EPA430-R-12-001
INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND SINKS:
                        1990-2010
                       APRIL 15, 2012
                U.S. Environmental Protection Agency
                   1200 Pennsylvania Ave., N.W.
                     Washington, DC  20460
                           U.S.A.

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HOW TO OBTAIN COPIES
You can electronically download this document on the U.S. EPA's homepage at
. To request free copies of this report, call
the National Service Center for Environmental Publications (NSCEP) at (800) 490-9198, or visit the web site above
and click on "order online" after selecting an edition.
All data tables of this document are available for the full time series 1990 through 2010, inclusive, at the internet site
mentioned above.
FOR FURTHER INFORMATION
Contact Mr. Leif Hockstad, Environmental Protection Agency, (202) 343-9432, hockstad.leif@epa.gov.
Or Mr. Brian Cook, Environmental Protection Agency, (202) 343-9135, cook.brianb@epa.gov.
For more information regarding climate change and greenhouse gas emissions, see the EPA web site at
.

Released for printing: April 15, 2012

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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 emissions from fuel combustion was led by Leif Hockstad and Brian Cook. Ed Coe and Venu Ghanta
directed the work on mobile  combustion and transportation. Work on industrial process  emissions was led by
Mausami Desai. Work on fugitive methane emissions from the energy sector was directed by Melissa Weitz and
Gate Hight. Calculations for the waste sector were led by Rachel Schmeltz. Tom Wirth directed work on the
Agriculture, and together with Jennifer Jenkins, directed work on the Land Use, Land-Use Change, and Forestry
chapters. Work on emissions of HFCs, PFCs, and SF6 was directed by Deborah Ottinger and Dave Godwin.

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,
Environment, and  Transportation Practice, including Don Robinson, Diana Pape, Michael Grant, Robert Lanza,
Toby Mandel, Lauren Pederson, Mollie Averyt, Ashley  Labrie, Sandy Seastream, Victoria Thompson, Mark Flugge,
Paul Stewart, Tristan Kessler, Katrin Moffroid, Seth Greenburg, Larry O'Rourke, Rubab Bhangu, Deborah Harris,
Emily Rowan, Joseph Indvik, Aaron Sobel, Dean Gouveia, Neha Mukhi, Mariella Cacho, Eric Stricklan, Kevin
Greene, Drew Kane, Alexander Lataille, Pier LaFarge, Leslie Chinery, Nick Devonshire, Andrew Pettit, Rachel
Steele, Mary Beth Riley, Sarah Biggar, Greg Carlock, and Cassandra Snow for synthesizing this report and
preparing many of the individual analyses. Eastern Research Group, RTI International,  Raven Ridge Resources, and
Ruby Canyon Engineering Inc. also provided significant analytical support.

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Preface

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).  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. 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.
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Table of Contents
ACKNOWLEDGMENTS	I
PREFACE	Ill
TABLE OF CONTENTS	V
LIST OF TABLES, FIGURES, AND BOXES	VII
EXECUTIVE SUMMARY	ES-1
ES.l. Background Information	ES-2
ES.2. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks	ES-4
ES.3. Overview of Sector Emissions and Trends	ES-11
ES.4. Other Information	ES-14
1.    INTRODUCTION	1-1
1.1.    Background Information	1-2
1.2.    Institutional Arrangements	1-9
1.3.    Inventory Process	1-10
1.4.    Methodology and Data Sources	1-11
1.5.    Key Categories	1-12
1.6.    Quality Assurance and Quality Control (QA/QC)	1-15
1.7.    Uncertainty Analysis of Emission Estimates	1-17
1.8.    Completeness	1-18
1.9.    Organization  of Report	1-18
2.    TRENDS  IN GREENHOUSE GAS EMISSIONS	2-1
2.1.    Recent Trends in U.S. Greenhouse Gas Emissions and Sinks	2-1
2.2.    Emissions by Economic Sector	2-15
2.3.    Indirect Greenhouse Gas Emissions (CO, NOx, NMVOCs, and SO2)	2-26
3.    ENERGY	3-1
3.1.    Fossil Fuel Combustion (IPCC Source Category 1A)	3-3
3.2.    Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A)	3-30
3.3.    Incineration of Waste (IPCC Source Category lAla)	3-36
3.4.    Coal Mining (IPCC Source Category IBla)	3-39
3.5.    Abandoned Underground Coal Mines (IPCC Source Category IBla)	3-42
3.6.    Natural Gas Systems (IPCC Source Category lB2b)	3-46
3.7.    Petroleum Systems (IPCC Source Category lB2a)	3-51
3.8.    Energy Sources of Indirect Greenhouse Gas Emissions	3-57
3.9.    International Bunker Fuels (IPCC Source Category 1: Memo Items)	3-58
3.10.   Wood Biomass and Ethanol Consumption (IPCC Source Category 1A)	3-62
4.    INDUSTRIAL  PROCESSES	4-1

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4.1.     Cement Production (IPCC Source Category 2Al)	4-4
4.2.     Lime Production (IPCC Source Category 2A2)	4-7
4.3.     Limestone and Dolomite Use (IPCC Source Category 2A3)	4-11
4.4.     Soda Ash Production and Consumption (IPCC Source Category 2A4)	4-14
4.5.     Ammonia Production (IPCC Source Category 2B1)	4-18
4.6.     Urea Consumption for Non-Agricultural Purposes	4-21
4.7.     Nitric Acid Production (IPCC Source Category 2B2)	4-23
4.8.     Adipic Acid Production (IPCC Source Category 2B3)	4-26
4.9.     Silicon Carbide Production (IPCC Source Category 2B4) and Consumption	4-28
4.10.    Petrochemical Production (IPCC Source Category 2B5)	4-31
4.11.    Titanium Dioxide Production (IPCC Source Category 2B5)	4-34
4.12.    Carbon Dioxide Consumption (IPCC Source Category 2B5)	4-36
4.13.    Phosphoric Acid Production (IPCC Source Category 2B5)	4-39
4.14.    Iron and Steel Production (IPCC Source Category 2C1) and Metallurgical Coke Production	4-42
4.15.    Ferroalloy Production (IPCC Source Category 2C2)	4-52
4.16.    Aluminum Production (IPCC Source Category 2C3)	4-55
4.17.    Magnesium Production and Processing (IPCC Source Category 2C4)	4-59
4.18.    Zinc Production (IPCC Source Category 2C5)	4-62
4.19.    Lead Production (IPCC Source Category 2C5)	4-65
4.20.    HCFC-22 Production (IPCC Source Category 2E1)	4-67
4.21.    Substitution of Ozone Depleting  Substances (IPCC Source Category 2F)	4-70
4.22.    Semiconductor Manufacture (IPCC Source Category 2F6)	4-74
4.23.    Electrical Transmission and Distribution (IPCC Source Category 2F7)	4-79
4.24.    Industrial Sources of Indirect Greenhouse Gases	4-83
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.     Rice Cultivation (IPCC Source Category 4C)	6-13
6.4.     Agricultural Soil Management (IPCC Source Category 4D)	6-17
6.5.     Field Burning of Agricultural Residues (IPCC Source Category 4F)	6-29
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	7-12
7.3.     Land Converted to Forest Land (IPCC Source Category 5A2)	7-25

vi  Inventory of  U.S. Greenhouse Gas Emissions  and Sinks: 1990-2010

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7.4.     Cropland Remaining Cropland (IPCC Source Category 5B1)	7-25
7.5.     Land Converted to Cropland (IPCC Source Category 5B2)	7-36
7.6.     Grassland Remaining Grassland (IPCC Source Category 5C1)	7-39
7.7.     Land Converted to Grassland (IPCC Source Category 5C2)	7-43
7.8.     Wetlands Remaining Wetlands	7-46
7.9.     Settlements Remaining Settlements	7-50
7.10.    Land Converted to Settlements (Source Category 5E2)	7-57
7.11.    Other (IPCC Source Category 5G)	7-57
8.    WASTE	8-1
8.1.     Landfills (IPCC Source Category 6A1)	8-3
8.2.     Wastewater Treatment (IPCC Source Category 6B)	8-8
8.3.     Composting (IPCC Source Category 6D)	8-20
8.4.     Waste Sources of Indirect Greenhouse Gases	8-22
9.    OTHER	9-1
10.   RECALCULATIONS AND IMPROVEMENTS	10-1
11.   REFERENCES	11-1


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 or million metric tons CO2 Eq.) ..ES-4
Table ES-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Consuming End-Use Sector (Tg or million metric
tonsCO2Eq.)	ES-8
Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/TPCC Sector (Tg or million
metric tons CO2 Eq.)	ES-11
Table ES-5: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg or million metric tons CO2 Eq.)..ES-
13
Table ES-6: Emissions from Land Use, Land-Use Change, and Forestry (Tg or million metric tons CO2 Eq.) ..ES-13
Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg or million metric tons CO2 Eq.)
	ES-15
Table ES-8: U.S Greenhouse Gas Emissions by Economic Sector with Electricity-Related Emissions Distributed
(Tg or million metric tons CO2 Eq.)	ES-15
Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100)	ES-16
Table ES-10: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)	ES-17
Table 1-1: Global Atmospheric Concentration, Rate of Concentration Change, and Atmospheric Lifetime (years) of
Selected Greenhouse Gases	1-4
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report	1-8
Table 1-3: Comparison of 100-Year GWPs	1-9
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Table 1-4: Key Categories for the United States (1990-2010)	1-13
Table 1 -5:  Estimated Overall Inventory Quantitative Uncertainty (Tg CO2 Eq. and Percent)	1-17
Table 1-6:  IPCC Sector Descriptions	1-18
Table 1-7:  List of Annexes	1-20
Table 2-1:  Recent Trends inU.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)	2-3
Table 2-2:  Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)	2-5
Table 2-3:  Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)... 2-7
Table 2-4:  Emissions from Energy (Tg CO2Eq.)	2-8
Table 2-5:  CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)	2-9
Table 2-6:  Emissions from Industrial Processes (TgCO2Eq.)	2-10
Table 2-7:  N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.)	2-12
Table 2-8:  Emissions from Agriculture (Tg CO2 Eq.)	2-12
Table 2-9: Net CO2 Flux fromLand Use, Land-Use Change, and Forestry (Tg CO2 Eq.)	2-13
Table 2-10: Emissions from Land Use, Land-Use Change, and Forestry (TgCO2Eq.)	2-14
Table 2-11: Emissions from Waste (Tg CO2 Eq.)	2-15
Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent of Total in
2010)	2-16
Table 2-13: Electricity Generation-Related Greenhouse Gas Emissions (TgCO2Eq.)	2-18
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 2010	2-19
Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)	2-22
Table 2-16: Recent Trends in Various U.S. Data (Index 1990 = 100)	2-25
Table 2-17: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)	2-26
Table 3-1:  CO2, CH4, and N2O Emissions from Energy (TgCO2Eq.)	3-1
Table 3-2:  CO2, CH4, andN2O Emissions fromEnergy (Gg)	3-2
Table 3-3:  CO2, CH4, and N2O Emissions from Fossil Fuel  Combustion (Tg CO2 Eq.)	3-3
Table 3-4:  CO2, CH4, 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.)	3-4
Table 3-6:  Annual Change in CO2 Emissions and Total  2010 Emissions from Fossil Fuel Combustion for Selected
Fuels and Sectors (Tg CO2 Eq. and Percent)	3-5
Table 3 -7:  CO2, CH4, and N2O Emissions from Fossil Fuel  Combustion by Sector (Tg CO2 Eq.)	3-7
Table 3 -8:  CO2, CH4, and N2O Emissions from Fossil Fuel  Combustion by End-Use Sector (Tg CO2 Eq.)	3-8
Table 3-9: CO2 Emissions from Stationary Fossil Fuel Combustion (Tg CO2 Eq.)	3-8
Table 3-10: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.)	3-10
Table 3-11: N2O Emissions from Stationary Combustion (Tg CO2 Eq.)	3-10
Table 3-12: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.)a	3-14
Table 3-13: CH4 Emissions from Mobile Combustion (Tg CO2 Eq.)	3-16
Table 3-14: N2O Emissions fromMobile Combustion (Tg CO2 Eq.)	3-16

viii   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 3-15: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu)	3-20
Table 3-16: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related Fossil Fuel
Combustion by Fuel Type and Sector (TgCO2Eq. and Percent)	3-22
Table 3-17: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Energy-Related Stationary
Combustion, Including Biomass (TgCO2Eq. and Percent)	3-26
Table 3-18: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Mobile Sources (Tg CO2
Eq. and Percent)	3-28
Table 3-19: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2 Eq.)	3-31
Table 3-20: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)	3-31
Table 3-21: 2010 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions	3-32
Table 3-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses of Fossil Fuels
(Tg CO2 Eq. and Percent)	3-33
Table 3-23: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
(Percent)	3-34
Table 3-24: CO2 and N2O Emissions from the Incineration of Waste (Tg CO2 Eq.)	3-36
Table 3-25: CO2 and N2O Emissions from the Incineration of Waste (Gg)	3-36
Table 3-26: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted	3-38
Table 3-27: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from the Incineration of Waste (Tg CO2 Eq.
and Percent)	3-38
Table 3-28: CH4 Emissions from Coal Mining (Tg CO2 Eq.)	3-40
Table 3-29: CH4 Emissions from Coal Mining (Gg)	3-40
Table 3-30: Coal  Production (Thousand Metric Tons)	3-41
Table 3-31: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
Percent)	3-42
Table 3-32: CH4 Emissions from Abandoned Coal Mines (Tg CO2 Eq.)	3-43
Table 3-33: CH4 Emissions from Abandoned Coal Mines (Gg)	3-43
Table 3-34: Number of gassy abandoned mines occurring in U.S. basins grouped by class according to post-
abandonment state 	3-44
Table 3-35: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
Mines (Tg CO2 Eq. and Percent)	3-45
Table 3-36: CH4 Emissions from Natural Gas Systems (TgCO2Eq.)*	3-47
Table 3-37: CH4Emissions from Natural Gas Systems (Gg)*	3-47
Table 3-38: Calculated Potential CH4 and Captured/Combusted CH4 from Natural Gas Systems (Tg CO2 Eq.)... 3-47
Table 3-39: Non-combustion CO2 Emissions from Natural Gas Systems (TgCO2Eq.)	3-48
Table 3-40: Non-combustion CO2 Emissions from Natural Gas Systems (Gg)	3-48
Table 3-41: Tier 2 Quantitative Uncertainty Estimates for CH4 and Non-energy CO2 Emissions from Natural Gas
Systems (Tg CO2  Eq. and Percent)	3-50
Table 3-42: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.)	3-52
Table 3-43: CH4 Emissions from Petroleum Systems (Gg)	3-52
Table 3-44: CO2 Emissions from Petroleum Systems (Tg CO2 Eq.)	3-53
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Table 3-45: CO2 Emissions from Petroleum Systems (Gg)	3-53
Table 3-46: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
Percent)	3-55
Table 3-47: Potential Emissions from CO2 Capture and Transport (Tg CO2 Eq.)	3-57
Table 3-48: Potential Emissions from CO2 Capture and Transport (Gg)	3-57
Table 3-49: NOX, CO, and NMVOC Emissions from Energy-Related Activities (Gg)	3-57
Table 3-50: CO2, CH4, and N2O Emissions from International Bunker Fuels (Tg CO2 Eq.)	3-59
Table 3-51: CO2, CH4 and N2O Emissions from International Bunker Fuels (Gg)	3-60
Table 3 -52: Aviation Jet Fuel Consumption for International Transport (Million Gallons)	3-61
Table 3-53: Marine Fuel Consumption for International Transport (Million Gallons)	3-61
Table 3-54: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.)	3-63
Table 3-55: CO2 Emissions from Wood Consumption by End-Use Sector (Gg)	3-63
Table 3-56: CO2 Emissions from Ethanol Consumption (Tg CO2 Eq.)	3-63
Table 3-57: CO2 Emissions fromEthanol Consumption (Gg)	3-63
Table 3-58: Woody Biomass Consumption by Sector (Trillion Btu)	3-64
Table 3-59: Ethanol Consumption by Sector (Trillion Btu)	3-64
Table 4-1: Emissions from Industrial Processes (TgCO2Eq.)	4-2
Table 4-2: Emissions from Industrial Processes (Gg)	4-3
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)	4-8
Table 4-8: High-Calcium- and Dolomitic-Quicklime, High-Calcium- and Dolomitic-Hydrated, and Dead-Burned-
Dolomite Lime Production (Gg)	4-9
Table 4-9: Adjusted Lime Production3 (Gg)	4-9
Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Production (Tg CO2 Eq. and
Percent)	4-11
Table 4-11: CO2 Emissions from Limestone & Dolomite Use (Tg CO2Eq.)	4-12
Table 4-12: CO2 Emissions from Limestone & Dolomite Use (Gg)	4-12
Table 4-13: Limestone and Dolomite Consumption (Thousand Metric Tons)	4-13
Table 4-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Limestone and Dolomite Use (Tg
CO2 Eq. and Percent)	4-13
Table 4-15: CO2 Emissions from Soda Ash Production and Consumption (Tg CO2 Eq.)	4-15
Table 4-16: CO2 Emissions from Soda Ash Production and Consumption (Gg)	4-15
Table 4-17: Soda Ash Production and Consumption (Gg)	4-17
Table 4-18: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Production and
Consumption (Tg CO2 Eq. and Percent)	4-17
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Table 4-19: CO2 Emissions from Ammonia Production (Tg CO2 Eq.)	4-19
Table 4-20: CO2 Emissions from Ammonia Production (Gg)	4-19
Table 4-21: Ammonia Production and Urea Production (Gg)	4-20
Table 4-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Production (Tg CO2 Eq.
and Percent)	4-20
Table 4-23: CO2 Emissions from Urea Consumption for Non-Agricultural Purposes (Tg CO2 Eq.)	4-22
Table 4-24: CO2 Emissions from Urea Consumption for Non-Agricultural Purposes (Gg)	4-22
Table 4-25: Urea Production, Urea Applied as Fertilizer, Urea Imports, and Urea Exports (Gg)	4-23
Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Urea Consumption for Non-
Agricultural Purposes (TgCO2Eq. and Percent)	4-23
Table 4-27: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg)	4-24
Table 4-28: Nitric Acid Production (Gg)	4-24
Table 4-29: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
and Percent)	4-25
Table 4-30: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg)	4-26
Table 4-31: Adipic Acid Production (Gg)	4-27
Table 4-32: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
Eq. and Percent)	4-28
Table 4-33: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Tg CO2 Eq.)	4-29
Table 4-34: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Gg)	4-29
Table 4-35: Production and Consumption of Silicon Carbide (Metric Tons)	4-30
Table 4-36: Tier 2 Quantitative Uncertainty Estimates for CH4 and CO2 Emissions from Silicon Carbide Production
and Consumption (Tg CO2 Eq. and Percent)	4-30
Table 4-37: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.)	4-31
Table 4-38: CO2and CH4 Emissions from Petrochemical Production (Gg)	4-31
Table 4-39: Production of Selected Petrochemicals (Thousand Metric Tons)	4-32
Table 4-40: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
Consumption (Thousand Metric Tons)	4-33
Table 4-41: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
Emissions from Carbon Black Production (Tg CO2 Eq. and Percent)	4-33
Table 4-42: CO2 Emissions from Titanium Dioxide (TgCO2Eq. andGg)	4-34
Table 4-43: Titanium Dioxide Production (Gg)	4-35
Table 4-44: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
CO2 Eq. and Percent)	4-36
Table 4-45: CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and Gg)	4-37
Table 4-46: CO2 Production (Gg CO2) and the Percent Used for Non-EOR  Applications	4-38
Table 4-47: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and
Percent)	4-38
Table 4-48: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg)	4-40
Table 4-49: Phosphate  Rock Domestic Production, Exports, and Imports (Gg)	4-41
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Table 4-50: Chemical Composition of Phosphate Rock (percent by weight)	4-41
Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
CO2 Eq. and Percent)	4-42
Table 4-52: CO2 and CH4 Emissions from Metallurgical Coke Production (Tg CO2 Eq.)	4-44
Table 4-53: CO2 and CH4 Emissions from Metallurgical Coke Production (Gg)	4-44
Table 4-54: CO2 Emissions from Iron and Steel Production (Tg CO2 Eq.)	4-45
Table 4-55: CO2 Emissions from Iron and Steel Production (Gg)	4-45
Table 4-56: CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.)	4-45
Table 4-57: CH4 Emissions from Iron and Steel Production (Gg)	4-45
Table 4-58: Material Carbon Contents for Metallurgical Coke Production	4-46
Table 4-59: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Metallurgical
Coke Production (Thousand Metric Tons)	4-47
Table 4-60: Production and Consumption Data for the Calculation of CO2 Emissions from Metallurgical Coke
Production (million ft3)	4-47
Table 4-61: CO2 Emission Factors for Sinter Production and Direct Reduced Iron Production	4-47
Table 4-62: Material Carbon Contents for Iron and Steel Production	4-48
Table 4-63: CH4 Emission Factors for Sinter and Pig Iron Production	4-49
Table 4-64: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Iron and Steel
Production (Thousand Metric Tons)	4-50
Table 4-65: Production and Consumption Data for the Calculation of CO2 Emissions from Iron and Steel
Production (million ft3 unless otherwise specified)	4-50
Table 4-66: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
and Metallurgical Coke Production (Tg. CO2Eq. and Percent)	4-51
Table 4-67: CO2 and CH4 Emissions from Ferroalloy Production (Tg CO2 Eq.)	4-52
Table 4-68: CO2 and CH4 Emissions from Ferroalloy Production (Gg)	4-53
Table 4-69: Production of Ferroalloys (Metric Tons)	4-53
Table 4-70: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
and Percent)	4-54
Table 4-71: CO2 Emissions from Aluminum Production (Tg CO2 Eq. and Gg)	4-55
Table 4-72: PFC Emissions from Aluminum Production (Tg CO2 Eq.)	4-55
Table 4-73: PFC Emissions from Aluminum Production (Gg)	4-56
Table 4-74: Production of Primary Aluminum (Gg)	4-58
Table 4-75: Tier 2 Quantitative Uncertainty Estimates for CO2 and PFC Emissions from Aluminum Production (Tg
CO2 Eq. and Percent)	4-58
Table 4-76: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg)	4-59
Table 4-77: SF6 Emission Factors (kg SF6 per metric ton of magnesium)	4-60
Table 4-78: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
Processing (Tg CO2 Eq. and Percent)	4-62
Table 4-79: Zinc Production (Metric Tons)	4-63
Table 4-80: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Zinc Production (Tg CO2 Eq. and
xii   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Percent)	4-65
Table 4-81: CO2 Emissions from Lead Production (Tg CO2 Eq. andGg)	4-66
Table 4-82: Lead Production (Metric Tons)	4-66
Table 4-83: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lead Production (Tg CO2 Eq. and
Percent)	4-67
Table 4-84: HFC-23 Emissions fromHCFC-22 Production (Tg CO2 Eq. and Gg)	4-68
Table 4-85: HCFC-22 Production (Gg)	4-69
Table 4-86: Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and
Percent)	4-69
Table 4-87: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.)	4-70
Table 4-88: Emissions of HFCs and PFCs from ODS Substitution (Mg)	4-70
Table 4-89: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.) by Sector	4-71
Table 4-90: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitutes (Tg CO2
Eq. and Percent)	4-73
Table 4-91: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.)	4-74
Table 4-92: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)	4-74
Table 4-4-93:  Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
Manufacture (Tg CO2 Eq. and Percent)	4-78
Table 4-94: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Tg CO2 Eq.).. 4-
79
Table 4-95: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Gg)	4-79
Table 4-96: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg CO2 Eq. and percent)	4-82
Table 4-97: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)	4-83
Table 5-1: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg)	5-1
Table 5-2: N2O Production (Gg)	5-1
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 CO2Eq.)	6-1
Table 6-2: Emissions from Agriculture (Gg)	6-1
Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.)	6-2
Table 6-4: CH4 Emissions from Enteric Fermentation (Gg)	6-3
Table 6-5: Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg CO2 Eq. and
Percent)	6-5
Table 6-6: CH4 and N2O Emissions fromManure Management (Tg CO2Eq.)	6-8
Table 6-7: CH4 and N2O Emissions fromManure 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
                                                                                               xill

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Table 6-9: CH4 Emissions from Rice Cultivation (Tg CO2 Eq.)	6-14
Table 6-10: CH4 Emissions from Rice Cultivation (Gg)	6-14
Table 6-11: Rice Areas Harvested (Hectares)	6-15
Table 6-12: Ratooned Area as Percent of Primary Growth Area	6-16
Table 6-13: Non-USDA Data Sources for Rice Harvest Information	6-16
Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
Percent)	6-17
Table 6-15: N2O Emissions from Agricultural Soils (Tg CO2 Eq.)	6-18
Table 6-16: N2O Emissions from Agricultural Soils (Gg)	6-19
Table 6-17: Direct N2O Emissions from Agricultural Soils by Land Use Type and N Input Type (Tg CO2 Eq.)... 6-19
Table 6-6-18: Indirect N2O Emissions from all Land-Use Types (TgCO2Eq.)	6-20
Table 6-19: Quantitative Uncertainty Estimates of N2O Emissions from Agricultural Soil Management in 2010 (Tg
CO2 Eq. and Percent)	6-27
Table 6-20: CH4 and N2O Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.)	6-29
Table 6-21: CH4, N2O, CO, and NOX Emissions from Field Burning of Agricultural Residues (Gg)	6-29
Table 6-22: Agricultural Crop Production (Gg of Product)	6-32
Table 6-23: U.S. Average Percent Crop Area Burned by Crop (Percent)	6-32
Table 6-24: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues	6-32
Table 6-25: Greenhouse Gas Emission Ratios and Conversion Factors	6-32
Table 6-26: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Field Burning of
Agricultural Residues (TgCO2Eq. and Percent)	6-33
Table 7-1: Net CO2 Flux from Carbon Stock Changes in Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.) 7-
1
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 (TgCO2Eq.)	7-2
Table 7-4: Emissions from Land Use, Land-Use Change, and Forestry (Gg)	7-3
Table 7-5: Size of Land Use and Land-Use Change Categories on Managed Land Area by Land Use and Land Use
Change Categories (thousands of hectares)	7-5
Table 7-6: Net Annual Changes inC Stocks (TgCO2/yr) in Forest and Harvested Wood Pools	7-14
Table 7-7: Net Annual Changes in C Stocks (Tg C/yr) in Forest and Harvested Wood Pools	7-15
Table 7-8: Forest area (1000 ha) and C Stocks (Tg C) inForest and Harvested Wood Pools	7-15
Table 7-9: Estimates of CO2 (Tg/yr) emissions for the lower 48 states and Alaska1	7-16
Table 7-10: Tier 2 Quantitative Uncertainty Estimates for Net CO2 Flux from Forest Land Remaining Forest Land:
Changes inForest C Stocks (Tg CO2 Eq. and Percent)	7-20
Table 7-11: Estimated Non-CO2 Emissions from Forest Fires (Tg CO2Eq.) for U.S. Forests1	7-22
Table 7-12: Estimated Non-CO2 Emissions from Forest Fires (Gg Gas) for U.S. Forests1	7-22
Table 7-13: Estimated Carbon Released from Forest Fires for U.S. Forests	7-22
Table 7-14: Tier 2 Quantitative Uncertainty Estimates of Non-CO2 Emissions from Forest Fires in Forest Land
Remaining Forest Land (Tg CO2 Eq. and Percent)	7-23
xiv  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 7-15: Direct N2O Fluxes from Soils in Forest Land Remaining Forest Land (Tg CO2 Eq. and Gg N2O).... 7-24
Table 7-16: Quantitative Uncertainty Estimates of N2O Fluxes from Soils in Forest Land Remaining Forest Land
(Tg CO2 Eq. and Percent)	7-25
Table 7-17: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg CO2 Eq.)	7-27
Table 7-18: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg C)	7-27
Table 7-19: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Cropland
Remaining Cropland (Tg CO2 Eq. and Percent)	7-31
Table 7-20: Emissions from Liming of Agricultural Soils (Tg CO2Eq.)	7-32
Table 7-21: Emissions from Liming of Agricultural Soils (TgC)	7-32
Table 7-22: Applied Minerals (Million Metric Tons)	7-33
Table 7-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Liming of Agricultural Soils (Tg
CO2 Eq. and Percent)	7-34
Table 7-24: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg CO2 Eq.)	7-35
Table 7-25: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg C)	7-35
Table 7-26: Applied Urea (Million Metric Tons)	7-35
Table 7-27: Quantitative Uncertainty Estimates for CO2 Emissions from Urea Fertilization (Tg CO2 Eq. and Percent)
	7-36
Table 7-28: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg CO2 Eq.)	7-37
Table 7-29: Net CO2 Flux from Soil C Stock Changes inLand Converted to Cropland (Tg C)	7-37
Table 7-30: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
Cropland (Tg CO2 Eq. and Percent)	7-39
Table 7-31: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg CO2 Eq.)	7-40
Table 7-32: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg C)	7-40
Table 7-33: Tier 2 Quantitative Uncertainty Estimates for C Stock Changes occurring within Grassland Remaining
Grassland (Tg CO2 Eq. and Percent)	7-42
Table 7-34: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg CO2 Eq.)	7-44
Table 7-35: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg C)	7-44
Table 7-36: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
Grassland (Tg CO2Eq. and Percent)	7-46
Table 7-37: Emissions from PeatlandsRemaining Peatlands (Tg CO2 Eq.)	7-47
Table 7-38: Emissions from Peatlands Remaining Peatlands (Gg)	7-48
Table 7-39: Peat Production of Lower 48 States (in thousands of Metric Tons)	7-49
Table 7-40: Peat Production of Alaska (in thousands of Cubic Meters)	7-49
Table 7-41: Tier-2 Quantitative Uncertainty Estimates for CO2 Emissions from Peatlands Remaining Peatlandsl-50
Table 7-42: Net C Flux from Urban Trees (Tg CO2 Eq.  and Tg  C)	7-51
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-yr) for 14 U.S. Cities	7-53
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)	7-54
Table 7-45: Direct N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2Eq. and GgN2O)	7-55
                                                                                                  xv

