncertainty surrounding reported production data
was assumed to be 1  percent (IPCC 2006). For additional
variables, such as net C consumption, and sulfur and
ash content in baked anodes, estimates for uncertainties
associated with reported and default data were obtained
from IPCC (2006). A Monte Carlo analysis was applied to
estimate the overall uncertainty of the CO2 emission estimate
for the U.S. aluminum industry as a whole, and the results
are provided below.
    To estimate the uncertainty associated with emissions
of CF4 and C2F6, the uncertainties associated with three
variables were estimated for each smelter: (1) the quantity of
aluminum produced; (2) the anode effect minutes per cell day
(which may be reported directly or calculated as the product
of anode effect frequency and anode effect duration); and
(3) the smelter- or technology-specific slope coefficient. A
Monte Carlo analysis was then applied to estimate the overall
uncertainty of the emission estimate for each smelter and for
the U.S. aluminum industry as a whole.
    The results of this quantitative uncertainty analysis are
summarized in Table 4-73. Aluminum production-related
CO2 emissions were estimated to be between 4.1 and 4.4 Tg
CO2 Eq. at the 95 percent confidence level. This indicates a
range of approximately 4 percent below to 4 percent above
the emission estimate of 4.3 Tg CO2 Eq. Also, production-
related CF4 emissions were estimated  to be  between 2.9
and 3.5 Tg CO2 Eq.  at the 95 percent confidence level.
This indicates a range of approximately 10 percent below
to 9 percent above the emission estimate of 3.2 Tg CO2
Eq. Finally, aluminum production-related C2F6 emissions
were estimated to be between 0.5 and  0.8 Tg CO2 Eq. at
                                                                                   Industrial Processes 4-49

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Table 4-73: Tier 2 Quantitative Uncertainty Estimates for C02 and PFC Emissions from Aluminum Production
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                     (%)

Aluminum Production
Aluminum Production
Aluminum Production

C02
CF4
C2F6

4.3
3.2
0.6
Lower Bound
4.1
2.9
0.5
Upper Bound
4.4
3.5
0.8
Lower Bound
-4%
-10%
-27%
Upper Bound
+4%
+ 9%
+32%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
the 95 percent confidence level. This indicates a range of
approximately 27 percent below to 32 percent above the
emission estimate of 0.6 Tg CO2 Eq.
    The 2007 emission estimate was developed using
site-specific PFC slope coefficients for all but 1 of the 14
operating smelters where default IPCC (2006) slope data
was used.
    This Inventory may slightly underestimate greenhouse
gas emissions from aluminum production and casting
because it does not account for the possible use of SF6 as a
cover gas or a fluxing and degassing agent in experimental
and specialized casting operations. The extent of such use in
the United States is not known. Historically, SF6 emissions
from aluminum activities have been omitted from estimates
of global SF6 emissions, with  the explanation  that any
emissions would be insignificant (Ko et al. 1993, Victor and
MacDonald 1998). The concentration of SF6 in the mixtures
is small and a portion of the SF6 is decomposed in the process
(MacNealetal. 1990,GariepyandDube 1992,Koetal. 1993,
Ten Eyck and Lukens 1996, Zurecki 1996).

Recalculations  Discussion
    There were no recalculations in the historical timeseries
for this source category.

4.16  Magnesium Production
and Processing (IPCC Source
Category 2C4)

    The magnesium metal production and casting industry
uses sulfur hexafluoride (SF6) as a cover gas to prevent the
                              rapid oxidation of molten magnesium in the presence of air.
                              A dilute gaseous mixture of SF6 with dry air and/or CO2 is
                              blown over molten magnesium metal to induce and stabilize
                              the formation of a protective crust. A small portion of the
                              SF6 reacts with the magnesium to form a thin molecular
                              film of mostly magnesium oxide and magnesium fluoride.
                              The amount of SF6 reacting in magnesium production and
                              processing is assumed to be  negligible and thus all SF6
                              used is assumed to be emitted into the atmosphere. Sulfur
                              hexafluoride has been used in this application around the
                              world for the last twenty-five years.
                                  The magnesium industry emitted 3.0 Tg CO2 Eq. (0.1
                              Gg) of SF6 in 2007, representing an increase of approximately
                              4 percent from 2006 emissions (see Table 4-74). The increase
                              is attributed to higher production by the sand casting sector
                              in 2007 (USGS 2008a). Counter to the increase in production
                              from sand casting, a combination of high magnesium prices
                              and reduced demand from the American auto industry has
                              adversely impacted die casting operations in the United
                              States (USGS 2008b).

                              Table 4-74: SF6 Emissions from Magnesium Production
                              and Processing (Tg C02 Eq. and Gg)
                                      Year
                  Tg C02 Eq.
Gg
                                      1990
                    5.4
0.2
                                      1995
                                      2000
                                     ^m
                                      2005
                                      2006
                                      2007
                    5.6

                    3.0
                    •
                    2.9
                    2.9
                    3.0
0.1
0.1
0.1
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Methodology
    Emission estimates  for the magnesium industry
incorporate information provided by industry participants
in EPA's SF6 Emission Reduction Partnership for the
Magnesium Industry. The Partnership started in 1999 and,
currently, participating companies represent 100 percent
of U.S. primary and secondary production and 90 percent
of the casting sector production (i.e., die, sand, permanent
mold, wrought, and anode casting). Absolute emissions for
1999 through 2007 from primary production,  secondary
production (i.e., recycling), and die casting were generally
reported by Partnership participants. Partners reported their
SF6 consumption, which was assumed to be equivalent to
emissions. When a partner did not report emissions, they
were estimated based on the metal processed and emission
rate reported by that partner in previous and (if available)
subsequent years.  Where  data for subsequent  years  was
not available, metal production and emissions rates were
extrapolated based on the trend shown by partners reporting
in the current and previous years.
    Emission factors  for 2002 to 2006 for sand casting
activities were also acquired through the Partnership.
For 2007, the sand casting partner did not report and the
reported emission factor from 2005 was utilized as being
representative of the industry. The  1999 through 2007
emissions from casting operations (other than die) were
estimated by multiplying emission factors (kg SF6 per metric
ton of magnesium produced or processed) by the amount of
metal produced or consumed. The emission factors for casting
activities are provided below in Table 4-75. The emission

Table 4-75: SF6 Emission Factors (kg SF6 per metric ton
of Magnesium)

               Die    Permanent
     Year      Casting      Mold     Wrought    Anodes
1999
2000
2001
2002
2003
2004
2005
2006
2007
2.14a
0.72
0.72
0.71
0.81
0.81
0.76
0.86
0.67
2 1
2 1
2 1
2 1
2 1
2 1
2 1
2 1
2 1
1
1
1
1
1
1
1
1
1
  a Weighted average that includes an estimated emission factor of 5.2 kg
  SF6 per metric ton of magnesium for die casters that do not participate
  in the Partnership.
factors for primary production, secondary production and
sand casting are withheld to protect company-specific
production information. However, the emission factor for
primary production has not risen above the average 1995
partner value of 1.1 kg SF6 per metric ton.
    Die casting emissions for 1999 through 2007,  which
accounted for 19 to 52 percent of all SF6 emissions from the
U.S. magnesium industry during this period, were estimated
based on information supplied by industry partners. From
2000 to 2007, partners accounted for all U.S. die casting
that was tracked by USGS. In 1999, partners did not account
for all die casting tracked by USGS, and, therefore,  it was
necessary to estimate the emissions of die casters who were
not partners. Die casters who were not partners were assumed
to be similar to partners who cast small parts. Due to process
requirements, these casters consume larger quantities  of SF6
per metric ton of processed magnesium than casters that
process large parts. Consequently, emission estimates from
this group of die casters were developed using an average
emission factor of 5.2 kg SF6 per metric ton of magnesium.
The emission factors for the other industry sectors (i.e.,
permanent mold, wrought, and anode casting) were based
on discussions with industry representatives.
    Data used to develop SF6 emission estimates were
provided by the Magnesium Partnership participants and
the USGS. U.S. magnesium metal  production (primary
and secondary) and consumption  (casting) data from 1990
through 2007 were available from the USGS (USGS 2002,
2003,2005,2006,2007,2008a). Emission factors from 1990
through 1998 were based on a number of sources. Emission
factors for primary production were available from U.S.
primary producers for 1994  and 1995,  and an emission
factor for die casting of 4.1 kg per metric ton was available
for the mid-1990s from an international survey (Gjestland
& Magers 1996).
    To estimate emissions for 1990 through 1998, industry
emission factors were multiplied by the corresponding metal
production and consumption (casting) statistics from USGS.
The primary production emission factors were 1.2 kg per
metric ton for 1990 through 1993, and 1.1 kg per metric
ton for  1994 through 1997.  For  die casting, an emission
factor of 4.1 kg per metric ton was used for the period 1990
through 1996. For 1996 through 1998, the emission factors
for primary  production and  die casting were assumed to
decline  linearly  to the level  estimated based on partner
                                                                                    Industrial Processes 4-51

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reports in 1999. This assumption is consistent with the trend
in SF6 sales to the magnesium sector that is reported in the
RAND survey of major SF6 manufacturers, which shows
a decline of 70 percent from 1996 to 1999 (RAND 2002).
Sand casting emission factors for 2002 through 2007 were
provided by the  Magnesium Partnership participants, and
1990 through 2001 emission factors for this process were
assumed to have been the same as the 2002 emission factor.
The emission factor  for secondary production from 1990
through 1998 was assumed to be constant at the 1999 average
partner value. The emission factors for the other processes
(i.e., permanent mold, wrought, and anode casting), about
which less  is known, were assumed to  remain constant at
levels defined in Table 4-75.

Uncertainty
    To estimate the uncertainty surrounding the estimated
2007 SF6  emissions from magnesium  production and
processing, the uncertainties associated with three variables
were  estimated  (1)  emissions reported by  magnesium
producers  and processors  that participate in the SF6
Emission Reduction Partnership; (2) emissions estimated for
magnesium producers and processors that participate in the
Partnership but did not report this year; and (3) emissions
estimated for magnesium producers and processors that do
not participate in the Partnership. An uncertainty of 5 percent
was assigned to the data reported by each participant in the
Partnership. If partners did not report emissions data during
the current reporting year, SF6 emissions data were estimated
using available emission factors and production information
reported in prior years; the extrapolation was based on the
average trend for partners reporting in the current reporting
year and the year prior. The uncertainty associated with the
SF6 usage estimate generated from the extrapolated emission
                                factor and production information was estimated to be 30
                                percent; the lone sand casting partner did not report in the
                                current reporting year and its activity and emission factor was
                                held constant at 2006 and 2005 levels, respectively, and given
                                an uncertainty of 30 percent. For those industry processes that
                                are not represented in Partnership, such as permanent mold
                                and wrought casting, SF6 emissions were estimated using
                                production and consumption statistics reported by USGS
                                and estimated process-specific emission factors (see Table
                                4-75). The uncertainties associated with the emission factors
                                and USGS-reported statistics were assumed to be 75 percent
                                and 25 percent, respectively. Emissions  associated with
                                sand casting activities utilized a partner-reported emission
                                factor with an uncertainty of 75 percent. In general, where
                                precise quantitative  information was  not available on the
                                uncertainty of a parameter, a conservative (upper-bound)
                                value was used.
                                    Additional uncertainties exist in these estimates, such as
                                the basic assumption that SF6 neither reacts nor decomposes
                                during use. The melt surface reactions and high temperatures
                                associated with molten magnesium could potentially
                                cause some gas degradation. Recent measurement studies
                                have identified SF6  cover gas degradation in die casting
                                applications on the order of 20 percent (Bartos et al. 2007).
                                Sulfur hexafluoride may also be used as a cover gas for the
                                casting of molten aluminum with high magnesium content;
                                however, the extent  to which this technique is used in the
                                United States is unknown.
                                    The results  of  this Tier 2 quantitative uncertainty
                                analysis are summarized in Table 4-76. Sulfur hexafluoride
                                emissions associated with magnesium production  and
                                processing were estimated to be between 2.6 and 3.4Tg CO2
                                Eq. at the 95 percent confidence level. This indicates a range
Table 4-76: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and Processing
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
 Uncertainty Range Relative to Emission Estimate3
   (Tg C02 Eq.)                      (%)
                                                      Lower Bound   Upper Bound   Lower Bound    Upper Bound
  Magnesium Production	SF6
                3.0
2.6
3.4
-12%
+13%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4-52  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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of approximately 12 percent below to 13 percent above the
2007 emission estimate of 3.0 Tg CO2 Eq.

Recalculations Discussion
    Newly reported historical data from a secondary remelt
partner led to revised SF6 emission estimates in the years
2001 to 2006; the new data resulted in an average decrease
of 0.3 Tg CO2 Eq. in emissions for the 2004 to 2006 period,
or about 10 percent of total emissions.

Planned Improvements
    As more work assessing the degree of cover gas
degradation and associated byproducts is undertaken and
published, results could potentially be used to refine the
emission estimates, which currently assume (per the 2006
IPCC Guidelines, IPCC 2006) that all SF6 utilized is emitted
to the atmosphere. EPA-funded measurements of SF6 in die
casting applications have indicated that the latter assumption
may be incorrect, with observed SF6 degradation on the
order of 20 percent (Bartos et al. 2007). Another issue that
will be addressed in future inventories is the likely adoption
of alternate cover gases by U.S. magnesium producers and
processors. These cover gases, which include AM-cover™
(containing HFC-134a) and  Novec™ 612, have lower
GWPs than SF6, and tend to quickly decompose during their
exposure to the molten metal. Magnesium producers and
processors have already begun using these cover gases for
2006 and 2007 in a limited fashion; because the amounts are
currently negligible these emissions are only being monitored
and recorded at this time.

4.17.  Zinc  Production
(IPCC Source  Category 2C5)

    Zinc production in the United States  consists of both
primary  and  secondary processes. Primary production
techniques used in the United States are the electrothermic
and electrolytic process  while secondary  techniques used
in the United States include a range of metallurgical,
hydrometallurgical, and pyrometallurgical processes.
Worldwide primary zinc production also  employs a
pyrometallurgical process using the Imperial Smelting Furnace
process; however, this process is not used in the United States
(Sjardin 2003). Of the primary and secondary processes used
in the United States, the electrothermic process results in non-
energy CO2 emissions, as does the Waelz Kiln process—a
technique used to produce secondary zinc from electric-arc
furnace (EAF) dust (Viklund-White 2000).
    During the electrothermic zinc production process,
roasted zinc concentrate and, when available, secondary
zinc products enter a sinter feed where they are burned to
remove impurities before entering an electric retort furnace.
Metallurgical coke added to the electric retort furnace reduces
the zinc oxides and produces vaporized zinc, which is then
captured in a vacuum condenser. This reduction process
produces non-energy CO2 emissions (Sjardin 2003). The
electrolytic zinc production process does not produce non-
energy CO2 emissions.
    In the Waelz Kiln process, EAF dust, which is captured
during the recycling of galvanized steel, enters a kiln along
with a reducing agent—often metallurgical coke. When kiln
temperatures reach approximately 1100-1200°C, zinc fumes
are produced, which are combusted with air entering the kiln.
This combustion forms zinc oxide, which is collected in a
baghouse or electrostatic precipitator, and is  then leached
to remove chloride and fluoride. Through this process,
approximately 0.33 ton of zinc is produced for every ton of
EAF dust treated (Viklund-White 2000).
    In 2007, U.S. primary and secondary zinc production
totaled 519,221 metric tons  (Tokin 2009). The resulting
emissions of CO2 from zinc production in 2007 were
estimated to be 0.5 Tg CO2 Eq. (530 Gg) (see Table
4-77). All 2007 CO2 emissions result from secondary zinc
production.
    After a gradual increase in total emissions from 1990 to
2000, largely due to an increase in secondary zinc production,
emissions have decreased in recent years due to the closing of
an electrothermic-process zinc plant in Monaca, PA (USGS

Table  4-77: C02 Emissions from Zinc Production
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
Gg
        1990
   0.9
949
        2005
        2006
        2007
                                                                                  Industrial Processes  4-53

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2004). Emissions for 2007, which are nearly half that of 1990
(44 percent), remained constant from 2006 due to the use of
proxied data for secondary zinc production.

Methodology
    Non-energy CO2 emissions from zinc production result
from those processes that use metallurgical coke or other
C-based materials as reductants. Sjardin (2003) provides an
emission factor of 0.43 metric tons CO2/ton zinc produced for
emissive zinc production processes; however, this emission
factor is based on the Imperial Smelting Furnace production
process. Because the Imperial Smelting Furnace production
process is not used in the United States, emission factors
specific to those emissive zinc production processes used
in the United States, which consist of the  electrothermic
and Waelz Kiln processes, were needed. Due to the limited
amount of information available for these  electrothermic
processes, only Waelz Kiln process-specific emission factors
were developed. These emission factors were  applied to
both the Waelz Kiln process and the electrothermic zinc
production processes. A Waelz Kiln emission factor based
on the amount of zinc produced was  developed based on
the amount of metallurgical coke consumed  for non-energy
purposes per ton of zinc produced,  1.19 metric  tons coke/
metric ton zinc produced (Viklund-White 2000), and the
following equation:
                 1.19  metric tons coke

      Waelz Kiln —
                       metric tons zinc
                 0.84   metric tons C
                       metric tons coke
                 3.67  metric tons CO2
                        metric tons C
                 3.66  metric tons CO2
                       metric tons zinc
    The USGS  disaggregates total U.S. primary zinc
production capacity into zinc produced using the
electrothermic  process and zinc produced using the
electrolytic process; however, the USGS  does not report
the amount of zinc produced using each process, only the
total zinc production capacity of the zinc plants using each
process. The total electrothermic zinc production capacity is
divided by total primary zinc production capacity to estimate
the percent of primary zinc produced using the electrothermic
process. This percent is then multiplied by total primary zinc
production to estimate the amount of zinc produced using the
electrothermic process, and the resulting value is multiplied
by the Waelz Kiln process emission factor to obtain total
CO2 emissions for primary zinc production. According to
the USGS, the only  remaining plant producing primary
zinc using the electrothermic process closed in 2003 (USGS
2004). Therefore, CO2 emissions for primary zinc production
are reported only for years  1990 through 2002.
    In the United States, secondary zinc is produced through
either the electrothermic or Waelz Kiln process. In 1997,
the Horsehead Corporation plant, located  in Monaca, PA,
produced 47,174 metric tons of secondary zinc using the
electrothermic process (Queneau et al.  1998). This is the
only plant in the United States that uses the electrothermic
process to produce secondary zinc, which, in 1997, accounted
for 13 percent of total secondary zinc production. This
percentage was applied to  all years within the time series
up until the Monaca plant's  closure in 2003  (USGS 2004) to
estimate the total amount of secondary zinc produced using
the electrothermic process. This  value is  then multiplied
by the Waelz Kiln process emission factor to obtain total
CO2 emissions for secondary zinc produced using  the
electrothermic process.
    U.S. secondary zinc is also  produced by processing
recycled EAF dust in a Waelz Kiln furnace. Due to the
complexities of recovering zinc from recycled EAF dust, an
emission factor based on the amount of EAF dust consumed
rather than the amount of secondary zinc produced is believed
to represent actual CO2 emissions from the process more
accurately (Stuart 2005). An emission factor based on the
amount of EAF dust consumed was developed based on the
amount of metallurgical coke consumed per ton of EAF dust
consumed, 0.4 metric tons coke/metric ton EAF dust consumed
(Viklund-White 2000), and the following equation:
    EFF
0.4    metric tons coke
     metric tons EAF dust
0.84     metric tons C
       metric tons coke
3.67   metric tons CO2
         metric tons C
1.23   metric tons CO2
     metric tons EAF dust
4-54  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-78: Zinc Production (Metric Tons)
        Year
Primary
Secondary
                       191,120
                       113,000
                       121,221
                349,000
                397,000
                398,000
    The Horsehead Corporation plant, located in Palmerton,
PA, is the only large plant in the United States that produces
secondary zinc by recycling EAF dust (Stuart 2005). In
2003, this plant consumed 408,240 metric tons of EAF dust,
producing 137,169 metric tons of secondary zinc (Recycling
Today 2005). This zinc production accounted for 36 percent
of total secondary zinc produced in 2003.  This percentage
was applied to the USGS data for total  secondary zinc
production for all years  within the time series to  estimate
the total amount of secondary zinc produced by consuming
recycled EAF dust in a Waelz Kiln furnace. This value is
multiplied by the Waelz Kiln process emission factor for
EAF dust to obtain total CO2 emissions.
    The 1990 through 2006 activity data  for primary and
secondary zinc production (see Table 4-78) were obtained
through the USGS Mineral Yearbook: Zinc (USGS  1994
through 2008). Preliminary data for 2007 primary production
and production from  scrap were obtained  from the USGS
Mineral Commodity Specialist (Tolcin 2009). Because data
for 2007 secondary zinc production were unavailable, 2006
data were used.
Uncertainty
    The uncertainties contained in these estimates are two-
fold, relating to activity data and emission factors used.
    First, there are uncertainties associated with the percent
of total zinc production, both primary and secondary, that
is attributed to the electrothermic and Waelz Kiln emissive
zinc production processes. For primary zinc production, the
amount of zinc produced annually using the electrothermic
process is  estimated from the percent of primary zinc
production capacity that electrothermic production capacity
constitutes for each year of the time series. This assumes
that each zinc plant is operating at the same percentage of
total production capacity, which may not be the case and
this calculation could either overestimate or underestimate
the percentage of the total primary zinc production that is
produced using the electrothermic process. The amount of
secondary zinc produced using the electrothermic process is
estimated from the percent of total secondary zinc production
that this process accounted for during a single year, 2003.
The amount of secondary  zinc produced using the Waelz
Kiln process is estimated from the percent of total secondary
zinc production this process accounted for during a single
year,  1997. This calculation could either overestimate or
underestimate the percentage of the total secondary zinc
production that is produced using the electrothermic or Waelz
Kiln processes. Therefore, there is uncertainty associated
with the fact that percents of total production data estimated
from production capacity, rather than actual production data,
are used for emission estimates.
    Second,  there are uncertainties  associated with the
emission factors used to estimate CO2 emissions from the
primary and secondary production processes. Because the
only published emission factors are based on the Imperial
Smelting Furnace, which is not used in the United States,
country-specific  emission factors  were developed for
the Waelz Kiln zinc  production process. Data  limitations
prevented the development of emission factors  for the
electrothermic process. Therefore, emission factors for the
Waelz Kiln process were applied to both electrothermic and
Waelz Kiln production processes. Furthermore, the Waelz
Kiln emission factors are based on materials balances for
metallurgical coke and EAF dust consumed during zinc
production provided by Viklund-White (2000). Therefore, the
accuracy of these emission factors depend upon the accuracy
of these materials balances.
    The  results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-79. Zinc production CO2
                                                                                    Industrial Processes 4-55

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Table 4-79: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Zinc Production
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                   Uncertainty Range Relative to Emission Estimate3
                    (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound    Lower Bound   Upper Bound
  Zinc Production
CO,
0.5
0.4
0.7
-21%
+25%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
emissions were estimated to be between 0.4 and 0.7 Tg CO2
Eq. at the 95 percent confidence level. This indicates a range
of approximately 21 percent below and 25 percent above the
emission estimate of 0.5 Tg CO2 Eq.

4.18.  Lead  Production
(IPCC Source  Category 2C5)

    Lead production  in the United States consists of  both
primary and secondary processes—both of which emit CO2
(Sjardin 2003). Primary lead production, in the form of
direct smelting, mostly occurs at plants located in Alaska
and Missouri, though to a lesser extent  in Idaho, Montana,
and Washington. Secondary production largely involves the
recycling of lead acid batteries at approximately 18 separate
smelters located in 11 states (USGS 2008 and 2009). Secondary
lead production has increased in the United States over the past
decade while primary lead production has decreased. In 2007,
secondary lead production accounted for approximately 91
percent of total lead production (USGS 2009).
    Primary production of lead through the direct smelting
of lead concentrate produces CO2 emissions as the  lead
concentrates are reduced in a furnace using metallurgical
coke (Sjardin 2003). U.S. primary lead production decreased
by 20 percent from 2006 to 2007 and has decreased by 68
percent since 1990 (USGS 2009, USGS 1995).
    At last reporting, approximately 93 percent of refined
lead production is produced primarily from scrapped
lead acid batteries  (USGS 2009). Similar to primary lead
production, CO2 emissions result when a reducing agent,
usually metallurgical coke, is added to the smelter to aid
in the reduction process (Sjardin 2003). U.S.  secondary
                               lead production decreased from 2006 to 2007 by 2 percent,
                               and has increased by 28 percent since 1990 (USGS 2009,
                               USGS  1995).
                                   At last reporting, the United States was the third largest
                               mine producer of lead in the world, behind China and Australia,
                               accounting for 12 percent of world production in 2007 (USGS
                               2009). In 2007, U.S. primary and secondary lead production
                               totaled 1,303,000 metric tons (USGS 2009). The resulting
                               emissions of CO2 from  2007 production were estimated to
                               be 0.3 Tg CO2 Eq. (267 Gg) (see Table 4-80). The majority
                               of 2007 lead production is from secondary processes, which
                               account for 88 percent of total 2007 CO2 emissions.
                                   After a gradual increase in total emissions from 1990 to
                               2000, total emissions have decreased by six percent since 1990,
                               largely due to a decrease in primary production (68 percent
                               since 1990) and a transition within the United States from
                               primary lead production to secondary lead production, which
                               is less emissive than primary production, although the sharp
                               decrease leveled off in 2005 (USGS 2009, Smith 2007).
                               Table 4-80: C02 Emissions from Lead Production
                               (Tg C02 Eq. and Gg)
                                       Year
                                     Tg C02 Eq.
                                       Gg
                                       1990
                                        0.3
                                      285
                                       2005
                                       2006
                                       2007
4-56  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-81: Lead Production (Metric Tons)
        Year
Primary
Secondary
                       143,000
                       153,000
                       123,000
                922,000
               1,020,000
               1,130,000
               ^^^H
               1,150,000
               1,160,000
               1,180,000
Methodology
    Non-energy CO2 emissions from lead production result
from primary and secondary production processes that use
metallurgical coke or other C-based materials as reductants.
For primary lead production using direct smelting, Sjardin
(2003) and the IPCC (2006) provide an emission factor of
0.25 metric tons CO2/ton lead. For secondary lead production,
Sjardin (2003) and IPCC (2006) provide an emission factor
of 0.2 metric tons  CO2/ton lead produced. Both factors
are multiplied by total U.S. primary and secondary  lead
production, respectively,  to estimate CO2 emissions.
    The 1990 through 2007 activity data for primary and
secondary lead production (see Table 4-81)  were obtained
through the USGS Minerals Yearbook: Lead (USGS 1994
through 2009).

Uncertainty
    Uncertainty  associated with lead  production relates
to the emission factors and activity data used. The direct
smelting emission factor used in primary production is taken
from Sjardin (2003) who averages the values provided by
three other studies (Dutrizac et al. 2000, Morris et al. 1983,
Ullman 1997). For secondary production, Sjardin  (2003)
reduces this factor by 50 percent and adds a CO2 emission
factor associated with battery treatment. The applicability
of these emission factors to plants  in the United States
is uncertain. There is also a smaller level of uncertainty
associated with the accuracy of primary and secondary
production data provided by the USGS.
    The results  of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-82. Lead production CO2
emissions were estimated to be between 0.2 and 0.3 Tg CO2
Eq. at the 95 percent confidence level. This indicates a range
of approximately 16 percent below and 17 percent above the
emission estimate of 0.3 Tg CO2 Eq.

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

    Trifluoromethane (HFC-23 or CHF3) is generated as a
byproduct during the manufacture of chlorodifluoromethane
(HCFC-22), which is primarily employed in refrigeration
and air conditioning systems and as  a chemical feedstock
for manufacturing synthetic polymers. Between 1990 and
2000, U.S. production of HCFC-22 increased significantly
as HCFC-22 replaced chlorofluorocarbons (CFCs) in many
applications. Since 2000, U.S. production has fluctuated but
has generally remained above 1990 levels. Because HCFC-22
depletes stratospheric ozone, its production for non-feedstock
uses is  scheduled to be phased out by 2020 under the U.S.
Table 4-82: Tier 2 Quantitative Uncertainty Estimates for C02 Emissions from Lead Production
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
 Gas         (Tg C02 Eq.)
                     Uncertainty Range Relative to Emission Estimate3
                      (Tg C02 Eq.)                      (%)
                                                     Lower Bound    Upper Bound   Lower Bound    Upper Bound
  Lead Production
 CO,
  0.3
   0.2
0.3
-16%
+17%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                  Industrial Processes  4-57

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Clean Air Act.17 Feedstock production, however, is permitted
to continue indefinitely.
    HCFC-22  is produced by the reaction of chloroform
(CHC13) and hydrogen fluoride (HF) in the presence of a
catalyst, SbQ5. The reaction of the catalyst and HF produces
SbClxFy, (where x + y = 5), which reacts with chlorinated
hydrocarbons to replace chlorine atoms with fluorine. The
HF and chloroform  are introduced  by submerged piping
into a continuous-flow reactor that contains the catalyst in a
hydrocarbon mixture of chloroform and partially fluorinated
intermediates. The vapors leaving the reactor contain HCFC-
21 (CHC12F), HCFC-22 (CHC1F2), HFC-23 (CHF3), HC1,
chloroform, and HF.  The under-fluorinated intermediates
(HCFC-21) and chloroform are then condensed and returned
to the reactor, along with residual catalyst, to undergo further
fluorination. The final vapors leaving the condenser are
primarily HCFC-22, HFC-23, HC1 and residual HF. The HC1
is recovered as a useful byproduct, and the HF is removed.
Once separated from HCFC-22, the HFC-23 may be released
to the atmosphere, recaptured for use in a limited number of
applications, or destroyed.
    Emissions of HFC-23 in 2007  were estimated to be
17.0 Tg CO2 Eq. (1.5 Gg) (Table 4-83). This quantity
represents a 23 percent increase from 2006 emissions and
a 53 percent decline from 1990 emissions. The increase
from 2006 emissions was caused by  a 5 percent increase in
HCFC-22 production and a 17 percent increase in the HFC-
23 emission rate. The decline from  1990 emissions is due
to a 60 percent decrease in the HFC-23 emission rate since
1990. The decrease is primarily attributable to four factors:
(a) five plants that did not capture and destroy the HFC-23
generated have ceased production of HCFC-22 since 1990;
(b) one plant that captures and destroys the HFC-23 generated
began to produce HCFC-22; (c) one plant implemented and
documented a process change that reduced the amount of
HFC-23 generated; and (d) the same plant began recovering
HFC-23, primarily for destruction and secondarily for sale.
Three HCFC-22 production plants operated in the United
States  in 2008, two of which used thermal oxidation to
significantly lower their HFC-23 emissions.
Table 4-83: HFC-23 Emissions from HCFC-22
Production (Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
Gg
        1990
  36.4
        2005
        2006
        2007
17 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].
Methodology
    To estimate their emissions of HFC-23, five of the eight
HCFC-22 plants that have operated in the U.S. since 1990
use (or, for those plants that have closed, used) methods
comparable to the Tier 3  methods  in the 2006 IPCC
Guidelines (IPCC 2006). The other three plants, the last of
which closed in 1993, used methods comparable to the Tier 1
method in the 2006 IPCC Guidelines. Emissions from these
three plants have been recalculated using the recommended
emission factor for unoptimized plants operating before
1995 (0.04 kg HCFC-23/kg HCFC-22 produced).  (This
recalculation was  reflected in the  1990 through  2006
inventory submission.)
    The five plants that have operated since 1994 measured
concentrations of HFC-23 to estimate their emissions of HFC-
23. Plants using thermal oxidation to abate their HFC-23
emissions monitor the performance of their oxidizers to verify
that the HFC-23 is almost completely destroyed. Plants that
release (or historically have released) some of their byproduct
HFC-23 periodically measure HFC-23 concentrations in the
output stream using gas chromatography. This information is
combined with information on quantities of products (e.g.,
HCFC-22) to estimate HFC-23 emissions.
    In most years, including 2008, an industry association
aggregates and reports to EPA  country-level estimates of
HCFC-22 production and HFC-23 emissions (ARAP  1997,
1999,2000,2001,2002,2003,2004,2005,2006,2007,2008).
However, in 1997 and 2008, EPA (through a contractor)
performed comprehensive reviews of plant-level estimates
of HFC-23 emissions and HCFC-22 production (RTI 1997;
RTI 2008). These reviews enabled EPA to review,  update,
4-58  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-84: HCFC-22 Production (Gg)
            Year
              Gg
            1990
            1995
            2000
           ^H
            2005
            2006
            2007
              139
             •
              155
             •
              186
             •
              156
              154
              162
and where necessary, correct U.S. totals, and also to perform
plant-level uncertainty analyses (Monte-Carlo simulations)
for 1990, 1995, 2000, 2005, and 2006. Estimates of annual
U.S. HCFC-22 production are presented in Table 4-84.

Uncertainty
    The uncertainty analysis  presented in this section was
based on a plant-level Monte Carlo simulation for 2006. The
Monte Carlo analysis used estimates of the uncertainties in
the individual variables in each plant's estimating procedure.
This analysis was based on the generation of 10,000 random
samples of model inputs from the probability density
functions for each input.  A normal probability density
function was assumed for all  measurements  and biases
except the equipment leak estimates for one plant; a log-
normal probability density function was used for this plant's
equipment leak estimates. The simulation for 2006 yielded
a 95-percent confidence interval for U.S. emissions of 6.8
percent below to 9.6 percent above the reported total.
    Because EPA did not have access  to plant-level
emissions data for 2007, the relative errors yielded by the
Monte Carlo simulation for 2006 were applied to the U.S.
emission estimate for 2007. The resulting estimates of
                absolute uncertainty are likely to be accurate because (1) the
                methods used by the three plants to estimate their emissions
                are not believed to have changed significantly since 2006;
                (2) the distribution of emissions among the plants is  not
                believed to have changed significantly since 2006 (one plant
                continues to dominate emissions); and (3) the country-level
                relative errors yielded by the Monte Carlo simulations for
                2005 and 2006 were very similar, implying that these errors
                are not sensitive to small, year-to-year changes.
                    The results of the Tier 2 quantitative uncertainty analysis
                are summarized in Table 4-85.  HFC-23 emissions from
                HCFC-22  production were estimated to be between 15.8
                and 18.6 Tg CO2 Eq. at the 95-percent confidence level. This
                indicates a range of approximately 7 percent below and 10
                percent above the emission estimate of 17.0 Tg CO2 Eq.

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

                    Hydrofluorocarbons (HFCs) andperfluorocarbons (PFCs)
                are used as alternatives to several classes of ozone depleting
                substances (ODSs) that are being phased out under the terms
                of the Montreal Protocol and the Clean Air Act Amendments
                of 1990.ls Ozone depleting substances—chlorofluorocarbons
                (CFCs), halons, carbon tetrachloride, methyl chloroform, and
                hydrochlorofluorocarbons (HCFCs)—are used in a variety
                of industrial applications including  refrigeration and air
                conditioning equipment, solvent cleaning, foam production,
                sterilization, fire extinguishing, and aerosols. Although HFCs
                and PFCs  are not harmful to the  stratospheric ozone layer,
                they  are potent  greenhouse gases. Emission estimates  for
                HFCs and PFCs used as substitutes for ODSs are provided
                in Table 4-86 and Table 4-87.
Table 4-85: Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production
(Tg C02 Eq. and Percent)
  Source
        2007 Emission Estimate
 Gas         (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound    Lower Bound   Upper Bound
  HCFC-22 Production
HFC-23
17.0
15.8
18.6
+ 10%
  ! Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                        8 [42 U.S.C § 7671, CAA § 601].
                                                                                   Industrial Processes  4-59

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Table 4-86: Emissions of MFCs and PFCs from ODS Substitutes (Tg C02 Eq.)
  Gas
1990
1995
2000
 2005
 2006
 2007
  HFC-23
  HFC-32
  HFC-125
  HFC-134a
  HFC-143a
  HFC-236fa
  CF4
  Others3
  ;
  0.3
                             0.4
                            10.3
                            70.5
                            12.2
                             0.8
                              +
                             5.9
                         0.6
                        12.3
                        70.7
                        14.4
                         0.8
                          +
                         6.2
                      0.9
                     14.7
                     68.6
                     16.7
                      0.9
                       +
                      6.5
  Total
  0.3
28.5
71.2
100.0
105.0
108.3
  + Does not exceed 0.05 Tg C02 Eq.
  'Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee, and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and
   perfluoropolyethers (PFPEs) employed for solvent applications. For estimating purposes, the GWP value used for PFC/PFPEs was based upon C6F14.
  Note: Totals may not sum due to independent rounding.
Table 4-87: Emissions of MFCs and PFCs from ODS Substitution (Mg)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF4
Others3
1990
+
+
\
M
1995
+
+ 1
291
19,537
1321
36 1
+ 1
M
2000
1
44l
1,873
44,011
1,089
85 1
ll
M|
2005
1
562
3,675
54,226
3,200
125
2
M
2006
1
913
4,394
54,362
3,782
131
2
M
2007
1
1,325
5,253
52,782
4,402
136
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.19 In 1993,  the use of HFCs in
foam production began, and in 1994 these compounds also
found applications as solvents and sterilants. In 1995, ODS
substitutes  for halons entered widespread use in the United
States as halon production was phased out.
    The use and subsequent emissions of HFCs and PFCs
as ODS substitutes has been increasing from small amounts
in 1990 to  108.3 Tg CO2 Eq. in 2007. This increase was in
 9 R-404A contains HFC-125, HFC-143a, and HFC-134a.
            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  4-88 presents HFCs and PFCs emissions by end-
            use sector  for 1990 through 2007. The end-use sectors that
            contributed the most toward emissions of HFCs and PFCs
            as ODS substitutes in 2007 include refrigeration and air-
            conditioning (97.5 Tg CO2 Eq., or approximately 90 percent),
            aerosols (6.2 Tg CO2 Eq., or approximately 6 percent), and
            foams (2.6 Tg CO2 Eq., or approximately 2 percent). Within
4-60  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 4-88: Emissions of MFCs and PFCs from ODS Substitutes (Tg C02 Eq.) by Sector
  Gas
1990
1995
2000
2005
2006
2007
  Refrigeration/Air-conditioning
  Aerosols
  Foams
  Solvents
  Fire Protection
  j
  +
 119.31       58.6
  8.11       10.1

  0.9          2.1 I
              90.1
               5.9
               2.2
               1.3
               0.5
          94.6
           6.1
           2.4
           1.3
           0.6
          97.5
           6.2
           2.6
           1.3
           0.7
  Total
             28.5
             71.2
             100.0
         105.0
         108.3
  + Does not exceed 0.05 Tg C02 Eq.
the refrigeration and air-conditioning end-use sector, motor
vehicle air-conditioning was the highest emitting end-use
(52.9 Tg CO2 Eq.), followed by refrigerated transport and
retail food. Each of the end-use sectors is described in more
detail below.