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Table 7-46: Quantitative Uncertainty Estimates of N2O Emissions from Soils in Settlements Remaining Settlements
(Tg CO2 Eq. and Percent)	7-57
Table 7-47: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg CO2 Eq.)	7-58
Table 7-48: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C)	7-58
Table 7-49: Moisture Content (%), C Storage Factor, Proportion of Initial C Sequestered (%), Initial C Content (%),
and Decay Rate (year"1) for Landfilled Yard Trimmings and Food Scraps in Landfills	7-60
Table 7-50: C Stocks in Yard Trimmings and Food Scraps in Landfills (Tg C)	7-60
Table 7-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and Food Scraps in
Landfills (Tg CO2 Eq. and Percent)	7-61
Table 8-1:  Emissions from Waste (Tg CO2 Eq.)	8-2
Table 8-2:  Emissions from Waste (Gg)	8-2
Table 8-3:  CH4 Emissions from Landfills (Tg CO2 Eq.)	8-4
Table 8-4 :CH4 Emissions from Landfills (Gg)	8-4
Table 8-5:  Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Landfills (Tg CO2 Eq. and Percent)8-6
Table 8-6:  CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.)	8-9
Table 8-7:  CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Gg)	8-9
Table 8-8:  U.S. Population (Millions) and Domestic Wastewater BOD5 Produced (Gg)	8-11
Table 8-9:  Domestic Wastewater CH4 Emissions from Septic and Centralized Systems (2010)	8-11
Table 8-10: Industrial Wastewater CH4 Emissions by Sector (2010)	8-12
Table 8-11: U.S. Pulp and Paper, Meat, Poultry, Vegetables, Fruits and Juices, Ethanol, and Petroleum Refining
Production (Tg)	8-12
Table 8-12: Variables Used to Calculate Percent Wastewater Treated Anaerobically by Industry (%)	8-13
Table 8-13:  Wastewater Flow (m3/ton) and BOD Production (g/L) for U.S. Vegetables, Fruits, and Juices Production
	8-14
Table 8-14:  U.S. Population (Millions), Available Protein (kg/person-year), and Protein Consumed (kg/person-year)
	8-17
Table 8-15:  Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Wastewater Treatment (Tg CO2 Eq.
and Percent)	8-18
Table 8-16:  CH4 and N2O Emissions from Composting (Tg CO2Eq.)	8-21
Table 8-17:  CH4 and N2O Emissions from Composting (Gg)	8-21
Table 8-18:  U.S. Waste Composted (Gg)	8-21
Table 8-19 : Tier 1 Quantitative Uncertainty Estimates for Emissions from Composting  (Tg CO2 Eq. and Percent) 8-
22
Table 8-20:  Emissions of NOX, CO, and NMVOC from Waste (Gg)	8-22
Table 10-1:  Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.)	10-5
Table 10-2:  Revisions to Annual Net CO2 Fluxes from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.) 10-7
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 Annual U.S. Greenhouse Gas Emissions Relative to 1990	ES-4

xvi   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Figure ES-4: 2010 Greenhouse Gas Emissions by Gas (percentages based on Tg CO2 Eq.)	ES-6
Figure ES-5: 2010 Sources of CO2 Emissions	ES-7
Figure ES-6: 2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	ES-7
Figure ES-7: 2010 End-Use Sector Emissions of CO2, CH4, andN2O from Fossil Fuel Combustion	ES-7
Figure ES-8: 2010 Sources of CH4 Emissions	ES-9
Figure ES-9: 2010 Sources of N2O Emissions	ES-10
Figure ES-10: 2010 Sources of HFCs, PFCs, and SF6 Emissions	ES-11
Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/TPCC Sector	ES-11
Figure ES-12: 2010 U.S. Energy  Consumption by Energy Source	ES-12
Figure ES-13: Emissions Allocated to Economic Sectors	ES-14
Figure ES-14: Emissions with Electricity Distributed to Economic Sectors	ES-16
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product	ES-16
Figure ES-16: 2010 Key Categories	ES-18
Figure 1-1:  U.S. QA/QC Plan Summary	1-16
Figure 2-1:  U.S. Greenhouse Gas Emissions by Gas	2-1
Figure 2-2:  Annual Percent Change in U.S. Greenhouse Gas Emissions	2-1
Figure 2-3:  Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990	2-1
Figure 2-4:  U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector	2-7
Figure 2-5: 2010 Energy Chapter Greenhouse Gas Sources	2-8
Figure 2-6: 2010 U.S. Fossil CarbonFlows (Tg CO2 Eq.)	2-8
Figure 2-7:  2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	2-9
Figure 2-8:  2010 End-Use Sector Emissions fromFossil Fuel Combustion	2-9
Figure 2-9:  2010 Industrial Processes Chapter Greenhouse Gas Sources	2-10
Figure 2-10: 2010 Agriculture Chapter Greenhouse Gas Sources	2-12
Figure 2-11: 2010 Waste Chapter Greenhouse Gas Sources	2-15
Figure 2-12: Emissions Allocated to Economic Sectors	2-16
Figure 2-13: Emissions with Electricity Distributed to Economic Sectors	2-19
Figure 2-14: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product	2-25
Figure 3-1:  2010 Energy Chapter Greenhouse Gas Sources	3-1
Figure 3-2:  2010 U.S. Fossil CarbonFlows (Tg CO2 Eq.)	3-1
Figure 3-3:  2010 U.S. Energy Consumption by Energy Source	3-5
Figure 3-4:  U.S. Energy Consumption (Quadrillion Btu)	3-5
Figure 3-5:  2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type	3-5
Figure 3-6:  Annual Deviations from Normal Heating Degree Days for the United States (1950-2010)	3-6
Figure 3-7:  Annual Deviations from Normal Cooling Degree Days for the United States (1950-2010)	3-6
Figure 3-8:  Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2010).... 3-6
Figure 3-9:  Electricity Generation Retail Sales by End-Use Sector	3-11
                                                                                                 xvn

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Figure 3-10:  Industrial Production Indices (Index 2007= 100)	3-12
Figure 3-11:  Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2010	3-14
Figure 3-12:  Sales of New Passenger Cars and Light-Duty Trucks, 1990-2010	3-14
Figure 3-13:  Mobile Source CH4 and N2O Emissions	3-16
Figure 3-14:  U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP	3-21
Figure 4-1: 2010 Industrial Processes Chapter Greenhouse Gas Sources	4-1
Figure 6-1: 2010 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	6-18
Figure 6-3: Major Crops, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-
2010(TgCO2Eq./year)	6-20
Figure 6-4: Grasslands, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-2010
(Tg CO2 Eq./year)	6-20
Figure 6-5: Major Crops, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
DAYCENT Model, 1990-2010 (GgN/year)	6-20
Figure 6-6: Grasslands, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
DAYCENT Model, 1990-2010 (GgN/year)	6-21
Figure 6-7: Comparison of Measured Emissions at Field Sites and Modeled Emissions Using the DAYCENT
Simulation Model	6-28
Figure 7-1. Percent of Total Land Area in the General Land-Use Categories for 2010	7-6
Figure 7-2: Forest Sector Carbon Pools and Flows	7-13
Figure 7-3: Estimates of Net Annual Changes inC  Stocks for Major C Pools	7-15
Figure 7-4: Average C Density in the Forest Tree Pool in the Conterminous United States, 2010	7-15
Figure 7-5: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2010,
Cropland Remaining Cropland	7-27
Figure 7-6: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2010,
Cropland Remaining Cropland	7-27
Figure 7-7: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2010, Land
Converted to Cropland	7-37
Figure 7-8: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2010, Land
Converted to Cropland	7-37
Figure 7-9: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2010,
Grassland Remaining Grassland	7-40
Figure 7-10:  Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2010,
Grassland Remaining Grassland	7-40
Figure 7-11:  Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2010,
Land Converted to Grassland	7-44
Figure 7-12:  Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2010,
Land Converted to Grassland	7-44
Figure 8-1: 2010 Waste Chapter Greenhouse Gas Sources	8-1
xviii   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Boxes
BoxES-
BoxES-
BoxES-
Box 1-1
Box 1-2
Box 1-3
Box 2-1
Box 2-2
Box 2-3
Box 3-1
Box 3-2
Box 3-3
Box 4-1
Box 6-1.
Box 6-2:
Box 7-1:
Box 7-2:
Box 7-3:
Box 8-1:
Box 8-2:
Box 8-3:
1: Methodological approach for estimating and reporting U.S. emissions and sinks	ES-1
2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data	ES-16
3: Recalculations of Inventory Estimates	ES-19
Methodological approach for estimating and reporting U.S. emissions and sinks	1-2
The IPCC Fourth Assessment Report and Global Warming Potentials	1-8
IPCC Reference Approach	1-12
 Methodology for Aggregating Emissions by Economic Sector	2-23
 Recent Trends in Various U.S.  Greenhouse Gas Emissions-Related Data	2-25
 Sources and Effects of Sulfur Dioxide	2-27
 Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends	3-6
 Carbon Intensity of U.S. Energy Consumption	3-20
 Carbon Dioxide Transport, Injection, and Geological Storage	3-56
Industrial Processes Data from EPA's Greenhouse Gas Reporting Program	4-4
 Tier 1 vs. Tier 3 Approach for Estimating N2O Emissions	6-22
Comparison of Tier 2 U.S.  Inventory Approach and IPCC (2006) Default Approach	6-30
Methodological approach for estimating and reporting U.S. emissions and sinks	7-3
 CO2 Emissions from Forest Fires	7-16
Tier 3 Approach for Soil C Stocks Compared to Tier 1 or 2 Approaches	7-28
Methodological approach for estimating and reporting U.S. emissions and sinks	8-1
Waste Data from the Greenhouse Gas Reporting Program	8-2
 Biogenic Wastes in Landfills	8-7
                                                                                                xix

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Executive  Summary
An emissions inventory that identifies and quantifies a country's primary anthropogenic l 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 2010.  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
1996 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse  Gas Inventories
(IPCC/UNEP/OECD/IEA 1997), the IPCC Good Practice Guidance and Uncertainty Management in National
Greenhouse Gas Inventories (IPCC 2000), and the IPCC Good Practice Guidance for Land Use, Land-Use Change,
and Forestry (IPCC 2003). Additionally, the U.S. emission inventory has continued 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 IPCC methodologies were expanded, resulting in a more comprehensive and  detailed estimate of
emissions.
[BEGIN BOX]

Box ES-1: Methodological approach for estimating and reporting U.S. emissions and sinks

In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
inventories, the emissions and sinks presented in this report are organized by source and sink categories and
calculated using internationally-accepted methods provided by the IPCC.5 Additionally, the calculated emissions
and sinks in a given year for the United States are presented in a common manner in line with the UNFCCC
reporting guidelines for the reporting of inventories under this international agreement.6 The use of consistent
methods to calculate emissions and sinks by all nations providing their inventories to the UNFCCC ensures that
1 The term "anthropogenic," in this context, refers to greenhouse gas emissions and removals that are a direct result of human
activities or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
2 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate
Change. See .
3 Article 4(1 Xa) of the United Nations Framework Convention on Climate Change (also identified in Article 12). Subsequent
decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories.  See
.
4 See < http://unfccc.int/resource/docs/2006/sbsta/eng/09.pdf>.
5 See < http://www.ipcc-nggip.iges.or.jp/public/index.html>.
6 See.


                                                                               Executive Summary   ES-1

-------
these reports are comparable. In this regard, U.S. emissions and sinks reported in this inventory report are
comparable to emissions and sinks reported by other countries.  Emissions and sinks provided in this inventory do
not preclude alternative examinations, but rather this inventory report presents emissions and sinks in a common
format consistent with how countries are to report inventories under the UNFCCC. The report itself follows this
standardized format, and provides an explanation of the IPCC methods used to calculate emissions and sinks, and
the manner in which those calculations are conducted.
On October 30, 2009, the U.S. Environmental Protection Agency (EPA) published a rule for the mandatory
reporting of greenhouse gases (GHG) from large GHG emissions sources in the United States. Implementation of 40
CFR Part 98 is referred to as the Greenhouse Gas Reporting Program (GHGRP). 40 CFR part 98 applies to direct
greenhouse gas emitters, fossil fuel suppliers, industrial gas suppliers, and facilities that inject CO2 underground for
sequestration or other reasons. Reporting is at the facility level, except for certain suppliers of fossil fuels and
industrial greenhouse gases. For calendar year 2010, the first year in which data were reported, facilities in 29
categories provided in 40 CFR part 98 were required to report their 2010 emissions by the September 30, 2011
reporting deadline.7 The GHGRP dataset  and the data presented in this inventory report are complementary and, as
indicated in the respective planned improvements sections in this report's chapters, EPA is analyzing how  to use
facility-level GHGRP data to improve the national estimates presented in this inventory.


[END BOX]
ES.1. Background Information

Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
(N2O), and ozone (O3).  Several classes of halogenated substances that contain fluorine, chlorine, or bromine are
also greenhouse gases, but they are, for the most part, solely a product of industrial activities.  Chlorofluorocarbons
(CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that
contain 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.8  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.

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-CH4
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, CH4, 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 2010,
concentrations of these greenhouse gases have increased globally by 39, 158, and 19 percent, respectively (IPCC
2007 and NOAA/ESLR 2009).

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
  See  and .
8 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in the annexes of the
Inventory report for informational purposes.


ES-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
HCFCs. Accordingly, atmospheric concentrations of these substitutes have been growing (IPCC 2007).

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).9 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 equivalent (Tg CO2 Eq.).10> 11 All
gases in this Executive Summary are presented in units of Tg CO2 Eq.

The UNFCCC reporting guidelines for national inventories were updated  in 2006,12 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 2010 are consistent with estimates developed prior to
the publication of the IPCC Third Assessment Report (TAR) (IPCC 2001) and the IPCC Fourth Assessment Report
(AR4) (IPCC 2007).  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 below 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
C4F10
C6F14
SF6
Source: IPCC (1996)
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

* The CH4 GWP includes the direct
effects and those indirect
effects due
9 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.
10 Carbon comprises 12/44ths of carbon dioxide by weight.
  One teragram is equal to 1012 grams or one million metric tons.
12 See .
                                                                               Executive Summary   ES-3

-------
    to the production of tropospheric
    ozone and stratospheric water vapor.
    The indirect effect due to the
    production of CO2 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

In 2010, total U.S. greenhouse gas emissions were 6,821.8 Tg or million metric tons CO2 Eq. Total U.S. emissions
have increased by 10.5 percent from 1990 to  2010, and emissions increased from 2009 to 2010 by 3.2 percent (213.5
Tg CO2 Eq.). The increase from 2009 to 2010 was primarily due to an increase in economic output resulting in an
increase in energy consumption across all sectors, and much warmer summer conditions resulting in an increase in
electricity demand for air conditioning that was generated primarily by combusting coal and natural gas.  Since
1990, U.S. emissions have increased at an average annual rate of 0.5 percent.

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 2010.
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
Figure ES-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990
Table ES-2:  Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg or million metric tons CO2 Eq.)
Gas/Source
CO2
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production &
Metallurgical Coke Production
Natural Gas Systems
Cement Production
Lime Production
Incineration of Waste
Limestone and Dolomite Use
Ammonia Production
Cropland Remaining Cropland
Urea Consumption for Non-
Agricultural Purposes
Soda Ash Production and Consumption
Petrochemical Production
1990
5,100.5
4,738.3
1,820.8
1,485.9
846.4
338.3
219.0
27.9
119.6

99.6
37.6
33.3
11.5
8.0
5.1
13.0
7.1

3.8
4.1
3.3
2005
6,107.6
5,746.5
2,402.1
1,896.6
816.4
357.9
223.5
50.0
144.1

66.0
29.9
45.2
14.4
12.5
6.8
9.2
7.9

3.7
4.2
4.2
2006
6,019.0
5,653.0
2,346.4
1,878.1
848.1
321.5
208.6
50.3
143.8

68.9
30.8
45.8
15.1
12.5
8.0
8.8
7.9

3.5
4.2
3.8
2007
6,118.6
5,757.8
2,412.8
1,893.9
844.4
341.6
218.9
46.1
134.9

71.1
31.0
44.5
14.6
12.7
7.7
9.1
8.2

4.9
4.1
3.9
2008
5,924.3
5,571.5
2,360.9
1,789.8
806.5
349.3
225.1
39.8
138.6

66.1
32.8
40.5
14.3
11.9
6.3
7.9
8.6

4.1
4.1
3.4
2009
5,500.5
5,206.2
2,146.4
1,727.9
726.6
339.0
224.6
41.7
123.7

42.1
32.2
29.0
11.2
11.7
7.6
7.9
7.2

3.4
3.6
2.7
2010
5,706.4
5,387.8
2,258.4
1,745.5
777.8
340.2
224.2
41.6
125.1

54.3
32.3
30.5
13.2
12.1
10.0
8.7
8.0

4.4
3.7
3.3
ES-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Aluminum Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
Zinc Production
Phosphoric Acid Production
Wetlands Remaining Wetlands
Lead Production
Petroleum Systems
Silicon Carbide Production and
Consumption
Land Use, Land-Use Change, and
Forestry (Sink)"
WoodBiomass andEthanol
Consumption
International Bunker Fuels0
CH,
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Rice Cultivation
Stationary Combustion
Abandoned Underground Coal Mines
Forest Land Remaining Forest Land
Mobile Combustion
Composting
Petrochemical Production
Iron and Steel Production &
Metallurgical Coke Production
Field Burning of Agricultural Residues
Ferroalloy Production
Silicon Carbide Production and
Consumption
Incineration of Waste
International Bunker FuesF
N2O
Agricultural Soil Management
Stationary Combustion
Mobile Combustion
Manure Management
Nitric Acid Production
Wastewater Treatment
N2O from Product Uses
Forest Land Remaining Forest Land
Adipic Acid Production
Composting
Settlements Remaining Settlements
Incineration of Waste
Field Burning of Agricultural Residues
Wetlands Remaining Wetlands
International Bunker Fuels0
HFCs
Substitution of Ozone Depleting
6.8
1.4
1.2
2.2
0.6
1.5
1.0
0.5
0.4

0.4

(881.8)

218.6
111.8
668.3
189.6
133.8
147.7
84.1
31.7
35.2
15.9
7.1
7.5
6.0
2.5
4.7
0.3
0.9

1.0
0.2
+

+
+
0.2
316.2
200.0
12.3
43.9
14.8
17.6
3.5
4.4
2.1
15.8
0.4
1.0
0.5
0.1
+
1.1
36.9
0.3
4.1
1.3
1.8
1.4
1.0
1.4
1.1
0.6
0.3

0.2

(1,085.9)

228.6
109.8
625.8
190.5
139.0
112.7
56.8
47.9
29.2
16.5
6.8
6.6
5.5
8.1
2.5
1.6
1.1

0.7
0.2
+

+
+
0.1
331.9
213.1
20.6
37.0
17.6
16.4
4.7
4.4
7.0
7.4
1.7
1.5
0.4
0.1
+
1.0
115.0
99.0
3.8
1.7
1.8
1.5
1.0
1.2
0.9
0.6
0.3

0.2

(1,110.4)

233.7
128.4
664.6
217.7
141.4
111.7
58.1
48.4
29.2
16.7
5.9
6.2
5.5
17.9
2.4
1.6
1.0

0.7
0.2
+

+
+
0.2
336.8
211.1
20.8
33.7
18.4
16.1
4.8
4.4
15.0
8.9
1.8
1.5
0.4
0.1
+
1.2
116.0
101.9
4.3
1.9
1.9
1.6
1.0
1.2
1.0
0.6
0.3

0.2

(1,108.2)

241.1
127.6
656.2
205.3
143.8
111.7
57.8
52.7
29.8
16.6
6.2
6.5
5.3
14.6
2.2
1.7
1.0

0.7
0.2
+

+
+
0.2
334.9
211.1
21.2
29.0
18.5
19.2
4.8
4.4
12.2
10.7
1.8
1.6
0.4
0.1
+
1.2
120.0
102.7
4.5
1.8
1.8
1.6
1.2
1.2
1.0
0.5
0.3

0.2

(1,087.5)

252.1
133.7
667.9
212.7
143.4
113.1
66.9
51.8
30.0
16.6
7.2
6.6
5.3
8.8
2.1
1.7
0.9

0.6
0.2
+

+
+
0.2
317.1
212.9
21.1
25.2
18.3
16.4
4.9
4.4
7.5
2.6
1.9
1.5
0.4
0.1
+
1.2
117.5
103.6
3.0
1.8
1.6
1.5
0.9
1.0
1.1
0.5
0.3

0.1

(1,062.6)

244.1
122.3
672.2
220.9
142.6
111.2
70.1
50.7
30.7
16.5
7.3
6.3
5.1
5.8
2.0
1.6
0.8

0.4
0.2
+

+
+
0.1
304.0
207.3
20.7
22.5
18.2
14.5
5.0
4.4
5.1
2.8
1.8
1.4
0.4
0.1
+
1.1
112.1
106.3
3.0
2.2
1.9
1.7
1.2
1.0
1.0
0.5
0.3

0.2

(1,074.7)

266.1
127.8
666.5
215.4
141.3
107.8
72.6
52.0
31.0
16.3
8.6
6.3
5.0
4.8
1.9
1.6
0.9

0.5
0.2
+

+
+
0.2
306.2
207.8
22.6
20.6
18.3
16.7
5.0
4.4
4.3
2.8
1.7
1.4
0.4
0.1
+
1.2
123.0
114.6
Executive Summary   ES-5

-------
Substances
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
Electrical Transmission and
Distribution
Magnesium Production and Processing
Semiconductor Manufacture
Total
Net Emission (Sources and Sinks)

36.4
0.2
20.6
2.2
18.4
32.6
26.7
5.4
0.5
6,175.2
5,293.4

15.8
0.2
6.2
3.2
3.0
17.8
13.9
2.9
1.0
7,204.2
6,118.3

13.8
0.3
6.0
3.5
2.5
16.8
13.0
2.9
1.0
7,159.3
6,048.9

17.0
0.3
7.5
3.7
3.8
15.6
12.2
2.6
0.8
7,252.8
6,144.5

13.6
0.3
6.6
4.0
2.7
15.0
12.2
1.9
0.9
7,048.3
5,960.9

5.4
0.3
5.6
4.0
1.6
13.9
11.8
1.1
1.0
6,608.3
5,545.7

8.1
0.3
5.6
4.1
1.6
14.0
11.8
1.3
0.9
6,821.8
5,747.1
  + Does not exceed 0.05 Tg CO2 Eq.
  a Parentheses indicate negative values or sequestration. The net CO2 flux total includes both emissions and sequestration, and
  constitutes a net sink in the United States.  Sinks are only included in net emissions total.
  b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
  carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change,
  and Forestry.
  0 Emissions from International Bunker Fuels are not included in totals.
  d Small amounts of PFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.

Figure ES-4 illustrates the relative contribution of the direct greenhouse gases to total U.S. emissions in 2010. The
primary greenhouse gas emitted by human activities in the United States was CO2, representing approximately 83.6
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 decreased by 0.3  percent since 1990, resulted primarily from
natural gas  systems, enteric fermentation associated with domestic livestock, and decomposition of wastes in
landfills. Agricultural soil management, mobile source fuel combustion and stationary fuel combustion were the
major sources of N2O emissions. Ozone depleting substance  substitute emissions and emissions of HFC-23 during
the production of HCFC-22 were the primary contributors to aggregate HFC emissions. PFC emissions resulted
from semiconductor manufacturing and as a by-product of primary aluminum production, while electrical
transmission and distribution systems accounted for most SF6 emissions.


Figure ES-4: 2010 Greenhouse  Gas Emissions by Gas (percentages based on Tg CO2 Eq.)


Overall, from 1990 to 2010, total emissions of CO2 increased by 605.9 Tg CO2 Eq. (11.9 percent), while total
emissions of CH4 and N2O decreased by 1.7 Tg CO2Eq. (0.3 percent), and 10.0 Tg CO2 Eq. (3.2 percent),
respectively.  During the same period, aggregate weighted emissions  of HFCs, PFCs, and SF6 rose by 52.5 Tg CO2
Eq. (58.2 percent). From 1990 to 2010, HFCs increased by 86.1 Tg CO2 Eq. (233.1 percent), PFCs decreased by
15.0 Tg CO2 Eq. (72.7 percent), and  SF6 decreased by 18.6 Tg CO2 Eq. (57.0 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 these gases 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 15.8 percent of total emissions in 2010. The following sections describe each gas's contribution to total U.S.
greenhouse gas emissions in more detail.

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 39 percent (IPCC 2007 and NOAA/ESLR 2009), principally due to the combustion of fossil fuels. Within the
ES-6  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
United States, fossil fuel combustion accounted for 94.4 percent of CO2 emissions in 2010. Globally, approximately
30,313 Tg of CO2 were added to the atmosphere through the combustion of fossil fuels in 2009, of which the United
States accounted for about 18 percent.13  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). In addition to fossil-fuel combustion, several other sources emit significant quantities of CO2. These
sources include, but are not limited to non-energy use of fuels, iron and steel production and cement production
(Figure ES-5).


Figure  ES-5: 2010 Sources of CO2 Emissions


As the  largest source of U.S.  greenhouse gas emissions, CO2 from fossil fuel combustion has accounted for
approximately 78 percent of GWP-weighted emissions since 1990, growing slowly from 77 percent of total GWP-
weighted emissions in 1990 to 79 percent in 2010.  Emissions of CO2 from fossil fuel combustion increased at an
average annual rate of 0.7 percent from 1990 to 2010. The fundamental factors influencing this trend include (1) a
generally growing domestic economy over the last 21 years, and (2) an overall growth in emissions from electricity
generation and transportation activities. Between 1990  and 2010, CO2 emissions from fossil fuel combustion
increased from 4,738.3 Tg CO2 Eq. to 5,387.8 Tg CO2 Eq.—a 13.7 percent total increase over the twenty-one-year
period. From 2009 to 2010, these emissions increased by 181.6 Tg CO2 Eq.  (3.5 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.  In the short term, the overall consumption of fossil fuels in the United States fluctuates
primarily 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. In the long 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 behavioral choices (e.g., walking, bicycling, or telecommuting to work instead of driving).


Figure  ES-6: 2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type


Figure  ES-7:  2010 End-Use Sector Emissions of CO2, CH4, and N2O from Fossil Fuel Combustion


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.
13 Global CO2 emissions from fossil fuel combustion were taken from Energy Information Administration International Energy
Statistics 2010 < http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm> EIA (2010a).


                                                                                Executive Summary   ES-7

-------
Figure ES-6, Figure ES-7, and Table ES-3 summarize CO2 emissions from fossil fuel combustion by end-use sector.
Table ES-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Consuming End-Use Sector (Tg or million metric
tons CO2 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories3
Total
Electricity Generation
1990
1,489.0
1,485.9
3.0
1,533.1
846.4
686.8
931.4
338.3
593.0
757.0
219.0
538.0
27.9
4,738.3
1,820.8
2005
1,901.3
1,896.6
4.7
1,553.3
816.4
737.0
1,214.7
357.9
856.7
1,027.2
223.5
803.7
50.0
5,746.5
2,402.1
2006
1,882.6
1,878.1
4.5
1,560.2
848.1
712.0
1,152.4
321.5
830.8
1,007.6
208.6
799.0
50.3
5,653.0
2,346.4
2007
1,899.0
1,893.9
5.1
1,559.8
844.4
715.4
1,205.2
341.6
863.5
1,047.7
218.9
828.8
46.1
5,757.8
2,412.8
2008
1,794.5
1,789.8
4.7
1,503.8
806.5
697.3
1,192.2
349.3
842.9
1,041.1
225.1
816.0
39.8
5,571.5
2,360.9
2009
1,732.4
1,727.9
4.5
1,328.6
726.6
602.0
1,125.5
339.0
786.5
978.0
224.6
753.5
41.7
5,206.2
2,146.4
2010
1,750.0
1,745.5
4.5
1,415.4
777.8
637.6
1,183.7
340.2
843.5
997.1
224.2
772.9
41.6
5,387.8
2,258.4
   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.
   a Fuel consumption by U.S. territories (i.e., American Samoa, Guam, Puerto Rico, U.S. Virgin Islands,
   Wake Island, and other U.S. Pacific Islands) is included in this report.

Transportation End-Use Sector.  Transportation activities (excluding international bunker fuels) accounted for 32
percent of CO2 emissions from fossil fuel combustion in 2010.14 Virtually all of the energy consumed in this end-
use sector came from petroleum products. Nearly 65 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. From 1990 to 2010, transportation
emissions rose by 18 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 34 percent from 1990 to 2010, as a result of a confluence of factors including population
growth, economic growth, urban sprawl, and low fuel prices over much of this period.

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 26 percent of CO2 from
fossil fuel combustion in 2010. Approximately 55 percent of these emissions resulted from direct fossil fuel
combustion to produce steam and/or heat for industrial processes. The remaining emissions resulted  from
consuming electricity for motors, electric furnaces, ovens, lighting, and other applications.  In contrast to the other
end-use sectors, emissions from industry have steadily declined since 1990. This decline is 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.

Residential and Commercial End-Use Sectors.  The residential and commercial end-use sectors accounted for 22
and 19 percent, respectively, of CO2 emissions from fossil fuel combustion in 2010.  Both sectors relied heavily on
electricity for meeting energy demands, with 71 and 78 percent, respectively, of their emissions attributable to
electricity consumption for lighting, heating, cooling, and operating appliances.  The remaining emissions were due
to the consumption of natural gas and petroleum for heating and cooking.  Emissions from these end-use sectors
have increased 29 percent since 1990, due to increasing electricity consumption for lighting, heating, air
conditioning, and operating appliances.
14 If emissions from international bunker fuels are included, the transportation end-use sector accounted for 34.0 percent of U.S.
emissions from fossil fuel combustion in 2010.
ES-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Electricity Generation. The United States relies on electricity to meet a significant portion of its energy demands.
Electricity generators consumed 36 percent of U.S. energy from fossil fuels and emitted 42 percent of the CO2 from
fossil fuel combustion in 2010. 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 2010. 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 5.5 Tg CO2 Eq. (4.6 percent) from 1990
        through 2010. Emissions from non-energy uses of fossil fuels were 125.1 Tg CO2 Eq. in 2010, 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 by 12.2 Tg CO2
        Eq. (28.9 percent) from 2009 to 2010, upsetting a trend of decreasing emissions. Despite this, from 1990
        through 2010 emissions declined by 45.5 percent (45.3 Tg CO2 Eq.). This decline is due to the
        restructuring of the industry, technological improvements, and increased scrap utilization.

    •   In 2010, CO2 emissions from cement production increased by 1.5 Tg CO2 Eq. (5.1 percent) from 2009.
        After decreasing in 1991 by two percent from 1990 levels, cement production emissions grew every year
        through 2006; emissions decreased in the three years prior to 2010. Overall, from 1990 to 2010, emissions
        from cement production have decreased by 8.3 percent, a decrease of 2.8 Tg CO2 Eq.

    •   Net CO2 uptake from Land Use, Land-Use Change, and Forestry increased by 192.8 Tg CO2 Eq. (21.9
        percent) from 1990 through 2010. This increase was primarily due to an increase in the rate of net carbon
        accumulation in forest carbon stocks, particularly in aboveground and belowground tree biomass,  and
        harvested wood pools. 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

Methane (CH4) is more than 20 times as effective as CO2 at trapping heat in the atmosphere (IPCC 1996).  Over the
last two hundred and fifty years, the concentration of CH4 in the atmosphere increased by 158 percent (IPCC 2007).
Anthropogenic sources of CH4 include natural gas and petroleum systems, agricultural activities, landfills,  coal
mining, wastewater treatment, stationary and mobile combustion, and certain industrial processes (see Figure ES-8).


Figure ES-8: 2010  Sources of CH4 Emissions


Some significant trends in U.S. emissions of CH4 include the following:

    •   Natural gas systems were the largest anthropogenic source category of CH4 emissions in the United States
        in 2010 with 215.4 Tg CO2 Eq. of CH4 emitted into the atmosphere. Those emissions have increased by
        25.8 Tg CO2 Eq. (13.6 percent) since 1990.

    •   Enteric fermentation is the second largest anthropogenic source of CH4 emissions in the United States. In
        2010, enteric fermentation CH4 emissions were 141.3 Tg CO2 Eq. (21.2 percent of total CH4 emissions),
        which represents an increase of 7.5 Tg CO2 Eq. (5.6 percent) since 1990.

    •   Landfills are the third largest anthropogenic  source of CH4 emissions in the United States, accounting for
        16.2 percent of total CH4 emissions (107.8 Tg CO2 Eq.) in 2010. From 1990 to 2010, CH4 emissions from
        landfills decreased by 39.8 Tg CO2 Eq. (27.0 percent), with small increases occurring in some interim
        years. This downward trend in overall emissions is the result of increases in the amount of landfill gas
                                                                              Executive Summary   ES-9

-------
        collected and combusted,15 which has more than offset the additional CH4 emissions resulting from an
        increase in the amount of municipal solid waste landfilled.

    •   In 2010, CH4 emissions from coal mining were 72.6 Tg CO2 Eq., a 2.5 Tg CO2 Eq. (3.5 percent) increase
        over 2009 emission levels.  The overall decline of 11.5 Tg CO2 Eq. (13.6 percent) from 1990 results from
        the mining of less gassy coal from underground mines and the increased use of CH4 collected from
        degasification systems.

    •   Methane emissions from manure management increased by 64.0 percent since 1990, from 31.7 Tg CO2 Eq.
        in 1990 to 52.0 Tg CO2 Eq. in 2010.  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 CH4 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.

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 (IPCC 1996).  Since 1750, the global atmospheric concentration of N2O has risen by approximately 19
percent (IPCC 2007). The main anthropogenic activities producing N2O in the United States are agricultural soil
management, fuel combustion in motor vehicles,  stationary fuel combustion, manure management and nitric acid
production (see Figure ES-9).


Figure ES-9: 2010 Sources of N2O Emissions


Some significant trends in U.S. emissions of N2O include the following:

    •   In 2010, N2O emissions from mobile combustion were 20.6 Tg CO2 Eq. (approximately 6.7 percent of U.S.
        N2O emissions). From 1990 to 2010, N2O emissions from mobile combustion decreased by 53.1 percent.
        However, from 1990 to 1998 emissions increased by 25.6 percent, due to control technologies that reduced
        NOX emissions while increasing N2O emissions. Since 1998, newer control technologies have led to an
        overall decline in N2O from this source.

    •   N2O emissions from adipic acid production were 2.8 Tg CO2 Eq. in 2010, and have decreased significantly
        in recent years due to the widespread installation of pollution control measures.  Emissions from adipic acid
        production have decreased by 82.2 percent since 1990 and by 84.0 percent since a peak in 1995.

    •   N2O emissions from stationary combustion increased 10.3 Tg CO2 Eq. (84.4 percent) from 1990 through
        2010.  N2O emissions from this source increased primarily as a result of an increase in the number of coal
        fluidized bed boilers in the electric power sector.

    •   Agricultural soils accounted for approximately 67.9 percent of N2O emissions in the United States in 2010.
        Estimated emissions from this source in 2010 were 207.8 Tg CO2 Eq. Annual N2O emissions from
        agricultural soils fluctuated between  1990 and 2010, although overall emissions were 3.9 percent higher in
        2010 than in 1990.

HFC, RFC,  and SF6 Emissions

HFCs and PFCs are families of synthetic chemicals that are used as alternatives to ODS, which are being phased out
under the Montreal Protocol and Clean Air Act Amendments of 1990. HFCs and PFCs do not deplete the
15 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: 1990-2010

-------
stratospheric ozone layer, and are therefore acceptable alternatives under the Montreal Protocol.

These compounds, however, along with SF6, are potent greenhouse gases. In addition to having high global
warming potentials, SF6 and PFCs have extremely long atmospheric lifetimes, resulting in their essentially
irreversible accumulation in the atmosphere once emitted. Sulfur hexafluoride is the most potent greenhouse gas the
IPCC has evaluated (IPCC 1996).

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


Figure ES-10:  2010 Sources of HFCs, PFCs, and SF6 Emissions


Some significant trends in U.S. HFC, PFC, and SF6 emissions include the following:

    •   Emissions resulting from the substitution of ozone depleting substances (ODS) (e.g., CFCs) have been
        consistently increasing, from small amounts in 1990 to 114.6 Tg CO2 Eq. in 2010. Emissions from ODS
        substitutes are both the largest and the fastest growing source of HFC, PFC, and SF6 emissions.  These
        emissions have been increasing as phase-out of ODS required under the Montreal Protocol came 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 77.8 percent (28.3 Tg CO2 Eq.) from 1990
        through 2010, 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 55.7 percent (14.9
        Tg CO2 Eq.) from  1990 to 2010, primarily because of higher purchase prices for SF6 and efforts by industry
        to reduce emissions.

    •   PFC emissions from aluminum production decreased by 91.5 percent (16.9 Tg CO2 Eq.) from 1990 to
        2010, due to both industry emission reduction efforts and declines in 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. Emissions of all gases can be
summed from each source category from IPCC guidance. Over the twenty-one-year period of 1990 to 2010, total
emissions in the Energy and Agriculture sectors grew by 645.8 Tg CO2 Eq. (12.2 percent), and 40.6 Tg CO2 Eq.
(10.5 percent), respectively. Emissions slightly decreased in the Industrial Processes  sector by 10.5 Tg CO2 Eq. (3.4
percent), while emissions from the Waste and Solvent and Other Product Use sectors decreased by 35.2 Tg CO2 Eq.
(21.0 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 (LULUCF) sector (magnitude of emissions plus CO2
flux from all LULUCF source categories) increased by 187.0 Tg CO2 Eq. (21.5 percent).


Figure ES-11:  U.S. Greenhouse Gas Emissions and Sinks by Chapter/TPCC Sector


Table ES-4:  Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by  Chapter/TPCC Sector (Tg or million
metric tons CO2 Eq.)

    Chapter/IPCC Sector	1990	2005      2006      2007      2008     2009      2010
   Energy                             5,287.7       6,282.4    6,214.4    6,294.3     6,125.4    5,752.7    5,933.5
   Industrial Processes                    313.9        330.1      335.5     347.3       319.1      268.2      303.4
                                                                            Executive Summary   ES-11

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Solvent and Other Product Use
Agriculture
Land-Use Change and Forestry
Waste
Total Emissions
Land-Use Change and Forestry (Sinks)
Net Emissions (Emissions and Sinks)
4.4
387.8
13.8
167.7
6,175.2
(881.8) 1
5,293.4
4.4
424.6
25.6
137.2
7,204.2
(1,085.9)
6,118.3
4.4
425.4
43.2
136.5
7,159.3
(1,110.4)
6,048.9
4.4
432.6
37.6
136.7
7,252.8
(1,108.2)
6,144.5
4.4
433.8
27.4
138.2
7,048.3
(1,087.5)
5,960.9
4.4
426.4
20.6
136.0
6,608.3
(1,062.6)
5,545.7
4.4
428.4
19.6
132.5
6,821.8
(1,074.7)
5,747.1
    * The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States.  Sinks are only
    included in net emissions total.
    Note: Totals may not sum due to independent rounding. Parentheses indicate negative values or sequestration.
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 2010.  In 2010,
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 CH4 and N2O
emissions (50 percent and 14 percent of total U.S. emissions of each gas, respectively). Overall, emission sources in
the Energy chapter account for a combined 87.0 percent of total U.S. greenhouse gas emissions in 2010.
Figure ES-12:  2010 U.S. Energy Consumption by Energy Source
Industrial Processes

The Industrial Processes chapter contains by-product or fugitive emissions of greenhouse gases from industrial
processes not directly related to energy activities such as fossil fuel combustion.  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 consumption, lime production, limestone and dolomite use (e.g., flux stone, flue gas
desulfurization, and glass manufacturing),  soda ash production and consumption, 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 Process chapter account for 4.4 percent of U.S. greenhouse gas emissions in 2010.

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 about 0.1 percent of total U.S.  anthropogenic
greenhouse gas emissions on a carbon equivalent basis in 2010.

Agriculture

The Agricultural 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 primary greenhouse gases emitted by agricultural activities. CH4 emissions from
enteric fermentation and manure management represented 21.2 percent and 7.8 percent of total CH4 emissions from
ES-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
anthropogenic activities, respectively, in 2010.  Agricultural soil management activities such as fertilizer application
and other cropping practices were the largest source of U.S. N2O emissions in 2010, accounting for 67.9 percent.  In
2010, emission sources accounted for in the Agricultural chapters were responsible for 6.3 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 CH4 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 resulted in a net uptake (sequestration) of C in the United States. Forests (including vegetation,
soils, and harvested wood) accounted for 86 percent of total 2010 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 2010.  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 5 times as much C as is emitted from these soils through liming and urea fertilization.
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 2010 resulted in a net C sequestration of 1,074.7 Tg CO2 Eq.
(Table ES-5). This represents an offset of 18.8 percent of total U.S. CO2 emissions, or 15.8 percent of total
greenhouse gas emissions in 2010. Between 1990 and 2010, total  land use, land-use change, and forestry net C flux
resulted in a 21.9 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, and harvested wood
pools.  Annual C accumulation in landfilled yard trimmings and food scraps slowed over this period, while the rate
of annual C accumulation increased in urban trees.
Table ES-5: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg or million metric tons CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining Grassland
Land Converted to Grassland
Settlements Remaining Settlements
Other (Landfilled Yard Lrimmings and Food
Scraps)
Total
1990
(701.4)
(29.4)1
2.2M
(52.2)1
(19.8)1
(57.1)1

(24.2)
(881.8)
I 2005
(940.9)
(18.3)
5.9
(8.9)
(24.4)
(87.8)

(11.6)
(1,085.9)
2006
(963.5)
(19.1)
5.9
(8.8)
(24.2)
(89.8)

(11.0)
(1,110.4)
2007
(959.2)
(19.7)
5.9
(8.6)
(24.0)
(91.9)

(10.9)
(1,108.2)
2008
(938.3)
(18.1)
5.9
(8.5)
(23.8)
(93.9)

(10.9)
(1,087.5)
2009
(910.6)
(17.4)
5.9
(8.3)
(23.6)
(95.9)

(12.7)
(1,062.6)
2010
(921.8)
(15.6)
5.9
(8.3)
(23.6)
(98.0)

(13.3)
(1,074.7)
  Note: Lotals may not sum due to independent rounding. Parentheses indicate net sequestration.


Emissions from Land Use, Land-Use Change, and Forestry are shown in Table ES-6. Liming of agricultural soils
and urea fertilization in 2010 resulted in CO2 emissions of 3.9 Tg CO2 Eq. (3,906 Gg) and 4.1 Tg CO2 Eq. (4,143
Gg), respectively. Lands undergoing peat extraction (i.e., Peatlands Remaining Peatlands) resulted in CO2
emissions of 1.0 Tg CO2 Eq. (983 Gg), and N2O emissions of less than 0.05 Tg CO2 Eq.  The application of
synthetic fertilizers to forest soils in 2010 resulted in direct N2O emissions of 0.4 Tg CO2 Eq. (1 Gg). Direct N2O
emissions from fertilizer application to forest soils have increased by 455 percent since 1990, but still account for a
relatively small portion of overall emissions.  Additionally, direct N2O emissions from fertilizer application to
settlement soils in 2010 accounted for 1.4 Tg CO2 Eq. (5 Gg). This represents an increase of 43 percent since 1990.
Forest fires in 2010 resulted in CH4 emissions of 4.8 Tg CO2 Eq. (231 Gg), and in N2O emissions of 4.0 Tg CO2 Eq.
(14 Gg).

Table ES-6: Emissions from Land Use, Land-Use Change, and Forestry (Tg or million metric tons CO2 Eq.)
                                                                              Executive Summary   ES-13

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Source Category
C02
Cropland Remaining Cropland: Liming
of Agricultural Soils
Cropland Remaining Cropland: Urea
Fertilization
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
CH,
Forest Land Remaining Forest Land:
Forest Fires
N2O
Forest Land Remaining Forest Land:
Forest Fires
Forest Land Remaining Forest Land:
Forest Soils
Settlements Remaining Settlements:
Settlement Soils
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
Total
1990 2005
8.1

4.7

2.4

1.0
2.5

2.5
3.1

2.1

0.1

1.0

8.9

4.3

3.5

1.1
8.1

8.1
8.5

6.6

0.4

1.5

+ +
13.8 25.6
2006
8.8

4.2

3.7

0.9
17.9

17.9
16.5

14.6

0.4

1.5

+
43.2
2007
9.2

4.5

3.8

1.0
14.6

14.6
13.8

11.9

0.4

1.6

+
37.6
2008
9.6

5.0

3.6

1.0
8.8

8.8
9.0

7.2

0.4

1.5

+
27.4
2009
8.3

3.7

3.6

1.1
5.8

5.8
6.5

4.7

0.4

1.4

+
20.6
2010
9.0

3.9

4.1

1.0
4.8

4.8
5.7

4.0

0.4

1.4

+
19.6
  + Less than 0.05 Tg CO2 Eq.
  Note: Totals may not sum due to independent rounding.
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 greenhouse gas emissions in
the Waste chapter, accounting for 81.4 percent of this chapter's emissions, and 16.2 percent of total U.S. CH4
emissions.16 Additionally, wastewater treatment accounts for 16.1 percent of Waste emissions, 2.5 percent of U.S.
CH4 emissions, and 1.6 percent of U.S. N2O emissions. Emissions of CH4 and N2O from composting are also
accounted for in this chapter; generating emissions of 1.6 Tg CO2 Eq. and 1.7 Tg CO2 Eq., respectively. Overall,
emission sources accounted for in the Waste chapter generated  1.9 percent of total U.S. greenhouse gas emissions in
2010.

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 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 2010.
Figure ES-13:  Emissions Allocated to Economic Sectors
16 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as
described in the Land-Use, Land-Use Change, and Forestry chapter of the Inventory report.
ES-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg or million metric tons CO2 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
1,866.2
1,545.2B
1,564.8
431.91
388.CH
345.4B
33.7
6,175.2

(881.8)
5,293.4
2005
2,448.8
2,017.5
1,438.1
496.0
374.3
371.3
58.2
7,204.2

(1,085.9)
6,118.3
2006
2,393.0
1,994.5
1,499.8
516.7
359.9
336.1
59.3
7,159.3

(1,110.4)
6,048.9
2007
2,459.1
2,002.4
1,489.6
517.6
372.2
358.4
53.5
7,252.8

(1,108.2)
6,144.5
2008
2,405.8
1,889.8
1,448.5
505.8
381.8
368.4
48.4
7,048.3

(1,087.5)
5,960.9
2009
2,191.4
1,819.3
1,317.2
492.8
382.0
360.0
45.5
6,608.3

(1,062.6)
5,545.7
2010
2,306.5
1,834.0
1,394.2
494.8
381.7
365.2
45.5
6,821.8

(1,074.7)
5,747.1
  Note: Totals may not sum due to independent rounding.
  See Table 2-12 for more detailed data.
Emissions include CO2, CH4, N2O, HFCs, PFCs, and SF6.
Using this categorization, emissions from electricity generation accounted for the largest portion (34 percent) of
U.S. greenhouse gas emissions in 2010. Transportation activities, in aggregate, accounted for the second largest
portion (27 percent), while emissions from industry accounted for the third largest portion (20 percent) of U.S.
greenhouse gas emissions in 2010.  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 19 percent of U.S. greenhouse gas emissions were contributed
by, in order of importance, the agriculture, commercial, and residential sectors, plus emissions from U.S.  territories.
Activities related to agriculture accounted for 7 percent of U.S. emissions; unlike other economic sectors,
agricultural sector emissions were dominated by N2O emissions from agricultural soil management and CH4
emissions from enteric fermentation. The commercial and residential sectors accounted for 6 and 5 percent,
respectively, of emissions and U.S. territories accounted for 1 percent of emissions; emissions from these sectors
primarily consisted of CO2 emissions from fossil fuel combustion.

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 generation were allocated to the residential, commercial, industry,  transportation, and
agriculture economic sectors according to retail sales of electricity.17 These source categories include CO2 from
fossil fuel combustion and the use of limestone and dolomite for flue gas desulfurization, CO2 and N2O from
incineration of waste, CH4 and N2O from stationary sources, and SF6 from electrical transmission and distribution
systems.

When emissions from electricity are distributed among these sectors, industrial activities account for the largest
share of U.S. greenhouse gas emissions (30 percent) in 2010.  Transportation is the second largest contributor to
total U.S. emissions (27 percent).  The residential and commercial sectors contributed the next largest shares of total
U.S. greenhouse gas emissions in 2010. Emissions from these sectors increase substantially when emissions from
electricity are included, due to their relatively large share of electricity consumption (e.g., lighting, appliances, etc.).
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 2010.

Table ES-8: U.S Greenhouse Gas Emissions by Economic Sector with Electricity-Related Emissions Distributed
17 Emissions were not distributed to U.S. territories, since the electricity generation sector only includes emissions related to the
generation of electricity in the 50 states and the District of Columbia.
                                                                                Executive Summary   ES-15

-------
(Tg or million metric tons CO2 Eq.)
Implied Sectors
Industry
Transportation
Residential
Commercial
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.
1990
2,237.7
1,548.3
953.2B
939.4B
462. (>M
33.7
6,175.2

(881. S)H
5,293.4

2005
2,159.9
2,022.3
1,244.6
1,193.6
525.5
58.2
7,204.2

(1,085.9)
6,118.3

2006
2,198.5
1,999.1
1,183.4
1,174.8
544.2
59.3
7,159.3

(1,110.4)
6,048.9

2007
2,185.9
2,007.6
1,238.5
1,216.9
550.5
53.5
7,252.8

(1,108.2)
6,144.5

2008
2,131.5
1,894.6
1,227.3
1,213.3
533.3
48.4
7,048.3

(1,087.5)
5,960.9

2009
1,905.8
1,823.9
1,162.9
1,151.3
518.9
45.5
6,608.3

(1,062.6)
5,545.7

2010
2,019.0
1,838.6
1,226.6
1,171.0
521.1
45.5
6,821.8

(1,074.7)
5,747.1

Figure ES-14: Emissions with Electricity Distributed to Economic Sectors
[BEGIN BOX]
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 2010; (4) emissions per unit of total gross domestic product as a measure of national economic activity;
and (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 0.5 percent
since 1990. This rate is slightly  slower than that for total energy and for fossil fuel consumption, and much slower
than that for electricity consumption, overall gross domestic product and national population (see Figure ES-15).

Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100)
Variable
GDP"
Electricity Consumption0
Fossil Fuel Consumption0
Energy Consumption0
Population"1
Greenhouse Gas Emissions6
1990
100
!()()•
!()()•
!()()•
!()()•
100
2005
157
134
119
119
118
117
2006
161
135
117
118
120
116
2007
165
137
119
121
121
117
2008
164
136
116
119
122
114
2009
158
131
109
113
123
107
Growth
2010 Rate3
163
137
113
117
123
110
2.5%
1.6%
0.6%
0.8%
1.1%
0.5%
  a Average annual growth rate
  b Gross Domestic Product in chained 2005 dollars (BEA 2010)
  0 Energy content-weighted values (EIA 201 Ob)
  d U.S. Census Bureau (2010)
  e GWP-weighted values
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
Source: BEA (2010), U.S. Census Bureau (2010), and emission estimates in this report.
ES-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
[END BOX]
Indirect Greenhouse Gases (CO, NOX, NMVOCs, and S02)

The reporting requirements of the UNFCCC  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.

Since 1970, the United States has published estimates of annual emissions of CO, NOX, NMVOCs, and SO2 (EPA
2010, EPA 2009),19 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.

Table ES-10: Emissions of NOX,  CO, NMVOCs, and SO2 (Gg)
Gas/Activity
NOX
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Oil and Gas Activities
Incineration of Waste
Agricultural Burning
Solvent Use
Waste
CO
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Incineration of Waste
Agricultural Burning
Oil and Gas Activities
Waste
Solvent Use
NMVOCs
Mobile Fossil Fuel Combustion
Solvent Use
Industrial Processes
Stationary Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Agricultural Burning
SO2
Stationary Fossil Fuel Combustion
Industrial Processes
Mobile Fossil Fuel Combustion
Oil and Gas Activities
1990
21,705
10,862|
10,023B
59ll
139
82
!
129,976
119,360
5,000
4,125(
978
268
302
1
5
20,930
10,932|
5,21 6M
2,422>
912
554
222
673
NAM
20,935
18,407H
1,307B
793
390
2005
15,899
9,012
5,858
569
321
129
6
3
2
70,791
62,692
4,649
1,555
1,403
184
318
7
2
13,761
6,330
3,851
1,997
716
510
241
114
NA
13,466
11,541
831
889
181
2006
15,039
8,488
5,545
553
319
121
7
4
2
67,227
58,972
4,695
1,597
1,412
233
319
7
2
13,594
6,037
3,846
1,933
918
510
238
113
NA
12,388
10,612
818
750
182
2007
14,380
7,965
5,432
537
318
114
8
4
2
63,613
55,253
4,744
1,640
1,421
237
320
7
2
13,423
5,742
3,839
1,869
1,120
509
234
111
NA
11,799
10,172
807
611
184
2008
13,545
7,441
5,148
520
318
106
8
4
2
59,993
51,533
4,792
1,682
1,430
270
322
7
2
13,254
5,447
3,834
1,804
1,321
509
230
109
NA
10,368
8,891
795
472
187
2009
11,467
6,206
4,159
568
393
128
8
3
2
51,431
43,355
4,543
1,549
1,403
247
345
7
2
9,313
4,151
2,583
1,322
424
599
159
76
NA
8,599
7,167
798
455
154
2010
11,467
6,206
4,159
568
393
128
8
3
2
51,431
43,355
4,543
1,549
1,403
247
345
7
2
9,313
4,151
2,583
1,322
424
599
159
76
NA
8,599
7,167
798
455
154
  See .
19 NOX and CO emission estimates from field burning of agricultural residues were estimated separately, and therefore not taken
from EPA (2008).
                                                                            Executive Summary   ES-17

-------
Incineration of Waste
Waste
Solvent Use
Agricultural Burning
38
1
•
NA
24
1
+
NA
24
1
+
NA
24
1
+
NA
23
1
+
NA
24
1
+
NA
24
1
+
NA
 Source:  (EPA 2010, EPA 2009) except for estimates from field burning of agricultural residues.
 NA (Not Available)
 Note: Totals may not sum due to independent rounding.
 + Does not exceed 0.5 Gg.

Key Categories

The 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006)  defines a key category as a
"[source or sink category] that is prioritized within the national inventory system because its estimate has a
significant influence on a country's total inventory of direct greenhouse gases in terms of the absolute level of
emissions, the trend in emissions, or both."20  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 2010 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 report.  For more information regarding key
categories, see section 1.5 and Annex 1.
Figure ES-16:  2010 Key Categories
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 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
20 See Chapter 7 "Methodological Choice and Recalculation" in IPCC (2000). 


ES-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks:  1990-2010

-------
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.


[BEGIN BOX]


Box ES- 3: 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 2006 IPCC
Guidelines (IPCC 2006), which states, "Both methodological changes and refinements over time are an essential
part of improving inventory quality. It is good practice to change or refine methods" when: available data have
changed; the previously used method is not consistent with the IPCC guidelines for that category; a category has
become key; the previously used method is insufficient to reflect mitigation activities in  a transparent manner; the
capacity for inventory preparation has increased; new inventory methods become available; and for correction of
errors." 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 2010) has been
recalculated to reflect the change, per the 2006 IPCC Guidelines (IPCC 2006). 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.
[END BOX]
                                                                                Executive Summary    ES-19

-------

-------
               • MFCs, PFCs, & SF6
     8,000  -,


     7,000  -


     6,000  -


S   5,000  -


°   4,000  -

P
     3,000  -


     2,000  -


     1,000  -


        0  -
    Methane
                                  Nitrous Oxide
                     • Carbon Dioxide
6,175 6,135
         6237  6,360  6,457  6,544
                                               7 104
                            6,757  6,803  6,846 6,909 _
7,022  7,053 7-163 7.204  7,159  ^,253
                                      6,822
Figure ES-1:  U.S. Greenhouse Gas Emissions by Gas
                                                  2.8%
                                                                                                   3.2%
                                                                                              -6.2%
      1991  1992  1993 1994 1995 1996 1997 1998 1999 2000  2001 2002 2003 2004 2005 2006 2007 2008 2009  2010


Figure ES-2:  Annual Percent Change in U.S. Greenhouse Gas Emissions
                                                                                           1,078
                                                                                            '
                                                                                                           647
    -100 J

                                                                                            r^   co   en   o
                                                                                            O   O   O   i-H
                                                                                       o   o   o   o   o
                                                                                       fN   fN   fN   fN   fN
Figure ES-3:  Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990

-------
                                             4.5%
                                                MFCs, PPCs,
                                                   &SF6
                                                   2.1%
Figure ES-4:  2010 Greenhouse Gas Emissions by Gas (percents based on Tg C02 Eq.)
                                 Fossil Fuel Combustion
                                Non-Energy Use of Fuels
             Iron and Steel Prod. & Metallurgical Coke Prod.
                                   Natural Gas Systems
                                    Cement Production
                                       Lime Production
                                  Incineration of Waste
                            Limestone and Dolomite Use
                                   Ammonia Production
                           Cropland Remaining Cropland
            Urea Consumption for Non-Agricultural Purposes
                    Soda Ash Production and Consumption
                               Petrochemical Production
                                  Aluminum Production
                            Carbon Dioxide Consumption
                            Titanium  Dioxide Production
                                   Ferroalloy Production
                                       Zinc Production
                             Phosphoric Acid Production
                           Wetlands Remaining Wetlands
                                       Lead Production
                                    Petroleum Systems
               Silicon Carbide Production and Consumption
Figure ES-5:  2010 Sources of C02 Emissions
                                              5,388
                    C02 as a Portion
                     of all Emissions
: 0.5
: 0.5
                                                             25      50      75      100
                                                                        Tg C02 Eq.
                                                                                            125
                                                                                                    150

-------
        2,500 -|

        2,000 -

        1,500 -

        1,000 -

          500 -

            0 -
Relative Contribution
   by Fuel Type
                                                                              2,258
42
                224
                               Petroleum

                              • Coal

                              • Natural Gas



                               340
                                                                 1,745
Figure ES-6:  2010 C02 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note:  Electricity generation also includes emissions of less than 0.5 Tg C02 Eq. from geothermal-based electricity generation.
            2,000  -,


            1,500  -
        S
        Q  1,000  -
        p

              500  -


                0  -
   From Direct Fossil Fuel Combustion

  • From Electricity Consumption


                   1,005
    42
                          |
                                       1,195
                                                      1,425
                                                                   1,773
                                                                                          t
                                                                                          a
Figure ES-7:  2010 End-Use Sector Emissions of C02, CH4, and N20 from Fossil Fuel Combustion

-------
                                      Natural Gas Systems
                                      Enteric Fermentation
                                                 Landfills
                                              Coal Mining
                                      Manure Management
                                        Petroleum Systems
                                    Wastewater Treatment  |
                                           Rice Cultivation  |
                                     Stationary Combustion  |
                         Abandoned Underground Coal Mines  |
                          Forest Land Remaining Forest Land  |
                                        Mobile Combustion  |
                                              Composting
                                  Petrochemical Production
                Iron and Steel Prod. & Metallurgical Coke Prod.
                        Field Burning of Agricultural Residues
                                      Ferroalloy Production
                  Silicon Carbide Production and Consumption
                                      Incineration of Waste
                             CH4 as a Portion
                             of all  Emissions
                                       9.8%

                            0
      < 0.5
      < 0.5
      < 0.5
      < 0.5
Figure ES-8:  2010 Sources of CH4 Emissions
                                                         0     25    50    75    100   125    150   175   200   225
                                                                                Tg C02 Eq.
                        Agricultural Soil Management
                             Stationary Combustion
                                 Mobile Combustion
                               Manure Management
                               Nitric Acid Production
                             Wastewater Treatment
                             N20 from Product Uses
                   Forest Land Remaining Forest Land
                              Adipic Acid Production  |
                                       Composting  |
                   Settlements Remaining Settlements  |
                               Incineration of Waste  |
                 Field Burning of Agricultural Residues
                       Wetlands Remaining Wetlands
                                                  0

Figure ES-9:  2010 Sources of N20 Emissions
                                                    208
                        N20 as a Portion
                        of all Emissions
                               4.5%
< 0.5
< 0.5
< 0.5
             10
                               20
                                                 30
                  Tg C02 Eq.