Refrigeration/Air-conditioning
    The refrigeration and air-conditioning sector includes a
wide variety of equipment types that have historically used
CFCs or HCFCs. End-uses within this sector include motor
vehicle air-conditioning, retail food refrigeration, refrigerated
transport (e.g., ship holds, truck trailers, railway freight cars),
household refrigeration, residential and small commercial
air-conditioning/heat pumps, chillers (large comfort
cooling), cold  storage facilities, and industrial process
refrigeration (e.g., systems used in food processing, chemical,
petrochemical, pharmaceutical, oil and gas, and metallurgical
industries). As  the ODS phaseout is taking effect, most
equipment is being  or  will eventually be retrofitted  or
replaced  to use HFC-based substitutes.  Common HFCs  in
use today in refrigeration/air-conditioning equipment are
HFC- 134a, R-410A, R-404A, and R-507A. These HFCs are
emitted to the atmosphere during equipment manufacture
and operation (as a result of component failure, leaks, and
purges), as well as at servicing and disposal events.

Aerosols
    Aerosol propellants are used in metered dose inhalers
(MDIs) and a variety of personal care products and technical/
specialty products (e.g., duster sprays  and safety horns).
Many pharmaceutical companies that produce MDIs—a
type of inhaled therapy used  to treat asthma and chronic
obstructive pulmonary disease—have committed to replace
the use of CFCs with HFC-propellant alternatives. The
earliest ozone-friendly MDIs were produced with HFC- 134a,
but eventually, the industry expects to use HFC-227ea as well.
           Conversely, since the use of CFC propellants was banned in
           1978, most consumer aerosol products have not transitioned
           to HFCs, but to "not-in-kind" technologies, such as solid or
           roll-on deodorants and finger-pump sprays.  The transition
           away from ODS in specialty aerosol products has also led
           to the introduction of non-fluorocarbon alternatives (e.g.,
           hydrocarbon propellants) in certain applications, in addition
           to HFC-134a or HFC-152a. These propellants are released
           into the atmosphere as the aerosol products are used.

           Foams
               CFCs and HCFCs have traditionally been used as foam
           blowing agents to produce polyurethane (PU), polystyrene,
           polyolefin, and phenolic foams, which are used in  a wide
           variety  of products and applications.  Since the Montreal
           Protocol, flexible PU foams as well as other types of
           foam, such as polystyrene sheet, polyolefin, and phenolic
           foam, have transitioned almost completely away from
           fluorocompounds, into alternatives such as CO2, methylene
           chloride, and hydrocarbons. The majority of rigid PU foams
           have transitioned to HFCs—primarily HFC- 134a and HFC-
           245fa. Today, these HFCs are used to produce polyurethane
           appliance foam, PU commercial refrigeration, PU spray, and
           PU panel foams—used in refrigerators, vending machines,
           roofing, wall insulation, garage doors, and cold storage
           applications. In addition, HFC-152a is used to produce
           polystyrene  sheet/board foam,  which is  used in food
           packaging and building insulation. Emissions of blowing
           agents occur when the foam is manufactured as well as
           during the foam lifetime and at foam  disposal, depending
           on the particular foam type.

           Solvents
               CFCs, methyl chloroform (1,1,1-trichloroethane or
           TCA), and to a lesser extent carbon tetrachloride  (CC14)
           were historically used as solvents in a wide range of cleaning
                                                                                    Industrial Processes  4-61

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applications, including precision, electronics, and metal
cleaning.  Since their phaseout, metal cleaning end-use
applications have primarily transitioned to non-fluorocarbon
solvents and not-in-kind processes.  The precision and
electronics cleaning end-uses have transitioned in part to
high-GWP gases, due to their high reliability, excellent
compatibility, good stability, low toxicity, and selective
solvency. These applications rely on HFC-43 lOmee, HFC-
365mfc, HFC-245fa, and to a lesser extent, PFCs. Electronics
cleaning involves removing flux residue that remains after
a soldering operation  for printed circuit boards and  other
contamination-sensitive electronics applications. Precision
cleaning may apply to either electronic components  or to
metal surfaces, and is characterized by products, such as disk
drives, gyroscopes, and optical components, that require a
high level of cleanliness and generally have complex shapes,
small clearances, and other cleaning challenges. The use of
solvents yields fugitive emissions of these HFCs and PFCs.

Fire Protection
    Fire protection applications  include portable fire
extinguishers ("streaming" applications) that originally used
halon 1211, and total  flooding applications that originally
used halon 1301, as well as some halon 2402. Since the
production and sale of halons were banned in the United
States in 1994, the halon replacement agent of choice in the
streaming sector has been dry chemical, although HFC-236ea
is also used to a limited extent. In the total flooding sector,
HFC-227ea has emerged as the  primary replacement for
halon 1301 in applications that require clean agents. Other
FfFCs, such as HFC-23, FfFC-236fa, andHFC-125, are used
in smaller amounts. The  majority of HFC-227ea in total
flooding systems is used to protect essential electronics, as
well as in civil aviation, military mobile weapons systems,
oil/gas/other process industries, and merchant shipping. As
fire protection equipment is tested or deployed, emissions of
these HFCs are released.

Methodology
    A  detailed  Vintaging Model of ODS-containing
equipment and products was used to estimate the actual —
versus  potential—emissions of various ODS substitutes,
including HFCs and PFCs. The name of the model refers to
the fact that the model tracks the use and emissions of various
compounds for the  annual "vintages" of new equipment
that enter service in each end-use. This Vintaging Model
predicts ODS and ODS substitute use in the United States
based on modeled estimates of the quantity of equipment
or products sold each year containing these chemicals and
the amount of the chemical required to manufacture and/or
maintain equipment and products over time. Emissions for
each end-use were estimated by applying annual leak rates
and release profiles, which account for the lag in emissions
from equipment as they leak over time. By aggregating the
data for more than 50 different end-uses, the model produces
estimates of annual  use and emissions of each compound.
Further information on the Vintaging Model is contained in
Annex 3.8.

Uncertainty
    Given that emissions  of ODS  substitutes occur from
thousands of different kinds of equipment and from millions
of point and mobile sources throughout the United States,
emission estimates must be made using analytical tools such
as the Vintaging Model or the methods outlined  in IPCC
(2006). Though the model is more comprehensive than the
IPCC default methodology,  significant uncertainties still
exist with regard to the levels of equipment sales, equipment
characteristics, and end-use emissions profiles that were used
to estimate annual emissions for the various compounds.
    The Vintaging Model estimates emissions from over 50
end-uses. The uncertainty analysis, however, quantifies the
level of uncertainty associated with the aggregate emissions
resulting from  the top 19 end-uses,  comprising over 97
percent of the total emissions, and 5 other end-uses. In an
effort to improve the uncertainty analysis, additional end-
uses are added  annually, with the intention that over time
uncertainty for all emissions from the Vintaging Model will
be fully characterized. This year, two new end-uses were
included in the uncertainty estimate—polyurethane flexible
integral skin foam and residential unitary air conditioners.
Any end-uses included in previous years' uncertainty analysis
were included in the current uncertainty analysis, whether
or not those end-uses were included in the top 97 percent of
emissions  from ODS Substitutes.
    In order to calculate uncertainty, functional forms were
developed to simplify some of the complex "vintaging"
aspects of some end-use sectors, especially with respect to
refrigeration and air-conditioning, and to a lesser degree,
fire extinguishing. These sectors calculate emissions based
on the entire lifetime of equipment, not just equipment put
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Table 4-89: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitutes
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)a
  Uncertainty Range Relative to Emission Estimate"
    (Tg C02 Eq.)                     (%)
                                                      Lower Bound    Upper Bound   Lower Bound    Upper Bound
  Substitution of Ozone    MFCs and
   Depleting Substances     PFCs
              105.9
97.5
115.2
+ 9%
  a2007 Emission estimates and the uncertainty range presented in this table correspond to aerosols, foams, solvents, fire extinguishing agents, and
   refrigerants, but not for other remaining categories. Therefore, because the uncertainty associated with emissions from "other" ODS substitutes was not
   estimated, they were exclude in the estimates reported in this table.
  b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
into commission in the current year, thereby necessitating
simplifying equations. The functional forms used variables
that included growth rates, emission factors, transition from
ODSs, change in charge size as a result of the transition,
disposal quantities, disposal emission rates, and either
stock for the current year or original ODS consumption.
Uncertainty was estimated around each variable within the
functional forms based on expert judgment, and a Monte
Carlo analysis was performed. The most significant sources
of uncertainty for this source category include the emission
factors for mobile air-conditioning and refrigerated transport,
as well as the percent of non-MDI aerosol propellant that is
HFC-152a.
    The results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-89. Substitution of ozone
depleting substances HFC and PFC emissions were estimated
to be between 97.5 and 115.2 Tg CO2 Eq. at the 95 percent
confidence level. This indicates a range of approximately 8
percent below to 9 percent above the emission estimate of
105.9 Tg CO2 Eq.

Recalculations Discussion
    An extensive review of the chemical substitution
trends,  market sizes, growth rates,  and charge sizes,
together with input from industry representatives, resulted
in updated assumptions for the Vintaging Model. These
changes resulted in an average annual net decrease of 1.2
Tg CO2 Eq. (1.2 percent) in HFC and PFC emissions from
the substitution of ozone depleting substances for the period
1990 through 2007. The primary change was a revision in
the non-MDI aerosol sector, where a fraction of the market
formerly assumed to use HFC- 134a (with a GWP of 1,300)
was discovered to be transitioning more quickly to HFC-
152a (with a GWP of 140).
                               4.21.  Semiconductor  Manufacture
                               (IPCC Source Category 2F6)

                                   The semiconductor industry uses multiple long-lived
                               fluorinated gases in plasma etching and plasma enhanced
                               chemical vapor deposition (PECVD) processes to produce
                               semiconductor products. The gases most commonly employed
                               are trifluoromethane (HFC-23 or CHF3), perfluoromethane
                               (CF4), perfluoroethane (C2F6), nitrogen trifluoride (NF3),
                               and sulfur  hexafluoride (SF6), although other compounds
                               such as perfluoropropane (C3F8) and perfluorocyclobutane
                               (c-C4F8) are also used. The exact combination of compounds
                               is specific to the process employed.
                                   A single 300 mm silicon wafer that yields between
                               400 to 500 semiconductor products (devices or chips) may
                               require as many as 100 distinct fluorinated-gas-using process
                               steps,  principally to deposit and  pattern  dielectric films.
                               Plasma etching (or patterning) of dielectric films, such as
                               silicon dioxide and silicon nitride, is performed to provide
                               pathways for conducting material to connect individual
                               circuit components in  each device. The patterning process
                               uses plasma-generated fluorine atoms, which chemically
                               react with exposed dielectric film to selectively remove the
                               desired portions of the film. The material removed as well as
                               undissociated fluorinated gases flow into waste streams and,
                               unless emission abatement systems are employed, into the
                               atmosphere. PECVD chambers, used for depositing dielectric
                               films, are cleaned periodically using fluorinated and other
                               gases. During the cleaning cycle the  gas is converted to
                               fluorine atoms in plasma, which etches away residual material
                               from  chamber walls,  electrodes,  and  chamber hardware.
                               Undissociated fluorinated gases and other products pass from
                               the chamber to waste streams and, unless abatement systems
                                                                                    Industrial Processes  4-63

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are employed, into the atmosphere. In addition to emissions
of unreacted gases, some fluorinated compounds can also be
transformed in the plasma processes into different fluorinated
compounds which are then exhausted, unless abated, into the
atmosphere. For example, when C2F6 is used in cleaning or
etching, CF4 is generated and emitted as a process byproduct.
Besides dielectric film etching andPECVD chamber cleaning,
much smaller quantities of fluorinated gases are used to etch
polysilicon films and refractory metal films like  tungsten.

    For 2007, total  weighted emissions of all fluorinated
greenhouse gases by the U.S. semiconductor industry were
estimated to be 4.7 Tg CO2 Eq. Combined emissions of all
            fluorinated greenhouse gases are presented in Table 4-90
            and Table 4-91 below for years 1990, 1995, 2000 and the
            period 2005 to 2007. The rapid growth of this industry and
            the increasing complexity (growing number of layers)20 of
            semiconductor products led to an increase in emissions of
            150 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 35 percent between
            1999 and 2007. Together, industrial growth and adoption of
            emissions reduction technologies, including but not limited
            to  abatement technologies, resulted in a net  increase in
            emissions of 63 percent between 1990 and 2007.
Table 4-90: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg C02 Eq.)
  Gas
1990
1995
2000
2005
2006
2007
  CF4
  C2F6
  CsFs
  c-C4F8
  HFC-23
  SFB
                                           1.1
                                           2.0
                                           0.0
                                           0.1
                                           0.2
                                           1.0
                                           0.4
                                       1.2
                                       2.2
                                       0.0
                                       0.1
                                       0.3
                                       1.0
                                       0.7
                                    1.3
                                    2.3
                                    0.0
                                    0.1
                                    0.3
                                    0.8
                                    0.5
  Total
  2.9
 4.9
  6.2
 4.4
 4.7
 4.7
  aNF3 emissions are presented for informational purposes, using the AR4 GWP of 17,200, and are not included in totals.
  Note: Totals may not sum due to independent rounding.
Table 4-91: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)
  Gas
  CF4
  C2F6
  C^FS
  c-C4F8
  HFC-23
  SF6
  NF3
1990
1995
2000
2005
                                          168
                                          216
                                            5
                                           13
                                           18
                                           40
                                           26
2006
                                       181
                                       240
                                         5
                                        13
                                        22
                                        40
                                        40
2007
                                   195
                                   246
                                     6
                                     7
                                    22
                                    34
                                    30
                                                           20 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.
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Methodology
    Emissions are based on Partner reported emissions
data received through the EPA's PFC Reduction/Climate
Partnership and the EPA's PFC Emissions  Vintage Model
(PEVM), a model  which estimates industry emissions in
the absence of emission control strategies (Burton and
Beizaie 2001).21 The availability and applicability of Partner
data differs across the  1990  through 2007 time series.
Consequently, emissions from semiconductor manufacturing
were estimated using four distinct methods, one each for
the periods 1990 through 1994,  1995 through 1999, 2000
through 2006, and 2007.

1990 through 1994
    From 1990 through 1994, Partnership data was
unavailable and emissions were modeled using the PEVM
(Burton and Beizaie 2001).22 1990  to 1994 emissions are
assumed to be uncontrolled, since reduction strategies such as
chemical substitution and abatement were yet developed.
    PEVM is based on the recognition that PFC emissions
from semiconductor manufacturing vary with (1) the number
of layers  that comprise  different kinds of semiconductor
devices, including both silicon wafer and metal interconnect
layers, and (2)  silicon consumption (i.e., the  area of
semiconductors produced) for each kind  of device. The
product of these two quantities, Total Manufactured Layer
Area (TMLA), constitutes the activity data for semiconductor
manufacturing. PEVM also incorporates an emission factor
that expresses emissions per unit of layer-area. Emissions are
estimated by multiplying TMLA by  this emission factor.
    PEVM incorporates information on the two attributes
of semiconductor devices that affect the number of layers:
(1) linewidth  technology (the smallest manufactured
21A 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.
22 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 1995 and 1996 emissions factors, which were
derived from Partner reported data for those years.
feature size),23 and (2) product type (discrete, memory
or logic).24 For each linewidth technology, a weighted
average number of layers is estimated using VLSI product-
specific worldwide silicon demand data in conjunction with
complexity factors (i.e., the number of layers per Integrated
Circuit (1C)) specific to product type (Burton and Beizaie
2001, ITRS 2007). PEVM derives historical consumption
of silicon (i.e., square inches) by linewidth technology from
published data on annual wafer starts and average wafer
size (VLSI Research, Inc. 2007).
    The emission factor in PEVM  is the average of four
historical emission factors, each derived by dividing the total
annual emissions reported by the Partners for each of the four
years between 1996 and 1999 by the total TMLA estimated
for  the Partners in each of those years. Over this period,
the  emission factors varied relatively little (i.e., the relative
standard deviation for the average  was 5 percent).  Since
Partners are believed not to have applied significant emission
reduction measures before 2000,  the resulting average
emission factor reflects uncontrolled emissions. The emission
factor is used to estimate world uncontrolled emissions using
publicly available data on world silicon consumption.

1995 through 1999
    For  1995  through 1999, total U.S. emissions were
extrapolated from the total annual emissions reported by the
Partners (1995 through 1999). Partner-reported emissions are
considered more representative (e.g., in terms of capacity
utilization in a given year) than PEVM estimated emissions,
and are used to generate total U.S. emissions when applicable.
The emissions reported by the Partners were  divided by the
ratio of  the total  capacity of the plants operated by the
23 By decreasing features of 1C 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).
24 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.
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Partners and the total capacity of all of the semiconductor
plants in the United States; this ratio represents the share
of capacity attributable to the Partnership. This  method
assumes that  Partners and non-Partners have identical
capacity utilizations and  distributions of manufacturing
technologies. Plant capacity data is contained in the World
Fab Forecast (WFF) database and its predecessors, which is
updated quarterly (Semiconductor Equipment and Materials
Industry 2007).

2000 through 2006
    The emission  estimate for the years 2000 through
2006 —the period during which Partners began the
consequential application of PFC-reduction measures—was
estimated using a combination of Partner-reported emissions
and PEVM modeled emissions. The  emissions reported
by  Partners for each year were accepted as the quantity
emitted from the share of the industry represented by those
Partners. Remaining emissions, those from non-Partners,
were estimated using PEVM and the method described
above. This is because non-Partners are assumed not  to
have implemented any PFC-reduction measures, and PEVM
models emissions  without such  measures.  The  portion
of the U.S. total attributed to non-Partners is  obtained by
multiplying PEVM's  total U.S. emissions figure by the
non-Partner share of U. S. total silicon capacity for each
year  as described  above.25 26 Annual updates to PEVM
reflect published figures for actual silicon consumption from
VLSI Research, Inc., revisions and additions to the world
population of semiconductor manufacturing plants, and
changes in 1C fabrication practices within the semiconductor
25 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.
26 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.
industry (see, ITRS, 2007 and Semiconductor Equipment
and Materials Industry 2008).27<28<29

2007
    For the year 2007, emissions were also estimated using
a combination  of Partner reported emissions and PEVM
modeled emissions; however, two improvements were
made to the estimation method employed for the previous
years in the time series. First, the 2007 emission estimates
account for the fact that Partners and non-Partners employ
different distributions of manufacturing technologies, with
the Partners using manufacturing technologies with greater
transistor densities and therefore greater numbers of layers.
Had the method  used to  estimate the 2000 through 2006
emissions (described above) been employed, the emissions
estimated for 2007  would have been 1.5  percent higher
27 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 percentage points. 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 (FQSV) to determine the average design
capacity over the 2006 period.
28 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
not Partners. Special attention was given to this occurrence when estimating
the Partner and non-Partner shares of U. S. manufacturing capacity.
29Two 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.
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because the estimate of uncontrolled non-Partner emissions
would have been overstated by 2.5 percent.30
    Second, the scope of the  2007 estimate is expanded
relative to the estimates for the years 2000 through 2006 to
include emissions from Research and Development fabs.
This was feasible through the use of more detailed data
published in the World Fab Forecast. PEVM databases are
updated annually as described above. The published world
average capacity utilization for 2007 was used for production
fabs while for R&D fabs, a 20 percent figure was assumed.
Inclusion of R&D fabs increased the estimated emissions
by less than 1 percent.