-------
    Substitution of Ozone Depleting Substances
        Electrical Transmission and Distribution
                        HCFC-22 Production
                 Semiconductor Manufacture
                       Aluminum Production
         Magnesium Production and Processing
                                                                                                          115
                                                                       MFCs, PFCs, and SF6 as a Portion
                                                                                of all Emissions
                                                                                       2.1%
                                                                         10
                                                                    TgC02Eq.
                                                                                                        20
Figure ES-10:  2010 Sources of MFCs, PFCs, and SF6 Emissions
          8
 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) -
                           Industrial Processes
                         Agriculture
                                                   Waste
                                                               LULUCF (sources)
                         Energy
Note: Relatively smaller amounts of GWP-weighted emissions are also emitted from the Solvent and Other Product Use sectors
Figure ES-11:  U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector

-------
                               Renewable
                                 Energy
                 Nuclear Electric   ,- „„,
                     Power
                     8.8%
   Figure ES-12:  2010 U.S. Energy Consumption by Energy Source


    2,500 -,


    2,000 -


ff  1,500 -

8
H   1,000 -


     500 -
                                                                                  Electric
                                                                                  Power Industry

                                                                                  Transportation

                                                                                  Industry
                                                                                  Agriculture
                                                                                 1 Commercial
                                                                                  Residential
Figure ES-13:  Emissions Allocated to Economic Sectors
Note: Does not include U.S. Territories.

-------
       2,500 -,


       2,000 -


       1,500 -


       1,000 -


         500 -
 Industry
 Transportation
 Residential (black)
 Commercial (gray)
• Agriculture
     Figure ES-14:  Emissions with Electricity Distributed to Economic Sectors
     Note: Does not include U.S. Territories.
                                                                                                     Real GDP
                                                                                                     Population
                                                                                                     Emissions
                                                                                                     per capita


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

-------
C02 Emissions from Stationary Combustion (Coal) Electricity Gen.
                 C02 Emissions from Mobile Combustion: Road
C02 Emissions from Stationary Combustion (Gas) Electricity Gen.
    C02 Emissions from Stationary Combustion - Gas - Industrial
     C02 Emissions from Stationary Combustion - Oil - Industrial
   C02 Emissions from Stationary Combustion - Gas - Residential
                  Fugitive Emissions from Natural Gas Systems
  C02 Emissions from Stationary Combustion - Gas - Commercial
        Direct N20 Emissions from Agricultural Soil Management
              C02 Emissions from Mobile Combustion: Aviation
                     CH4 Emissions from Enteric Fermentation
                 C02 Emissions from Non-Energy Use of Fuels
      Emissions from Substitutes for Ozone Depleting Substances
                                CH4 Emissions from Landfills
   C02 Emissions from Stationary Combustion - Coal - Industrial
                C02 Emissions from Mobile Combustion: Other
    C02 Emissions from Stationary Combustion - Oil - Residential
                          Fugitive Emissions from Coal Mining
   C02 Em. from Iron and Steel Prod. & Metallurgical Coke Prod.
                     CH4 Emissions from Manure Management
   C02 Emissions from Stationary Combustion - Oil  - Commercial
                 Indirect N20 Emissions from Applied Nitrogen
               C02  Emissions from Mobile Combustion: Marine
C02 Emissions from Stationary Combustion - Oil - U.S. Territories
                     C02 Emissions from Natural Gas Systems
                   Fugitive Emissions from Petroleum Systems
Non-C02 Emissions from Stationary  Combustion - Electricity Gen.
                         CH4 Emissions from Rice Cultivation
Key Categories as a  Portion of All
              Emissions
                                                              200   400    600   800  1,000  1,200  1,400  1,600  1,800 2,000
                                                                                    TgC02Eq.
    Figure ES-16:  2010 Key Categories
    Notes: For a complete discussion of the key category analysis, see Annex 1.
             Black bars indicate a Tier 1 level assessment key category.
             Gray bars indicate a Tier 2  level assessment key category.

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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 2010. 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.21 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."22'23
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..." 24 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/IEA  1997) 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 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 2006 IPCC
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 inventory provides a national estimate of sources and sinks for
the United States, including all states and U.S. territories.25 The structure of this report is consistent with the current
  See the section below entitled Global Warming Potentials for an explanation of GWP values.
  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).
23 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate
Change.  See . (UNEP/WMO 2000)
24 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
.
25 U.S. Territories include American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. Pacific
Islands.


                                                                                        Introduction    1-1

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UNFCCC Guidelines on Annual Inventories (UNFCCC 2006).


[BEGIN BOX]


Box 1-1: Methodological approach for estimating and reporting U.S. emissions and sinks


In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
inventories, the emissions and sinks presented in this report are organized by source and sink categories and
calculated using internationally-accepted methods provided by the IPCC.26 Additionally, the calculated emissions
and sinks in a given year for the U.S. are presented in a common manner in line with the UNFCCC reporting
guidelines for the reporting of inventories under this international agreement.27  The use of consistent methods to
calculate emissions and sinks by all nations providing their inventories to the UNFCCC ensures that these reports
are comparable. In this regard, U.S. emissions and sinks reported in this inventory report are comparable to
emissions and sinks reported by other countries. Emissions and sinks provided in this inventory do not preclude
alternative examinations, but rather this inventory report presents emissions and sinks in a common format
consistent with how countries are to report inventories under the UNFCCC. The report itself follows this
standardized format, and provides an explanation of the IPCC methods used to calculate emissions and sinks, and
the manner in which those calculations are conducted.

On October 30, 2009, the U.S. Environmental Protection Agency (EPA) published a rule for the mandatory
reporting of greenhouse gases (GHG) from large GHG  emissions sources in the  United States. Implementation of 40
CFR Part 98 is referred to as the Greenhouse Gas Reporting Program (GHGRP). 40 CFR part 98 applies to direct
greenhouse gas emitters, fossil fuel suppliers, industrial gas suppliers, and facilities that inject CO2 underground for
sequestration or other reasons. Reporting is at the facility level, except for certain suppliers of fossil fuels and
industrial greenhouse gases. For calendar year 2010, the first year in which data were reported, facilities in 29
categories provided in 40 CFR part 98 were required to report their 2010 emissions by the September 30, 2011
reporting deadline.28 The  GHGRP dataset and the data presented in this inventory report are complementary and, as
indicated in the respective planned improvements sections in this report's chapters, EPA is analyzing how to use
facility-level GHGRP data to improve the national estimates presented in this inventory.
[END BOX]

1.1.    Background Information

Science

For over the past 200 years, the burning of fossil fuels such as coal and oil, deforestation, and other sources have
caused the concentrations of heat-trapping "greenhouse gases" to increase significantly in our atmosphere. These
gases absorb some of the energy being radiated from the surface of the earth and trap it in the atmosphere,
essentially acting like a blanket that makes the earth's surface warmer than it would be otherwise.
Greenhouse gases are necessary to life as we know it, because without them the planet's surface would be about 60
°F cooler than present. But, as the concentrations of these gases continue to increase in the atmosphere, the Earth's
temperature is climbing above past levels. According to NOAA and NASA data, the Earth's average surface
temperature has increased by about 1.2 to 1.4 °F since 1900. The ten warmest years on record (since 1850) have all
occurred in the past 13 years (EPA 2009). Most of the warming in recent decades is very likely the result of human
activities. Other aspects of the climate are also changing such as rainfall patterns, snow and ice cover, and sea level.
26 See .
27 See
28 See  and .


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If greenhouse gases continue to increase, climate models predict that the average temperature at the Earth's surface
could increase from 2.0 to 11.5 °F above 1990 levels by the end of this century (IPCC 2007). Scientists are certain
that human activities are changing the composition of the atmosphere, and that increasing the concentration of
greenhouse gases will change the planet's climate. But they are not sure by how much it will change, at what rate it
will change, or what the exact effects will be.29

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.30 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 ofradiatively
    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.31 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) ozone 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).

CO2, CH4, 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,
  For more information see 
  For more on the science of climate change, see NRC (2001).
31 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for
informational purposes.


                                                                                         Introduction    1-3

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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.
Table 1-1:  Global Atmospheric Concentration, Rate of Concentration Change, and Atmospheric Lifetime (years) of
Selected Greenhouse Gases

  Atmospheric Variable	CO2	CH^	N2O	SF«	CF4
Pre-industrial atmospheric
concentration
Atmospheric concentration
Rate of concentration change
Atmospheric lifetime (years)

280 ppm
390 ppm
1 .4 ppm/yr
50-200d

0.700 ppm
1.750-1. 871 ppma
0.005 ppm/yrb
12e

0.270 ppm
0.322-0.323 ppma
0.26%/yr
114e

Oppt
6.8-7.4ppt
Linear0
3,200

40ppt
74ppt
Linear0
>50,000
  Source: Pre-industrial atmospheric concentrations and rate of concentration changes for all gases are from IPCC (2007). Lhe
  current atmospheric concentration for CO2 is from NOAA/ESRL (2009).
  a Lhe range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
  Hemisphere site for October 2006 through September 2007 (CDIAC 2009).
  b Lhe growth rate for atmospheric CH4 has been decreasing from 1.4 ppb/yr in 1984 to less than 0 ppb/yr in 2001, 2004, and 2005.
  0 IPCC (2007) identifies the rate of concentration change for SF6 and CF4 as linear.
  d No single lifetime can be defined for CO2 because of the different rates of uptake by different removal processes.
  e Lhis lifetime has been defined as an "adjustment time" that takes into account the indirect effect of the gas on its own residence
  time.

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 (CO2).  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. CO2 concentrations in the atmosphere increased from approximately 280
parts per million by volume (ppmv) in pre-industrial times to 390ppmvin2010, a 39.2 percent increase (IPCC 2007
and NOAA/ESRL 2009).32>33  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. In its Fourth Assessment Report, the IPCC stated "most of
the observed increase in global average temperatures since the mid^O* century is very likely due to the observed
increased in anthropogenic greenhouse gas concentrations," of which CO2is the most important (IPCC 2007).

Methane (CH4).  CH4 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. CH4 is also
emitted during the production and distribution of natural gas and petroleum, and is released as a by-product of coal
32 Lhe pre-industrial period is considered as the time preceding the year 1750 (IPCC 2001).
33 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).


1-4   Inventory of U.S. Greenhouse Gas  Emissions and Sinks: 1990-2010

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mining and incomplete fossil fuel combustion. Atmospheric concentrations of CH4 have increased by about 158
percent since 1750, from a pre-industrial value of about 700 ppb to 1,750-1,871 ppb in2010,34 although the rate of
increase has been declining.  The IPCC has estimated that slightly more than half of the current CH4 flux to the
atmosphere is anthropogenic, from human activities such as agriculture, fossil fuel use, and waste disposal (IPCC
2007).

CH4 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 (N2O).  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 19
percent since 1750, from a pre-industrial value of about 270 ppb to 322-323 ppb in 2010,35 a concentration that  has
not been exceeded during the last thousand years. N2O 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,36 where it shields the Earth from harmful levels of
ultraviolet radiation, and at lower concentrations in the troposphere,37 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. As of IPCC's fourth assessment,
"whether or not recently observed  changes in ozone trends are already indicative  of recovery of the global  ozone
layer is not yet clear" (IPCC 2007).

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 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
34 The range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
Hemisphere site for October 2006 through September 2007 (CDIAC 2010).
3 ^ The range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
Hemisphere site for October 2006 through September 2007 (CDIAC 2010).
36 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.
37 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.


                                                                                         Introduction   1-5

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importation of HCFCs by non-Article 538 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 (NO,J.  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 they have positive radiative forcing effects.39 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-CH4 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
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
38 Article 5 of the Montreal Protocol covers several groups of countries, especially developing countries, with low consumption
rates of ozone depleting substances. Developing countries with per capita consumption of less than 0.3 kg of certain ozone
depleting substances (weighted by their ozone depleting potential) receive financial assistance and a grace period often
additional years in the phase-out of ozone depleting substances.
39 NOX emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic
aircraft, can lead to stratospheric ozone depletion.


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aerosols, sulfates, and volcanic aerosols, and anthropogenically manufactured aerosols such as industrial dust and
carbonaceous40 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.41  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, has a positive radiative forcing, and that its presence "in the atmosphere above highly
reflective surfaces such as snow and ice, or clouds, may cause a significant positive radiative forcing" (IPCC 2007).
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 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.)42
The relationship between gigagrams (Gg) of a gas and Tg CO2 Eq. can be expressed as follows:
                                                                  (    T     ^
                           Tg CO 2 Eq = (Gg of gas) x (GWP) x I   QQQg    I
where,

        Tg CO2 Eq. = Teragrams of CO2 Equivalent

        Gg = Gigagrams (equivalent to a thousand metric tons)

        GWP = Global Warming Potential

        Tg = Teragrams

GWP values allow for a comparison of the impacts of 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 2/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
40 Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot)
(IPCC 2001).
  Volcanic activity can inject significant quantities of aerosol producing sulfur dioxide and other sulfur compounds into the
stratosphere, which can result in a longer negative forcing effect (i.e., a few years) (IPCC 1996).
42 Carbon comprises 12/44ths of carbon dioxide by weight.


                                                                                          Introduction   1-7

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    100-year time horizon.
                         43
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 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.

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
C4F10
C6F14
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
   Source: (IPCC 1996)
   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 CO2 is not included.


[BEGIN BOX]


Box 1-2: 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
CO2 radiative forcing and an improved CO2 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.
43 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)


1-8   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 1-3 presents the new GWPs, relative to those presented in the SAR.
Table 1-3: Comparison of 100-Year GWPs
Gas

C02
CH4*
N2O
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C^O
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 from SAR
TAR
NC
2
(14)
300
(100)
600
NC
500
(20)
600
3,100
200
(800)
2,700
1,600
1,600
(1,700)
AR4
0
4
(12)
3,100
25
700
130
670
(16)
320
3,510
340
890
3,000
1,860
1,900
(1,100)
   Source: (IPCC 2007, IPCC 2001)
   NC (No Change)
   Note: Parentheses indicate negative values.
   * 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 CO2 is not included.

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 inventories44 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 2010 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.
[END BOX]
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
44 See .
                                                                                       Introduction    1-9

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

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 Common Reporting
Format, 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.
1-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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.

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
                                                                                     Introduction   1-11

-------
(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.


[BEGIN BOX]


Box 1-3:  IPCC Reference Approach

The UNFCCC reporting guidelines require countries to complete a "top-down" reference approach for estimating
CO2 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.


[END BOX]

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." 45
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 any 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 category's uncertainty assessments (or proxies) in  its
45 See Chapter 7 "Methodological Choice and Recalculation" in IPCC (2000). 


1-12   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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  calculations, was also performed twice to include or exclude LULUCF categories.
  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, because it would qualify
  bunker fuels 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 2010. 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.
  Table 1-4: Key Categories for the United States (1990-2010)
IPCC Source Categories
Gas
Tierl
Level Trend Level Trend
Without Without With With
LULUCF LULUCF LULUCF LULUCF
Tier 2
Level Trend Level Trend
Without Without With With
.ULUCF LULUCF LULUCF LULUCF
Qual
a
2010
Emissions
(Tg C02
Eq.)
Energy
CO2 Emissions from Stationary
Combustion - Coal - Electricity

CO2 Emissions from Mobile
Combustion: Road
CO2 Emissions from Stationary
Combustion - Gas - Electricity
Generation
CO2 Emissions from Stationary
Combustion - Gas - Industrial

CO2 Emissions from Stationary
Combustion - Oil - Industrial
CO2 Emissions from Stationary
Combustion - Gas - Residential

CO2 Emissions from Stationary
Combustion - Gas - Commercial

CO2 Emissions from Mobile
Combustion: Aviation

CO2 Emissions from Non-Energy
Use of Fuels

CO2 Emissions from Stationary
Combustion - Coal - Industrial

CO2 Emissions from Mobile
Combustion: Other
CO2 Emissions from Stationary
Combustion - Oil - Residential

CO2 Emissions from Stationary
Combustion - Oil - Commercial
C02

C02


C02


CO2


C02


C02


C02


CO2


C02


C02


C02


CO2


C02
 1,827.3

 1,478.9

H
  399.4

  394.2

  287.4

  258.8

  167.7
  142.4


  125.1
   96.2
                                                                                           Introduction    1-13

-------
IPCC Source Categories
Gas
  	Tierl	

  Level   Trend   Level   Trend
Without  Without   With    With
LULUCF LULUCF LULUCF LULUCF
 	Tier 2	

 Level    Trend    Level   Trend
Without  Without  With    With
 ULUCF LULUCF LULUCF LULUCF
                                                                                                       Qual
     2010
Emissions
  (Tg C02
     Eq.)
CO2 Emissions from Mobile
Combustion: Marine

CO2 Emissions from Stationary
Combustion-Oil-U.S.
Territories
CO2 Emissions from Natural Gas
    f'ems

   _ Emissions from Stationary
Combustion - Oil - Electricity
Generation
CO2 Emissions from Stationary
Combustion - Coal - Commercial

Fugitive Emissions from Natural
Gas Systems

Fugitive Emissions from Coal
Mining

Fugitive Emissions from
Petroleum Systems

Non-CO2 Emissions from
Stationary Combustion -
Residential
Non-CO2 Emissions from
Stationary Combustion -
Electricity Generation
Non-CO2 Emissions from
Stationary Combustion -
Industrial

International Bunker Fuelsb
C02


C02


CO2


CO2


C02


CH4


CH4


CH4


CH4


N2O


N2O

Seve
 ral
                                                                               42.6

                                                                               36.7
                                                                               32.3
Industrial Processes
CO2 Emissions from Iron and
Steel Production & Metallurgical
Coke Production
CO2 Emissions from Cement
Production

CO2 Emissions from Aluminum
Production
N2O Emissions from Adipic Acid
Production

Emissions from Substitutes for
Ozone Depleting Substances

SF6 Emissions from Electrical
Transmission and Distribution
CO,
C02
N20

HiG
WP

HiG
WP
                                                                               54.3
                                                                               30.5
                                                                                3.0


                                                                                2.8


                                                                              114.6


                                                                               11.8
  1-14  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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IPCC Source Categories
HFC-23 Emissions from HCFC-
22 Production
PFC Emissions from Aluminum
Production
Agriculture
CH4 Emissions from Enteric
Fermentation
CH4 Emissions from Manure
Management
CH4 Emissions from Rice
Cultivation
Direct N2O Emissions from
Agricultural Soil Management
Indirect N2O Emissions from
Applied Nitrogen

Gas
HiG
WP
HiG
WP

CH4
CH4
CH4
N2O
N20
Tierl
Level Trend Level Trend
Without Without With With
LULUCF LULUCF LULUCF LULUCF
• • • •
• •

• • • •
• • • •

• • • •
• •
Tier 2
Level Trend Level Trend
Without Without With With
.ULUCF LULUCF LULUCF LULUCF
• •
• • • •

• •
• • • •
• •
• • • •
• • • •

Qual
a









2010
Emissions
(Tg C02
Eq.)
8.1
1.6

141.3
52.0
8.6
162.3
45.5
Waste
CH4 Emissions from Landfills
CH4
• • • •
• • • •

107.8
Land Use, Land Use Change, and Forestry
CO2 Emissions from Changes in
Forest Carbon Stocks

CO2 Emissions from Urban Trees

CO2 Emissions from Cropland
Remaining Cropland

CO2 Emissions from Landfilled
Yard Trimmings and Food Scraps

CO2 Emissions from Grassland
Remaining Grassland

CH4 Emissions from Forest Fires

N2O Emissions from Forest Fires
                                                                                                             (921.8)

                                                                                                              (98.0)

                                                                                                              (15.6)


                                                                                                              (13.3)
Key Categories Subtotal Without LULUCF
                                                                                                             6,644.0
Total Emissions Without LULUCF
                                                                                                             6,802.2
Percent of Total Without LULUCF
                                                                                                             97.7%
Key Categories Subtotal With LULUCF
                                                                                                             5,595.7
Total Emissions With LULUCF
                                                                                                             5,747.1
Percent of Total With LULUCF
                                                                                                             97.4%
Qualitative criteria.
'Emissions from this source not included in totals.
Note: Parentheses indicate negative values (or sequestration).
  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
                                                                                         Introduction   1-15

-------
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.

Key attributes of the QA/QC plan are summarized in Figure 1-1. These attributes 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;

    •   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 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.

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.


Figure 1-1: U.S. QA/QC Plan Summary
1-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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, 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 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) and
require that countries provide single point estimates for each gas and emission or removal source category.  Within
the discussion of each emission source, specific factors affecting the 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 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. Estimates of quantitative uncertainty for the overall greenhouse gas
emissions inventory are shown below, 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 and in Annex 7. Consistent with the IPCC Good Practice Guidance (IPCC 2000), over a multi-
year timeframe, the United States expects to continue to improve the uncertainty estimates presented in this report.

Table 1-5:  Estimated Overall Inventory Quantitative Uncertainty (Tg CO2 Eq. and Percent)
Gas
2010 Emission
Estimate3
(Tg C02 Eq.)
Uncertainty Range Relative to Emission
Estimate1"
(Tg C02 Eq.) (%)
Standard
Mean0 Deviation0
(Tg C02 Eq.)
                                                     Lower     Upper    Lower    Upper
                                                     Bound*1    Bound*1    Bound    Bound
C02
CH4e
N2Oe
PFC, HFC & SF6e
Total
Net Emissions (Sources and Sinks)
5,706.0
666.5
306.2
140.3
6,819.1
5,744.4
5,570
578
265
138
6,682
5,575
5,958
751
431
156
7,137
6,094
-2%
-13%
-14%
-1%
-2%
-3%
4%
13%
41%
11%
5%
6%
5,763
658
339
147
6,906
5,830
101
43
43
4
117
133
Notes:
                                                                                        Introduction   1-17

-------
  a Emission estimates reported in this table correspond to emissions from only those source categories for which quantitative
  uncertainty was performed this year. Thus the totals reported in this table exclude approximately 2.8 Tg CO2 Eq. of emissions
  for which quantitative uncertainty was not assessed. Hence, these emission estimates do not match the final total U.S.
  greenhouse gas emission estimates presented in this Inventory.
  b The lower and upper bounds for emission estimates correspond to a 95 percent confidence interval, with the lower bound
  corresponding to 2.5th percentile and the upper bound corresponding to 97.5th percentile.
  0 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.
  d The lower and upper bound emission estimates for the sub-source categories do not sum to total emissions because the low and
  high estimates for total emissions were calculated separately through simulations.
  e The overall uncertainty estimates did not take into account the uncertainty in the GWP values for CH4, N2O and high GWP
  gases used in the inventory emission calculations for 2010.


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 uncertainty associated with the 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 CRF 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 2010.
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 implemented, new emission sources  are quantified and
included in the Inventory. For a complete list of sources not included, 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 2006 UNFCCC Guidelines  on Reporting and Review (UNFCCC 2006),
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.

Table 1-6: IPCC Sector Descriptions
   Chapter/IPCC Sector       Activities Included
   Energy                    Emissions of all greenhouse gases resulting
                             from stationary and mobile energy activities
                             including fuel combustion and fugitive fuel
                             emissions.
   Industrial Processes          By-product or fugitive emissions of greenhouse
                             gases from industrial processes not directly
                             related to energy activities such as fossil fuel
                             combustion.
   Solvent and Other Product    Emissions, of primarily NMVOCs, resulting
    Use                      from the use of solvents and N2O from product
                             uses.
   Agriculture                 Anthropogenic emissions from  agricultural
                             activities except fuel combustion, which is
                             addressed under Energy.
   Land Use, Land-Use         Emissions and removals of CO2, CH4, and N2O
1-18   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
    Change, and Forestry       from forest management, other land-use
                            activities, and land-use change.
   Waste                    Emissions from waste management activities.
   Source: (IPCC/UNEP/OECD/IEA 1997)


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

Chapter/IPCC Sector  Overview of emission trends for each IPCC defined sector

        SOUK6 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.
                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.
                                                                                         Introduction   1-19

-------
Table 1-7:  List of Annexes
ANNEX 1 Key Category Analysis
ANNEX 2 Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion
2.1.     Methodology for Estimating Emissions of CO2 from Fo ssil Fuel Combustion
2.2.     Methodology for Estimating the Carbon Content of Fossil Fuels
2.3.     Methodology for Estimating Carbon Emitted from Non-Energy Uses of Fossil Fuels
ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories
3.1.     Methodology for Estimating Emissions of CH4, N2O, and Indirect Greenhouse Gases from Stationary
        Combustion
3.2.     Methodology for Estimating Emissions of CH4, N2O, and Indirect Greenhouse Gases from Mobile
        Combustion and Methodology for and Supplemental Information on Transportation-Related Greenhouse Gas
        Emissions
3.3.     Methodology for Estimating CH4 Emissions from Coal Mining
3.4.     Methodology for Estimating CH4 Emissions from Natural Gas Systems
3.5.     Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems
3.6.     Methodology for Estimating CO2 and N2O Emissions from Incineration of Waste
3.7.     Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
3.8.     Methodology for Estimating HFC and PFC Emissions from Substitution of Ozone Depleting Substances
3.9.     Methodology for Estimating CH4 Emissions from Enteric Fermentation
3.10.    Methodology for Estimating CH4 and N2O Emissions from Manure Management
3.11.    Methodology for Estimating N2O Emissions from Agricultural Soil Management
3.12.    Methodology for Estimating Net Carbon Stock Changes in Forest Lands Remaining Forest Lands
3.13.    Methodology for Estimating Net Changes in Carbon Stocks in Mineral and Organic Soils on Cropland and
        Grassland
3.14.    Methodology for Estimating CH4 Emissions from Landfills
ANNEX 4 IPCC Reference Approach for Estimating  CO2 Emissions from Fossil Fuel Combustion
ANNEX 5 Assessment of the Sources and Sinks of Greenhouse Gas Emissions Not Included
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
1-20   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
                                             Figure 1-1: U.S. QA/QC Plan Summary
I-
 rc
I
ns
c
<
•Obtain data in electronic
format (if possible)

•Review spreadsheet
construction
    •Avoid hardwiring
    *Use data validation
    • Protect cells

•Develop automatic
checkers for:
    • Outliers, negative values, or
    missing data
    •Variable types match values
    •Time series consistency

•Maintain trackingtab for
status of gat he ring efforts
         Check input data for
        transcription errors
        •Inspect automatic checkers

        •Identifyspreadsheet
        modifications that could
        provide additional QA/QC
        checks
            Data Gathering
•Contact reports for non-
electronic comm uni cati ons
•Provide cell references for
primary data elements

•Obtain copies of all data
sources

•Li st and I ocati on of any
working/external
spreadsheets

•Document assumptions
                                                                        •Clearly label parameters,
                                                                            Sj and conversion factors
                                                                        •Review spreadsheet
                                                                        integrity
                                                                           •Equations
                                                                           •Units
                                                                           •In put and output

                                                                        •Develop automated
                                                                        checkers for;
                                                                           •Input ranges
                                                                           •Calculations
                                                                           •Emission aggregation
                                 •Check citations in
                                 spreadsheet and text for
                                 accuracy and style
                                 •Check reference  dod
-------
2.           Trends in  Greenhouse Gas Emissions

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

In 2010, total U.S. greenhouse gas emissions were 6,821.8 Tg or million metric tons CO2 Eq.  Total U.S. emissions
have increased by 10.5 percent from 1990 to 2010, and emissions increased from 2009 to 2010 by 3.2 percent (213.5
Tg CO2 Eq.).  The increase from 2009 to 2010 was primarily due to an increase in economic output resulting in an
increase in energy consumption across all sectors, and, much warmer summer conditions resulting in an increase in
electricity demand for air conditioning that was generated primarily by combusting coal and natural gas. Since
1990, U.S. emissions have increased at an average annual rate of 0.5 percent.


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


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


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


As the largest contributor to U.S. greenhouse gas emissions, carbon dioxide (CO2) from fossil fuel combustion has
accounted for approximately 78 percent of global warming potential (GWP) weighted emissions since 1990, from
77 percent of total GWP-weighted emissions in 1990 to 79 percent in 2010. Emissions from this source category
grew by 13.7 percent (649.5 Tg CO2 Eq.) from 1990 to 2010 and were responsible for most of the increase in
national emissions during this period. From 2009 to 2010, these emissions increased by 3.5 percent (181.6 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 fluctuates primarily 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 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 behavioral choices (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.

A brief discussion of the year to year variability in fuel combustion emissions is provided below, beginning with
2006.

From 2006  to 2007, emissions from fuel combustion grew at a rate slightly higher than the average growth rate since
1990. There were a number of factors contributing to this increase.  More energy-intensive 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 1.7 percent,
and with an increase in natural gas consumption of 9.9 percent.  This increase in fossil fuel consumption, combined
with a 14.4 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
                                                             Trends in Greenhouse Gas Emissions     2-1

-------
consumption due to warmer summer conditions and cooler winter conditions compared to 2006. In addition to these
more energy-intensive weather conditions, electricity prices remained relatively stable compared to 2006, and
natural gas prices decreased slightly.  Emissions from the industrial sector decreased compared to 2006 as a result of
a decrease in industrial production and 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.

Emissions from fossil fuel combustion decreased from 2007 to 2008. Several factors contributed to this decrease in
emissions. An increase in energy prices coupled with the economic downturn led to a decrease in energy demand
and a resulting decrease in emissions from 2007 to 2008. In 2008, the price of coal, natural gas, and petroleum used
to generate electricity, as well as the price of fuels used for transportation, increased significantly. As a result of this
price increase, coal, natural gas, and petroleum consumption used for electricity generation decreased by 1.4
percent, 2.5 percent, and 28.8 percent, respectively. The increase in the cost of fuels to generate electricity translated
into an increase in the price of electricity, leading to a decrease in electricity consumption across all sectors except
the commercial sector.  The increase in transportation fuel prices led to a decrease in vehicle miles traveled (VMT)
and a 5.5 percent decrease in transportation fossil fuel combustion emissions from 2007 to 2008. Cooler weather
conditions in the summer led to a decrease in cooling degree days by 8.7 percent and a decrease in electricity
demand compared to 2007, whereas cooler winter conditions led to a 5.6 percent increase in heating degree days
compared to 2007 and a resulting increase in demand for heating fuels. The increased emissions from winter heating
energy demand was offset by a decrease in emissions from summer cooling related electricity demand. Lastly,
renewable energy46 consumption for electricity generation increased by 16.6 percent from 2007 to 2008, driven by a
significant increase  in solar and wind energy consumption (of 17.0 percent and 60.2 percent, respectively). This
increase in renewable energy generation contributed to a decrease in the carbon intensity of electricity generation.

From 2008 to 2009, CO2 from fossil fuel combustion emissions experienced a decrease of 6.6 percent, the greatest
decrease of any year over the course of the twenty one-year period. Various factors contributed to this decrease in
emissions. The continued economic downturn resulted in a 3.5 percent decrease in GDP, and a decrease in energy
consumption across all sectors. The economic downturn also impacted total industrial production and manufacturing
output, which decreased by 11.2 and 13.5 percent, respectively. In 2009, the price of coal used to generate electricity
increased, while the price of natural gas used to generate electricity decreased significantly. As a result, natural gas
was used for a greater share of electricity generation in 2009 than 2008, and coal was used for a smaller share.  The
fuel switching from coal to  natural gas and additional electricity generation from other energy sources in 2009,
which included a 7.3 percent increase in hydropower generation from the previous year, resulted in a decrease in
carbon intensity, and in turn, a decrease in emissions from electricity generation. From 2008 to  2009, industrial
sector emissions decreased  significantly  as a result of a decrease in output from energy-intensive industries of 23.6
percent in nonmetallic mineral and 30.3 percent in primary metal industries. The residential and commercial sectors
only experienced minor decreases in emissions as summer and winter weather conditions were less energy-intensive
from 2008 to 2009,  and the price of electricity only increased slightly. Heating degree days decreased slightly and
cooling degree days decreased by 3.8 percent from 2008 to 2009.

From 2009 to 2010, CC>2 emissions from fossil fuel combustion increased by 3.5 percent, which represents the
largest annual  increase  in CO2 emissions from fossil fuel combustion for the twenty one-year period.47 This increase
is primarily due to an increase in economic output 2009 to 2010, where total industrial production and
manufacturing output increased by 5.3 and 5.8 percent, respectively (FRB 2011). Carbon dioxide emissions from
fossil fuel combustion in the industrial sector increased by 7.0 percent, including increased emissions from the
combustion of fuel oil,  natural gas and coal. Overall, coal consumption increased by 5.4 percent, the largest increase
in coal consumption for the twenty one-year period. In 2010, weather conditions remained fairly constant in the
winter and were much hotter in the summer compared to 2009, as heating degree days decreased slightly (0.7
percent) and cooling degree days increased by 19 percent to their highest levels in the twenty one-year period.  As a
result of the more energy-intensive summer weather conditions, electricity sales to the residential and commercial
end-use sectors in 2010 increased approximately 6.3 percent and 1.7 percent, respectively.
  Renewable energy, as defined in EIA's energy statistics, includes the following energy sources: hydroelectric power,
geothermal energy, biofuels, solar energy, and wind energy.
47 This increase also represents the largest absolute and percentage increase since 1988 (EIA 201 la).


2-2   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Overall, from 1990 to 2010, total emissions of CO2 increased by 605.9 Tg CO2 Eq. (11.9 percent), while total
emissions of CH4 and N2O decreased by 1.7 Tg CO2Eq. (0.3 percent), and 10.0 Tg CO2 Eq. (3.2 percent),
respectively. During the same period, aggregate weighted emissions of HFCs, PFCs, and SF6 rose by 52.5 Tg CO2
Eq. (58.2 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. These
were estimated to offset 15.8 percent of total emissions in 2010.

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.

Table 2-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)
Gas/Source
CO2
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production &
Metallurgical Coke Production
Natural Gas Systems
Cement Production
Lime Production
Incineration of Waste
Limestone and Dolomite Use
Ammonia Production
Cropland Remaining Cropland
Urea Consumption for Non-
Agricultural Purposes
Soda Ash Production and
Consumption
Petrochemical Production
Aluminum Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
Zinc Production
Phosphoric Acid Production
Wetlands Remaining Wetlands
Lead Production
Petroleum Systems
Silicon Carbide Production and
Consumption
Land Use, Land-Use Change,
and Forestry (Sink)"
Wood Biomass and Ethanol
Consumption
International Bunker Fuels0
CH,
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
1990
5,100.5
4,738.3
1,820.8
1,485.9
846.4
338.31
219.o!
27.91
119.61

99.6
37.6 1
33.3
11.5
8.0
5.1
13.0
7.1 1



6.8
1.4
1.2


1.5
i.ol
0.5
0.4

0.4

(881.8)

218.6^
111.8^
668.3
189.61
133. sl
147.71
84.1 (
2005
6,107.6
5,746.5
2,402.1
1,896.6
816.4
357.9
223.5
50.0
144.1

66.0
29.9
45.2
14.4
12.5
6.8
9.2
7.9

3.7
4.2
4.2
4.1
1.3
1.8
1.4
1.0
1.4
1.1
0.6
0.3

0.2

(1,085.9)

228.6
109.8
625.8
190.5
139.0
112.7
56.8
2006
6,019.0
5,653.0
2,346.4
1,878.1
848.1
321.5
208.6
50.3
143.8

68.9
30.8
45.8
15.1
12.5
8.0
8.8
7.9

3.5
4.2
3.8
3.8
1.7
1.8
1.5
1.0
1.2
0.9
0.6
0.3

0.2

(1,110.4)

233.7
128.4
664.6
217.7
141.4
111.7
58.1
2007
6,118.6
5,757.8
2,412.8
1,893.9
844.4
341.6
218.9
46.1
134.9

71.1
31.0
44.5
14.6
12.7
7.7
9.1
8.2

4.9
4.1
3.9
4.3
1.9
1.9
1.6
1.0
1.2
1.0
0.6
0.3

0.2

(1,108.2)

241.1
127.6
656.2
205.3
143.8
111.7
57.8
2008
5,924.3
5,571.5
2,360.9
1,789.8
806.5
349.3
225.1
39.8
138.6

66.1
32.8
40.5
14.3
11.9
6.3
7.9
8.6

4.1
4.1
3.4
4.5
1.8
1.8
1.6
1.2
1.2
1.0
0.5
0.3

0.2

(1,087.5)

252.1
133.7
667.9
212.7
143.4
113.1
66.9
2009
5,500.5
5,206.2
2,146.4
1,727.9
726.6
339.0
224.6
41.7
123.7

42.1
32.2
29.0
11.2
11.7
7.6
7.9
7.2

3.4
3.6
2.7
3.0
1.8
1.6
1.5
0.9
1.0
1.1
0.5
0.3

0.1

(1,062.6)

244.1
122.3
672.2
220.9
142.6
111.2
70.1
2010
5,706.4
5,387.8
2,258.4
1,745.5
777.8
340.2
224.2
41.6
125.1

54.3
32.3
30.5
13.2
12.1
10.0
8.7
8.0

4.4
3.7
3.3
3.0
2.2
1.9
1.7
1.2
1.0
1.0
0.5
0.3

0.2

(1,074.7)

266.1
127.8
666.5
215.4
141.3
107.8
72.6
                                                              Trends in Greenhouse Gas Emissions
2-3

-------
Manure Management 31.7
Petroleum Systems 35.2
Wastewater Treatment 15.9
Rice Cultivation 7. 1 1
Stationary Combustion 7.5l
Abandoned Underground Coal
Mines 6.01
Forest Land Remaining Forest
Land 2.5
Mobile Combustion 4.7
Composting 0.3
Petrochemical Production 0.9
Iron and Steel Production &
Metallurgical Coke Production 1 -0 1
Field Burning of Agricultural
Residues 0.2
Ferroalloy Production + 1
Silicon Carbide Production and
Consumption + 1
Incineration of Waste + 1
International Bunker Fuels' 0.2m
N2O 316.2
Agricultural Soil Management 200.0
Stationary Combustion 12.3
Mobile Combustion 43.9
Manure Management 14.8
Nitric Acid Production 17.6
Wastewater Treatment 3.5
N2O from Product Uses 4.4
Forest Land Remaining Forest
Land 2.1
Adipic Acid Production 15.8
Composting 0.4
Settlements Remaining
Settlements l.OJ
Incineration of Waste 0.5
Field Burning of Agricultural
Residues 0.1
Wetlands Remaining Wetlands + 1
International Bunker Fuels0 1.1
HFCs 36.9
Substitution of Ozone Depleting
Substances 0.3
HCFC-22 Production 36.4
Semiconductor Manufacture 0.2
PFCs 20.6
Semiconductor Manufacture 2.2
Aluminum Production 18.4
SF6 32.6
Electrical Transmission and
Distribution 26-7
Magnesium Production and
Processing 5.4
Semiconductor Manufacture 0 . 5
Total 6,175.2
Net Emissions (Sources and Sinks) 5,293.4
+ Does not exceed 0.05 Tg CO2 Eq.
147.9 48.4
29.2 29.2
16.5 16.7
6.8 5.9
6.6 6.2

5.5 5.5

18.1 17.9
2.5 2.4
1.6 1.6
1.1 1.0
0.7 0.7

10.2 0.2
: :
+ +
0.1 0.2
331.9 336.8
213.1 211.1
120.6 20.8
37.0 33.7
17.6 18.4
16.4 16.1
4.7 4.8
4.4 4.4

7.0 15.0
17.4 8.9
1.7 1.8
1.5 1.5
0.4 0.4

0.1 0.1
+ +
11.0 1.2
115.0 116.0

99.0 101.9
15.8 13.8
0.2 0.3
6.2 6.0
3.2 3.5
3.0 2.5
17.8 16.8

13.9 13.0

2.9 2.9
1.0 1.0
7,204.2 7,159.3
6,118.3 6,048.9

52.7
29.8
16.6
6.2
6.5

5.3

14.6
2.2
1.7
1.0
0.7

0.2
+
+
0.2
334.9
211.1
21.2
29.0
18.5
19.2
4.8
4.4

12.2
10.7
1.8
1.6
0.4

0.1
+
1.2
120.0

102.7
17.0
0.3
7.5
3.7
3.8
15.6

12.2

2.6
0.8
7,252.8
6,144.5

a The net CO2 flux total includes both emissions and sequestration, and constitutes a
51.8
30.0
16.6
7.2
6.6

5.3

8.8
2.1
1.7
0.9
0.6

0.2
+
+
0.2
317.1
212.9
21.1
25.2
18.3
16.4
4.9
4.4

7.5
2.6
1.9
1.5
0.4

0.1
+
1.2
117.5

103.6
13.6
0.3
6.6
4.0
2.7
15.0

12.2

1.9
0.9
7,048.3
5,960.9

50.7
30.7
16.5
7.3
6.3

5.1

5.8
2.0
1.6
0.8
0.4

0.2
+
+
0.1
304.0
207.3
20.7
22.5
18.2
14.5
5.0
4.4

5.1
2.8
1.8
1.4
0.4

0.1
+
1.1
112.1

106.3
5.4
0.3
5.6
4.0
1.6
13.9

11.8

1.1
1.0
6,608.3
5,545.7

sink in the United States
52.0
31.0
16.3
8.6
6.3

5.0

4.8
1.9
1.6
0.9
0.5

0.2
+
+
0.2
306.2
207.8
22.6
20.6
18.3
16.7
5.0
4.4

4.3
2.8
1.7
1.4
0.4

0.1
+
1.2
123.0

114.6
8.1
0.3
5.6
4.1
1.6
14.0

11.8

1.3
0.9
6,821.8
5,747.1

Sinks
2-4   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
  are only included in net emissions total. Parentheses indicate negative values or sequestration.
  b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector
  totals. Net carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use,
  Land-Use Change, and Forestry.
  0 Emissions from International Bunker Fuels are not included in totals.
  d Small amounts of PFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production &
Metallurgical Coke
Production
Natural Gas Systems
Cement Production
Lime Production
Incineration of Waste
Limestone and Dolomite Use
Ammonia Production
Cropland Remaining
Cropland
Urea Consumption for Non-
Agricultural Purposes
Soda Ash Production and
Consumption
Petrochemical Production
Aluminum Production
Carbon Dioxide
Consumption
Titanium Dioxide Production
Ferroalloy Production
Zinc Production
Phosphoric Acid Production
Wetlands Remaining
Wetlands
Lead Production
Petroleum Systems
Silicon Carbide Production
and Consumption
Land Use, Land-Use
Change, and Forestry
Wood Biomass and Ethanol
Consumption
International Bunker Fuels0
CH,
Natural Gas Systems
Enteric Fermentation
1990
5,100,499
4,742,080
1,820,818
1,485,939
846,389
338,347
218,963
27,882
119,627


99,593 B
37,5741
3 3, 278 1
ll,533i
7,989 1
5,127l
13,047

7,084 •

3,784l

4,141 1
3,31 1 1
6,83 ll

i,4iel
1,195(
2,152|
632
1,529|

l,033l
siel
394

375

(881,848)

218,637
111,828
31,822
9,029l
6,373!
2005
6,107,587
5,757,404
2,402,143
1,896,604
816,352
357,903
223,511
49,968
144,098


66,000
30,140
45,197
14,379
12,468
6,768
9,196

7,854

3,653

4,228
4,181
4,142

1,321
1,755
1,392
1,030
1,386

1,079
553
305

219

(1,085,929)

228,614
109,765
29,798
9,071
6,618
2006
6,019,033
5,666,588
2,346,407
1,878,114
848,134
321,514
208,580
50,284
143,761


68,854
30,118
45,792
15,100
12,531
8,035
8,781

7,875

3,519

4,162
3,837
3,801

1,709
1,836
1,505
1,030
1,167

879
560
306

207

(1,110,385)

233,665
128,413
31,649
10,369
6,731
2007
6,118,566
5,771,185
2,412,827
1,893,889
844,412
341,649
218,875
46,123
134,863


71,138
31,047
44,538
14,595
12,727
7,702
9,074

8,222

4,944

4,140
3,931
4,251

1,867
1,930
1,552
1,025
1,166

1,012
562
310

196

(1,108,249)

241,128
127,643
31,247
9,774
6,850
2008
5,924,259
5,579,548
2,360,920
1,789,846
806,539
349,318
225,069
39,845
138,624


66,092
32,811
40,531
14,330
11,888
6,276
7,883

8,638

4,065

4,099
3,449
4,477

1,780
1,809
1,599
1,159
1,187

992
547
297

175

(1,087,454)

252,097
133,730
31,804
10,127
6,829
2009
5,500,517
5,214,694
2,146,415
1,727,909
726,622
338,985
224,586
41,650
123,712


42,113
32,165
29,018
11,225
11,703
7,649
7,855

7,245

3,415

3,554
2,735
3,009

1,784
1,648
1,469
943
1,018

1,089
525
325

145

(1,062,559)

244,078
122,338
32,010
10,519
6,788
2010
5,706,370
5,406,848
2,258,358
1,745,466
777,840
340,235
224,243
41,649
125,130


54,276
32,297
30,509
13,151
12,054
10,017
8,678

8,050

4,365

3,735
3,336
3,009

2,203
1,876
1,663
1,168
1,017

983
542
337

181

(1,074,684)

266,110
127,841
31,740
10,259
6,728
                                                                   Trends in Greenhouse Gas Emissions
2-5

-------
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Rice Cultivation
Stationary Combustion
Abandoned Underground
Coal Mines
Forest Land Remaining
Forest Land
Mobile Combustion
Composting
Petrochemical Production
Iron and Steel Production &
Metallurgical Coke
Field Burning of Agricultural
Residues
Ferroalloy Production
Silicon Carbide Production
and Consumption
Incineration of Waste
International Bunker Fuels'
N2O
Agricultural Soil
Management
Stationary Combustion
Mobile Combustion
Manure Management
Nitric Acid Production
Wastewater Treatment
N2O from Product Uses
Forest Land Remaining
Forest Land
Adipic Acid Production
Composting
Settlements Remaining
Settlements
Incineration of Waste
Field Burning of
Agricultural Residues
Wetlands Remaining
Wetlands
International Bunker Fuels'
HFCs
Substitution of Ozone
Depleting Substances
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
Electrical Transmission and
Distribution
Magnesium Production and
Processing
Semiconductor Manufacture
7,032 • 5,367
4,003 • 2,705
1,51 ll 2,280
1,67?B 1,390
758 785
339 326
355 315

288

120
223
15
41

46

10
1

1
+
8
1,020

645

264

388
121
75
51

34

8
+

+
+
7
1,071

687
40 66
142 119
48
57
11
14

7
51
1

3
2

+

+
3
M
57
53
15
14

23
24
6

5
1

+

+
3
M

M M
11
+
M
M
M
1

1

+
+ +
5,320
2,768
2,303
1,389
794
282
296

261

854
114
75
48

35

11
+

+
+
8
1,087

681
67
109
59
52
15
14

48
29
6

5
1

+

+
4
M

M
1
+
M
M
M
1

1

+
+
5,320
2,754
2,508
1,420
791
295
311

254

693
107
79
48

33

11
+

+
+
8
1,080

681
68
94
60
62
16
14

39
34
6

5
1

+

+
4
M

M
1
+
M
M
M
1

1

+
+
5,386
3,186
2,465
1,427
792
343
313

253

419
99
80
43

31

11
+

+
+
8
1,023

687
68
81
59
53
16
14

24
8
6

5
1

+

+
4
M

M
1
+
M
M
M
1

1

+
+
5,295
3,340
2,416
1,460
787
349
298

244

276
93
75
39

17

11
+

+
+
7
981

669
67
73
59
47
16
14

16
9
6

4
1

+

+
4
M

M
+
+
M
M
M
1

+

+
+
5,135
3,458
2,478
1,478
779
410
301

237

231
91
75
44

25

11
+

+
+
8
988

670
73
66
59
54
16
14

14
9
6

5
1

+

+
4
M

M
1
+
M
M
M
1

+

+
+

2-6   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
  + Does not exceed 0.5 Gg.
  M Mixture of multiple gases
  a The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are
  only included in net emissions total.  Parentheses indicate negative values or sequestration.
  b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals.
  Net carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use
  Change, and Forestry
  0 Emissions from International Bunker Fuels are not included in totals.
  d Small amounts of PFC emissions also result from this source.
  Note:  Totals may not sum due to independent rounding.


Emissions of all gases can be summed from each source category into a set of six sectors defined by the
Intergovernmental Panel on Climate Change (IPCC).  Over the twenty-one-year period of 1990 to 2010, total
emissions in the Energy and Agriculture sectors grew by 645.8 Tg CO2 Eq. (12.2 percent) and 40.6 Tg CO2 Eq.
(10.5 percent), respectively. Emissions decreased in the Industrial Process, Waste and Solvent and Other Product
Use sectors by 10.5  Tg CO2 Eq. (3.4 percent), 35.2 Tg CO2 Eq. (21.0 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 192.8 Tg CO2 Eq. (21.9 percent).
Figure 2-4: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
Table 2-3:  Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)
Chapter/IPCC Sector
Energy
Industrial Processes
Solvent and Other Product Use
Agriculture
Land Use, Land-Use Change, and
Forestry (Emissions)
Waste
Total Emissions
Net CO2 Flux from Land Use, Land-Use
Change, and Forestry (Sinks)*
Net Emissions (Sources and Sinks)
1990
5,287.7
313. 9l
4.4l
387.sl

13.sl
167.7
6,175.2

(881.8)
5,293.4
2005
6,282.4
330.1
4.4
424.6

25.6
137.2
7,204.2

(1085.9)
6,118.3
* The net CO2 flux total includes both emissions and sequestratioi
2006
6,214.4
335.5
4.4
425.4

43.2
136.5
7,159.3

(1110.4)
6,048.9
2007
6,294.3
347.3
4.4
432.6

37.6
136.7
7,252.8

(1108.2)
6,144.5
2008
6,125.4
319.1
4.4
433.8

27.4
138.2
7,048.3

(1087.5)
5,960.9
2009
5,752.7
268.2
4.4
426.4

20.6
136.0
6,608.3

(1062.6)
5,545.7
a, and constitutes a sink in the United States.
2010
5,933.5
303.4
4.4
428.4

19.6
132.5
6,821.8

(1074.7)
5,747.1
Sinks
   are only included in net emissions total. Please refer to Table 2-9 for a breakout by source.
   Note:  Totals may not sum due to independent rounding.
   Note:  Parentheses indicate negative values or sequestration.
Energy
Energy-related activities, primarily fossil fuel combustion, accounted for the vast majority of U.S. CO2 emissions for
the period of 1990 through 2010. In 2010, 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 also responsible for CH4 and N2O emissions (50
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.
                                                                Trends in Greenhouse Gas Emissions
2-7

-------
Figure 2-5: 2010 Energy Chapter Greenhouse Gas Sources
Figure 2-6: 2010 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
Table 2-4: Emissions from Energy (Tg CO2 Eq.)
Gas/Source
CO2
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass - Wood"
International Bunker Fuels
Biomass - Ethanol"
CH,
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Abandoned Underground Coal
Mobile Combustion
Incineration of Waste
International Bunker Fuelf
N20
Stationary Combustion
Mobile Combustion
Incineration of Waste
International Bunker Fuels0
Total
1990 2005
4,903.9 5,933.3
4,738.3 5,746.5
l,820.sH 2,402.1
1,485.9 1,896.6
846.4B 816.4
338.3
219.0
27.9
119.6
37.6
8.0
0.4
214.4
111.8
4.2
327.1
189.6
84.1
35.2
7.5
6.0
4.7
0.0
0.2
56.7
12.3
43.9
357.9
223.5
50.0
144.1
29.9
12.5
0.3
205.7
109.8
22.9
291.2
190.5
56.8
29.2
6.6
5.5
2.5
0.0
0.1
58.0
20.6
37.0
0.5 0.4
1.1 1.0
5,287.7 6,282.4
2006
5,840.4
5,653.0
2,346.4
1,878.1
848.1
321.5
208.6
50.3
143.8
30.8
12.5
0.3
202.7
128.4
31.0
319.1
217.7
58.1
29.2
6.2
5.5
2.4
0.0
0.2
54.8
20.8
33.7
0.4
1.2
6,214.4
2007
5,936.7
5,757.8
2,412.8
1,893.9
844.4
341.6
218.9
46.1
134.9
31.0
12.7
0.3
202.2
127.6
38.9
307.0
205.3
57.8
29.8
6.5
5.3
2.2
0.0
0.2
50.6
21.2
29.0
0.4
1.2
6,294.3
2008
5,755.2
5,571.5
2,360.9
1,789.8
806.5
349.3
225.1
39.8
138.6
32.8
11.9
0.3
197.4
133.7
54.7
323.5
212.7
66.9
30.0
6.6
5.3
2.1
0.0
0.2
46.7
21.1
25.2
0.4
1.2
6,125.4
2009
5,374.1
5,206.2
2,146.4
1,727.9
726.6
339.0
224.6
41.7
123.7
32.2
11.7
0.3
181.8
122.3
62.3
335.1
220.9
70.1
30.7
6.3
5.1
2.0
0.0
0.1
43.6
20.7
22.5
0.4
1.1
5,752.7
2010
5,557.6
5,387.8
2,258.4
1,745.5
777.8
340.2
224.2
41.6
125.1
32.3
12.1
0.3
191.6
127.8
74.5
332.3
215.4
72.6
31.0
6.3
5.0
1.9
0.0
0.2
43.6
22.6
20.6
0.4
1.2
5,933.5
+ Does not exceed 0.05 Tg CO2 Eq.
a Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change, and
Forestry
b Emissions from International Bunker Fuels are not included in totals.
Note:  Totals may not sum due to independent rounding.

Carbon dioxide 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 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 they 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
2-8   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
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.

Table 2-5: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial

Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1990
1,489.0
1,485.9
3.0
1,533.1
846.4
686.8
931.4
338.3
593.0
757.0

219.0
538.0
27.9
4,738.3
1,820.8














2005
1,901.3
1,896.6
4.7
1,553.3
816.4
737.0
1,214.7
357.9
856.7
1,027.2

223.5
803.7
50.0
5,746.5
2,402.1

1
1
1


1
1




5
7
2006
,882.6
,878.1
4.5
,560.2
848.1
712.0
,152.4
321.5
830.8
,007.6

208.6
799.0
50.3
,653.0
,346.4

1
1
1


1
1




5
7
2007
,899.0
,893.9
5.1
,559.8
844.4
715.4
,205.2
341.6
863.5
,047.7

218.9
828.8
46.1
,757.8
,412.8
2008
1,794.5
1,789.8
4.7
1,503.8
806.5
697.3
1,192.2
349.3
842.9
1,041.1

225.1
816.0
39.8
5,571.5
2,360.9

1
1
1


1





5
7
2009
,732.4
,727.9
4.5
,328.6
726.6
602.0
,125.5
339.0
786.5
978.0

224.6
753.5
41.7
,206.2
,146.4
2010
1,750.0
1,745.5
4.5
1,415.4
777.8
637.6
1,183.7
340.2
843.5
997.1

224.2
772.9
41.6
5,387.8
2,258.4
  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.


Figure 2-7: 2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type


Figure 2-8: 2010 End-Use Sector Emissions from Fossil Fuel Combustion
The main driver of emissions in the Energy sector is CO2 from fossil fuel combustion. Electricity generation is the
largest emitter of CO2, and electricity generators consumed 36 percent of U.S. energy from fossil fuels and emitted
42 percent of the CO2 from fossil fuel combustion in 2010. Electricity generation emissions can also be allocated to
the end-use sectors that are consuming that electricity, as presented in Table 2-5. The transportation end-use sector
accounted for 1,750.0 Tg CO2 Eq. in 2010, or approximately 32 percent of total CO2 emissions from fossil fuel
combustion. The industrial end-use sector accounted for 26 percent of CO2 emissions from fossil fuel combustion.
The residential and commercial end-use sectors accounted for 22 and 19 percent, respectively, of CO2 emissions
from fossil fuel combustion. Both of these end-use sectors were heavily reliant on electricity for meeting energy
needs, with electricity consumption for lighting, heating, air conditioning, and operating appliances contributing 71
and 78 percent of emissions from the residential and commercial end-use sectors, respectively.  Significant trends in
emissions from energy source categories over the twenty one-year period from 1990 through 2010 included the
following:

    •   Total CO2 emissions from fossil fuel combustion increased from 4,738.3 Tg CO2 Eq. to 5,387.8 Tg CO2
        Eq.—a 13.7 percent total increase over the twenty one-year period.  From 2009 to 2010, these emissions
        increased by 181.6 Tg CO2 Eq. (3.5 percent).

    •   CO2 emissions from non-energy use of fossil fuels increased 5.5 Tg CO2 Eq. (4.6 percent) from 1990
        through 2010. Emissions from non-energy uses of fossil fuels were 125.1 Tg CO2 Eq.  in 2010, which
        constituted  2.2 percent of total national CO2 emissions.

    •   CO2 emissions from incineration of waste (12.1 Tg CO2Eq. in 2010) increased by 4.1 Tg CO2Eq. (50.9
        percent) from 1990 through 2010, as the volume of plastics  and other fossil carbon-containing materials in
                                                              Trends in Greenhouse Gas Emissions
2-9

-------
        municipal solid waste grew.

    •   N2O emissions from stationary combustion increased 10.3 Tg CO2 Eq. (84.4 percent) from 1990 through
        2010. N2O emissions from this source increased primarily as a result of an increase in the number of coal
        fluidized bed boilers in the electric power sector.

    •   CH4 emissions from coal mining were 72.6 Tg CO2 Eq. in 2010, a decline in emissions of 11.5 Tg CO2 Eq.
        (13.6 percent) from 1990. This occurred as a result of the mining of less gassy coal from underground
        mines and the increased use of CH4 collected from degasification systems.

    •   CH4 emissions from natural gas systems were 215.4 Tg CO2 Eq. in 2010; emissions have increased by
        25.8Tg CO2 Eq. (13.6 percent) since 1990.

    •   In 2010, N2O emissions from mobile combustion were 20.6 Tg CO2 Eq. (approximately 6.7 percent of U.S.
        N2O emissions). From 1990 to 2010, N2O emissions from mobile combustion decreased by 53.1 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.

Industrial  Processes

Greenhouse gas emissions are produced as the by-products of many non-energy-related industrial 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, urea consumption, lime production, limestone and dolomite use (e.g., flux stone,
flue gas desulfurization, and glass manufacturing), soda ash production and consumption, 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).  Industrial processes also release HFCs, PFCs and SF6. 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. Table 2-6  presents greenhouse gas emissions from industrial processes by source
category.