Gas-Specific Emissions
    Two different approaches  were also used  to estimate
the distribution of emissions of specific fluorinated gases.
Before 1999, when there was no consequential adoption
of fluorinated-gas-reducing measures, a fixed distribution
of fluorinated-gas-use was assumed to apply to the entire
U.S. industry. This distribution was based upon  the average
fluorinated-gas purchases by semiconductor manufacturers
during this period and the application of IPCC default emission
factors for each gas (Burton andBeizaie 2001). For the 2000
through 2007 period, the 1990 through 1999 distribution was
assumed to apply to the  non-Partners. Partners, however,
began reporting gas-specific emissions during this period.
Thus, gas-specific emissions for 2000 through 2007 were
estimated by adding the emissions reported by the Partners
to those estimated for the non-Partners.

Data Sources
    Partners estimate their emissions using  a range of
methods. For 2007, it is assumed that most Partners
used a method at least as accurate as the IPCC's Tier 2a
Methodology,  recommended in the IPCC Guidelines for
National Greenhouse Inventories (2006). The Partners with
relatively high emissions use leading-edge manufacturing
technology, the newest process equipment. When purchased,
30 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.
this equipment is supplied with fluorinated-gas emission
factors, measured using industry standard guidelines
(International Sematech 2006). The larger emitting Partners
likely use these process-specific emission factors instead of
the somewhat less representative default emission factors
provided in the IPCC guidelines. Data used to develop
emission estimates are attributed in part to estimates provided
by the members of the Partnership, and in part from data
obtained from PEVM estimates. Estimates of operating
plant  capacities and characteristics for Partners and non-
Partners were  derived from the  Semiconductor Equipment
and Materials Industry (SEMI) World Fab Forecast (formerly
World Fab Watch) database (1996 through 2008). Estimates
of world average capacity utilizations for 2007 were obtained
from  Semiconductor International Capacity Statistics
(SICAS).  Estimates of silicon consumed by linewidth
from  1990 through 2007  were  derived from information
from VLSI Research (2008), and the number of layers per
linewidth was obtained  from International Technology
Roadmap for  Semiconductors:  2006 Update (Burton and
Beizaie 2001, ITRS 2007, ITRS 2008).

Uncertainty
    A quantitative uncertainty analysis  of this source
category was performed using the IPCC-recommended Tier
2 uncertainty  estimation methodology, the Monte Carlo
Stochastic Simulation technique. The equation  used to
estimate uncertainty is:
 U.S. emissions = ^Partnership gas-specific submittals +
         [(non-Partner share of world TMLA) x
        (PEVM emission factor x world TMLA)]
    The Monte Carlo analysis results presented below relied
on estimates of uncertainty attributed to the four quantities
on the right side of the equation. Estimates of uncertainty
for the four quantities were  in turn developed using the
estimated uncertainties associated with the individual inputs
to each quantity, error propagation analysis, Monte Carlo
simulation and expert judgment. The relative uncertainty
associated with World TMLA estimate  in 2007 is +9
percent, based on the uncertainty estimate obtained from
discussions with VLSI, Inc. For the share of World layer-
weighted silicon capacity accounted for by non-Partners,
a relative uncertainty of +8 percent was estimated based
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on a separate Monte Carlo simulation to account for the
random occurrence of missing data in the World Fab Watch
database. For the aggregate PFC emissions data supplied
to the partnership, a relative uncertainty of +50 percent
was estimated for each gas-specific PFC emissions value
reported by an individual  Partner,  and error propagation
techniques were used  to  estimate  uncertainty for total
Partnership gas-specific submittals.31 A relative error of
approximately 10 percent was estimated for the PEVM
emission factor, based on the standard deviation of the 1996
to 1999 emission factors.32 All estimates of uncertainties
are given at 95-percent confidence intervals.
    In developing estimates of uncertainty, consideration
was also given to the nature and magnitude of the potential
bias  that World activity data (i.e., World TMLA) might
have in its estimates of the number of layers associated with
devices  manufactured at each technology node. The result
of a brief analysis indicated that U.S. TMLA overstates the
average number of layers across all product categories and
all manufacturing technologies for 2004 by 0.12 layers or 2.9
percent. The same upward bias is assumed for World TMLA,
and is represented in the uncertainty analysis by deducting the
absolute bias value from the World activity estimate when it
is incorporated into the Monte Carlo analysis.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-92. The emissions estimate for
total U.S. PFC emissions from semiconductor manufacturing
were estimated to be between 4.7 and 5.7 Tg CO2 Eq. at a
95 percent confidence level. This range represents 9 percent
below to 9 percent above  the 2007 emission estimate of
                                5.2 Tg CO2 Eq. This range and the associated percentages
                                apply to the estimate of total emissions rather than those of
                                individual gases. Uncertainties associated with individual
                                gases will be somewhat higher than the aggregate, but were
                                not explicitly modeled.

                                Planned  Improvements
                                    With the exception of possible future updates to emission
                                factors, the method to estimate non-Partner related emissions
                                (i.e., PEVM) is not expected to change. Future improvements
                                to the national emission estimates will primarily be associated
                                with determining the portion of national emissions to attribute
                                to Partner report totals (about 80 percent in recent years)
                                and improvements  in estimates of non-Partner totals. As
                                the nature of the Partner reports change through time and
                                industry-wide reduction efforts increase, consideration will
                                be given to what emission reduction efforts—if any—are
                                likely to be occurring at non-Partner facilities. Currently,
                                none are assumed to occur.
                                    Another point of consideration for future national
                                emissions estimates is the inclusion of PFC emissions from
                                heat transfer fluid (HTF) loss to the atmosphere and the
                                production of photovoltaic cells (PVs). Heat transfer fluids,
                                of which some are liquid perfluorinated compounds, are used
                                during testing of semiconductor devices and, increasingly, are
                                used to manage heat during the manufacture of semiconductor
                                devices. Evaporation of these fluids is a source of emissions
                                (EPA 2006). PFCs are also used during manufacture of PV
                                cells that use silicon technology, specifically, crystalline,
                                polycrystalline and amorphous silicon technologies. PV
Table 4-92: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
Manufacture (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)a
Uncertainty Range Relative to Emission Estimate"
 (Tg C02 Eq.)                      (%)

Semiconductor
Manufacture

HFC, PFC,
and SF6

5.2
Lower Bound0
4.7
Upper Bound0
5.7
Lower Bound
-9%
Upper Bound
+ 9%
  'Because the uncertainty analysis covered all emissions (including NF3), the emission estimate presented here does not match that shown in Table 4-90.
  b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
  c Absolute lower and upper bounds were calculated using the corresponding lower and upper bounds in percentages.
31 Error propagation resulted in Partnership gas-specific uncertainties ranging
from 18 to 36 percent.
32The average of 1996 to 1999 emission factor is used to derive the PEVM
emission factor.
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manufacture is growing in the United States, and therefore
may be expected to constitute a growing share of U.S. PFC
emissions from the electronics sector.

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

    The largest use of SF6, both in the United States and
internationally, is as an electrical insulator and interrupter in
equipment that transmits and distributes electricity (RAND
2004). The gas has been employed by the electric power
industry in the United States since the 1950s because of its
dielectric strength and arc-quenching characteristics. It is
used in gas-insulated substations, circuit breakers, and other
switchgear. Sulfur hexafluoride has replaced flammable
insulating oils in many applications and allows for more
compact substations in dense urban areas.
    Fugitive emissions of SF6 can escape from gas-insulated
substations  and switchgear through seals, especially from
older equipment. The  gas can also be released during
equipment manufacturing, installation, servicing,  and
disposal.  Emissions of SF6  from equipment manufacturing
and from electrical transmission and distribution systems
were estimated to be 12.7 Tg CO2 Eq. (0.5 Gg) in 2007. This
quantity represents a 53  percent decrease from the estimate
for 1990 (see Table 4-93 and Table 4-94). This decrease is
Table 4-93: SF6 Emissions from Electric Power Systems
and Electrical Equipment Manufacturers (Tg C02 Eq.)
   Year
Electric Power
  Systems
Electrical Equipment
  Manufacturers     Total
   2005
   2006
   2007
    13.2
    12.4
    12.0
       0.8
       0.8
       0.7
14.0
13.2
12.7
                                            Table 4-94: SF6 Emissions from Electric Power Systems
                                            and Electrical Equipment Manufacturers (Gg)
                                                        Year
                                                               Emissions
                                                        1990
                                                                  1.1
                                                       2005
                                                       2006
                                                       2007
believed to have two causes: a sharp increase in the price
of SF6 during the 1990s and a growing awareness of the
environmental impact of SF6 emissions through programs
such as EPA's SF6 Emission Reduction Partnership for
Electric Power Systems.

Methodology
    The estimates of emissions from electric transmission
and distribution are comprised of emissions from electric
power systems  and emissions from the manufacture of
electrical equipment. The methodologies for estimating both
sets of emissions are described below.

1999 through 2007 Emissions from Electric Power Systems
    Emissions from electric power systems from  1999 to
2007 were estimated based on: (1) reporting from utilities
participating in EPA's SF6 Emission Reduction Partnership
for Electric Power Systems (partners),  which began in
1999, and  (2) the relationship  between emissions and
utilities' transmission miles as reported in the 2001, 2004
and 2007 Utility Data Institute (UDI) Directories of Electric
Power Producers and Distributors (UDI 2001, 2004, 2007).
(Transmission miles are defined as the miles of lines carrying
voltages above 34.5 kV.) Over the period from 1999 to 2007,
partner utilities, which for inventory purposes are defined as
utilities that either currently are or previously have been part
of the Partnership, represented between 42 percent and 47
percent of total U.S. transmission miles. For each year, the
emissions reported by or estimated for partner utilities were
                                                                                  Industrial Processes  4-69

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added to the emissions estimated for utilities that have never
participated in the Partnership (i.e., non-partners).33
    Partner utilities estimated their emissions using a Tier
3 utility-level mass balance approach (IPCC 2006). If a
partner utility did not provide data for a particular  year,
emissions were interpolated between years for which data
were available or extrapolated based on partner-specific
transmission mile growth rates. In  2007, non-reporting
partners accounted for approximately 8 percent of the total
emissions attributed to partner utilities.
    Emissions from non-partners in every year since  1999
were estimated using the results of a regression analysis
that showed that the emissions from reporting utilities were
most strongly correlated with their transmission miles. The
results of this analysis are not surprising given that, in the
United States, SF6 is  contained  primarily in  transmission
equipment rated at or above 34.5 kV. The equations  were
developed based on the 1999 SF6 emissions reported by 43
partner utilities (representing approximately 24 percent of
U.S. transmission miles), and 2000 transmission mileage
data obtained from the 2001UDI Directory of Electric Power
Producers  and Distributors (UDI 2001). Two equations
were developed, one for small and one for large utilities
(i.e., with fewer or more than 10,000 transmission miles,
respectively). The distinction between utility sizes was made
because the regression analysis showed that the relationship
between emissions and transmission miles differed for small
and large transmission networks. The same equations  were
used to estimate non-partner emissions in 1999 and every
year thereafter because non-partners  were assumed not to
have implemented any changes that would have resulted in
reduced emissions since 1999.
    The regression equations are:
Non-Partner small utilities (less  than 10,000  transmission
miles, in kilograms):
    Emissions (kg) = 0.89 x Transmission Miles
Non-Partner large utilities (more than 10,000  transmission
miles, in kilograms):
    Emissions (kg) = 0.58 x Transmission Miles
    Data on transmission miles for each non-partner utility
for the years 2000, 2003, and 2006 were obtained from the
2001, 2004, and 2007 UDI Directories of Electric Power
Producers and Distributors, respectively (UDI 2001, 2004,
2007). The U.S. transmission system grew by over 22,000
miles between 2000 and 2003 and by over 55,000 miles
between 2003 and 2006. These periodic increases are assumed
to have occurred gradually, therefore transmission mileage
was assumed to increase at an annual rate of 1.2 percent
between 2000 and 2003  and 2.8 percent between 2003 and
2006. Transmission miles in 2007 were then extrapolated
from 2006 based on the 2.8 percent growth rate.
    As a  final step, total  emissions were determined for
each year by summing the partner reported and estimated
emissions  (reported data was available through the EPA's SF6
Emission Reduction Partnership for Electric Power Systems),
and the non-partner emissions (determined using the 1999
regression equations).

1990 through 1998 Emissions from Electric Power Systems
    Because most participating utilities reported emissions
only for 1999 through 2007, modeling was used to estimate
SF6 emissions from electric power systems for the years 1990
through 1998. To perform this modeling, U.S. emissions were
assumed to follow the same trajectory as global34 emissions
from this source during the 1990 to 1999 period. To estimate
global emissions, the PsAND survey of global SF6 sales were
used,  together with the  following equation for estimating
emissions, which is derived from the mass-balance equation
for chemical emissions (Volume 3, Equation 7.3) in the
IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC 2006). (Although equation 7.3 of the IPCC Guidelines
appears in the discussion of substitutes for ozone depleting
substances, it is applicable to emissions from any long-lived
pressurized equipment that is periodically serviced during
its lifetime.)
33 Partners in EPA's SF6 Emission Reduction Partnership reduced their
emissions by approximately 54% from 1999 to 2007.
34Ideally sales to utilities in the U.S. between 1990 and 1999 would be
used as a model. However, this information was not available. There are
only two U.S. manufacturers of SF6, so sensitive sales information is not
concealed by aggregation.
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   Emissions (kilograms SF6) = SF6 purchased to refill
existing equipment (kilograms) + SF6 nameplate capacity35
            of retiring equipment (kilograms)
    Note that the above equation holds whether the gas
from retiring equipment is released or recaptured; if the
gas is recaptured, it is used to refill existing equipment,
thereby lowering the amount of SF6 purchased by utilities
for this purpose.
    Gas purchases by utilities and equipment manufacturers
from 1961 through 2003  are available from the RAND
(2004) survey. To estimate the quantity of SF6 released or
recovered from retiring equipment, the nameplate capacity
of retiring equipment in a given year was assumed to equal
81.2 percent of the amount of gas purchased by electrical
equipment manufacturers 40 years previous (e.g., in 2000,
the nameplate capacity of retiring equipment was assumed
to equal 81.2 percent of the gas  purchased in 1960). The
remaining 18.8 percent was assumed to have been emitted
at the time of manufacture. The 18.8 percent emission factor
is an average of IPCC default SF6  emission rates for Europe
and Japan for 1995 (IPCC  2006). The 40-year lifetime for
electrical equipment is  also based on IPCC (2006). The
results of the two components of the above equation were
then summed to yield estimates of global SF6 emissions from
1990 through 1999.
    U.S. emissions between 1990 and 1999 are assumed to
follow the same trajectory  as global emissions during this
period. To estimate U.S. emissions, global emissions for each
year from 1990 through 1998 were divided by the estimated
global emissions from 1999. The result was  a time series of
factors that express each year's global emissions as a multiple
of 1999 global emissions.  Historical U.S. emissions were
estimated by multiplying the factor for each respective year
by the estimated U.S. emissions of SF6 from electric power
systems in 1999 (estimated to be 15.1 Tg CO2 Eq.).
    Two factors may affect the relationship between the
RAND sales trends and actual global emission trends. One is
utilities' inventories of SF6 in storage containers. When SF6
prices rise, utilities are likely to deplete internal inventories
before purchasing new SF6 at the higher price, in which case
35 Nameplate capacity is defined as the amount of SF6 within fully charged
electrical equipment.
SF6 sales will fall more quickly than emissions. On the other
hand, when SF6 prices fall, utilities are likely to purchase
more SF6 to rebuild inventories, in which case sales will rise
more quickly than emissions. This effect was accounted for
by applying 3-year smoothing to utility SF6 sales data. The
other factor that may affect the relationship between the
PvAND sales trends and actual global emissions is the level
of imports from  and exports to Russia and China. Sulfur
hexafluoride production in these countries is not included
in the RAND survey and is not accounted for in any other
manner by RAND. However, atmospheric studies confirm
that the downward trend  in estimated global  emissions
between 1995 and 1998 was  real (see the Uncertainty
discussion below).

1990 through 2007 Emissions from Manufacture  of
Electrical Equipment
    The 1990 to 2007 emission estimates for original
equipment manufacturers (OEMs) were derived by assuming
that manufacturing emissions equal 10 percent of the quantity
of SF6 provided with new equipment. The quantity of SF6
provided with new equipment was estimated based on
statistics compiled by the National Electrical Manufacturers
Association (NEMA). These statistics were provided for 1990
to 2000; the quantities of SF6 provided with new  equipment
for 2001 to 2007 were estimated using partner-reported data
and the total industry SF6 nameplate capacity estimate (131.8
Tg CO2 Eq. in 2007). Specifically, the ratio of new nameplate
capacity to total nameplate capacity of a subset of partners
for which new nameplate capacity data was available from
1999 to 2007 was calculated. This ratio was then multiplied
by the total industry nameplate capacity estimate to derive
the amount of SF6 provided with new  equipment for the
entire industry. The 10 percent emission rate is the average
of the "ideal" and "realistic" manufacturing emission rates
(4 percent and 17 percent, respectively) identified in a paper
prepared under the auspices of the International Council
on Large Electric Systems (CIGRE) in February 2002
(O'Connelletal.  2002).

Uncertainty
    To estimate the uncertainty associated with emissions of
SF6 from electric transmission and distribution, uncertainties
associated with three quantities were estimated: (1) emissions
                                                                                    Industrial Processes  4-71

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from partners;  (2) emissions from non-partners; and
(3) emissions from manufacturers of electrical equipment.
A Monte Carlo analysis was then applied to estimate the
overall uncertainty of the emissions estimate.
    Total emissions from the SF6 Emission Reduction
Partnership include emissions from both reporting and non-
reporting partners. For reporting partners, individual partner-
reported SF6 data was assumed to have an uncertainty of 10
percent. Based on a Monte Carlo analysis, the cumulative
uncertainty of all partner reported data was estimated to be
3.6 percent. The uncertainty associated  with extrapolated
or interpolated emissions from non-reporting partners was
assumed to be 20 percent.
    There are two sources of uncertainty associated with
the regression equations used to estimate emissions in 2007
from non-partners: (1) uncertainty in the coefficients (as
defined by the regression standard error estimate), and (2) the
uncertainty in total transmission miles for non-partners. In
addition, there is uncertainty associated with the assumption
that the emission factor used for non-partner utilities (which
accounted for approximately 58 percent of U.S. transmission
miles in 2007) will remain at levels defined by partners who
reported in 1999. However, the last source of uncertainty
was not modeled.
    Uncertainties were also estimated regarding the quantity
of SF6 supplied with equipment by equipment manufacturers,
which is projected from partner provided nameplate capacity
data  and industry SF6 nameplate capacity estimates, and the
manufacturers' SF6 emissions rate.
    The results of the Tier 2 quantitative uncertainty analysis
are summarized in Table 4-95. Electrical Transmission and
Distribution SF6 emissions were estimated to be between 10.0
and 15.5 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range of approximately 21 percent below and 22
percent above the emission estimate of 12.7 Tg CO2 Eq.
                                    In addition to the uncertainty quantified above, there
                                is uncertainty associated with using global SF6 sales data
                                to estimate U.S. emission trends from 1990 through 1999.
                                However, the trend in global emissions implied by sales of
                                SF6 appears to reflect the trend in global emissions implied
                                by changing SF6  concentrations in the atmosphere. That
                                is, emissions based on global sales declined by 29 percent
                                between 1995 and  1998, and emissions based on atmospheric
                                measurements declined by 27 percent over the same period.
                                    Several pieces of evidence  indicate that U.S. SF6
                                emissions were reduced as global emissions were reduced.
                                First, the decreases in sales and emissions coincided with a
                                sharp increase in the price of SF6 that occurred in the mid-
                                1990s and that affected the United States as well as the rest of
                                the world. A representative from Dilo, a major manufacturer
                                of SF6 recycling equipment, stated that most U.S. utilities
                                began recycling rather than venting SF6 within two years of
                                the price rise. Finally, the emissions reported by the one U.S.
                                utility that  reported 1990 through 1999 emissions to EPA
                                showed a downward trend beginning in the mid-1990s.

                                Recalculations  Discussion
                                    Sulfur  hexafluoride emission estimates  for the period
                                1990 through 2006 were updated based on (1) new data from
                                EPA's SF6  Emission Reduction Partnership; (2) revisions
                                to interpolated and extrapolated non-reported partner data;
                                and (3) a revised  regression equation coefficient for non-
                                partner small  utilities  (fewer than 10,000 transmission
                                miles). The new  regression coefficient resulted from a
                                revised 1999 emission estimate from a Partner of EPA's SF6
                                Emission Reduction Partnership. This new emission estimate
                                changed the regression coefficient from 0.88 to 0.89. Based
                                on the revisions listed above, SF6 emissions from electric
                                transmission and distribution increased 1 percent or less for
                                each year from 1990 through 2006.
Table 4-95: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
  Uncertainty Range Relative to Emission Estimate3
    (Tg C02 Eq.)                      (%)
                                                       Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Electrical Transmission
   and Distribution          SFfi
               12.7
10.0
15.5
-21%
+22%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4-72   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Box 4-1: Potential Emission Estimates of MFCs, PFCs, and SF6

      Emissions of MFCs, PFCs and SF6 from industrial processes can be estimated in two ways, either as potential emissions or as actual
  emissions. Emission estimates in this chapter are "actual emissions," which are defined by the Revised 1996IPCC Guidelines for National
  Greenhouse Gas  Inventories (IPCC/UNEP/OECD/IEA 1997) as estimates that take into account the time lag between consumption and
  emissions. In contrast, "potential emissions" are defined to be equal to the amount of a chemical consumed in a country, minus the amount
  of a chemical recovered for destruction or export in the year of consideration. Potential emissions will generally be greater for a given year
  than actual emissions, since some amount of chemical consumed will be stored in products or equipment and will not be emitted to the
  atmosphere until a later date, if ever. Although actual emissions are considered to be the more accurate estimation approach for a single
  year, estimates of potential emissions are provided for informational purposes.
      Separate estimates of potential emissions were not made for industrial processes that fall into the following categories:
      • Byproduct emissions. Some emissions do not result from the consumption or use of a chemical, but are the unintended byproducts
        of another process. For such emissions, which include  emissions of CF4 and C2F6 from aluminum production and of HFC-23 from
        HCFC-22 production, the distinction between potential and actual emissions is not relevant.
      • Potential emissions that equal actual emissions. For some sources,  such  as magnesium production  and processing, no delay
        between consumption and emission is assumed and, consequently, no destruction of the chemical takes place. In this case, actual
        emissions equal potential emissions.
      Table 4-96 presents potential emission estimates for MFCs and PFCs from the substitution of ozone depleting substances, MFCs, PFCs,
  and SF6 from semiconductor manufacture, and SF6 from magnesium production and processing and electrical transmission and distribution.36
  Potential emissions associated with the  substitution for ozone depleting substances were  calculated using the EPA's Vintaging Model.
  Estimates of MFCs, PFCs, and SF6 consumed by semiconductor manufacture were developed by dividing chemical-by-chemical emissions
  by the appropriate chemical-specific emission factors from the IPCC Good Practice Guidance  (Tier 2c). Estimates of CF4 consumption were
  adjusted to account for the conversion of other chemicals into CF4 during the semiconductor manufacturing process, again using the default
  factors from the IPCC Good Practice Guidance. Potential SF6 emissions estimates for electrical transmission and distribution were developed
  using U.S. utility purchases of SF6 for electrical equipment. From 1999  through 2007, estimates were obtained from reports submitted by
  participants in EPA's SF6 Emission Reduction Partnership for Electric Power Systems. U.S. utility purchases of SF6 for electrical equipment
  from 1990 through 1998 were backcasted based on world sales of SF6 to utilities. Purchases of SF6 by utilities were added to SF6 purchases
  by electrical equipment manufacturers to obtain total SF6 purchases by the electrical equipment sector.

                      Table 4-96:2007 Potential and Actual Emissions of MFCs, PFCs, and SF6
                      from Selected Sources (Tg C02 Eq.)
Source
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Magnesium Production and Processing
Electrical Transmission and Distribution
Potential
185.5
-
-
7.6
3.0
20.9
Actual
108.3
3.8
17.0
4.7
3.0
12.7
-Not applicable.
  36 See Annex 5 for a discussion of sources of SF6 emissions excluded from the actual emissions estimates in this report.
                                                                                                Industrial Processes   4-73

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4.23.  Industrial Sources  of Indirect
Greenhouse Gases
    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 2007 are reported in Table 4-97.

Methodology
    These emission estimates were obtained from preliminary
data (EPA 2008), 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
                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.
Table 4-97: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
  Gas/Source
1990
1995
2000
2005
2006
2007
  NOX                                          591           607          626           534       527      520
    Other Industrial Processes                       3431        3621        435           389       382      375
    Chemical & Allied Product Manufacturing           1521        14sl         951          64        64        64
    Metals Processing                              881         891         811          63        63        63
    Storage and Transport                            3             5           14            17        17        17

  CO                                         4,125         3,959         2,216         1,744     1,743     1,743
    Metals Processing                           2,395         2,159         1,175           895       895      894
    Other Industrial Processes                       4871        5661        5371         445       444      444
    Chemical & Allied Product Manufacturing         1,073         1,110          3271         258       258      258
    Storage and Transport                           691         231        1531         107       107      107
    Miscellaneous3                                101           1021         231          39        40        40
  NMVOCs                                    2,422         2,642         1,773          2035      1950      1878
    Storage and Transport                        1,352         1,499         1,067          1346      1280      1228
    Other Industrial Processes                       3641        408          4121         401       388      376
    Chemical & Allied Product Manufacturing           5751        5991        2301         226       221      216
    Metals Processing                             111           1131         611          42        42        42
    Miscellaneous3                                 201         231          3            20        19        17
  'Miscellaneous includes the following categories: catastrophic/accidental release, other combustion
   It does not include agricultural fires or slash/prescribed burning, which are accounted for under the
  Note: Totals may not sum due to independent rounding.
                          , health services, cooling towers, and fugitive dust.
                          Field Burning of Agricultural Residues source.
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5.   Solvent  and  Other  Product  Use

         Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United
         States, emissions from Nitrous Oxide (N2O) Product Usage, the only source of greenhouse gas emissions from
         this sector, accounted for less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a carbon
equivalent basis in 2007 (see Table 5-1). Indirect greenhouse gas emissions also result from solvent and other product use,
and are presented in Table 5-5 in gigagrams (Gg).

Table 5-1: N20 Emissions from Solvent and Other Product Use (Tg C02 Eq. and Gg)
Gas/Source
N20 from Product Uses
Tg C02 Eq.
eg
1990
4.4l
u|
1995
4.6 1
15
2000
4.9 1
ie|
2005
4.4
14
2006
4.4
14
2007
4.4
14
5.1.  Nitrous Oxide from Product Uses (IPCC Source Category 3D)

    N2O is a clear, colorless, oxidizing liquefied gas, with a slightly sweet odor. Two companies operate a total of five N2O
production facilities in the United States (Airgas 2007; FTC 2001). N2O is primarily used in carrier gases with oxygen to
administer more potent inhalation anesthetics for general anesthesia and as an anesthetic in various dental and veterinary
applications. As such, it is used to treat short-term pain, for sedation in minor elective surgeries, and as an induction
anesthetic. The second main use of N2O is as a propellant in pressure and aerosol products, the largest application being
pressure-packaged whipped cream. Small quantities of N2O also are used in the following applications:
•   Oxidizing agent and etchant used in semiconductor manufacturing;
•   Oxidizing agent used, with acetylene, in atomic absorption spectrometry;
•   Production of sodium azide, which  is used to inflate airbags;
•   Fuel oxidant in auto racing; and
•   Oxidizing agent in blowtorches used by jewelers and others (Heydorn 1997).
    Production of N2O in 2007 was approximately 15 Gg (Table 5-2). N2O emissions were 4.4 Tg CO2 Eq. (14 Gg) in
2007 (Table 5-3). Production of N2O stabilized during the 1990s because medical markets had found other substitutes for
anesthetics, and more medical procedures were being performed on an outpatient basis using local anesthetics that do not
require N2O. The use of N2O as a propellant for whipped cream has also stabilized due to the increased popularity of cream
products packaged in reusable plastic tubs (Heydorn 1997).
                                                                  Solvent and Other Product Use 5-1

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Table 5-2: N20 Production (Gg)
            Year
               Gg
            2005
            2006
            2007
Table 5-3: N20 Emissions from N20 Product Usage
(Tg C02 Eq. and Gg)
        Year
Tg C02 Eq.
Gg
Methodology
    Emissions from N2O product usage were calculated
by first multiplying the total amount of N2O produced in
the United States by the share of the total quantity of N2O
attributed to each end use. This value was then multiplied
by the associated emission rate for each end use. After
the emissions were calculated for each end use, they were
added together to obtain a total estimate of N2O product
usage emissions. Emissions were  determined using  the
following equation:

            N2O Product Usage Emissions =
          2, [Total U.S. Production of N2O] x
   [Share of Total Quantity of N2O Usage by Sector i] x
             [Emissions Rate for Sector i],
where,
    i = sector.
    The share of total quantity of N2O usage by end  use
represents the share of national N2O produced that is used
by the specific subcategory (i.e., anesthesia, food processing,
etc.). In 2007, the medical/dental industry used an estimated
89.5 percent of total N2O produced, followed by food
processing propellants at 6.5 percent. All other categories
combined used the remainder of the N2O produced. This
subcategory breakdown has changed only slightly over the
past decade. For instance, the small share of N2O usage in
the production of sodium azide has declined significantly
during the decade of the 1990s. Due to the lack of information
on the specific time period of the phase-out in this market
subcategory, most of the N2O usage for sodium azide
production is assumed to have ceased after 1996, with the
majority of its small share of the market assigned to the larger
medical/dental consumption subcategory (Heydorn 1997).
The N2O was allocated across the following  categories:
medical applications, food processing propellant, and sodium
azide production (pre-1996). A usage emissions rate was
then applied for each  sector to estimate the amount of N2O
emitted.
    Only the medical/dental and food propellant subcategories
were estimated to release emissions into the atmosphere,
and therefore these  subcategories were the only usage
subcategories with emission rates. For the medical/dental
subcategory, due to the poor solubility of N2O in blood and
other tissues, none of the N2O is assumed to be metabolized
during anesthesia and quickly leaves  the body in exhaled
breath. Therefore, an emission factor of  100 percent was
used for this subcategory (IPCC 2006). For N2O used as a
propellant in pressurized and aerosol  food products, none
of the N2O is reacted  during the process and all of the N2O
is emitted to the atmosphere, resulting in an emission factor
of 100 percent for this subcategory (IPCC 2006). For the
remaining subcategories, all of the N2O is consumed/reacted
during the process, and therefore the emission rate was
considered to be zero  percent (Tupman 2002).
    The  1990 through 1992 N2O production data were
obtained from SRI Consulting's Nitrous Oxide, North
America report (Heydorn 1997).  N2O production data for
1993 through 1995 were not available. Production data for
1996 was specified as a range in two data sources (Heydorn
1997, Tupman 2002). In particular, for 1996, Heydorn (1997)
estimates N2O production to range between 13.6 and 18.1
thousand metric tons. Tupman (2003)  provided a narrower
range (i.e., 15.9 to 18.1 thousand metric tons) for 1996 that
falls within the production bounds described by Heydorn
5-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 5-4: Tier 2 Quantitative Uncertainty Estimates for N20 Emissions From N20 Product Usage
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
                   Uncertainty Range Relative to Emission Estimate3
                    (Tg C02 Eq.)                     (%)
                                                     Lower Bound    Upper Bound   Lower Bound    Upper Bound
  N20 Product Usage
N,0
4.4
4.3
4.5
-2%
+ 2%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
(1997). Tupman (2003) data are considered more industry-
specific and current. Therefore, the midpoint of the narrower
production range was used to estimate N2O emissions for
years 1993 through 2001 (Tupman 2003). The 2002 and 2003
N2O production data were obtained from the Compressed
Gas Association Nitrous Oxide Fact Sheet and Nitrous
Oxide Abuse Hotline (CGA 2002, 2003). These data were
also provided as a range. For example, in 2003, CGA (2003)
estimates N2O production to range between 13.6 and 15.9
thousand metric tons. Due to unavailable data, production for
2004, 2005, 2006, and 2007 were held at the 2003 value.
    The 1996 share of the total quantity of N2O used by
each subcategory was obtained from SRI Consul ting's
Nitrous Oxide, North America report (Heydorn 1997). The
1990 through  1995 share of total quantity of N2O used by
each subcategory was kept the  same as the 1996 number
provided by SRI Consulting. The 1997 through 2001 share
of total quantity of N2O usage by sector was obtained from
communication with a N2O industry expert (Tupman 2002).
The 2002 and 2003 share of total  quantity of N2O  usage
by sector was obtained from CGA (2002, 2003). Due to
unavailable data, the share  of total quantity of N2O usage
data for 2004, 2005, 2006, and 2007 was  assumed to equal
the 2003 value. The emissions rate for the food processing
propellant industry was  obtained from SRI Consul ting's
Nitrous Oxide, North America report (Heydorn 1997),  and
confirmed by a N2O industry expert (Tupman 2002). The
emissions rate for all other subcategories was obtained from
communication with a N2O industry expert (Tupman 2002).
The emissions rate for the medical/dental subcategory was
obtained from the 2006IPCC Guidelines.

Uncertainty
    The overall uncertainty associated with the 2007 N2O
emission estimate from N2O product usage was calculated
using the IPCC Guidelines for National Greenhouse
                               Gas Inventories (2006) Tier 2 methodology. Uncertainty
                               associated with the parameters used to estimate N2O
                               emissions included that of production data, total market
                               share of each end use, and the emission factors applied to
                               each end use, respectively.
                                   The results of this Tier 2 quantitative uncertainty
                               analysis are summarized in Table 5-4. N2O emissions from
                               N2O product usage were estimated to be between 4.3 and 4.5
                               Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
                               of 20 Monte Carlo Stochastic Simulations). This indicates a
                               range of approximately 2 percent below to 2 percent above
                               the 2007 emissions estimate of 4.4 Tg CO2 Eq.

                               Planned Improvements
                                   Planned improvements include a continued evaluation
                               of alternative production statistics for cross verification and
                               a reassessment of subcategory usage to accurately represent
                               the latest trends in the product usage, and investigation
                               of production and use cycles and the  potential need to
                               incorporate a time lag between production and ultimate
                               product use and resulting release of N2O. Additionally,
                               planned improvements include considering imports and
                               exports of N2O for product uses.

                               5.2.   Indirect Greenhouse  Gas
                               Emissions from  Solvent Use

                                   The use of solvents and other  chemical products
                               can result in emissions of various  ozone precursors
                               (i.e., indirect greenhouse gases).1 Non-methane volatile
                               organic compounds (NMVOCs),  commonly referred to
                               as "hydrocarbons," are the primary gases emitted from
                               1 Solvent usage in the United States also results in the emission of small
                               amounts of hydrofluorocarbons (HFCs) and hydrofluoroethers (HFEs),
                               which are included under Substitution of Ozone Depleting Substances in
                               the Industrial Processes chapter.
                                                                         Solvent and Other Product Use  5-3

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most processes employing organic or petroleum based
solvents. As  some industrial applications also employ
thermal incineration as a control technology, combustion
byproducts, 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 2007 are reported in Table 5-5.
Table 5-5: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
  Activity
 1990
 1995
 2000
 2005
 2006
 2007
  NO,
    Surface Coating
    Graphic Arts
    Degreasing
    Dry Cleaning
    Other Industrial Processes3
    Non-Industrial Processes"
    Other
  CO
    Surface Coating
    Other Industrial Processes3
    Dry Cleaning
    Degreasing
    Graphic Arts
    Non-Industrial Processes"
    Other
  NMVOCs
    Surface Coating
    Non-Industrial Processes"
    Degreasing
    Dry Cleaning
    Graphic Arts
    Other Industrial Processes3
    Other
   j
  NA
   j

  NA
5,216
2,289
1,724
  675
  195
  249
  85
    3










   I

  NA
5,609
2,432
1,858
  716
  209
  307
  87
    3


  I

  I
4,384
1,766
1,676
  316
  265
  222
   98
   40
3,881
1,590
1,457
  283
  232
  195
   88
   36
3,867
1,584
1,452
  282
  231
  194
   88
   36
3,855
1,579
1,447
  281
  230
  194
   88
   36
  + Does not exceed 0.5 Gg.
  '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.
5-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Methodology
    Emissions were calculated by aggregating solvent use
data based on information relating to solvent uses from
different applications such as degreasing, graphic arts, etc.
Emission factors for each consumption category were then
applied to the data to estimate emissions. For example,
emissions from surface coatings were mostly due to solvent
evaporation as  the coatings solidify. By applying the
appropriate solvent-specific emission factors to the amount of
solvents used for surface coatings, an estimate of emissions
was obtained. Emissions of CO and NOX result primarily
from thermal and catalytic incineration of solvent-laden
gas streams from painting booths, printing operations, and
oven exhaust.
    These emission estimates were obtained from preliminary
data (EPA 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 solvent purchased) as an
indicator of emissions. National activity data were collected
for individual applications from various agencies.
    Activity data were used in conjunction with emission
factors, which together relate the quantity of emissions to the
activity. Emission factors are generally available from the
EPA's Compilation of Air Pollutant Emission Factors, AP-42
(EPA 1997). The EPA currently derives the overall emission
control efficiency of a source category from a  variety of
information sources, including published reports, the 1985
National Acid Precipitation and Assessment Program
emissions inventory, and other EPA databases.