Figure 2-9: 2010 Industrial Processes Chapter Greenhouse Gas Sources


Table 2-6: Emissions from Industrial Processes (Tg CO2 Eq.)
Gas/Source
CO2
Iron and Steel Production & Metallurgical
Iron and Steel Production
Metallurgical Coke Production
Cement Production
Lime Production
Limestone and Dolomite Use
Ammonia Production
Urea Consumption for Non- Agriculture
Purposes
Soda Ash Production and Consumption
Petrochemical Production
Aluminum Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
1990
188.5
99.61
97.1
2.5
33.3
11.5
5.1
13.0








2005
165.4
66.0
64.0
2.0
45.2
14.4
6.8
9.2

3.7
4.2
4.2
4.1
1.3
1.8
1.4
2006
169.9
68.9
66.9
1.9
45.8
15.1
8.0
8.8

3.5
4.2
3.8
3.8
1.7
1.8
1.5
2007
172.6
71.1
69.1
2.1
44.5
14.6
7.7
9.1

4.9
4.1
3.9
4.3
1.9
1.9
1.6
2008
159.5
66.1
63.8
2.3
40.5
14.3
6.3
7.9

4.1
4.1
3.4
4.5
1.8
1.8
1.6
2009
118.1
42.1
41.2
1.0
29.0
11.2
7.6
7.9

3.4
3.6
2.7
3.0
1.8
1.6
1.5
2010
139.7
54.3
52.2
2.1
30.5
13.2
10.0
8.7

4.4
3.7
3.3
3.0
2.2
1.9
1.7
2-10   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Zinc Production
Phosphoric Acid Production
Lead Production
Silicon Carbide Production and Consumption
CH,
Petrochemical Production
Iron and Steel Production & Metallurgical
Iron and Steel Production
Metallurgical Coke Production
Ferroalloy Production
Silicon Carbide Production and Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone Depleting Substances*
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
Electrical Transmission and Distribution
Magnesium Production and Processing
Semiconductor Manufacture
Total
0.6
L5
0.5
0.4
1.9
0.9
:!
33.4
17.61
15.8
36.9
0.3
36.4
0.2
20.6
2.2
18.4
32.6
26.7
5.4
0.5
313.9
1.0
1.4
0.6
0.2
1.8
1.1
0.7
0.7
+
+
+
23.9
16.4
7.4
115.0
99.0
15.8
0.2
6.2
3.2
3.0
17.8
13.9
2.9
1.0
330.1
1.0
1.2
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
25.0
16.1
8.9
116.0
101.9
13.8
0.3
6.0
3.5
2.5
16.8
13.0
2.9
1.0
335.5
1.0
1.2
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
29.8
19.2
10.7
120.0
102.7
17.0
0.3
7.5
3.7
3.8
15.6
12.2
2.6
0.8
347.3
1.2
1.2
0.5
0.2
1.6
0.9
0.6
0.6
+
+
+
18.9
16.4
2.6
117.5
103.6
13.6
0.3
6.6
4.0
2.7
15.0
12.2
1.9
0.9
319.1
0.9
1.0
0.5
0.1
1.2
0.8
0.4
0.4
+
+
+
17.3
14.5
2.8
112.1
106.3
5.4
0.3
5.6
4.0
1.6
13.9
11.8
1.1
1.0
268.2
1.2
1.0
0.5
0.2
1.5
0.9
0.5
0.5
+
+
+
19.5
16.7
2.8
123.0
114.6
8.1
0.3
5.6
4.1
1.6
14.0
11.8
1.3
0.9
303.4
  + Does not exceed 0.05 Tg CO2 Eq.
  a Small amounts of PFC emissions also result from this source.
  Note: Totals may not sum due to independent rounding.
Overall, emissions from the Industrial Processes sector decreased by 3.4 percent from 1990 to 2010, as emission
decreases from some sources have been offset by increases from other sources. Significant trends in emissions from
industrial processes source categories over the twenty-one-year period from 1990 through 2010 included the
following:

    •   Combined CO2 and CH4 emissions from iron and steel production and metallurgical coke production
        increased by 29 percent to 54.8 Tg CO2 Eq. from 2009 to 2010, but have declined overall by 45.8 Tg CO2
        Eq. (45.5 percent) from 1990 through 2010, due to restructuring of the industry, technological
        improvements, and increased scrap steel utilization.

    •   CO2 emissions from ammonia production (8.7 Tg CO2 Eq. in 2010) decreased by 4.4 Tg CO2 Eq. (33.5
        percent) since 1990. This is due to a decrease in domestic ammonia production primarily attributed to
        market fluctuations. Urea consumption for non-agricultural purposes (4.4 Tg CO2 Eq. in 2010) increased by
        0.6 Tg CO2 Eq. (15.3 percent) since  1990.

    •   N2O emissions from adipic acid production were 2.8 Tg CO2 Eq. in 2010, and have decreased significantly
        in recent years due to the widespread installation of pollution control measures. Emissions from adipic acid
        production have decreased by 82.2 percent since 1990 and by 84.0 percent since a peak in 1995.

    •   HFC emissions from ODS substitutes have been increasing from small amounts in 1990 to 114.6 Tg CO2
        Eq. in 2010.  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.

    •   PFC emissions from aluminum production decreased by about 91.5 percent (16.9 Tg CO2 Eq.) from 1990
        to 2010, due to both industry emission  reduction efforts and lower domestic aluminum production.
                                                             Trends in Greenhouse Gas Emissions
2-11

-------
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, 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. greenhouse gas emissions in 2010 (see Table 2-7).
Table 2-7: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.)
Gas/Source
N2O
N2O from Product Uses
Total
1990
4.4
4.4
4.4
2005
4.4
4.4
4.4
2006
4.4
4.4
4.4
2007
4.4
4.4
4.4
2008
4.4
4.4
4.4
2009
4.4
4.4
4.4
2010
4.4
4.4
4.4
In 2010, N2O emissions from product uses constituted 1.4 percent of U.S. N2O emissions. From 1990 to 2010,
emissions from this source category decreased by just under 0.4 percent, though slight increases occurred in
intermediate years.

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.

In 2010, agricultural activities were responsible for emissions of 428.4 Tg CO2 Eq., or 6.3 percent of total U.S.
greenhouse gas emissions. CH4 and N2O were the primary greenhouse gases emitted by agricultural activities.  CH4
emissions from enteric fermentation and manure management represented about 21.2 percent and 7.8 percent of total
CH4 emissions from anthropogenic activities, respectively, in 2010. Agricultural soil management activities, such as
fertilizer application and other cropping practices, were the largest source of U.S. N2O emissions in 2010,
accounting for 67.9 percent.
Figure 2-10: 2010 Agriculture Chapter Greenhouse Gas Sources
Table 2-8: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH,
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N20
Agricultural Soil Management
Manure Management
Field Burning of Agricultural
Residues
Total
1990
172.9
1 J J .O
;
214.9
200.0 1
14.8 I
0.1 1

387.8
2005
193.9
139.0
47.9
6.8
0.2
230.7
213.1
17.6
0.1

424.6
2006
195.9
141.4
48.4
5.9
0.2
229.6
211.1
18.4
0.1

425.4
2007
202.9
143.8
52.7
6.2
0.2
229.7
211.1
18.5
0.1

432.6
2008
202.6
143.4
51.8
7.2
0.2
231.3
212.9
18.3
0.1

433.8
2009
200.8
142.6
50.7
7.3
0.2
225.6
207.3
18.2
0.1

426.4
2010
202.2
141.3
52.0
8.6
0.2
226.2
207.8
18.3
0.1

428.4
  Note: Totals may not sum due to independent rounding.
Some significant trends in U.S. emissions from Agriculture source categories include the following:

    •   Agricultural soils produced approximately 67.9 percent of N2O emissions in the United States in 2010.
        Estimated emissions from this source in 2010 were 207.8 Tg CO2 Eq. Annual N2O emissions from
        agricultural soils fluctuated between 1990 and 2010, although overall emissions were 3.9 percent higher in
2-12   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
        2010 than in 1990. Nitrous oxide emissions from this source have not shown any significant long-term
        trend, as their estimation is 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 second largest source of CH4 emissions in the United States in 2010, at 141.3
        Tg CO2 Eq.  Generally, emissions decreased from 1995 to 2003, though with a slight increase in 2002.
        This trend was mainly due to decreasing populations of both beef and dairy cattle and increased
        digestibility of feed for feedlot cattle. Emissions increased from 2004 through 2007, as both dairy and beef
        populations increased and the literature for dairy cow diets indicated a trend toward a decrease in feed
        digestibility for those years. Emissions decreased again in 2008, 2009, and 2010 as beef cattle populations
        decreased. During the timeframe of this analysis, populations of sheep have decreased 51 percent since
        1990 while horse populations have increased over 87 percent, mostly since 1999.  Goat and swine
        populations have increased 25 percent and 20 percent, respectively, during this timeframe.

    •   Overall, emissions from manure management increased 51.2 percent between 1990 and 2010. This
        encompassed an increase of 64.0 percent for CH4, from 31.7 TgCO2Eq. in 1990 to 52.0 TgCO2Eq. in
        2010; and an increase of 23.7 percent for N2O, from 14.8 Tg CO2 Eq. in 1990 to 18.3 Tg CO2 Eq. in 2010.
        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 CH4 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 16
percent of total U.S. greenhouse gas emissions in 2010.  Forests (including vegetation, soils, and harvested wood)
accounted for approximately 86 percent of total 2010 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 2010. 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 5.9 times as much C as is emitted from these soils through liming and urea fertilization.
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 and food  scraps carbon in landfills.

Land use, land-use change, and forestry activities in 2010 resulted in a net C sequestration of 1,074.7 Tg CO2 Eq.
(293.1 Tg C) (Table 2-9).  This represents an offset of approximately 19 percent of total U.S. CO2 emissions, or 16
percent of total greenhouse gas emissions in 2010. Between 1990 and 2010, total land use, land-use change, and
forestry net C flux resulted in a 21.9 percent increase in CO2 sequestration.

Table 2-9: Net CO2 Flux from Land Use, Land-Use Change, and Forestry  (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining Grassland
Land Converted to Grassland
Settlements Remaining Settlements
Other (Landfilled Yard Lrimmings
and Food Scraps)
Total
1990
(701.4)
(29.4)
2.2 •
(52.2)1
(19.8)1
(57.1)1

(24.2)
(881.8)
2005
(940.9)
(18.3)
5.9
(8.9)
(24.4)
(87.8)

(11.6)
(1,085.9)
2006
(963.5)
(19.1)
5.9
(8.8)
(24.2)
(89.8)

(11.0)
(1,110.4)
2007
(959.2)
(19.7)
5.9
(8.6)
(24.0)
(91.9)

(10.9)
(1,108.2)
2008
(938.3)
(18.1)
5.9
(8.5)
(23.8)
(93.9)

(10.9)
(1,087.5)
2009
(910.6)
(17.4)
5.9
(8.3)
(23.6)
(95.9)

(12.7)
(1,062.6)
2010
(921.8)
(15.6)
5.9
(8.3)
(23.6)
(98.0)

(13.3)
(1,074.7)
  Note: Lotals may not sum due to independent rounding. Parentheses indicate net sequestration.
                                                              Trends in Greenhouse Gas Emissions
2-13

-------
Land use, land-use change, and forestry source categories also resulted in emissions of CO2, CH4, and N2O that are
not included in the net CO2 flux estimates presented in Table 2-9.  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
2010, an increase of about 13.6 percent relative to 1990.  Lands undergoing peat extraction resulted in CO2
emissions of 1.0 Tg CO2 Eq. (983 Gg), and N2O emissions of less than 0.05 Tg CO2 Eq. N2O emissions from the
application of synthetic fertilizers to forest soils have increased from 0.1 Tg CO2 Eq. in 1990 to 0.4 Tg CO2 Eq. in
2010. Settlement soils in 2010 resulted in direct N2O emissions of 1.4 Tg CO2 Eq., a 43 percent increase relative to
1990. Emissions from forest fires in 2010 resulted in CH4 emissions of 4.8 TgCO2Eq., andinN2O emissions of 4.0
Tg CO2 Eq. (Table 2-10).

Table 2-10: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Source Category
C02
Cropland Remaining Cropland:
Liming of Agricultural Soils
Cropland Remaining Cropland: Urea
Fertilization
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands
CH,
Forest Land Remaining Forest Land:
Forest Fires
N20
Forest Land Remaining Forest Land:
Forest Fires
Forest Land Remaining Forest Land:
Forest Soils
Settlements Remaining Settlements:
Settlement Soils
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands
Total
1990
8.1


2. -f •

1.0
2.5

2,
3.1

2.1

0.1

1.0

+
13.8
2005
8.9

4.3
3.5

1.1
8.1

8.1
8.5

6.6

0.4

1.5

+
25.6
2006
8.8

4.2
3.7

0.9
17.9

17.9
16.5

14.6

0.4

1.5

+
43.2
2007
9.2

4.5
3.8

1.0
14.6

14.6
13.8

11.9

0.4

1.6

+
37.6
2008
9.6

5.0
3.6

1.0
8.8

8.8
9.0

7.2

0.4

1.5

+
27.4
2009
8.3

3.7
3.6

1.1
5.8

5.8
6.5

4.7

0.4

1.4

+
20.6
2010
9.0

3.9
4.1

1.0
4.8

4.8
5.7

4.0

0.4

1.4

+
19.6
  + Less than 0.05 Lg CO2 Eq.
  Note: Lotals may not sum due to independent rounding.


Other significant trends from 1990 to 2010 in emissions from land use, land-use change, and forestry source
categories include:

    •   Net C sequestration by forest land has increased by approximately 31 percent. This is primarily due to
        increased forest 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 20 years, although only at an average
        rate of 0.22 percent per year.

    •   Net sequestration of C by urban trees has increased by 71.8 percent over the period from 1990 to 2010.
        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 44.9 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.
2-14   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Waste
Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 2-11).  In 2010,
landfills were the third largest source of U.S. anthropogenic CH4 emissions, accounting for 16.2 percent of total U.S.
CH4 emissions.48 Additionally, wastewater treatment accounts for 2.5 percent of U.S. CH4 emissions, and 1.6
percent of N2O emissions. Emissions of CH4 and N2O from composting grew from 1990 to 2010, and resulted in
emissions of 3.3 TgCO2Eq. in 2010. A summary of greenhouse gas emissions from the Waste chapter is presented
in Table 2-11.
Figure 2-11: 2010 Waste Chapter Greenhouse Gas Sources


Overall, in 2010, waste activities generated emissions of 132.5 Tg CO2 Eq., or 1.9 percent of total U.S. greenhouse
gas emissions.

Table 2-11: Emissions from Waste (Tg CO2 Eq.)
Gas/Source
CH,
Landfills
Wastewater Treatment
Composting
N20
Wastewater Treatment
Composting
Total
1990
163.9
147. im
15.9
0.3
3.8
3.5
0.4
167.7
2005
130.8
112.7
16.5
1.6
6.4
4.7
1.7
137.2
2006
130.0
111.7
16.7
1.6
6.5
4.8
1.8
136.5
2007
130.0
111.7
16.6
1.7
6.7
4.8
1.8
136.7
2008
131.4
113.1
16.6
1.7
6.8
4.9
1.9
138.2
2009
129.3
111.2
16.5
1.6
6.7
5.0
1.8
136.0
2010
125.8
107.8
16.3
1.6
6.8
5.0
1.7
132.5
  Note: Totals may not sum due to independent rounding.


Some significant trends in U.S. emissions from waste source categories include the following:

    •   From 1990 to 2010, net CH4 emissions from landfills decreased by 39.8 Tg CO2 Eq. (27 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,49 which has more than offset the
        additional CH4 emissions resulting from an increase in the amount of municipal solid waste landfilled.

    •   Combined CH4 and N2O emissions from composting have generally increased since 1990, from 0.7 Tg CO2
        Eq. to 3.3 Tg CO2 Eq. in 2010, which represents slightly less than a five-fold increase over the time series.

    •   From 1990 to 2010, CH4 and N2O emissions from wastewater treatment increased by 0.4 Tg CO2 Eq. (2.7
        percent) and 1.6 Tg CO2 Eq. (46 percent), respectively.

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
48 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.
49 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.


                                                             Trends in Greenhouse Gas Emissions     2-15

-------
U.S. greenhouse gas emissions in 2010.  Transportation activities, in aggregate, accounted for the second largest
portion (27 percent).  Emissions from industry accounted for about 20 percent of U.S. greenhouse gas emissions in
2010. 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 19 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 5.4 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 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 less than 1 percent.

CO2 was also emitted and sequestered (in the form of C) 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 2010.
Figure 2-12: Emissions Allocated to Economic Sectors
Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent of Total in
2010)
Sector/Source
Electric Power Industry
CO2 from Fossil Fuel Combustion
Stationary Combustion - N2O and CH4
Incineration of Waste
Electrical Transmission and Distribution
Limestone and Dolomite Use
Transportation
CO2 from Fossil Fuel Combustion
Substitution of Ozone Depleting Substances
Mobile Combustion
Non-Energy Use of Fuels
Industry
CO2 from Fossil Fuel Combustion
Natural Gas Systems
Non-Energy Use of Fuels
Coal Mining
Iron and Steel Production
Petroleum Systems
Cement Production
Nitric Acid Production
Substitution of Ozone Depleting Substances
Lime Production
Ammonia Production
HCFC-22 Production
Semiconductor Manufacture
Limestone and Dolomite Use
Abandoned Underground Coal Mines
Aluminum Production
N2O from Product Uses
Urea Consumption for Non- Agricultural
1990
1,866.2
1,820.8
™
8.5
26.7
2.6\
1,545.2
1,485.9
+ 1
47.4J
11. 8J
1,564.8
815.3
227.2
102.1
84.1
100.5
35.6
33.3
17.6
+ 1
11.5
13.ol
36.41
2.9l
2.6
6.0
25.3
4.4J
3.sl
2005
2,448.8
2,402.1
116.5
12.9
13.9
3.4
2,017.5
1,896.6
72.9
37.8
10.2
1,438.1
769.5
228.6
125.9
56.8
66.7
29.5
45.2
16.4
6.4
14.4
9.2
15.8
4.4
3.4
5.5
7.1
4.4
3.7
2006
2,393.0
2,346.4
16.7
12
13
4
1,994
1,878
72
34
9
9
0
0
5
1
2
3
9
1,499.8
799
1
229.6
125
58
0
1
69.6
29
45
16
7
15
8
13
4
4
5
6
4
3
5
8
1
1
1
8
8
7
0
5
3
4
5
2007
2,459.1
2,412.8
17.2
13.1
12.2
3.9
2,002
4
1,893.9
68.8
29.4
10.2
1,489.6
796.0
236.6
117.5
57.8
71.8
30.1
44.5
19.2
7.8
14.6
9.1
17.0
4.8
3.9
5.3
8.1
4.4
4.9
2008
2,405.8
2,360.9
17.3
12.3
12.2
3.1
1,889.8
1,789.8
64.9
25.5
9.5
1,448.5
761.1
240.8
120.7
66.9
66.7
30.3
40.5
16.4
8.5
14.3
7.9
13.6
5.1
3.1
5.3
7.2
4.4
4.1
2009
2,191.4
2,146.4
17.2
12.1
11.8
3.8
1,819.3
1,727.9
60.2
22.6
8.5
1,317.2
680.0
252.6
111.5
70.1
42.5
31.0
29.0
14.5
10.9
11.2
7.9
5.4
5.3
3.8
5.1
4.6
4.4
3.4
2010 Percent3
2,306.5
2,258.4
18.9
12.4
11.8
5.0
1,834.0
1,745.5
58.4
20.6
9.5
1,394.2
730.2
247.3
111.9
72.6
54.8
31.4
30.5
16.7
13.5
13.2
8.7
8.1
5.4
5.0
5.0
4.6
4.4
4.4
33
33
0
0
0
0
26
25
0
0
0
8%
.1%
.3%
.2%
.2%
.1%
9%
.6%
.9%
.3%
.1%
20.4%
10
3
1
1
0
0
.7%
.6%
.6%
.1%
.8%
.5%
0.4%
0
0
0
0
0
0
0
0
0
0
0
.2%
.2%
.2%
.1%
.1%
.1%
.1%
.1%
.1%
.1%
.1%
2-16   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Purposes
Petrochemical Production
Stationary Combustion
Soda Ash Production and Consumption
Adipic Acid Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
Mobile Combustion
Magnesium Production and Processing
Zinc Production
Phosphoric Acid Production
Lead Production
Silicon Carbide Production and Consumption
Agriculture
N2O from Agricultural Soil Management
Enteric Fermentation
Manure Management
CO2 from Fossil Fuel Combustion
CH4 and N2O from Forest Fires
Rice Cultivation
Liming of Agricultural Soils
Urea Fertilization
CO2 and N2O from Managed Peatlands
Mobile Combustion
N2O from Forest Soils
Field Burning of Agricultural Residues
Stationary Combustion
Commercial
CO2 from Fossil Fuel Combustion
Landfills
Substitution of Ozone Depleting Substances
Wastewater Treatment
Human Sewage
Composting
Stationary Combustion
Residential
CO2 from Fossil Fuel Combustion
Substitution of Ozone Depleting Substances
Stationary Combustion
Settlement Soil Fertilization
U.S. Territories
CO2 from Fossil Fuel Combustion
Non-Energy Use of Fuels
Stationary Combustion
Total Emissions
Sinks
CO2 Flux from Forestsb
Urban Trees
CO2 Flux from Agricultural Soil Carbon
Stocks
Landfilled Yard Trimmings and Food
Scraps
Net Emissions
Note: Includes all emissions of CO2, CH4, N2O,
may not sum due to independent rounding.
ODS (Ozone Depleting Substances)

4.2
4.9
4.1
15.8
1.4
1.2
2.2
0.9
5.4
0.6
1.5
0.5

5.3
4.6
4.2
7.4
1.3
1.8
1.4
1.3
2.9
1.0
1.4
0.6
0.4 1 0.2
431.91 496.0
200.ol 213.1
133.8
46.5
31.0
4.6
7.1
4.7
2.4
1.0
0.3
0.1
0.3
+
388.0
219.0
147.7
139.0
65.5
46.8
14.8
6.8
4.3
3.5
1.1
0.5
0.4
0.2
+
374.3
223.5
112.7
+ | 12.3
15.9 16.5
3.5 4.7
0.7l 3.3
l.sl 1.3
345.41 371.3
338. 3l 357.9
O.sl 7.3
5.7 4.6
l.ol 1.5
33.7 58.2
27.9 i 50.0
5.7 8.1
0.1 0.2
6,175.2 7,204.2
(881.8) (1,085.9)
(701.4) (940.9)
(57.1) (87.8)

(99.2)1 (45.6)

(24.2) (11.6)
5,293.4 6,118.3
HFCs, PFCs, and SF6.



4.8
4.7
4.2
8.9
1.7
1.8
1.5
1.3
2.9
1.0
1.2
0.6
0.2
516.7
211.1
141.4
66.7
49.0
32.6
5.9
4.2
3.7
0.9
0.5
0.4
0.3
+
359.9
208.6
111.7
13.6
16.7
4.8
3.3
1.2
336.1
321.5
8.9
4.1
1.5
59.3
50.3
8.8
0.2
7,159.3
(1,110.4)
(963.5)
(89.8)

(46.1)

(11.0)
6,048.9

4.9
4.6
4.1
10.7
1.9
1.9
1.6
1.3
2.6
1.0
1.2
0.6
0.2
517.6
211.1
143.8
71.1
48.4
26.4
6.2
4.5
3.8
1.0
0.5
0.4
0.3
+
372.2
218.9
111.7
15.4
16.6
4.8
3.5
1.3
358.4
341.6
10.7
4.5
1.6
53.5
46.1
7.2
0.2
7,252.8
(1,108.2)
(959.2)
(91.9)

(46.3)

(10.9)
6,144.5

4.3
4.3
4.1
2.6
1.8
1.8
1.6
1.3
1.9
1.2
1.2
0.6
0.2
505.8
212.9
143.4
70.0
45.4
16.0
7.2
5.0
3.6
1.0
0.5
0.4
0.3
+
381.8
225.1
113.1
17.2
16.6
4.9
3.5
1.3
368.4
349.3
12.9
4.7
1.5
48.4
39.8
8.4
0.2
7,048.3
(1,087.5)
(938.3)
(93.9)

(44.4)

(10.9)
5,960.9

3.6
3.7
3.6
2.8
1.8
1.6
1.5
1.3
1.1
0.9
1.0
0.5
0.2
492.8
207.3
142.6
68.9
46.7
10.5
7.3
3.7
3.6
1.1
0.5
0.4
0.3
+
382.0
224.6
111.2
20.1
16.5
5.0
3.3
1.3
360.0
339.0
15.1
4.5
1.4
45.5
41.7
3.7
0.2
6,608.3
(1,062.6)
(910.6)
(95.9)

(43.4)

(12.7)
5,545.7

4.3
4.1
3.7
2.8
2.2
1.9
1.7
1.4
1.3
1.2
1.0
0.5
0.2
494.8
207.8
141.3
70.4
47.6
8.8
8.6
3.9
4.1
1.0
0.5
0.4
0.3
+
381.7
224.2
107.8
23.6
16.3
5.0
3.3
1.3
365.2
340.2
19.1
4.4
1.4
45.5
41.6
3.7
0.2
6,821.8
(1,074.7)
(921.8)
(98.0)

(41.6)

(13.3)
5,747.1
Parentheses indicate negative values or sequestration.











0.1%
0.1%
0.1%
+
+
+
+
+
+
+
+
+
+
7.3%
3.0%
2.1%
1.0%
0.7%
0.1%
0.1%
0.1%
0.1%
+
+
+
+
+
5.6%
3.3%
1.6%
0.3%
0.2%
0.1%
+
+
5.4%
5.0%
0.3%
0.1%
+
0.7%
0.6%
0.1%
+
100.0%
-15.8%
-13.5%
-1.4%

-0.6%

-0.2%
84.2%
Totals


Trends in Greenhouse Gas Emissions
2-17

-------
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
a Percent of total emissions for year 2010.
b Includes the effects of net additions to stocks of carbon stored in harvested wood products.
  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 2010. Emissions increased by 24 percent since 1990, as electricity demand grew and fossil fuels
  remained the dominant energy source for generation. Electricity generation-related emissions increased from 2009
  to 2010 by 5.3 percent, primarily due to increased CO2 emissions from fossil fuel combustion. The increase in
  electricity-related emissions was due to increased economic output and the resulting increase in electricity demand.
  Electricity-related emissions also increased due to an increase in the carbon intensity of fuels used to generate
  electricity. This was caused by fuel switching as the price of coal increased only slightly while the price of natural
  gas increased significantly. The fuel switching from coal to natural gas and the decrease in electricity generation
  from other energy sources in 2010, which included a 6 percent decline in hydropower generation from the previous
  year, resulted in an increase in carbon intensity,  and in turn, an increase in emissions from electricity generation.
  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.

  Table 2-13:  Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Fuel Type or Source
C02
Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Incineration of Waste
Limestone and Dolomite Use
CH,
Stationary Combustion*
Incineration of Waste
N2O
Stationary Combustion*
Incineration of Waste
SF6
Electrical Transmission and
Distribution
Total
1990
1,831.4
1,820.8
1,547.6
175.3
97.5
0.4
8.0
2.6
0.3
0.3
+ 1
7.8
7.4
0.5
26.7

26.7
1,866.2
2005
2,418.0
2,402.1
1,983.8
318.8
99.2
0.4
12.5
3.4
0.5
0.5
+
16.4
16.0
0.4
13.9

13.9
2,448.8
2006
2,363.0
2,346.4
1,953.7
338.0
54.4
0.4
12.5
4.0
0.5
0.5
+
16.6
16.2
0.4
13.0

13.0
2,393.0
2007
2,429.4
2,412.8
1,987.3
371.3
53.9
0.4
12.7
3.9
0.5
0.5
+
17.1
16.7
0.4
12.2

12.2
2,459.1
2008
2,375.9
2,360.9
1,959.4
361.9
39.2
0.4
11.9
3.1
0.5
0.5
+
17.2
16.8
0.4
12.2

12.2
2,405.8
2009
2,161.9
2,146.4
1,740.9
372.2
33.0
0.4
11.7
3.8
0.4
0.4
+
17.2
16.8
0.4
11.8

11.8
2,191.4
2010
2,275.4
2,258.4
1,827.3
399.4
31.3
0.4
12.1
5.0
0.5
0.5
+
18.8
18.5
0.4
11.8

11.8
2,306.5
    Note:  Totals may not sum due to independent rounding.
    * Includes only stationary combustion emissions related to the generation of electricity.
    + Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.


  To distribute electricity emissions among economic end-use sectors, emissions from the source categories assigned
  to the electricity generation sector were allocated to the residential, commercial, industry, transportation, and
  agriculture economic sectors according to each economic sector's share of retail sales of electricity consumption
  (EIA 2011 and Duffield 2006). These source categories include CO2 from Fossil Fuel Combustion, CH4 and N2O
  from Stationary Combustion, Incineration of Waste, Limestone and Dolomite Use, and SF6 from Electrical
  Transmission and Distribution Systems. Note that only 33 percent of the Limestone and Dolomite Use emissions
  2-18   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
were associated with electricity generation and distributed as described; the remainder of Limestone and Dolomite
Use emissions were attributed to the industrial processes economic end-use sector.50

When emissions from electricity are distributed among these sectors, industry activities account for the largest share
of total U.S. greenhouse gas emissions (29.6 percent), followed closely by emissions from transportation (27.0
percent). Emissions from the residential and commercial sectors also increase substantially when emissions from
electricity are included. In all sectors except agriculture, CO2 accounts for more than 80 percent of greenhouse gas
emissions, primarily from the combustion of fossil fuels.