Uncertainty
    Uncertainties in these estimates are partly due to the
accuracy of the emission factors used and the reliability of
correlations between activity data and actual emissions.
                                                                            Solvent and Other Product Use  5-5

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6.   Agriculture
                                                        Figure 6-1
                                                                2007 Agriculture Chapter Greenhouse Gas
                                                                           Emission Sources
                                                                                                      207.9
          Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes.
          This chapter provides an assessment of non-carbon-dioxide emissions from the following source categories:
          enteric fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil
management, and field burning of agricultural residues (see Figure 6-1). Carbon dioxide (CO2) emissions and removals from
agriculture-related land-use activities, such as conversion of
grassland to cultivated land, are presented in the Land Use,
Land-Use Change, and Forestry chapter.  Carbon dioxide
emissions from on-farm energy use are accounted for in the
Energy chapter.

    In 2007, the Agricultural  sector was responsible for
emissions of 413.1 teragrams of CO2 equivalents (Tg CO2
Eq.), or 6 percent of total U.S. greenhouse gas emissions.
Methane (CFL,) and nitrous  oxide (N2O) were the primary
greenhouse gases emitted by agricultural activities. Methane
emissions from enteric fermentation and manure management
represent about 24 percent and 8 percent of total CH4
emissions from anthropogenic activities, respectively. Of all
domestic animal types, beef and dairy cattle were by far the
largest emitters of CK4. Rice cultivation and field burning of
agricultural residues were minor sources of CH4. Agricultural
                                                           Agricultural Soil Management

                                                                Enteric Fermentation

                                                                Manure Management

                                                                    Rice Cultivation

                                                                    Field Burning of
                                                                Agricultural Residues
                                     Agriculture
                                    as a Portion of
                                    all Emissions
                                                                                      50
                                                                                             100
                                                                                         Tg CO, Eq.
                                                                                                     150
Table 6-1: Emissions from Agriculture (Tg C02 Eq.)
  Gas/Source
                                             1990
1995
2000
2005
2006
2007
  CH4
    Enteric Fermentation
    Manure Management
    Rice Cultivation
    Field Burning of Agricultural Residues
  N20
    Agricultural Soil Management
    Manure Management
    Field Burning of Agricultural Residues
  Total
                                                         402.0
            399.4
                                                                                   185.5
                                                                                   136.0
                                                                                    41.8
                                                                                     6.8
                                                                                     0.9
                                                                                   225.5
                                                                                   210.6
                                                                                    14.2
                                                                                     0.5
             410.8
                                   186.8
                                   138.2
                                    41.9
                                     5.9
                                     0.8
                                   223.5
                                   208.4
                                    14.6
                                     0.5
         410.3
                                190.0
                                139.0
                                 44.0
                                  6.2
                                  0.9
                                223.1
                                207.9
                                 14.7
                                  0.5
         413.1
  Note: Totals may not sum due to independent rounding.
                                                                                             Agriculture  6-1

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Table 6-2: Emissions from Agriculture (Gg)
  Gas/Source
1990
1995
2000
2005
2006
2007
  CH4
    Enteric Fermentation
    Manure Management
    Rice Cultivation
    Field Burning of Agricultural Residues
  N20
    Agricultural Soil Management
    Manure Management
    Field Burning of Agricultural Residues
                                      8,833
                                      6,474
                                      1,991
                                        326
                                         41
                                        727
                                        679
                                         46
                                          2
                                   8,894
                                   6,580
                                   1,993
                                    282
                                     39
                                    721
                                    672
                                     47
                                      2
                                9,047
                                6,618
                                2,093
                                 293
                                  42
                                 720
                                 671
                                  47
                                   2
  Note: Totals may not sum due to independent rounding.
soil management activities such as fertilizer application and
other cropping practices were the largest source of U. S. N2O
emissions, accounting for 67 percent. Manure management
and field burning of agricultural residues were also small
sources of N2O emissions.
    Table 6-1 and Table 6-2  present emission estimates
for the Agriculture sector. Between 1990 and 2007, CH4
emissions from agricultural activities increased by 11 percent,
while N2O emissions fluctuated from year to year, but overall
increased by 5 percent.

6.1.  Enteric  Fermentation (IPCC
Source Category 4A)

    Methane is produced as part of normal digestive
processes in animals. During digestion, microbes resident
in an animal's digestive system ferment food consumed by
the animal. This microbial fermentation process, referred to
as enteric fermentation, produces CK4 as a byproduct, which
can be exhaled or eructated by the animal. The amount of
CtLj produced and emitted by an individual animal depends
primarily upon the animal's digestive system, and the amount
and type of feed it consumes.
    Ruminant animals (e.g., cattle, buffalo, sheep, goats, and
camels) are the major emitters of CK4 because of their unique
digestive system. Ruminants possess a rumen, or large "fore-
stomach," in which microbial fermentation breaks down the
feed they consume into products that can be absorbed and
metabolized. The microbial fermentation that occurs in the
rumen enables them to digest coarse plant material that non-
ruminant animals cannot. Ruminant animals, consequently,
have the highest CH4 emissions among all animal types.
               Non-ruminant animals (e.g., swine, horses, and mules)
           also produce CH4 emissions through enteric fermentation,
           although this microbial fermentation occurs  in the large
           intestine. These non-ruminants emit significantly less CH4
           on a per-animal basis than ruminants because  the capacity
           of the large intestine to produce CH4 is lower.
               In addition to the type of digestive system, an animal's
           feed quality and feed intake also affects CH4 emissions. In
           general, lower feed quality and/or higher feed intake leads
           to higher CH4 emissions. Feed intake is positively correlated
           to animal size, growth rate, and production (e.g., milk
           production, wool growth, pregnancy, or work). Therefore,
           feed intake varies among animal types as well as among
           different management practices for individual animal types
           (e.g., animals in feedlots or grazing on pasture).
               Methane emission estimates from enteric fermentation
           are provided in Table 6-3 and Table 6-4. Total livestock
           CH4 emissions in 2007 were 139.0 Tg CO2 Eq. (6,618 Gg).
           Beef cattle remain the largest contributor of CH4 emissions
           from enteric fermentation, accounting for 72 percent in
           2007.  Emissions from dairy cattle in 2007 accounted for
           23 percent, and the remaining emissions were from horses,
           sheep, swine, and goats.
               From 1990 to 2007, emissions from enteric fermentation
           have  increased by 4.3  percent.  Generally, emissions
           decreased from 1995 to 2004, though with slight increases
           in 2002 and 2003. This trend was mainly due to decreasing
           populations of both beef and dairy cattle and  increased
           digestibility of feed for feedlot cattle. Emissions have
           increased from 2004 through 2007, as both dairy and
           beef populations  have undergone increases. During  the
           timeframe  of  this analysis, populations of  sheep have
6-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 6-3: CH4 Emissions from Enteric Fermentation (Tg C02 Eq.)
                                                           1995
Livestock Type
1990
              2005
          2006
          2007
  Beef Cattle
  Dairy Cattle
  Horses
  Sheep
  Swine
  Goats
                                             94.6
                                             32.8
                                              1.9
                                              1.9
                                              1.7
                                              0.3
             106.7

  Total
                                            133.2
             143.6
             136.0
                       100.0
                        31.4
                         3.5
                         1.0
                         1.9
                         0.3
         138.2
                   100.2
                    31.9
                     3.5
                     1.0
                     2.0
                     0.3
         139.0
  Note: Totals may not sum due to independent rounding.
Table 6-4: CH4 Emissions from Enteric Fermentation (Gg)
  Livestock Type
                                            1990
             1995
2000
2005
2006
2007
  Beef Cattle
  Dairy Cattle
  Horses
  Sheep
  Swine
  Goats
  Total
                                                                                              4,762
                                                                                              1,497
                                                                                               166
                                                                                                50
                                                                                                93
                                                                                                13
                                                                                    6,474      6,580
                                                            4,772
                                                            1,521
                                                             166
                                                              49
                                                              98
                                                              13
                                                            6,618
  Note: Totals may not sum due to independent rounding.
decreased 46 percent since  1990 while horse populations
have increased over 80 percent, mostly since 1999. Goat and
swine populations have increased 1 percent and 21 percent,
respectively, during this timeframe.

Methodology
    Livestock emission estimate methodologies fall into two
categories: cattle and other domesticated animals. Cattle, due
to their large population, large size, and particular digestive
characteristics, account for the majority of CH4 emissions
from livestock  in the United  States. A more detailed
methodology (i.e., IPCC Tier 2) was therefore applied to
estimate emissions for all cattle except for bulls. Emission
estimates for other domesticated animals (horses,  sheep,
swine, goats, and bulls) were handled using a less detailed
approach (i.e., IPCC Tier 1).
    While the large diversity of animal management practices
cannot be precisely characterized and evaluated, significant
scientific literature exists that provides the necessary data to
estimate cattle emissions using the IPCC Tier 2 approach.
The Cattle Enteric Fermentation Model (CEFM), developed
by EPA and used to  estimate cattle CH4 emissions from
                                                        enteric fermentation, incorporates this information and other
                                                        analyses of livestock population, feeding practices, and
                                                        production characteristics.
                                                            National cattle population statistics were disaggregated
                                                        into the following cattle sub-populations:
                                                        •    Dairy Cattle
                                                            •   Calves
                                                            •   Heifer Replacements
                                                            •   Cows
                                                        •    Beef Cattle
                                                            •   Calves
                                                            •   Heifer Replacements
                                                            •   Heifer and Steer Stackers
                                                            •   Animals in Feedlots (Heifers and Steers)
                                                            •   Cows
                                                            •   Bulls
                                                            Calf birth rates, end of year population statistics, detailed
                                                        feedlot placement information, and  slaughter weight data
                                                        were used to create a transition matrix that models cohorts of
                                                                                                Agriculture  6-3

-------
individual animal types and their specific emission profiles.
The key variables tracked for each of the cattle population
categories are described in Annex 3.9. These variables
include performance factors such as pregnancy and lactation
as well as average weights  and weight gain. Annual cattle
population data were obtained from the U.S. Department
of Agriculture's (USDA) National Agricultural Statistics
Service Quick Stats database (USDA 2008).
    Diet characteristics were estimated by region for U.S.
dairy, beef, and feedlot cattle. These estimates were used to
calculate Digestible Energy (DE)  values (expressed as the
percent of gross energy intake digested by the animal) and
CELj conversion rates (Ym) (expressed as the fraction of gross
energy converted to CK4) for each population category. The
IPCC recommends Ym values of 3.0+1.0 percent for feedlot
cattle and 6.5+1.0 percent for other well-fed cattle consuming
temperate-climate feed  types (IPCC 2006). Given the
availability of detailed diet information for different regions
and animal types in the United States, DE and Ym values
unique to the United States were developed, rather than using
the recommended IPCC values. The diet characterizations
and estimation of DE  and Ym  values were based  on
information from state agricultural extension specialists, a
review of published forage  quality studies, expert opinion,
and modeling of animal physiology. The diet characteristics
for dairy cattle were from Donovan (1999), while those for
beef cattle were derived from NRC (2000). DE and Ym for
dairy  cows were calculated from diet characteristics using
a model simulating ruminant digestion in growing and/or
lactating cattle (Donovan and Baldwin 1999). Values from
EPA (1993) were used for  dairy replacement heifers. For
feedlot animals, DE and Ym values recommended by Johnson
(1999) were used. For grazing beef cattle, DE values were
based on diet information in NRC (2000) and Ym values were
based on Johnson (2002).  Weight and weight gains for cattle
were estimated from Enns  (2008), Patton et al. (2008), Lippke
et al.  (2000), Pinchack et al., (2004), Platter et al. (2003),
Skogerboe et al. (2000), and expert opinion. See Annex 3.9
for more details on the method used to characterize cattle
diets and weights in the United States.
    To estimate CH4 emissions from all cattle types except
bulls and calves younger than 7 months,1 the population
was divided into state, age, sub-type (i.e., dairy cows and
replacements, beef cows and replacements, heifer and steer
stackers, and heifer and steer in feedlots), and production
(i.e., pregnant,  lactating) groupings to more fully capture
differences in CH4 emissions from these animal types. The
transition matrix was used to simulate the age and weight
structure of each sub-type on a monthly basis, to more
accurately reflect the fluctuations that occur throughout the
year. Cattle diet characteristics were then used in conjunction
with Tier 2 equations from IPCC (2006) to  produce CFLj
emission factors for the following cattle  types: dairy
cows, beef cows, dairy replacements, beef replacements,
steer stackers,  heifer stackers, steer feedlot animals, and
heifer feedlot animals. To estimate  emissions from cattle,
population data from the transition matrix were multiplied
by the calculated emission factor for each cattle type. More
details are provided in Annex 3.9.
    Emission estimates for other animal types were based on
average emission factors representative of entire populations
of each animal type. Methane emissions from these animals
accounted for a minor portion of total CH4 emissions  from
livestock in the United States from 1990 through 2007. Also,
the variability in emission factors for each of these other
animal types (e.g., variability by age, production system, and
feeding practice within each animal type) is  less than that
for cattle. Annual livestock population data for these other
livestock types, except horses and goats, as well as feedlot
placement information were obtained for all years  from
the U.S. Department  of Agriculture's National Agricultural
Statistics Service (USDA 2008). Horse population data were
obtained from the FAOSTAT database (FAO 2008), because
USDA does not estimate U.S. horse populations annually.
Goat population data were obtained for 1992,1997, and 2002
(USDA 2008); these data were interpolated and extrapolated
to derive estimates for the other years. Methane emissions
1 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  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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from sheep, goats, swine, and horses were estimated by
using emission factors utilized in Crutzen et al. (1986, cited
in IPCC 2006). These emission factors are representative of
typical animal sizes, feed intakes, and feed characteristics
in developed countries. The methodology is the same as that
recommended by IPCC (2006).
    See Annex 3.9 for more detailed information on the
methodology and data used to calculate CH4 emissions from
enteric fermentation.

Uncertainty
    Quantitative  uncertainty analysis for this  source
category was performed  through the IPCC-recommended
Tier 2  uncertainty estimation methodology, Monte Carlo
Stochastic Simulation technique as described in ICF (2003).
These uncertainty  estimates were developed for the  1990
through 2001 Inventory report. No significant changes
occurred in the method of data collection, data estimation
methodology, or  other factors that influence the uncertainty
ranges  around the 2007 activity data and emission factor
input variables used in the current submission. Consequently,
these uncertainty estimates were directly applied to the 2007
emission estimates.
    A total of 185 primary input variables (177 for cattle
and 8 for non-cattle) were identified as key input variables
for the uncertainty analysis. A normal distribution was
assumed for almost all activity- and emission factor-related
input variables. Triangular distributions were  assigned to
three input variables (specifically, cow-birth ratios for the
three most  recent years included in the 2001 model run) to
capture the fact that these variables cannot be negative. For
some key input variables, the uncertainty ranges around their
                                estimates (used for inventory estimation) were collected
                                from published documents and other public sources; others
                                were based on expert opinion and our best estimates. In
                                addition, both endogenous and exogenous correlations
                                between selected primary input variables were modeled. The
                                exogenous correlation coefficients between the probability
                                distributions  of selected activity-related variables were
                                developed through expert judgment.
                                    The uncertainty ranges associated with the activity data-
                                related input variables were plus or minus 10 percent or lower.
                                However, for many emission factor-related input variables,
                                the lower- and/or the upper-bound uncertainty estimates were
                                over 20 percent. The results of the quantitative uncertainty
                                analysis (Table 6-5) indicate that, on average, the emission
                                estimate range of this source is approximately 123.7 to 164.0
                                Tg CO2 Eq., calculated as 11 percent below and 18 percent
                                above the actual 2007 emission estimate of  139.0 Tg CO2 Eq.
                                Among the individual cattle sub-source categories, beef cattle
                                account for the largest amount of CH4 emissions as well as
                                the largest degree of  uncertainty in the inventory emission
                                estimates. Among non-cattle, horses account for the largest
                                degree of uncertainty in the inventory emission estimates
                                because there is a higher degree of uncertainty among the
                                FAO population estimates used for horses than for the USDA
                                population estimates used for swine, goats, and sheep.

                                QA/QC and Verification
                                    In order to ensure the quality of the emission estimates
                                from  enteric fermentation, the IPCC  Tier 1  and Tier 2
                                Quality Assurance/Quality Control (QA/QC)  procedures
                                were implemented consistent with the U.S. QA/QC plan.
                                Tier 2 QA procedures included independent peer review of
Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation
(Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
                     Uncertainty Range Relative to Emission Estimate3'b
                       (Tg C02 Eq.)                     (%)
                                                       Lower Bound   Upper Bound   Lower Bound   Upper Bound
  Enteric Fermentation
CH4
139.0
123.7
164.0
-11%
+ 18%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
  b Note that the relative uncertainty range was estimated with respect to the 2001 emission estimates submitted in 2003 and applied to the 2007 estimates.
                                                                                               Agriculture  6-5

-------
emission estimates. As described below, particular emphasis
this year was placed on revising CEFM weight assumptions
and modifications of the stacker population estimates in the
transition matrix, which required further QA/QC to ensure
consistency of estimates generated by the updated model.

Recalculations Discussion
    There were several modifications to the estimates
relative to the previous Inventory that had an effect on
emission estimates, including the following:
•   During the QA/QC process, it was noted that a portion
    of the steer and heifer populations that were held aside
    (e.g., not eligible to be placed in feedlots)  to establish
    the stacker population for the following January were
    inadvertently left out of the emissions calculations. These
    heifer and steer stacker populations are now included.
•   An additional adjustment was made to the CEFM to
    allow feedlot placements for the 700-800 Ibs category
    to use excess animals from the over 800 Ibs category
    if insufficient animals  are  available to  place in a
    given month at 700-800 Ibs. This process reduced the
    discrepancy in the model  between actual placement
    numbers by weight category from USDA and available
    animals within the transition matrix.
•   Calf weight at 7 months was adjusted to be equal for
    all months, as current research indicated that evidence
    was not sufficient to suggest that calf weight at weaning
    differs by birth month.
•   Mature weight for beef cows was revised based on
    annual data collected from 1989 through 2007, as was
    replacement weight at 15 and 24 months.
•   Mature weight for dairy cows was adjusted to 1,550 for
    all years, and replacement weight at 15 and 24 months
    was adjusted accordingly.
•   Monthly weight gain for stackers was increased to 1.83
    Ibs per day starting in 2000, and a linear function was
    used to determine adjustments from previous estimates
    between 1989 and 2000.
•   Bulls were added to the CEFM calculations for the first
    time, as previously they had been calculated separately;
    however, the estimates are still carried out with the Tier 1
    approach, so this change did not result in any  changes
    in emissions from previous years.
•   The USDA published revised population estimates that
    affected historical emissions estimated for swine in
    2006. In addition, some historical population estimates
    for certain beef and dairy populations were also updated
    as a result of changes in USDA inputs.
•   As a result of these changes, dairy cattle emissions
    increased an average of 65 Gg (4.6 percent) per year and
    beef cattle increased an average of 423 Gg (9.7 percent)
    per year over the entire time series relative to the previous
    Inventory. Historical emission estimates for swine in 2006
    increased by less than one half of one percent as a result
    of the USDA revisions described above.

Planned  Improvements
    Continued research and regular updates are necessary
to maintain a current model of cattle diet characterization,
feedlot placement data, rates of weight gain and calving,
among other data inputs. Research is currently underway to
update the diet assumptions. There are a variety of models
available to predict CH4 production from cattle. Four of
these models (two mechanistic, and two empirical) are
being evaluated to determine appropriate Ym and DE values
for  each cattle type  and state. In addition to the  model
evaluation,  separate research  is being conducted to  update
the  assumptions used for cattle diet components for each
animal type. At the conclusion of both of these updates, it
is anticipated that a peer-reviewed article will be published
and will serve as the basis for future emission estimates for
enteric fermentation.
    In addition to the diet characteristics research discussed
above several revisions will be investigated, including:
•   Estimating bull emissions using the IPCC  Tier
    2 approach;
•   Updating input  variables that are  from older data
    sources, such as beef births by month and beef cow
    lactation rates;
•   Continue to evaluate and improve the CEFM handling
    of the differences between the USDA feedlot placement
    data by weight category and the number of animals that
    are available for  placement by weight class according
    to the CEFM transition matrix;
•   The possible breakout of other animal types (i.e., sheep,
    swine,  goats, horses) from national estimates to state-
    level estimates; and
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•   Including bison in the estimates for other domesticated
    animals.
    These updates may result in significant changes to
some of the activity data used in  generating emissions.
Additionally, since these revised inputs will be state-
specific and peer-reviewed, uncertainty ranges around these
variables will likely decrease. As a consequence, the current
uncertainty analysis will become outdated, and a revision of
the quantitative uncertainty surrounding emission estimates
from this source category will be initiated.

6.2.  Manure  Management (IPCC
Source  Category  4B)

    The management of livestock manure  can produce
CH4 and N2O emissions. Methane is produced by the
anaerobic decomposition of manure. Direct N2O emissions
are produced as part of the N cycle through the nitrification
and denitrification of the organic N in livestock manure and
urine.2 Indirect N2O emissions are produced as result of the
volatilization of N as ammonia (NH3) and oxides of nitrogen
(NOX) and runoff and leaching of N during treatment, storage
and transportation.
    When livestock  or poultry manure are stored or
treated in systems that promote anaerobic conditions (e.g.,
as a liquid/slurry in lagoons, ponds, tanks,  or pits), the
decomposition of materials in the manure tends to produce
CH4. When manure is handled as a solid (e.g., in stacks or
drylots) or deposited on pasture, range, or paddock lands,
it tends to decompose aerobically and produce little or no
CH4. Ambient temperature, moisture, and manure storage or
residency time affect the amount of CH4 produced because
they influence the growth of the bacteria responsible for CH4
formation. For non-liquid-based manure systems, moist
conditions (which are a function of rainfall and humidity)
can promote CH4 production. Manure composition, which
varies by animal diet, growth rate, and type, including the
animal's digestive system, also affects the amount of CH4
produced. In general, the greater the energy content of the
feed, the greater the potential for CH4 emissions. However,
2 Direct and indirect N2O emissions from manure 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 manure
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.
some higher energy feeds also are more digestible than
lower quality forages, which can result in less overall waste
excreted from the animal.
    The production of direct N2O emissions from livestock
manure depends on the composition of the manure and
urine, the type of bacteria involved in the process, and the
amount of oxygen and liquid in the manure system. For direct
N2O emissions to occur, the manure must first be handled
aerobically where NH3 or organic N is converted to nitrates
and nitrites (nitrification), and then handled anaerobically
where the nitrates  and nitrites are reduced to nitrogen
gas (N2), with intermediate production  of N2O and nitric
oxide (NO) (denitrification) (Groffman et al. 2000). These
emissions are most likely to occur in dry manure handling
systems that have aerobic conditions, but that also contain
pockets of anaerobic conditions due to  saturation. A very
small portion of the total N excreted is expected to convert
to N2O in the waste management system (WMS). Indirect
N2O emissions are produced when N is lost from the system
through volatilization (as NH3  or NOX) or through runoff
and leaching. The vast majority of volatilization losses from
these operations are NH3. Although there are also some small
losses of NOX, there are no quantified estimates available
for use, so losses due to volatilization are only based on
NH3 loss factors. Runoff losses would  be expected from
operations that house animals or store manure in a manner
that results in exposure to weather. Runoff losses are also
specific to the type of animal housed on the operation due
to differences in manure characteristics. Little information
is known about leaching from manure management systems
as most research focuses on leaching from land application
systems. Since leaching losses are expected to be minimal,
leaching losses are coupled with runoff losses and the runoff/
leaching estimate does not include any leaching losses.
    Estimates of CH4 emissions in 2007 were 44.0 Tg CO2
Eq. (2,093 Gg), 45 percent higher than in 1990. Emissions
increased on average by 0.8 Tg CO2 Eq. (2.5 percent)
annually over  this period. The majority of this increase
was from swine  and dairy cow  manure, where emissions
increased 51 and 60 percent, respectively. Although the
majority of manure in  the United States  is handled as a
solid, producing little CH4, the general trend in manure
management, particularly for dairy and swine (which are
both shifting towards larger facilities), is one of increasing
use of liquid  systems. Also,  new regulations limiting
                                                                                             Agriculture  6-7

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the application of manure nutrients have shifted manure
management practices at smaller dairies from daily spread
to manure managed and stored on site. Although national
dairy animal populations have been generally decreasing,
some states have seen increases in their dairy populations
as the  industry becomes more concentrated in certain
areas of the country. These areas of concentration, such as
California, New Mexico, and Idaho, tend to utilize more
liquid-based systems to manage (flush or scrape) and store
manure. Thus the shift toward larger facilities is translated
into an increasing use of liquid  manure management
systems, which have higher potential CH4 emissions than
dry systems. This shift was accounted for by incorporating
state and WMS-specific CH4 conversion factor (MCF)
values in combination with the 1992,1997, and 2002 farm-
size distribution data reported in the Census of Agriculture
(USDA 2005). Methane emissions from horses have nearly
doubled since 1990 (an 82 percent increase from 1990 to
2007);  however, this is due to population increases rather
than changes in manure management practices. Overall,
horses  contribute only 2 percent of CH4 emissions from
animal manure management. From 2006 to 2007, there was
           a 5 percent increase in total CH4 emissions, due to minor
           shifts in the animal populations and the resultant effects on
           manure management system allocations.

               In 2007, total N2O emissions were estimated to be 14.7
           Tg CO2 Eq. (47 Gg); in 1990, emissions were 12.1 Tg CO2
           Eq. (39 Gg). These values include both direct and indirect
           N2O emissions from manure management.  Nitrous oxide
           emissions have remained fairly steady  since 1990. Small
           changes in N2O emissions from individual animal groups
           exhibit the same  trends as the animal group populations,
           with the overall net effect that N2O emissions showed a 22
           percent increase from 1990 to 2007 and a 1 percent increase
           from 2006 through 2007.

               Table 6-6 and Table 6-7 provide estimates of CH^ and N2O
           emissions from manure management by animal catagory.
           Methodology
               The methodologies presented in IPCC (2006) form
           the basis of the  CH4 and N2O emission  estimates for
           each animal type. This section presents a summary of the
           methodologies used to estimate CH4 and N2O emissions
Table 6-6: CH4 and N20 Emissions from Manure Management (Tg C02 Eq.)
  Gas/Animal Type
1990
1995
2000
2005
2006
2007
  CH4a
    Dairy Cattle
    Beef Cattle
    Swine
    Sheep
    Goats
    Poultry
    Horses
  N20"
    Dairy Cattle
    Beef Cattle
    Swine
    Sheep
    Goats
    Poultry
    Horses
  Total
30.4
11.3
 2.6
13.1

 "
 2.8
 0.5
12.1
 3.5
 5.5
 1.2

 "
 1.5
 0.2
42.5
34.5
12.5
 2.6
16.0

 "
 2.7
 0.4
12.9
 3.5
 6.0
 1.4
 0.2
 0.2
47.4
37.9
14.7
 2.5
17.5

 "
 2.6
 0.5
14.0
 3.6
 6.7
 1.4
 0.3
 0.2
51.9
41.8
17.2
 2.4
18.6
 0.1
  +
 2.7
 0.8
14.2
 3.7
 6.5
 1.5
 0.3
  +
 1.7
 0.4
56.0
  + Less than 0.05 Tg C02 Eq.
  a Includes CH4 emission reductions due to CH4 collection and combustion by anaerobic digestion utilization systems.
  b Includes both direct and indirect N20 emissions.
  Note: Totals may not sum due to independent rounding.
41.9
17.5
 2.5
18.3
 0.1
  +
 2.7
 0.8
14.6
 3.8
 6.7
 1.5
 0.4
  +
 1.8
 0.4
56.4
44.0
18.1
 2.4
19.7
 0.1

 2.7
 0.8
14.7
 3.9
 6.7
 1.6
 0.3

 1.8
 0.4
58.7
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Table 6-7: CH4 and N20 Emissions from Manure Management (Gg)
  Gas/Animal Type
1990
1995
2000
2005
2006
2007
  CH4a
    Dairy Cattle
    Beef Cattle
    Swine
    Sheep
    Goats
    Poultry
    Horses
  N20"
    Dairy Cattle
    Beef Cattle
    Swine
    Sheep
    Goats
    Poultry
    Horses
1,447
 538
 124
 624
   7
   1
 131
   22
   39
   11
   18
   4

1,642
 597
 125
 764
  128
   21
   42

1,804
 701
 118
 832
  126
   22
   45
   12
   22
                             5
1,991
 820
 114
 887
   4
   1
 127
   39
   46
   12
   21
   5
   1
   +
   6
   1
1,993
 833
 119
 870
   4
   1
 128
   39
   47
   12
   22
   5
   1
   +
   6
   1
2,093
 863
 116
 940
   4
   1
 130
   39
   47
   13
   22
   5
   1
   +
   6
   1
  + Less than 0.5 Gg.
  a Includes CH4 emission reductions due to CH4 collection and combustion by anaerobic digestion utilization systems.
  b Includes both direct and indirect N20 emissions.
  Note: Totals may not sum due to independent rounding.
from manure management for this Inventory. See Annex
3.10 for more detailed information on the methodology and
data used to calculate CH4 and N2O emissions from manure
management.

Methane Calculation Methods
    The following inputs  were used in the calculation of
    j emissions:
    Animal population data (by animal type and state);
    Typical Animal Mass (TAM) data (by animal type);
    Portion of manure managed in each Waste Management
    System (WMS), by state and animal type;
    Volatile solids (VS) production rate (by animal type and
    state or U.S.);
    CtLj producing potential (B0) of the volatile solids (by
    animal type); and
    Methane Conversion Factors (MCF), representing the
    extent to which the CFLj producing potential is realized
    for each type of WMS (by state and manure management
    system, including the impacts of any biogas collection/
    utilization efforts).
                Methane emissions were estimated by first determining
            activity data, including animal population, TAM, WMS
            usage, and waste characteristics. The activity data sources
            are described below:
            •   Annual animal population data for 1990 through 2007
                for  all livestock types, except horses and goats were
                obtained from the USDA National Agricultural Statistics
                Service (NASS). Horse population data were obtained
                from the Food and Agriculture Organization (FAO)
                FAOSTAT database (FAO 2008). Goat population data
                for 1992,1997, and 2002 were obtained from the Census
                of Agriculture (USDA 2005).
            •   The TAM is an annual average weight which was obtained
                for  each animal type from information in USDA's
                Agricultural Waste Management Field Handbook (USDA
                1996a), the American Society of Agricultural Engineers,
                Standard D384.1 (ASAE 1999) and others (EPA 1992,
                Shuyler 2000, and Safley 2000).
            •   WMS usage was estimated for swine and dairy cattle
                for  different farm size categories  using data from
                USDA (USDA 1996b, 1998, 2000a) and EPA (ERG
                2000a, EPA 2002a, 2002b). For beef cattle and poultry,
                                                                                              Agriculture  6-9

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    manure management system usage data were not tied
    to farm size but were based on other data sources (ERG
    2000a, USDA 2000b, UEP 1999). For other animal
    types, manure management system usage was based on
    previous estimates (EPA 1992).
•   VS production rates for all cattle except for bulls and
    calves were calculated for each state and animal type
    in the CEFM, which is described in section 6.1, Enteric
    Fermentation. VS production rates for all other animals
    were determined using data from USDA's Agricultural
    Waste Management Field Handbook (USDA 1996a)
    and data from the American Society of Agricultural
    Engineers, Standard D384.1 (ASAE 1999).
•   The maximum CFLj producing capacity of the VS (B0)
    was determined for each animal type based on literature
    values (Morris 1976, Bryant et al, 1976, Hashimoto 1981,
    Hashimoto 1984, EPA 1992, Hill 1982, and Hill 1984).
•   MCFs for dry systems were set equal to default IPCC
    factors based on state climate for each year (IPCC
    2006). MCFs for liquid/slurry, anaerobic  lagoon,
    and deep pit systems were calculated based on  the
    forecast performance of biological systems relative
    to temperature changes as predicted in the van't Hoff-
    Arrhenius equation which is consistent with IPCC 2006
    Tier 2 methodology.
•   Anaerobic digestion system data were obtained from
    the EPA AgSTAR Program, including information
    presented in the AgSTAR Digest (EPA 2000, 2003b,
    2006).
•   Emissions from  anaerobic digestion systems were
    estimated based on the methodology described in EPA's
    Climate Leaders Greenhouse Gas Inventory Protocol
    Offset Project Methodology for Project Types Managing
    Manure with Biogas Recovery Systems (EPA 2008).
    To estimate CH4 emissions, first the annual amount of
VS (kg per year) from manure that is excreted in each WMS
for each animal type, state, and year was calculated. This
calculation multiplied the animal population (head) by the VS
excretion rate (kg VS per 1,000 kg animal mass per day), the
TAM (kg animal mass per head) divided by 1,000, the WMS
distribution (percent), and the number of days per year.
    The estimated amount of VS managed in each WMS was
used to estimate the CH4 emissions (kg CH4 per year) from
each WMS. The amount of VS (kg per year) was multiplied
by the maximum CH4 producing capacity of the VS (B0) (m3
CH4 per kg VS), the MCF for that WMS (percent), and the
density of CH4 (kg CH4 per m3 CH4).
    For anaerobic digestion systems, the maximum CFLj
producing capacity of the VS (B0) (m3 CH4 per kg VS) was
multiplied by an estimated CH4 production value (percent),
assumed values of  the system collection efficiency (CE)
(percent), an assumed value  of the system destruction
efficiency (DE) (percent), and the density of CH4 (kg CH4
per m3 CH4) (ERG 2008). Anaerobic digestion systems
were assumed to produce 90 percent of the maximum CH4
producing capacity of the VS (B0). The CH4 CE of covered
lagoon systems was estimated to be 75 percent, and the
CH4 CE of complete mix and plug flow anaerobic digestion
systems was assumed to be 99 percent (EPA 2008). Any CH4
that was not collected was assumed to be emitted as leakage.
A DE from flaring or burning in  an engine is estimated to
be 98 percent; therefore, the amount of CH4 that would not
be flared or combusted and would be emitted is 2 percent
(EPA 2008).
    The CH4 emissions for each WMS (including anaerobic
digestion systems), state,  and animal type were summed to
determine the total U.S. Methane emissions from manure
management.

Nitrous Oxide Calculation  Methods
    The following inputs were used in the calculation of
direct and indirect N2O emissions:
•   Animal population data (by animal type and state);
•   TAM data (by animal type);
•   Portion of manure managed in each WMS (by state and
    animal type);
•   Total Kjeldahl N excretion rate (Nex);
•   Direct N2O emission factor (EFWMS);
•   Indirect N2O  emission  factor for volatilization
    (-tiTvolitalization)'
•   Indirect  N2O emission factor for runoff and leaching
•   Fraction of N loss from volatilization of ammonia and
    NOX (Fracgas); and
•   Fraction  of N  loss from  runoff and leaching
    (Frac,
        'runoff/le:
:ach)-
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    N2O emissions were estimated by first determining
activity data, including animal population, TAM, WMS
usage, and waste characteristics. The activity data sources
(except for population, TAM, and WMS,  which were
described above) are described below:
•   N excretion rates from the USDA Agricultural Waste
    Management Field Handbook (USDA 1996a) were used
    for all animal types except sheep, goats, and horses. Data
    from the American Society of Agricultural Engineers
    (ASAE1999) were used for these animal types.
•   All N2O emissions factors (direct and indirect) were
    from IPCC (IPCC 2006).
•   Country-specific estimates for the fraction of N loss from
    volatilization (Fracgas) and runoff and leaching (Frac^^i
    leach) were  developed. Fracgas values were based on
    WMS-specific volatilization values as estimated from
    U.S. EPA's National Emission Inventory—Ammonia
    Emissions from Animal Agriculture  Operations (EPA
    2005). Frac,
              'runoff/leaching
values were based on regional
    cattle runoff data from EPA's Office of Water (EPA
    2002b; see Annex 3.1).
    To estimate N2O emissions, first the amount of Nexcreted
(kg per year) in manure in each WMS for each animal type,
state, and year was calculated. The population (head) for
each state and animal was multiplied by TAM (kg  animal
mass per head) divided by 1,000, the N excretion rate (Nex,
in kg N per 1000 kg animal mass per day), WMS distribution
(percent), and the number of days per year.
    Direct N2O emissions were calculated by multiplying
the amount of Nexcreted (kg per year) in each WMS by the
N2O direct emission factor for that WMS (EFWMS, in kg
N2O-N per kg N) and the conversion factor of N2O-N to
N2O. These emissions were summed over state, animal and
WMS to determine the total direct N2O emissions (kg of
N2O per year).
    Then, indirect N2O emissions from volatilization (kg
N2O per  year) were calculated by multiplying the amount
of N excreted (kg per year) in each WMS by the fraction of
N lost through volatilization (Fracgas) divided by 100, and
the emission factor for volatilization (EFvolatilization, in kg N2O
per kg N), and the conversion factor of N2O-N to N2O. Next,
indirect N2O emissions from runoff and leaching (kg N2O
per year) were calculated by multiplying the amount of N
excreted (kg per year) in each WMS by the fraction of N lost
through runoff and leaching (Frac^^,!,,^) divided by 100,
and the emission factor for runoff and leaching (EFrunoff/leach,
in kg N2O per kg N), and the conversion factor of N2O-N
to N2O. The indirect N2O emissions from volatilization and
runoff and leaching were summed to determine the total
indirect N2O emissions.
    The direct and indirect N2O emissions were summed to
determine total N2O emissions (kg N2O per year).