Table 2-14 presents a detailed breakdown of emissions from each of these economic sectors, with emissions from
electricity generation distributed to them.  Figure 2-13 shows the trend in these emissions by sector from 1990 to
2010.
Figure 2-13: Emissions with Electricity Distributed to Economic Sectors
Table 2-14:  U.S. Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg CO2 Eq.) and Percent of Total in 2010
Sector/Gas
Industry
Direct Emissions
CO2
CH4
N20
1990
2,237.7
1,564.8
1,141.3
318.5
41.8
HFCs, PFCs, and SF6 63.2
Electricity -Related
CO2
CH4
N20
SF6
Transportation
Direct Emissions
C02
CH4
N2O
HFCsb
Electricity -Related
C02
CH4
N2O
SF6
Commercial
Direct Emissions
C02
CH4
N2O
HFCs
Electricity -Related
C02
672. 9 •
660.31
Oil
2.8
9.6
1,548.3
1,545.2
1,497.8
4.5 B
42.95B
+B





	
388.oB
219.oB
164. sB
4.2B
+
541.1
2005
2,159.9
1,438.1
1,087.6
285.5
32.5
32.5
721.8
712.7
0.1
4.8
4.1
2,022.3
2,017.5
1,906.8
2.2
35.53
72.9
4.8
4.8
+
+
+
1,193.6
374.3
223.5
131.7
6.8
12.3
2006
2,198.5
1,499.8
1,121.1
314.0
33.7
31.0
698.7
689.9
0.1
4.9
3.8
1,999.1
1,994.5
1,888.0
2.1
32.18
72.2
4.6
4.6
+
+
+
1,174.8
359.9
208.6
130.8
6.8
13.6
819.3 814.9
809.0 804.7
2007
2,185.9
1,489.6
1,113.5
301.6
38.4
36.0
696.3
687.9
0.1
4.8
3.4
2,007.6
2,002.4
1,904.1
1.9
27.49
68.8
5.2
5.1
+
+
+
1,216.9
372.2
218.9
130.9
7.0
15.4
844.7
834.5
2008
2,131.5 1
1,448.5 1
1,071.3
318.0
27.4
31.9
683.0
674.5
0.1
4.9
3.5
1,894.6 1
1,889.8 1
2009
,905.8
,317.2
938.2
329.4
25.4
24.2
588.6
580.6
0.1
4.6
3.2
,823.9
,819.3
1,799.4 1,736.5
1.8
23.73
64.9
4.8
4.7
+
+
+
1,213.3 1
381.8
225.1
132.4
7.1
17.2
831.6
821.2
50 Emissions were not distributed to U.S. territories, since the electricity generation
generation of electricity in the 50 states and the District of Columbia.
1.6
20.99
60.2
4.6
4.5
+
+
+
,151.3
382.0
224.6
130.3
7.1
20.1
2010
2.019.0
1,394.2
1,009.5
327.1
27.9
29.7
624.9
616.4
0.1
5.1
3.2
1,838.6
1,834.0
1,755.0
1.6
19.02
58.4
4.6
4.5
+
+
+
1,171.0
381.7
224.2
126.7
7.1
23.6
Percent3
29.6%
20.4%
14.8%
4.8%
0.4%
0.4%
9.2%
9.0%
+
0.1%
+
27.0%
26.9%
25.7%
+
0.3%
0.9%
0.1%
0.1%
+
+
+
17.2%
5.6%
3.3%
1.9%
0.1%
0.3%
769.2 789.3 11.6%
758.9 778.7 11.4%
sector only includes emissions related to the
                                                              Trends in Greenhouse Gas Emissions
2-19

-------
CH4
N20
SF6
Residential
Direct Emissions
CO2
CH4
N20
HFCs
Electricity -Related
CO2
CH4
N20
SF6
Agriculture
Direct Emissions
C02
CH4
N2O
Electricity -Related
CO2
CH4
N20
SF6
U.S. Territories
Total
0.!
2.3
7.9
953.2
345.4B
338.31
4.6l
2.1
0.3
607.8 1
596. 5 1
0,
2.6
8.7
462.91
431.91
39.21
175.5 1
217.21
31. ()l
30.4
+
0.1
0.4 1
33.7
6,175.2
0.2
5.5
4.7
1,244.6
371.3
357.9
3.6
2.4
7.3
873.4
862.4
0.2
5.8
5.0
525.5
496.0
55.7
202.2
238.1
29.5
29.1
+
0.2
0.2
58.2
7,204.2
0.2
5.7
4.4
1,183.4
336.1
321.5
3.3
2.4
8.9
847.4
836.7
0.2
5.9
4.6
544.2
516.7
57.8
214.0
245.0
27.5
27.1
+
0.2
0.1
59.3
7,159.3
0.2
5.9
4.2
1,238.5
358.4
341.6
3.6
2.5
10.7
880.1
869.4
0.2
6.1
4.4
550.5
517.6
57.7
217.6
242.3
32.9
32.5
+
0.2
0.2
53.5
7,252.8
0.2
5.9
4.2
1,227.3
368.4
349.3
3.7
2.4
12.9
858.9
848.3
0.2
6.1
4.3
533.3
505.8
55.1
211.5
239.2
27.5
27.2
+
0.2
0.1
48.4
7,048.3
0.2
6.0
4.2
1,162.9
360.0
339.0
3.6
2.3
15.1
803.0
792.2
0.2
6.3
4.3
518.9
492.8
55.0
206.8
231.0
26.0
25.7
+
0.2
0.1
45.5
6,608.3
0.2
6.4
4.0
1,226.6
365.2
340.2
3.5
2.3
19.1
861.4
849.8
0.2
7.0
4.4
521.1
494.8
56.7
207.2
230.9
26.3
25.9
+
0.2
0.1
45.5
6,821.8
+
0.1%
0.1%
18.0%
5.4%
5.0%
0.1%
+
0.3%
12.6%
12.5%
+
0.1%
0.1%
7.6%
7.3%
0.8%
3.0%
3.4%
0.4%
0.4%
+
+
+
0.7%
100%
  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.
  + Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
  a Percent of total emissions for year 2010.
  b Includes primarily HFC-134a.
Industry

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 by-product of the non-energy-related
industrial process activities. The variety of activities producing these non-energy-related emissions includes
methane emissions from petroleum and natural gas systems, fugitive CH4 emissions from coal mining, by-product
CO2 emissions from cement manufacture, and HFC, PFC, and SF6 by-product emissions from semiconductor
manufacture, to name a few. Since 1990, industrial sector emissions have declined. The decline has occurred both
in direct emissions and indirect emissions associated with electricity use.  However, the decline in direct emissions
has been sharper. 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 effect on industrial emissions.

Transportation

When electricity-related emissions are distributed to economic end-use sectors, transportation activities accounted
for 27 percent of U.S. greenhouse gas emissions in 2010. The largest sources of transportation greenhouse gases in
2010 were passenger cars (43 percent),  light duty trucks, which include sport utility vehicles, pickup trucks, and
minivans (19 percent), freight trucks (22 percent) and commercial aircraft (6 percent).  These figures include direct
2-20   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
emissions from fossil fuel combustion, as well as HFC emissions from mobile air conditioners and refrigerated
transport allocated to these vehicle types. 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. Over the 1990s through early this decade, growth in vehicle travel substantially  outweighed
improvements in vehicle fuel economy; however, the rate of Vehicle Miles Traveled (VMT) growth slowed
considerably starting in 2005 (and  declined rapidly in 2008) while average vehicle fuel economy
increased. However, in 2010, fuel VMT grew by 0.3 percent, while average fuel economy decreased
slightly.  Among new vehicles sold annually, average fuel economy gradually  declined from 1990 to 2004,
reflecting substantial growth in sales of light-duty trucks—in particular, growth in the market share of sport utility
vehicles—relative to passenger cars. Gasoline fuel consumption increased slightly, while consumption of diesel fuel
continued to decrease, due in part to a decrease in commercial activity and freight trucking as a result of the
economic recession.

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 2010, transportation emissions rose by 19 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 34 percent from 1990 to 2010, as a result of a
confluence of factors including population growth, economic growth, urban sprawl, and low fuel prices over much
of this period.

From 2008 to 2009, CO2 emissions from the transportation end-use sector declined 4 percent. The decrease in
emissions can largely be attributed to decreased economic activity in 2009 and an associated decline in the demand
for transportation. Modes such as medium- and heavy-duty trucks were significantly impacted by the decline in
freight transport. Similarly, increased jet fuel prices were a factor in the  17 percent decrease in commercial aircraft
emissions since 2007. From 2009 to 2010, CO2 emissions from the transportation end-use  sector increased by 1
percent as economic activity rebounded  slightly in 2010.

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 17 percent from 1990 to
2010. This rise in CO2 emissions,  combined with an increase in HFCs from close to zero emissions in 1990 to 58.4
Tg CO2 Eq. in 2010, led to an increase in overall emissions from transportation activities of 19 percent.

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. Over the 1990s through early this decade,
growth in vehicle travel substantially outweighed improvements in vehicle fuel economy; however, the rate of
Vehicle Miles Traveled (VMT) growth slowed considerably starting in 2005 (and declined rapidly in 2008) while
average vehicle fuel economy increased.  However, in 2010, fuel VMT grew by 0.3 percent, while average fuel
economy decreased slightly.  Among new vehicles sold annually, average fuel economy gradually declined from
1990 to 2004, reflecting substantial growth in sales of light-duty trucks—in particular, growth in the market share of
sport utility vehicles—relative to passenger cars. Gasoline fuel consumption increased slightly, while consumption
of diesel fuel continued to decrease, due in part to a decrease in commercial activity and freight trucking as a result
of the economic recession.
                                                              Trends in Greenhouse Gas Emissions     2-21

-------
Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Vehicle
Passenger Cars
C02
CH4
N2O
HFCs
Light-Duty Trucks
C02
CH4
N2O
HFCs
Medium- and Heavy-Duty
Trucks
CO2
CH4
N20
HFCs
Buses
C02
CH4
N2O
HFCs
Motorcycles
C02
CH4
N2O
Commercial Aircraft3
C02
CH4
N2O
Other Aircraft1"
C02
CH4
N20
Ships and Boats0
CO2
CH4
N20
HFCs
Rail
C02
CH4
N2O
HFCs
Other Emissions from
Electricity Generation"1
Pipelines"
C02
Lubricants
C02
Total Transportation
International Bunker Fueld
Note: Totals may not sum due to
typically used for personal travel
1990 2005
657.4 709.6
629.3
2.6
25.4
+
336.6
321.1
1.4
14.1
+

662.3
1.1
17.8
28.4
551.3
505.9
0.7
13.7
31.0

231.1B 408.5
230.1 1 396.0
O.ll 0.2
0.8 1.2
+ 11.1
8.4
8.4
+
+
+
1.8
1.7
+
+
136.8
135.4
0.1
12.0
11.8
+
+
0.2
1.7
1.6
+
+
162.8
161.2
0.1
1.3 1.5
44.4 35.8
43.9
0.1
0.4
45.1
44.5
+
0.6
+
39.0
38.5
0.1
0.3
+

0.1
36.0
35.5
0.1
0.3
45.2
44.5
+
0.6
+
53.0
50.3
0.1
0.4
2.2

0.1
32.2
36.0 32.2
11.8 10.2
11.8 10.2
1,548.3 2,022.3
113.0 110.9
2006
682.9
639.1
1.0
15.7
27.1
564.0
519.5
0.7
12.6
31.2

418.7
406.0
0.2
1.1
11.4
12.3
12.0
+
+
0.3
1.9
1.9
+
+
138.5
137.1
0.1
1.3
35.0
34.7
0.1
0.3
48.4
47.7
+
0.7
+
55.1
52.4
0.1
0.4
2.2

0.1
32.3
32.3
9.9
9.9
1,999.1
129.8
2007
847.4
804.4
1.1
17.3
24.6
366.4
330.1
0.3
5.9
30.1

444.7
431.6
0.2
1.5
11.5
18.0
17.6
+
+
0.3
4.3
4.3
+
+
139.5
138.1
0.1
1.3
33.1
32.8
0.1
0.3
55.2
54.4
+
0.8
+
54.4
51.6
0.1
0.4
2.2

0.1
34.2
34.2
10.2
10.2
2,007.6
129.0
2008
807.0
769.3
1.0
14.7
22.1
347.0
312.8
0.3
5.2
28.6

427.1
413.9
0.2
1.4
11.6
17.5
17.1
+
+
0.4
4.5
4.4
+
+
123.4
122.2
0.1
1.2
35.2
34.8
0.1
0.3
37.1
36.6
+
0.5
+
50.7
47.9
0.1
0.4
2.3

0.1
35.6
35.6
9.5
9.5
1,894.6
135.1
2009
798.7
766.0
0.9
12.4
19.3
349.5
317.4
0.3
5.2
26.6

389.3
376.3
0.2
1.2
11.6
16.6
16.2
+
+
0.4
4.3
4.2
+
+
112.5
111.4
0.1
1.1
30.4
30.1
+
0.3
34.0
33.5
+
0.5
+
43.4
40.7
0.1
0.3
2.3

0.1
36.6
36.6
8.5
8.5
1,823.9 1
123.6
2010
787.9
757.5
0.9
10.9
18.6
346.4
316.0
0.3
4.7
25.4

402.3
389.3
0.2
1.1
11.6
16.5
16.0
+
+
0.4
3.8
3.7
+
+
115.2
114.0
0.1
1.1
28.7
28.4
+
0.3
43.3
42.6
+
0.6
+
46.3
43.5
0.1
0.3
2.3

0.1
38.8
38.8
9.5
9.5
8386
129.2
independent rounding. Passenger cars and light-duty trucks include vehicles
and less than 8500 Ibs; medium- and heavy-duty trucks include vehicles
2-22   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
  larger than 8500 Ibs. HFC emissions primarily reflect HFC-134a.
  + Does not exceed 0.05 Tg CO2 Eq.
  a 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.
  0 Fluctuations in emission estimates are associated with fluctuations in reported fuel consumption, and may
  reflect data collection problems.
  d 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 CO2 estimates reflect natural gas used to power pipelines, but not electricity. While the operation of pipelines
  produces CH4 and N2O, these emissions are not directly attributed to pipelines in the US Inventory.
  f Emissions from International Bunker Fuels include emissions from both civilian and military activities; these
  emissions are not included in the transportation totals.
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 and wastewater treatment emissions increasing 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 agriculture sector includes a variety of processes, including enteric fermentation in domestic livestock, livestock
manure management, and agricultural soil management. In 2010, agricultural soil management was the largest
source of N2O emissions, and enteric fermentation was the second largest source of CH4 emissions in the United
States.  This sector also includes small amounts of CO2 emissions from fossil fuel combustion by motorized farm
equipment like tractors.  The agriculture sector relies less heavily on electricity than the other sectors.


 [BEGIN BOX]


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, the
Inventory expands upon the standard IPCC sectors  common for UNFCCC reporting. Discussing greenhouse gas
emissions relevant to U.S.-specific sectors improves communication of the report's findings.
                                                                Trends in Greenhouse Gas Emissions     2-23

-------
In the Electricity Generation economic sector, CO2 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 N2O are also based on the EIA electric utility sector. Additional sources include CO2, CH4 and N2O
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 CO2 from Limestone and Dolomite Use (from pollution control equipment installed in
electricity generation plants).

In the Transportation economic sector, the CO2 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
the CH4 and N2O from Mobile Combustion, based on the EIA transportation sector. Substitutes of Ozone Depleting
Substitutes  are apportioned based on their specific end-uses within the source category, with emissions from
transportation refrigeration/air-conditioning systems to this economic sector. Finally, CO2 emissions from Non-
Energy Uses of Fossil Fuels identified as lubricants for transportation vehicles are included in the Transportation
economic sector.

For the Industry economic sector, the CO2 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 N2O are also based on the EIA industrial
sector, minus emissions  apportioned to the Agriculture economic sector described below. Substitutes of Ozone
Depleting Substitutes are apportioned based on their specific end-uses within the source category, with most
emissions falling within the Industry economic sector (minus emissions from the other economic sectors).
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 from the actual process to make the material, not from fuels to power the plant) 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 CO2 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 CO2 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.

As agriculture equipment is included in EIA's industrial fuel consuming sector surveys, additional data is used to
extract 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 CO2 emissions from fossil fuel combustion, and CH4 and N2O emissions
from stationary and mobile combustion (all data is removed  from the Industrial economic sector, to avoid double-
counting).  The other emission sources included in this economic sector are intuitive for the agriculture sectors, such
as N2O emissions from Agricultural Soils, CH4 from Enteric Fermentation (i.e., exhalation from the digestive tracts
of domesticated animals), CH4 and N2O from Manure Management, CH4 from Rice Cultivation, CO2 emissions
from Liming of Agricultural Soils and Urea Application, and CH4 and N2O from Forest Fires.  N2O emissions  from
the Application of Fertilizers to tree plantations (termed "forest land" by the IPCC) are also included in the
Agriculture economic sector.

The Residential economic sector includes the CO2 emissions from the combustion of fossil fuels reported for the
EIA residential sector. Stationary combustion emissions of CH4 and N2O are also based on the EIA residential fuel
consuming sector.  Substitutes of Ozone Depleting Substitutes are apportioned based on their specific end-uses
within the source category, with emissions from residential air-conditioning systems to this economic sector. N2O
emissions from the Application of Fertilizers to developed land (termed "settlements" by the IPCC) are also
included in the Residential economic sector.

The Commercial economic sector includes the CO2 emissions from the combustion of fossil fuels reported in the
EIA commercial fuel consuming sector data. Stationary combustion emissions of CH4 and N2O are also based  on the
EIA commercial sector.  Substitutes of Ozone Depleting Substitutes are apportioned based on their specific end-uses
within the source category, with emissions from commercial refrigeration/air-conditioning systems to this economic
2-24   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
sector. Public works sources including direct CH4 from Landfills and CH4 and N2O from Wastewater Treatment and
Composting are included in this economic sector.
[END BOX]
[BEGIN BOX]
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 2010; (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 0.5  percent
since 1990. This rate is slightly slower than that for total energy consumption and growth in national population
since 1990 and much slower than that for electricity consumption and overall gross domestic product, respectively.
Total U.S. greenhouse gas emissions are growing at a rate similar to that of fossil fuel consumption since 1990 (see
Table 2-16).

Table 2-16: Recent Trends in Various U.S. Data (Index 1990 =  100)
Variable
GDP"
Electricity Consumption0
Fossil Fuel Consumption0
Energy Consumption0
Population"1
Greenhouse Gas Emissions6
1990
100
100 1
100 1
100 1
100 1
100
2005
157
134
119
119
118
117
2006
161
135
117
118
120
116
2007
165
137
119
121
121
117
2008
164
136
116
119
122
114
2009
158
131
109
113
123
107
2010
163
137
113
117
123
111
Growth
2.5%
1.6%
0.6%
0.8%
1.1%
0.5%
   ' Average annual growth rate
   b Gross Domestic Product in chained 2005 dollars (BEA 2011)
   0 Energy-content-weighted values (EIA 2011)
   d U.S. Census Bureau (2011)
   e GWP-weighted values
Figure 2-14: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
Source: BEA (2011), U.S. Census Bureau (2011), and emission estimates in this report.
[END BOX]

2.3.    Indirect Greenhouse Gas Emissions (CO, NOx, NMVOCs, and SO2)

The reporting requirements of the UNFCCC51 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
51 See .
                                                            Trends in Greenhouse Gas Emissions
2-25

-------
affect terrestrial radiation absorption by influencing the formation and destruction of tropospheric and stratospheric
ozone, or, in the case of SO2, by affecting the absorptive characteristics of the atmosphere. Additionally, some of
these gases may react with other chemical compounds in the atmosphere to form compounds that are greenhouse
gases. Carbon monoxide is produced when carbon-containing fuels are combusted incompletely. Nitrogen oxides
(i.e., NO and NO2) are created by lightning, fires, fossil fuel combustion, and in the stratosphere from N2O. Non-
CH4 volatile organic compounds—which include hundreds of organic compounds that participate in atmospheric
chemical reactions (i.e., propane, butane, xylene, toluene, ethane, and many others)—are emitted primarily from
transportation, industrial processes, and non-industrial consumption of organic solvents. In the United States, SO2 is
primarily emitted from coal combustion for electric power generation and the metals industry.  Sulfur-containing
compounds emitted into the atmosphere tend to exert a negative radiative forcing (i.e., cooling) and therefore are
discussed separately.
One important indirect climate change effect of NMVOCs and NOX is their role as precursors for tropospheric ozone
formation.  They can also alter the atmospheric lifetimes of other greenhouse gases. Another example of indirect
greenhouse gas formation into greenhouse gases is CO's interaction with the hydroxyl radical—the major
atmospheric sink for CH4 emissions—to form CO2. Therefore, increased atmospheric concentrations of CO limit
the number of hydroxyl molecules (OH) available to destroy CH4.

Since 1970, the United States has published estimates of annual emissions of CO, NOX, NMVOCs, and SO2 (EPA
2010, EPA 2009),52 which are regulated under the Clean Air Act. Table 2-17 shows that fuel combustion accounts
for the majority of emissions of these indirect greenhouse gases. Industrial processes—such as the manufacture of
chemical and allied products, metals processing, and industrial uses of solvents—are also significant sources of CO,
NOX, and NMVOCs.

Table 2-17:  Emissions of NOX, CO, NMVOCs, and SO2 (Gg)
Gas/Activity
NOX
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Oil and Gas Activities
Incineration of Waste
Agricultural Burning
Solvent Use
Waste
CO
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Incineration of Waste
Agricultural Burning
Oil and Gas Activities
Waste
Solvent Use
NMVOCs
Mobile Fossil Fuel Combustion
Solvent Use
Industrial Processes
Stationary Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Agricultural Burning
1990
21,707
10,862
1 0,023 B
59ll
139
82
|
I
130,038
119,360
5,000
4,125 •
978
268
302
1
5
20,930
10,932|
5,2ieB
2,422!
912
554
222
673
NA
2005
15,900
9,012
5,858
569
321
129
6
3
2
70,809
62,692
4,649
1,555
1,403
184
318
7
2
13,761
6,330
3,851
1,997
716
510
241
114
NA
2006
15,039
8,488
5,545
553
319
121
7
4
2
67,238
58,972
4,695
1,597
1,412
233
319
7
2
13,594
6,037
3,846
1,933
918
510
238
113
NA
2007
14,380
7,965
5,432
537
318
114
8
4
2
63,625
55,253
4,744
1,640
1,421
237
320
7
2
13,423
5,742
3,839
1,869
1,120
509
234
111
NA
2008
13,547
7,441
5,148
520
318
106
8
4
2
60,039
51,533
4,792
1,682
1,430
270
322
7
2
13,254
5,447
3,834
1,804
1,321
509
230
109
NA
2009
11,468
6,206
4,159
568
393
128
8
3
2
51,452
43,355
4,543
1,549
1,403
247
345
7
2
9,313
4,151
2,583
1,322
424
599
159
76
NA
2010
11,468
6,206
4,159
568
393
128
8
3
2
51,452
43,355
4,543
1,549
1,403
247
345
7
2
9,313
4,151
2,583
1,322
424
599
159
76
NA
52 NOX and CO emission estimates from field burning of agricultural residues were estimated separately, and therefore not taken
from EPA (2009) and EPA (2010).
2-26   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
  S02                              20,935       13,466     12,388    11,799     10,368      8,599     8,599
  Stationary Fossil Fuel Combustion    18,407       11,541     10,612    10,172      8,891      7,167     7,167
  Industrial Processes                   1,307         831        818       807       795        798       798
  Mobile Fossil Fuel Combustion          7931       889        750       611       472        455       455
  Oil and Gas Activities                  39oB       181        182       184       187        154       154
  Incineration of Waste                   381        24         24        24        23         24        24
  Waste                                 +•          1          1         1         1          1         1
  Solvent Use                            +1         +          +         +         +          +         +
  Agricultural Burning	NA	NA	NA	NA	NA	NA	NA
  Source: (EPA 2010, EPA 2009) except for estimates from field burning of agricultural residues.
  NA (Not Available)
  Note:  Totals may not sum due to independent rounding.
[BEGIN BOX]


Box 2-3: Sources and Effects of Sulfur Dioxide
Sulfur dioxide (SO2) 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 SO2 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 SO2 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 SO2 emissions in the Clean Air Act.

Electricity generation is the largest anthropogenic source of SO2 emissions in the United  States, accounting for 60
percent in 2010. 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.


[END BOX]
                                                                Trends in Greenhouse Gas Emissions     2-27

-------

-------
                • MFCs, PFCs, & SF6





                  Methane
                                  • Carbon Dioxide
                       em
                       6,237
                                     ecxx
                            6360 6,457  6,544

                                     —
6,757  6,803 6,846  6,909
    8,000 -i



    7,000 -



    6,000 -



S  5,000 -



8   4,000 -



    3,000 -



    2,000 -



    1,000 -



        0 -
Figure 2-1: U.S. Greenhouse Gas Emissions by Gas
                                                            7,104
                                                                              7,163 7,204  7,159 753
                                                                                                          6,822
                                                                                                  3.2%
                                                                                             -6.2%




       1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010



Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
                                                                                988 1'029  984
                                                                                               1,078
                                                                                                               647
 8
Figure 2-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990

-------
  8
 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) -1
                       Industrial Processes
                                                Waste
                                                                  LULUCF (sources)
                 Agriculture
                Energy
                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 sector

Figure 2-4:  U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
                                   Fossil Fuel Combustion

                                     Natural Gas Systems

                                 Non-Energy Use of Fuels

                                            Coal Mining

                                      Petroleum Systems  |

                                   Stationary Combustion  I

                                      Mobile Combustion  I

                                    Incineration of Waste  |

                       Abandoned Underground Coal Mines  |

                                                       0
Figure 2-5:  2010 Energy Sector Greenhouse Gas Sources
                                                                             Energy as a Portion
                                                                               of all Emissions
                                                                                                   5,388
                                                               50
                                                                       100      150
                                                                          Tg C02 Eq.
                                                                                       200
                                                                                               250
                                                                                                       300

-------
                                                                                                                          NEU Emissions 5
                                           Fossi! Fuei
                                           Energy Exports
                                           527
                                                                                                                                     Natural Gas Emissions
                                                                                                                                     1,266
                                                                                                                                    NEU Emissions 60
                                                                                                   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
2-6 2010 U.S.                                   (Tg C02 Eq.)

-------
2,500  -i
2,000  -
1,500  -
1,000  -
  500  -
    0  -
Relative Contribution
   by Fuel Type
                         42
                         |
                                         224
                                                        Petroleum
                                                       • Coal
                                                       • Natural Gas

                                                        340
                                                   778
                                                                  1,745
                                                                                                        2,258
                                                                                                       Eg
Figure 2-7:  2010 C02 Emissions from  Fossil Fuel Combustion by Sector and Fuel Type
Note:  Electricity generation also includes emissions of less than 0.5 Tg C02 Eq. from geothermal-based electricity generation.
             2,000 -,

             1,500 -
         8  1,000 -
               500 -
                 0 J
    From Direct Fossil Fuel Combustion
   • From Electricity Consumption

                    1,005
                           42
                           |
                                                              1,425
                                                          1,195
                                                                     1,773
Figure 2-8:  2010 End-Use Sector Emissions from Fossil Fuel Combustion

-------
                     Substitution of Ozone Depleting Substances
                  Iron and Steel Prod. & Metallurgical Coke Prod.
                                           Cement Production
                                         Nitric Acid Production
                                             Lime Production
                         Electrical Transmission and Distribution
                                  Limestone and Dolomite Use
                                         Ammonia Production
                                          HCFC-22 Production
                                   Semiconductor Manufacture
                                         Aluminum Production
                 Urea Consumption for Non-Agricultural Purposes
                                     Petrochemical Production
                         Soda Ash Production and Consumption
                                        Adipic Acid Production
                                  Carbon Dioxide Consumption
                                  Titanium Dioxide Production
                                         Ferroalloy Production
                          Magnesium Production and Processing
                                              Zinc Production
                                   Phosphoric Acid Production
                                             Lead Production
                     Silicon Carbide Production and Consumption
                                                                                                                            115
                     Industrial Processes as a Portion
                             of all Emissions
                                    4.4%
< 0.5
                                                                      10
                                                                                 20
                                                                                           30
                                                                                       TgC02Eq.
                                                                                                     40
                                                                                                               50
                                                                                                                          60
Figure 2-9:  2010 Industrial Processes Chapter Greenhouse Gas Sources
               Agricultural Soil Management
                      Enteric Fermentation
                      Manure Management
                           Rice Cultivation
        Field Burning of Agricultural Residues   < 0.5
                                                                                                         208
            Agriculture as a Portion of all Emissions
                           6.3%
                      G
                                          0                  50                  100
                                                                   TgC02Eq.
Figure 2-10:  2010 Agriculture Chapter Greenhouse Gas Sources
                                                                                                     150

-------
                                Landfills
                   Wastewater Treatment
                             Composting
I
                                                            Waste as a Portion of all Emissions
                                                                         1.9%
                                                     25
Figure 2-11: 2010 Waste Chapter Greenhouse Gas Sources
                                                                  50           75
                                                                     TgC02Eq.
                                                                                            100
                                                                                                          125
     2,500 -|


     2,000 -


  6-  1,500 -
  LU   '

  8
  H  1,000 -


       500 -
                                                   Electric
                                                   Power Industry

                                                   Transportation


                                                   Industry
                                                   Agriculture
                                                  I Commercial
                                                   Residential
           CTiCTiCTiCTiCrtCTiCTiCTiCTiCTiOOOOOOOOOOi—i
           cncncncncncncncncncnooooooooooo
Figure 2-12: Emissions Allocated to Economic Sectors
Note: Does not include U.S. Territories.

-------
    2,500 -,


    2,000 -


d-  1,500 -
LU

8
D>  1,000 -


      500 -
                                         Industry
                                         Transportation


                                         Residential (black)
                                         Commercial (gray)
                                       • Agriculture
          8
a
                                      _
8   S
8   5  §  8
Figure 2-13:  Emissions with Electricity Distributed to Economic Sectors
                                                                                                           Real GDP
                                                                                                           Population
                                                                                                           Emissions
                                                                                                           per capita


                                                                                                           Emissions
                                                                                                           per $GDP
                                                                    fNfNfNfNfNfNfNfN
Figure 2-14:  U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product

-------
3.
Energy
Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting for
87.0 percent of total greenhouse gas emissions on a carbon dioxide (CO2) equivalent basis53 in 2010.  This included
97, 50, and 14 percent of the nation's CO2, methane (CH4), and nitrous oxide (N2O) emissions, respectively.
Energy-related CO2 emissions alone constituted 81 percent of national emissions from all sources on a CO2
equivalent basis, while the non-CO2 emissions from energy-related activities represented a much smaller portion of
total national emissions (5.5 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 30,313 Tg of CO2 were added to the atmosphere
through the combustion of fossil fuels in 2009, of which the United States accounted for about 18 percent.54 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. Stationary
combustion of fossil fuels was the second largest source of N2O emissions in the United States and  mobile fossil fuel
combustion was the third largest source.
Figure 3-1: 2010 Energy Chapter Greenhouse Gas Sources
Figure 3-2: 2010 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
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.