Uncertainty
    An analysis was conducted for the manure management
emission estimates presented in EPA's Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001 (EPA
2003a, ERG 2003) to determine the uncertainty associated
with estimating CH4 and N2O emissions from livestock
manure management. The quantitative uncertainty analysis
for  this  source category was performed in 2002 through
the IPCC-recommended Tier 2 uncertainty  estimation
methodology, the Monte Carlo Stochastic Simulation
technique. The uncertainty analysis was developed based
on the methods used to estimate CH4 and N2O emissions
from manure management systems. A normal  probability
distribution was assumed for each source data category.
The series of equations used were condensed into a single
equation for each animal type and state. The equations for
each animal group contained four to five variables around
which the uncertainty analysis was performed for each state.
No significant changes occurred in the methods, data or other
factors that influence the uncertainty ranges around the 2007
activity data. Consequently, these uncertainty estimates were
directly applied to the 2007 emission estimates.
    The results of the Tier 2 quantitative uncertainty analysis
are  summarized in Table 6-8. Manure management CH4
emissions  in 2007 were estimated to be between 36.0 and
52.8 Tg CO2 Eq.  at a  95 percent confidence level, which
indicates a range of 18 percent below to 20 percent above the
actual 2007 emission estimate of 44.0 Tg CO2 Eq. At the 95
percent confidence level, N2O emissions were estimated to
be between 12.3 and 18.2 Tg CO2 Eq. (or approximately 16
percent below and 24 percent above the actual 2007 emission
estimate of 14.7 Tg CO2 Eq.).
                                                                                           Agriculture  6-11

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Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N20 (Direct and Indirect) Emissions from
Manure Management (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas        (Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)                     (%)

Manure Management
Manure Management

CH4
N20

44.0
14.7
Lower Bound
36.0
12.3
Upper Bound
52.8
18.2
Lower Bound
-18%
-16%
Upper Bound
+20%
+24%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
QA/QC and Verification
    Tier 1 and Tier 2 QA/QC activities were conducted
consistent with the U.S. QA/QC plan. Tier 2 activities
focused on comparing estimates  for the previous and
current inventories for CH^ and N2O emissions from manure
management. All errors identified were corrected. Order of
magnitude checks were also conducted, and corrections made
where needed. Manure N data were checked by comparing
state-level data with bottom up estimates  derived at the
county level and summed to the state level. Similarly, a
comparison was made by animal and WMS type for the full
time series, between national level estimates for N excreted
and the sum of county estimates for the full time series.

Recalculations Discussion
    For the current Inventory, anaerobic digester systems were
incorporated into the WMS distributions in the CtLj estimates
using the existing WMS distributions and EPA AgSTAR data.
Emissions for anaerobic digestion systems were also calculated
using an assumed CH4 production rate, collection efficiency,
and combustion efficiency (ERG 2008).
    Using the APHIS 2001  Sheep report, the WMS
distribution for sheep was  updated. The APHIS report
presents regional percentages of sheep and lambs that are
primarily managed in open range/pasture, fenced range/
pasture, farms, or feedlots in 2001 (USDA 2003). WMS
data for sheep were previously obtained from USDA NASS
sheep report for years 1990 through 1993 (USDA 1994).
The WMS data for years 1994 through 2000 were calculated
assuming a linear progression from 1993 to 2001. Due to
lack of additional data, data for years 2002 and beyond were
assumed to be the same as 2001.
    The CEFM produces volatile solids data for cattle that
are used in the manure management estimates. The CEFM
                              team implemented methodological changes to the VS
                              estimation, which created changes in VS data and changes
                              in the amount of methane estimated for manure management
                              (see Section 6.1, Enteric Fermentation).
                                  With these recalculations, CH4 emission estimates
                              from manure management systems are slightly higher than
                              reported in the previous Inventory for swine and slightly
                              lower for dairy cattle. On average,  annual CH4 emission
                              estimates are less than those of the previous Inventory by
                              1.7 percent.
                                  Nitrous oxide emission estimates  from manure
                              management systems have increased for all years for beef
                              cattle and since 1994 for sheep in the current Inventory as
                              compared to the previous Inventory due to the recalculations.
                              Overall the total emission estimates for the current Inventory
                              increased by 1.2 percent, relative to the previous Inventory.
                               Planned Improvements
                                  The manure management emission estimates will
                              be updated to reflect changes in the Cattle  Enteric
                              Fermentation Model (CEFM). In addition, efforts will
                              be made to ensure that the manure management emission
                              estimates and CEFM are using the same data sources and
                              variables where appropriate.
                                  An updated version of the USDA Agricultural Waste
                              Management Field Handbook became available in March
                              2008. This reference will be reviewed to determine if updates
                              should be made to any of the inventory activity data.
                                  The current inventory estimates take into  account
                              anaerobic digestion systems for only dairy and swine
                              operations.  Data from the AgSTAR Program will also be
                              reviewed and anaerobic digestions systems that exist for
                              other animal types will be incorporated.
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    The uncertainty analysis will be updated in the future to
more accurately assess uncertainty of emission calculations.
This update is necessary due to changes in emission
calculation methodology in the current Inventory, including
estimation of emissions at the WMS level and the use of new
calculations  and variables for indirect N2O emissions.

6.3.   Rice  Cultivation  (IPCC Source
Category 4C)

    Most of the world's rice, and all rice in the United States,
is grown on flooded fields. When fields are flooded, aerobic
decomposition of organic material gradually depletes most
of the oxygen present in the soil, causing  anaerobic soil
conditions. Once the environment becomes anaerobic, CH4
is produced through anaerobic decomposition of soil organic
matter by methanogenic bacteria. As much as 60 to 90 percent
of the CtLj produced is oxidized by aerobic methanotrophic
bacteria in the soil (some oxygen remains at the interfaces of
soil and water, and soil and root system) (Holzapfel-Pschorn
et al. 1985, Sass et al. 1990). Some of the CH4 is also leached
away as dissolved CK4 in floodwater that percolates from
the field. The remaining un-oxidized CH4 is  transported
from the submerged soil to the atmosphere primarily by
diffusive transport through the rice plants. Minor amounts
of CtLj also escape from the soil via diffusion and bubbling
through floodwaters.
    The water management system under which rice is
grown is one of the most important factors affecting CH4
emissions. Upland rice fields are not flooded, and therefore
are not believed to produce  CH4. In deepwater rice fields
(i.e., fields with flooding depths greater than one meter),
the lower stems and roots of the rice plants are dead, so
the primary  CH^  transport pathway to the atmosphere is
blocked. The quantities of CH4 released from deepwater
fields, therefore, are believed to be significantly less than
the quantities released from  areas with shallower flooding
depths. Some flooded fields are drained periodically during
the growing season, either intentionally or accidentally. If
water is drained and soils are  allowed to dry sufficiently,
CH4 emissions decrease or stop entirely. This is due to soil
aeration, which not only causes existing soil CH^ to oxidize
but also inhibits further CH4 production in soils. All  rice
in the United States is grown under continuously flooded
conditions; none is grown under deepwater conditions. Mid-
season drainage does not occur except by accident (e.g., due
to levee breach).
    Other factors that influence CH^ emissions from flooded
rice fields include fertilization practices (especially the use of
organic fertilizers), soil temperature, soil type, rice variety,
and cultivation practices (e.g., tillage, seeding, and weeding
practices). The factors that determine the amount of organic
material available to decompose (i.e., organic fertilizer use,
soil type, rice variety,3 and cultivation practices) are the most
important variables influencing the amount of CH4 emitted
over the growing season; the total amount of CH^ released
depends primarily  on the amount of organic  substrate
available. Soil temperature is known to be an important
factor regulating the activity of methanogenic bacteria, and
therefore the rate of CH^ production. However, although
temperature controls the amount of time it takes to convert
a given amount of organic material to CK4, that time is short
relative to a growing season, so the dependence of total
emissions over an entire growing season on soil temperature
is weak. The application of synthetic fertilizers has also
been found to influence CK4 emissions; in particular, both
nitrate and sulfate fertilizers (e.g., ammonium nitrate  and
ammonium sulfate) appear to inhibit CH^ formation.
    Rice is cultivated in seven states: Arkansas, California,
Florida, Louisiana, Mississippi, Missouri, and Texas.4 Until
2006, rice was also cultivated in Oklahoma, but as of 2007
rice cultivation in the state ceased (Anderson 2008). Soil
types, rice varieties, and cultivation practices for rice vary
from state to state, and even from farm to farm. However,
most rice farmers apply organic fertilizers in the form of
3 The roots of rice plants shed organic material, which is referred to as
"root exudate." The amount of root exudate produced by a rice plant over
a growing season varies among rice varieties.
4A 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 emissions estimates.
                                                                                              Agriculture  6-13

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residue from the previous rice crop, which is left standing,
disked, or rolled into the fields. Most farmers also apply
synthetic fertilizer to their fields, usually urea. Nitrate and
sulfate fertilizers are not commonly used in rice cultivation
in the United States. In addition, the climatic conditions of
southwest Louisiana, Texas, and Florida often allow for a
second, or ratoon, rice  crop. Ratoon  crops  are much less
common or non-existent in Arkansas, California, Mississippi,
Missouri, Oklahoma, and northern  areas  of Louisiana.
Methane emissions from ratoon crops have been found to be
considerably higher than those from the primary crop. This
second rice crop is produced from regrowth of the stubble
after the first crop has been harvested. Because the first crop's
stubble is left behind in ratooned fields, and there is no time
delay between cropping seasons (which would allow the
stubble to decay aerobically), the amount of organic material
that is available for anaerobic decomposition is considerably
higher than with the first (i.e., primary) crop.
    Rice cultivation is a small source  of CH4 in the United
States ( and Table 6-10). In 2007, CIL, emissions from rice
cultivation were 6.2 Tg CO2 Eq. (293 Gg). Although annual
emissions fluctuated unevenly between the years 1990 and
2007, ranging from an annual decrease of 14 percent to an
           annual increase of 17 percent, there was an overall decrease
           of 14 percent  over  the seventeen-year period, due to an
           overall decrease in primary crop area.5 The factors that affect
           the rice acreage in any year vary from state to state, although
           the price of rice relative to competing crops is the primary
           controlling variable in most states.

           Methodology
                IPCC (2006) recommends using harvested rice areas,
           area-based daily emission factors (i.e., amount of CH4 emitted
           per day per unit harvested area), and length of growing season
           to estimate annual CH4 emissions from rice cultivation. This
           Inventory uses the recommended methodology and employs
           Tier 2 U.S.-specific emission factors derived from rice field
           measurements.  State-specific and daily emission factors were
           not available, however, so average U.S. seasonal emission
           factors were used. Seasonal emissions have been found to
           be much higher for ratooned crops than for primary crops,
           so emissions from ratooned and primary areas are estimated
           separately using emission factors that are representative of
           the particular growing season. This approach is consistent
           with IPCC (2006).
Table 6-9: CH4 Emissions from Rice Cultivation (Tg C02 Eq.)
  State
1990
1995
2000
2005
2006
2007
  Primary
    Arkansas
    California
    Florida
    Louisiana
    Mississippi
    Missouri
    Oklahoma
    Texas
  Ratoon
    Arkansas
    Florida
    Louisiana
    Texas
 5.1
 2.1
  1.0
  0.4
  "
  0.6
  "
  »
  0.9
 5.6
 2.4
 0.8
  0.5
  0.2
  0.6
  "
  "
  0.8
 5.5
 2.5
  0.9
  0.4
  0.3

  0.4
  2.0 1

  0+
  6.0
  2.9
  0.9
   +
  0.9
  0.5
  0.4
   +
  0.4
  0.8
               0.5
               0.4
 5.1
 2.5
 0.9
   +
 0.6
 0.3
 0.4
   +
 0.3
 0.9
            0.5
            0.4
 4.9
 2.4
 1.0
   +
 0.7
 0.3
 0.3
 0.0
 0.3
 1.2
            0.9
            0.3
  Total
  7.1
  7.6
  7.5
  6.8
 5.9
  6.2
  + Less than 0.05 Tg C02 Eq.
  Note: Totals may not sum due to independent rounding.
                                                          5The 14 percent decrease occurred between 2005 and 2006; the 17 percent
                                                          increase happened between 1993 and 1994.
6-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 6-10: CH4 Emissions from Rice Cultivation (Gg)
  State
  Primary
    Arkansas
    California
    Florida
    Louisiana
    Mississippi
    Missouri
    Oklahoma
    Texas
  Ratoon
    Arkansas
    Florida
    Louisiana
    Texas
1990
                          2005
                       2006
                                                   241
                                                   119
                                                    44
                                                     1
                                                    29
                                                    16
                                                    18
                                                    +
                                                    13
                                                    41
                                                    +
                                                     1
                                                    22
                                                    18
                   2007
                                               234
                                               113
                                                45
                                                 1
                                                32
                                                16
                                                15
                                                +
                                                12
                                                59
                                                +
                                                 1
                                                42
                                                16
  Total
 339
363
357
326
282
293
  + Less than 0.5 Gg
  Note: Totals may not sum due to independent rounding.
    The harvested rice areas for the primary and ratoon crops
in each state are presented in Table 6-11, and the area of
ratoon crop area as a percent of primary crop area is shown
in Table 6-12. Primary crop areas for 1990 through 2007 for
all states except Florida and Oklahoma were taken from U.S.
Department of Agriculture's Field Crops Final Estimates
1987-1992  (USDA 1994), Field Crops Final Estimates
1992-1997  (USDA 1998), Field Crops Final Estimates
1997-2002 (USDA 2003), and Crop Production Summary
(USDA 2005 through 2008). Source data for non-USDA
sources of primary  and ratoon harvest areas are shown in
Table 6-13. California, Mississippi, Missouri, and Oklahoma
have not ratooned rice over the period 1990 through 2007
(Guethle 1999, 2000, 2001a, 2002 through 2008; Lee 2003
through 2007; Mutters  2002 through 2005; Street 1999
through 2003; Walker 2005, 2007, 2008).
    To determine what CH4 emission factors should be used
for the primary and ratoon crops, CJL, flux information from
rice field measurements in the United States was collected.
Experiments that involved atypical or nonrepresentative
           management practices (e.g., the application of nitrate
           or sulfate fertilizers, or other substances believed to
           suppress CH4 formation), as well as experiments in which
           measurements were not made over an entire flooding season
           or floodwaters were drained mid-season, were excluded
           from the analysis. The remaining experimental results6 were
           then sorted by season (i.e., primary and ratoon) and type
           of fertilizer amendment (i.e., no fertilizer added,  organic
           fertilizer added, and synthetic and organic fertilizer added).
           The experimental results from primary crops with added
           synthetic and organic fertilizer (Bossio et al. 1999; Cicerone
           etal. 1992;Sassetal. 1991a, 199Ib) were averaged to derive
           an emission factor for the primary crop, and the experimental
           results from ratoon crops with added synthetic fertilizer
           (Lindau and Bollich 1993, Lindau et al. 1995) were averaged
           6 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

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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
Total Ratoon
Total
1990
485,

159,
4,
2,
220,
66,
101,
32,
142,
57,
1,148,
125,
1,273,
633
0
854
978
489
558
168
174
376
617
857
143
047
799
847












1995
542,

188,
9,
4,
230,
69,
116,
45,
128,
51,
1,261,
125,
1,387,
291
0
183
713
856
676
203
552
326
364
693
477
796
536
333












2000
570,

221,
7,
3,
194,
77,
88,
68,
86,
43,
1,237,
124,
1,362,
619
0
773
801
193
253
701
223
393
283
605
302
951
197
148
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
50,245
1,416,473
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
52,899
1,199,135
2007
536,220
5
215,702
4,199
840
152,975
53,541
76,487
72,036
0
58,681
21,125
1,116,299
75,511
1,191,810
  'Arkansas ratooning occurred only in 1998,1999, 2005, and 2006 and was assumed to occur in 2007.
  Note: Totals may not sum due to independent rounding.
Table 6-12: Ratooned Area as Percent of Primary Growth Area
State
                   1990
1997   1998    1999   2000    2001    2002    2003   2004    2005    2006    2007
Arkansas
Florida
Louisiana
Texas
                        0%
                           50%
                              30%
                              40%
                 +                  0%
                65%    41%    60%    54%   100%    77%
                       40%    30%    15%    35%    30%
                       50%    40%    37%    38%    35%
13%
27%
       20%
20%    35%
39%    36%
  + Indicates ratooning rate less than 0.5 percent.
to derive an emission factor for the ratoon crop. The resultant
emission factor for the primary crop is 210 kg CtLj/hectare-
season, and the resultant emission factor for the ratoon crop
is 780 kg CHVhectare-season.

Uncertainty
    The largest uncertainty in the calculation of CH4
emissions from rice  cultivation is associated with the
emission factors. Seasonal  emissions, derived from field
measurements in the United States, vary by  more than
one order of magnitude. This inherent variability is due to
                                                       differences in cultivation practices, in particular, fertilizer
                                                       type, amount, and mode of application; differences in cultivar
                                                       type; and differences in soil and climatic conditions. A portion
                                                       of this variability is accounted for by separating primary from
                                                       ratooned areas. However, even within a cropping season or
                                                       a given management regime, measured emissions may vary
                                                       significantly. Of the experiments used to derive the emission
                                                       factors  applied here, primary emissions ranged from 22 to
                                                       479 kg CH4/hectare-season and ratoon emissions ranged
                                                       from 481 to 1,490 kg CtLj/hectare-season. The uncertainty
                                                       distributions around the primary and ratoon emission factors
6-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007

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Table 6-13: Non-USDA Data Sources for Rice Harvest Information
State/Crop
Arkansas
Ratoon
Florida
Primary
Ratoon
Louisiana
Ratoon
Oklahoma
Primary
Texas
Ratoon
1990 1999 2000
2001
2002 2003 2004 2005 2006 2007
Wilson (2002-2007)
Scheuneman
(1999b, 1999c, 2000, 2001 a)
Scheuneman
(1999a)
Bollich (2000)
Deren
(2002)
Deren
(2002)
Kirstein
(2003, 2006)
Kirstein Cantens
(2003-2004) (2005)
Linscombe (1999, 2001 a, 2002 through
l_66
(2003-2007)
Klosterboer
(1999-2003)
Gonzales
(2006-2008)
Gonzales
(2006-2008)
2008)
Anderson
(2008)
Stansel Texas Ag Experiment Station
(2004-2005) (2006-2008)
were derived using the distributions of the relevant primary
or ratoon emission factors available in the literature and
described above. Variability about the rice emission factor
means was not normally distributed for either primary or
ratooned crops, but rather skewed, with a tail trailing to the
right of the mean. A lognormal statistical distribution was,
therefore, applied in the Tier 2 Monte Carlo analysis.
    Other sources of uncertainty include the primary rice-
cropped area for each state, percent of rice-cropped area
that is ratooned, and the extent to which flooding outside of
the normal rice season is practiced. Expert judgment was
used to estimate the uncertainty  associated with primary
rice-cropped area for each state at 1 to 5 percent, and a
normal distribution was assumed. Uncertainties were applied
to ratooned area by state, based on the level of reporting
                                performed by the state. No uncertainties were calculated for
                                the practice of flooding outside of the normal rice season
                                because CK4 flux measurements have not been undertaken
                                over a sufficient geographic range or under a broad enough
                                range of representative conditions to account for this source
                                in the emission estimates or its associated uncertainty.
                                    To quantify the uncertainties for emissions from rice
                                cultivation, a  Monte Carlo (Tier 2) uncertainty analysis
                                was performed using the information provided above. The
                                results of the  Tier 2 quantitative uncertainty analysis are
                                summarized in Table 6-14. Rice cultivation CH^ emissions
                                in 2007 were estimated to be between 2.1 and 16.3 Tg CO2
                                Eq. at a 95 percent confidence level, which indicates a range
                                of 66 percent  below to 164 percent above the actual 2007
                                emission estimate of 6.2 Tg CO2 Eq.
Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation
Manure Management (Tg C02 Eq. and Percent)
  Source
       2007 Emission Estimate
Gas         (Tg C02 Eq.)
                    Uncertainty Range Relative to Emission Estimate3
                     (Tg C02 Eq.)                      (%)
                                                       Lower Bound    Upper Bound    Lower Bound    Upper Bound
  Rice Cultivation
CH4
6.2
2.1
16.3
-66%
+ 164%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                                               Agriculture  6-17

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QA/QC and Verification
    A source-specific QA/QC plan for rice cultivation was