Table 3-1 summarizes emissions from the Energy sector in units of teragrams (or million metric tons) 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 5,933.5 Tg CO2 Eq. in 2010, an increase of 12 percent since 1990.

Table 3-1: CO2, CH4, and N2O Emissions from Energy (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass - Wood
International Bunker Fuels
Biomass - Ethanol
CH,
Natural Gas Systems
1990
4,903.9
4,738.3
1,820.8
1,485.9
846.4
338.3
219.0
27.9 1
119.6
37.6 1
8.0 1
0.4 1
214.4
111.8
4.2
327.1
189.6
2005
5,933.3
5,746.5
2,402.1
1,896.6
816.4
357.9
223.5
50.0
144.1
29.9
12.5
0.3
205.7
109.8
22.9
291.2
190.5
2006
5,840.4
5,653.0
2,346.4
1,878.1
848.1
321.5
208.6
50.3
143.8
30.8
12.5
0.3
202.7
128.4
31.0
319.1
217.7
2007
5,936.7
5,757.8
2,412.8
1,893.9
844.4
341.6
218.9
46.1
134.9
31.0
12.7
0.3
202.2
127.6
38.9
307.0
205.3
2008
5,755.2
5,571.5
2,360.9
1,789.8
806.5
349.3
225.1
39.8
138.6
32.8
11.9
0.3
197.4
133.7
54.7
323.5
212.7
2009
5,374.1
5,206.2
2,146.4
1,727.9
726.6
339.0
224.6
41.7
123.7
32.2
11.7
0.3
181.8
122.3
62.3
335.1
220.9
2010
5,557.6
5,387.8
2,258.4
1,745.5
777.8
340.2
224.2
41.6
125.1
32.3
12.1
0.3
191.6
127.8
74.5
332.3
215.4
53 Estimates are presented in units of teragrams of carbon dioxide equivalent (Tg CO2 Eq.), which weight each gas by its global
warming potential, or GWP, value. See section on global warming potentials in the Executive Summary.
54 Global CO2 emissions from fossil fuel combustion were taken from Energy Information Administration International Energy
Statistics 2010 < http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm> EIA (2010).
                                                                                            Energy   3-1

-------
Coal Mining
Petroleum Systems
Stationary Combustion
Abandoned Underground Coal
Mines
Mobile Combustion
Incineration of Waste
International Bunker Fuels
N2O
Mobile Combustion
Stationary Combustion
Incineration of Waste
International Bunker Fuels
Total
84.1
35.2 1
7.5 1
6.0 1
4.7 1
+ 1
0.2 1
56.7 1
43.9 1
12.3 1
0.5
1.1
5,287.7
56.8
29.2
6.6
5.5
2.5
+
0.1
58.0
37.0
20.6
0.4
1.0
6,282.4
58.1
29.2
6.2
5.5
2.4
+
0.2
54.8
33.7
20.8
0.4
1.2
6,214.4
57.8
29.8
6.5
5.3
2.2
+
0.2
50.6
29.0
21.2
0.4
1.2
6,294.3
66.9
30.0
6.6
5.3
2.1
+
0.2
46.7
25.2
21.1
0.4
1.2
6,125.4
70.1
30.7
6.3
5.1
2.0
+
0.1
43.6
22.5
20.7
0.4
1.1
5,752.7
72.6
31.0
6.3
5.0
1.9
+
0.2
43.6
20.6
22.6
0.4
1.2
5,933.5
   + Does not exceed 0.05 Tg CO2 Eq.
   * These values are presented for informational purposes only, in line with IPCC methodological guidance and UNFCCC
   reporting obligations, and are not included in the specific energy sector contribution to the totals, and are already accounted
   for elsewhere.
   Note:  Totals may not sum due to independent rounding.


Table 3-2:  CO2, CH4, and N2O Emissions from Energy (Gg)
Gas/Source
C02
Fossil Fuel Combustion
Non-Energy Use of Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass -Wood
International Bunker
Fuels*
Biomass - Ethanol
CH,
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Abandoned Underground
Coal Mines
Mobile Combustion
Incineration of Waste
International Bunker
Fuels'"
N2O
Mobile Combustion
Stationary Combustion
Incineration of Waste
International Bunker
Fuels
1990
4,903,922
4,738,338 1
119,627 1
37,574
7,989
394
214,410 1

111,828 \
4,227
15,575
9,029
4,003
1,677
355

288 1
223 1
+ 1

8 1
183 1
142 1
40 1
2

3
2005
5,933,252
5,746,480
144,098
29,901
12,468
305
205, 671

109,765
22,943
13,864
9,071
2,705
1,390
315

264
121
+

7
187
119
66
1

3
2006
5,840,384
5,653,032
143,761
30,754
12,531
306
202,680

128,413
30,985
15,196
10,369
2,768
1,389
296

261
114
+

8
111
109
67
1

4
2007
5,936,724
5,757,775
134,863
31,049
12,727
310
202,204

127,643
38,924
14,619
9,774
2,754
1,420
311

254
107
+

8
163
94
68
1

4
2008
5,755,172
5,571,537
138,624
32,826
11,888
297
197,358

133,730
54,739
15,405
10,127
3,186
1,427
313

253
99
+

8
151
81
68
1

4
2009
5,374,077
5,206,168
123,712
32,169
11,703
325
181,806

122,338
62,272
15,955
10,519
3,340
1,460
298

244
93
+

7
141
73
67
1

4
2010
5,557,611
5,387,790
125,130
32,301
12,054
337
191,591

127,841
74,519
15,825
10,259
3,458
1,478
301

237
91
+

8
141
66
73
1

4
   + Does not exceed 0.05 Tg CO2 Eq.
   * These values are presented for informational purposes only, in line with IPCC methodological guidance and UNFCCC
   reporting obligations, and are not included in the specific energy sector contribution to the totals, and are already accounted for
   elsewhere.
   Note:  Totals may not sum due to independent rounding.


[BEGIN BOX]

Box 3  1: Energy Data from the Greenhouse Gas Reporting Program
3-2   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
On October 30, 2009, the U.S. Environmental Protection Agency (EPA) published a rule for the mandatory
reporting of greenhouse gases (GHG) from large GHG emissions sources in the United States. Implementation of 40
CFR Part 98 is referred to as the Greenhouse Gas Reporting Program (GHGRP). 40 CFR part 98 applies to direct
greenhouse gas emitters, fossil fuel suppliers, industrial gas suppliers, and facilities that inject CO2 underground for
sequestration or other reasons. Reporting is at the facility level, except for certain suppliers of fossil fuels and
industrial greenhouse gases. 40 CFR part 98 requires reporting by 41 industrial categories. In general, the threshold
for reporting is 25,000 metric tons or more of CO2 Eq. per year. For calendar year 20 10, the first year in which data
were reported, facilities in 29 categories provided in 40 CFR part 98 were required to report their 2010 emissions by
the September 30, 20 1 1 reporting deadline. Data reporting by affected facilities included the reporting of emissions
from fuel combustion at that affected facility.

The GHGRP dataset and the data presented in this inventory  report are complementary and, as indicated in the
respective planned improvements sections for source categories in this chapter, EPA is analyzing how to use
facility-level GHGRP data to improve the national estimates  presented in this inventory. Most methodologies used
in the GHGRP are consistent with IPCC, though for the GHGRP, facilities collect detailed information specific to
their operations according to detailed measurement standards, which may differ with the more aggregated data
collected for the inventory to estimate total, national U.S. emissions. It should be noted that the definitions and
provisions for reporting fuel types in the GHGRP may differ from those used in the inventory in meeting the
UNFCCC reporting guidelines. In line with the UNFCCC reporting guidelines, the inventory report is a
comprehensive accounting of all emissions from fuel types identified in the IPCC guidelines and provides a separate
reporting of emissions from biomass. Further information on the reporting categorizations in GHGRP and specific
data caveats associated with monitoring methods in the GHGRP has been provided on the GHGRP website.

EPA presents the data collected by the GHGRP through a data publication tool that allows data to be viewed in
several formats including maps, tables, charts and graphs for individual facilities or groups of facilities.
[END BOX]
3.1.    Fossil Fuel Combustion (IPCC Source Category 1A)

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.

Table 3-3: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion (Tg CO2 Eq.)
Gas
CO2
CH4
N2O
Total
1990
4,738.3
12.1
56.2 •
4,806.7
2005
5,746.5
9.1
57.6
5,813.3
2006
5,653.0
8.6
54.5
5,716.1
2007
5,757.8
8.8
50.2
5,816.8
2008
5,571.5
8.7
46.4
5,626.6
2009
5,206.2
8.2
43.3
5,257.7
2010
5,387.8
8.2
43.2
5,439.3
  Note: Totals may not sum due to independent rounding.
                                                                                          Energy   3-3

-------
Table 3-4: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion (Gg)
Gas
CO2
CH4
N2O
1990
4,738,338
578
181
2005
5,746,480
436
186
2006
5,653,032
410
176
2007
5,757,775
417
162
2008
5,571,537
412
150
2009
5,206,168
392
140
2010
5,387,790
392
139
  Note:  Totals may not sum due to independent rounding.
CCbfrom Fossil Fuel Combustion

CO2 is the primary gas emitted from fossil fuel combustion and represents the largest share of U.S. total greenhouse
gas emissions. CO2 emissions from fossil fuel combustion are presented in Table 3-5. In 2010, CO2 emissions from
fossil fuel combustion increased by 3.7 percent relative to the previous year which represents the largest annual
increase in CO2 emissions from fossil fuel combustion for the twenty-one-year period.55 The increase in CO2
emissions from fossil fuel combustion was a result of multiple factors including: (1) an increase in economic output
resulting in an increase in energy consumption across all sectors; (2) an increase in the carbon intensity of fuels
consumed due to only a slight increase in the price of coal, and a significant increase in the price of petroleum and
natural gas; and (3) much warmer summer conditions resulting in an increase in electricity demand. In 2010, CO2
emissions from fossil fuel combustion were  5,387.8 Tg CO2 Eq., or 14 percent above emissions in 1990 (see Table
3-5).56

Table 3-5: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.)
Fuel/Sector
Coal
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Geo thermal*
Total
1990
1,718.4
3.0
12.0
155.3
NE
1,547.6
0.6
1,001.4
238.0
142.1
409.9
36.0
175.3
NO
2,018.1
97.4
64.9
281.2
1,449.9
97.5
27.2
0.4
4,738.3
	



















	
2005
2,112.3
0.8
9.3
115.3
NE
1,983.8
3.0
1,159.6
262.2
162.9
381.4
33.1
318.8
1.3
2,474.2
94.9
51.3
319.6
1,863.5
99.2
45.7
0.4
5,746.5
2006
2,076.6
0.6
6.2
112.6
NE
1,953.7
3.4
1,151.8
237.3
153.8
388.2
33.1
338.0
1.4
2,424.2
83.6
48.5
347.3
1,845.0
54.4
45.5
0.4
5,653.0
2007
2,106.0
0.7
6.7
107.0
NE
1,987.3
4.3
1,226.3
256.3
163.5
398.6
35.2
371.3
1.4
2,425.1
84.6
48.7
338.7
1,858.7
53.9
40.4
0.4
5,757.8
2008
2,072.5
0.7
6.5
102.6
NE
1,959.4
3.3
1,237.9
265.5
171.1
401.0
36.7
361.9
1.6
2,260.8
83.1
47.4
302.9
1,753.2
39.2
35.0
0.4
5,571.5
2009
1,834.4
0.7
5.9
83.3
NE
1,740.9
3.5
1,216.6
258.8
168.9
377.3
37.9
372.2
1.5
2,154.8
79.4
49.7
265.9
1,690.0
33.0
36.7
0.4
5,206.2
2010
1,933.2
0.7
5.5
96.2
NE
1,827.3
3.5
1,261.6
258.8
167.7
394.2
40.1
399.4
1.5
2,192.6
80.7
51.1
287.4
1,705.4
31.3
36.7
0.4
5,387.8
   NE (Not estimated)
   * Although not technically a fossil fuel, geothermal energy-related CO2 emissions are included for reporting
   purposes.
   Note: Totals may not sum due to independent rounding.
Trends in CO2 emissions from fossil fuel combustion are influenced by many long-term and short-term factors. On
a year-to-year basis, the overall demand for fossil fuels in the United States and other countries generally fluctuates
55 This increase also represents the largest absolute and percentage increase since 1988 (EIA 201 la).
56 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: 1990-2010

-------
in response to changes in general economic conditions, energy prices, weather, and the availability of non-fossil
alternatives. For example, in a year with increased consumption of goods and services, low fuel prices, severe
summer and winter weather conditions, nuclear plant closures, and lower precipitation feeding hydroelectric dams,
there would likely be proportionally greater fossil fuel consumption than a year with poor economic performance,
high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants.

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

CO2 emissions also depend on the  source of energy and its carbon (C) intensity. The amount of C in fuels varies
significantly by fuel type. For example, coal contains the highest amount of C per unit of useful energy. Petroleum
has roughly 75 percent of the C per unit of energy as coal, and natural gas has only about 55 percent.57 Table 3-6
shows annual changes in emissions during the last five years for coal, petroleum, and natural gas in selected sectors.

Table 3-6:  Annual Change in CC>2 Emissions and Total 2010 Emissions from Fossil Fuel Combustion for Selected
Fuels and Sectors (Tg CO2 Eq. and Percent)
Sector Fuel Type
Electricity Generation Coal
Electricity Generation Natural Gas
Electricity Generation Petroleum
Transportation8 Petroleum
Residential Natural Gas
Commercial Natural Gas
Industrial Coal
Industrial Natural Gas
All Sectors" All Fuels"
2006 to 2007
33.6 1.7%
33.3 9.9%
-0.5 -0.9%
13.7 0.7%
19.0 8.0%
9.7 6.3%
-5.6 -5.0%
10.4 2.7%
104.7 1.9%
2007 to 2008
-27.9 -1.4%
-9.3 -2.5%
-14.7 -27.2%
-105.6 -5.7%
9.3 3.6%
7.6 4.6%
-4.4 -4.1%
2.4 0.6%
-186.2 -3.2%
2008 to 2009
-218.5 -11.2%
10.3 2.8%
-6.3 -15.9%
-63.1 -3.6%
-6.7 -2.5%
-2.2 -1.3%
-19.3 -18.8%
-23.7 -5.9%
-365.4 -6.6%
2009 to 2010
86.4 5.0%
27.2 7.3%
-1.7 -5.2%
15.4 0.9%
0.0 0.0%
-1.2 -0.7%
12.8 15.4%
16.9 4.5%
181.6 3.5%
Total 2010
1,827.3
399.4
31.3
1,705.4
258.8
167.7
96.2
394.2
5,387.8
  a Excludes emissions from International Bunker Fuels.
  b Includes fuels and sectors not shown in table.
In the United States, 85 percent of the energy consumed in 2010 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 (9 percent) and by a variety of renewable energy sources58 (6 percent), primarily
hydroelectric power and biofuels (EIA 201 la). Specifically, petroleum supplied the largest share of domestic
energy demands, accounting for 41 percent of total fossil fuel based energy consumption in 2010. Natural gas and
coal followed in order of energy demand importance, accounting for approximately 32 and 27 percent of total
consumption, respectively. Petroleum was consumed primarily in the transportation end-use sector and the vast
majority of coal was used in electricity generation. Natural gas was broadly consumed in all end-use sectors except
transportation (see Figure 3-5) (EIA 201 la).
Figure 3-3: 2010 U.S. Energy Consumption by Energy Source
Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)
Figure 3-5: 2010 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Fossil fuels are generally combusted for the purpose of producing energy for useful heat and work. During the
  Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
58 Renewable energy, as defined in EIA's energy statistics, includes the following energy sources: hydroelectric power,
geothermal energy, biofuels, solar energy, and wind energy
                                                                                             Energy    3-5

-------
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.59 These other C containing non-CO2 gases are emitted as a byproduct 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.


[BEGIN BOX]


Box 3-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends

In 2010, weather conditions remained fairly constant in the winter and much hotter in the summer compared to
2009, as heating degree days  decreased slightly (0.7 percent) and cooling degree days increased by  19 percent. This
increase in cooling degree days led to an increase in electricity demand to cool homes. Winter conditions were
relatively constant in 2010 compared to 2009, and the winter was slightly warmer than normal, with heating degree
days in the United States 1.4  percent below normal (see Figure 3-6). Summer conditions were much warmer in
2010 compared to 2009, and  summer temperatures were much warmer than normal, with cooling degree days 17
percent above normal (see Figure 3-7) (ElA 2011 a).60


Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1950-2010)


Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1950-2010)


Although no new U.S. nuclear power plants have been constructed in recent years, the utilization (i.e., capacity
factors61)  of existing plants in 2010 remained high at just over 91 percent. Electricity output by hydroelectric power
plants decreased in 2010 by approximately 6.0 percent. Electricity generated by nuclear plants in 2010 provided
more than 3 times as much of the energy consumed in the United States as hydroelectric plants (EIA 201 la).
Nuclear, hydroelectric, and wind power capacity factors since 1990 are shown in Figure 3-8.


Figure 3-8: Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2010)


[END BOX]



Fossil Fuel Combustion Emissions by  Sector

In addition to the CO2 emitted from fossil fuel combustion, CH4 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.
59 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas
emissions from fossil fuel combustion.
  Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily
temperature below 65° F, while cooling degree days are deviations of the mean daily temperature above 65° F.  Heating degree
days have a considerably greater affect on energy demand and related emissions than do cooling degree days. Excludes Alaska
and Hawaii. Normals are based on data from 1971 through 2000. The variation in these normals during this time period was +10
percent and +14 percent for heating and cooling degree days, respectively (99 percent confidence interval).
61The capacity factor equals generation divided by net summer capacity. Summer capacity is defined as "The maximum output
that generating equipment can supply to system load, as demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30)." Data for both the generation and net summer capacity are from EIA (201 la).


3-6  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Table 3-7: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by Sector (Tg CO2 Eq.)
End-Use Sector
Electricity Generation
C02
CH4
N20
Transportation
CO2
CH4
N2O
Industrial
C02
CH4
N2O
Residential
C02
CH4
N20
Commercial
C02
CH4
N20
U.S. Territories*
Total
1990
1,828.5
1,820.8


1,534.6
1,485.9
4.7
43.9
851.3
846.4
1.6
3.3 1
344.1
338.3
4.6
1.1 1
220.2
219.0
0.9
0.4
28.0
4,806.7
2005
2,418.6
2,402.1
0.5
16.0
1,936.1
1,896.6
2.5
37.0
821.0
816.4
1.5
3.1
362.5
357.9
3.6
1.0
224.8
223.5
0.9
0.4
50.2
5,813.3
2006
2,363.1
2,346.4
0.5
16.2
1,914.2
1,878.1
2.4
33.7
852.9
848.1
1.5
3.2
325.6
321.5
3.3
0.9
209.8
208.6
0.9
0.3
50.5
5,716.1
2007
2,430.0
2,412.8
0.5
16.7
1,925.1
1,893.9
2.2
29.0
849.0
844.4
1.5
3.1
346.2
341.6
3.6
0.9
220.1
218.9
0.9
0.3
46.3
5,816.8
2008
2,378.2
2,360.9
0.5
16.9
1,817.1
1,789.8
2.1
25.2
810.8
806.5
1.4
2.9
354.0
349.3
3.7
1.0
226.4
225.1
0.9
0.3
40.0
5,626.6
2009
2,163.7
2,146.4
0.4
16.9
1,752.4
1,727.9
2.0
22.5
730.4
726.6
1.2
2.5
343.5
339.0
3.6
0.9
225.9
224.6
1.0
0.3
41.8
5,257.7
2010
2,277.3
2,258.4
0.5
18.5
1,768.0
1,745.5
1.9
20.6
782.0
777.8
1.4
2.8
344.7
340.2
3.5
0.9
225.5
224.2
0.9
0.3
41.8
5,439.3
  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.
  * U.S. Territories are not apportioned by sector, and emissions are total greenhouse gas emissions from all
  fuel combustion sources.

Other than CO2, gases emitted from stationary combustion include the greenhouse gases CH4 and N2O and the
indirect greenhouse gases NOX, CO, and NMVOCs.62 Methane and N2O emissions from stationary combustion
sources depend upon fuel characteristics, size and vintage, along with combustion technology, pollution control
equipment, ambient environmental conditions, and operation and maintenance practices. N2O emissions from
stationary combustion are closely related to air-fuel mixes and combustion temperatures, as well as the
characteristics of any pollution control equipment that is employed.  Methane emissions from stationary combustion
are primarily a function of the CH4 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.  N2O 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. CO
emissions are highest when air-fuel mixtures have less oxygen than required for complete combustion.  These
emissions occur especially in idle, low speed, and cold start conditions.  Methane and NMVOC emissions from
motor vehicles are a function of the CH4 content of the motor fuel, the amount of hydrocarbons passing
uncombusted through the engine, and any post-combustion control of hydrocarbon emissions (such as catalytic
converters).

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 the table below, 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 andN2O
62 Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex 6.3.
                                                                                            Energy    3-7

-------
from transportation.63 Emissions from U.S. territories are also calculated separately due to a lack of end-use-specific
consumption data. This method assumes that emissions from combustion sources are distributed across the four end-
use sectors based on the ratio of electricity consumption in that sector. The results of this alternative method are
presented in Table 3-8.

Table 3-8: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Transportation
C02
CH4
N20
Industrial
C02
CH4
N2O
Residential
CO2
CH4
N2O
Commercial
C02
CH4
N20
U.S. Territories*
Total
1990
1,537.6
1,489.0
4.7
44.0
1,540.9
1,533.1
1.7
6.1
939.6
931.4
4.7
3.5
760.5
757.0
1.0
2.6
28.0
4,806.7















1
1

1
1

1
1
1
1



5
2005
,940.9
,901.3
2.5
37.0
,563.0
,553.3
1.7
8.1
,225.1
,214.7
3.8
6.7
,034.0
,027.2
1.1
5.7
50.2
,813.3

1
1

1
1

1
1
1
1



5
2006
,918.8
,882.6
2.4
33.7
,570.0
,560.2
1.7
8.2
,162.4
,152.4
3.4
6.6
,014.5
,007.6
1.0
5.9
50.5
,716.1
2007
1,930.2
1,899.0
2.2
29.0
1,569.5
1,559.8
1.6
8.1
1,215.8
1,205.2
3.8
6.9
1,054.9
1,047.7
1.1
6.1
46.3
5,816.8
2008
1,821.9
1,794.5
2.1
25.3
1,513.2
1,503.8
1.5
7.9
1,203.1
1,192.2
3.9
7.0
1,048.4
1,041.1
1.1
6.2
40.0
5,626.6
2009
1,756.9
1,732.4
2.0
22.5
1,337.2
1,328.6
1.4
7.2
1,136.3
1,125.5
3.8
7.1
985.4
978.0
1.1
6.3
41.8
5,257.7

1
1

1
1

1
1
1




5
2010
,772.5
,750.0
1.9
20.6
,424.9
,415.4
1.5
8.0
,195.2
,183.7
3.7
7.8
,004.9
997.1
1.1
6.7
41.8
,439.3
   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.
   * U.S. Territories are not apportioned by sector, and emissions are total greenhouse gas emissions from
   all fuel combustion sources.
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. 64 Methane and N2O emissions from
stationary combustion sources depend upon fuel characteristics, combustion technology, pollution control
equipment, ambient environmental conditions, and operation and maintenance practices. N2O emissions from
stationary combustion are closely related to air-fuel mixes and combustion temperatures, as well as the
characteristics of any pollution control equipment that is employed.  Methane emissions from stationary combustion
are primarily a function of the CH4 content of the fuel and combustion efficiency. The CH4 and N2O emission
estimation methodology was revised in 2010 to utilize the facility-specific technology and fuel use data reported to
EPA's Acid Rain Program (see Methodology section for CH4 and N2O from stationary combustion). Please refer to
Table 3-7 for the corresponding presentation of all direct emission sources of fuel combustion.

Table 3-9: CO2 Emissions from Stationary Fossil Fuel Combustion (Tg CO2 Eq.)
63 Separate calculations were performed for transportation-related CH4 and N2O. The methodology used to calculate these
emissions are discussed in the mobile combustion section.
"4 Since emissions estimates for U.S. territories cannot be disaggregated by gas in Table 3-10 and Table 3-11, the percentages
for CH4 and N2O exclude U.S. territory estimates.
3-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Sector/Fuel Type
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. Territories
Coal
Natural Gas
Fuel Oil
Total
1990 2005
1,820.8 2,402.1
1,547.6
175.3
97.5
0.4
846.4
155.3
409.9
281.2
219.0
12.0
142.1
64.9
338.3
3.0
238.0
97.4
27.9
0.6
NO
27.2
1,983.8
318.8
99.2
0.38
816.4
115.3
381.4
319.6
223.5
9.3
162.9
51.3
357.9
0.8
262.2
94.9
50.0
3.0
1.3
45.7
3,252.4 3,849.9
2006
2,346.4
1,953.7
338.0
54.4
0.37
848.1
112.6
388.2
347.3
208.6
6.2
153.8
48.5
321.5
0.6
237.3
83.6
50.3
3.4
1.4
45.5
3,774.9
2007
2,412.8
1,987.3
371.3
53.9
0.38
844.4
107.0
398.6
338.7
218.9
6.7
163.5
48.7
341.6
0.7
256.3
84.6
46.1
4.3
1.4
40.4
3,863.9
2008
2,360.9
1,959.4
361.9
39.2
0.38
806.5
102.6
401.0
302.9
225.1
6.5
171.1
47.4
349.3
0.7
265.5
83.1
39.8
3.3
1.6
35.0
3,781.7
2009
2,146.4
1,740.9
372.2
33.0
0.38
726.6
83.3
377.3
265.9
224.6
5.9
168.9
49.7
339.0
0.7
258.8
79.4
41.7
3.5
1.5
36.7
3,478.3
2010
2,258.4
1,827.3
399.4
31.3
0.40
777.8
96.2
394.2
287.4
224.2
5.5
167.7
51.1
340.2
0.7
258.8
80.7
41.6
3.5
1.5
36.7
3,642.3
* U.S. Territories are not apportioned by sector, and emissions are from all fuel combustion sources (stationary
and mobile) are presented in this table.
                                                                                                      Energy    3-9

-------
Table 3-10: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.)
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
1990 2005
0.3 0.5
0.3 1 0.3
+
0.1
+
1.6
0.3
0.2
0.2
0.9
0.9
+
0.2
0.3
0.4
4.6
0.2
0.3
0.4
3.7
+
+
+
+
+
+
0.1
+
1.5
0.3
0.2
0.1
0.9
0.9
+
0.2
0.3
0.5
3.6
0.1
0.3
0.5
2.8
0.1
+
0.1
+
+
7.5 6.6
2006
0.5
0.3
+
0.1
+
1.5
0.3
0.2
0.1
1.0
0.9
+
0.1
0.3
0.4
3.3
+
0.3
0.4
2.5
0.1
+
0.1
+
+
6.2
2007
0.5
0.3
+
0.1
+
1.5
0.2
0.2
0.1
0.9
0.9
+
0.1
0.3
0.5
3.6
+
0.3
0.5
2.8
0.1
+
0.1
+
+
6.5
2008
0.5
0.3
+
0.1
+
1.4
0.2
0.2
0.2
0.9
0.9
+
0.1
0.3
0.5
3.7
+
0.3
0.5
2.9
0.1
+
0.1
+
+
6.6
2009
0.4
0.3
+
0.1
+
1.2
0.2
0.1
0.1
0.8
1.0
+
0.1
0.3
0.5
3.6
+
0.2
0.5
2.8
0.1
+
0.1
+
+
6.3
2010
0.5
0.3
+
0.2
+
1.4
0.2
0.1
0.1
0.9
0.9
+
0.2
0.3
0.5
3.5
+
0.3
0.5
2.7
0.1
+
0.1
+
+
6.3
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.
Table 3-11: N2O Emissions from Stationary Combustion (Tg CO2 Eq.)
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
1990 2005
7.4 16.0
6.3
0.1
1.0
+
3.3
0.8
0.5
0.2
1.8
0.4
0.1
0.2
0.1
0.1
1.1
+
0.3
0.1
0.7
0.1
+
0.1
+
11.6
0.1
4.3
+
3.1
0.6
0.5
0.2
1.9
0.4
+
0.1
0.1
0.1
1.0
+
0.3
0.1
0.6
0.1
+
0.1
+

12.3 20.6
2006
16.2
11.5
0.1
4.7
+
3.2
0.6
0.6
0.2
1.9
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
0.1
+
+
20.8
2007
16.7
11.4
0.1
5.2
+
3.1
0.5
0.6
0.2
1.8
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
0.1
+
+
21.2
2008
16.8
11.6
+
5.2
+
2.9
0.5
0.5
0.2
1.7
0.3
+
0.1
0.1
0.1
1.0
+
0.2
0.1
0.6
0.1
+
0.1
+
+
21.1
2009
16.8
11.2
+
5.6
+
2.5
0.4
0.4
0.2
1.5
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.6
0.1
+
0.1
+
+
20.7
2010
18.5
12.5
+
5.9
+
2.8
0.5
0.4
0.2
1.7
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
0.1
+
+
22.6

3-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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   + Does not exceed 0.05 Tg CO2 Eq.
   Note:  Totals may not sum due to independent rounding.


Electricity Generation

The process of generating electricity is the single largest source of CO2 emissions in the United States, representing
42 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 0.8
percent, respectively. Electricity generation also accounted for the largest share of CO2 emissions from fossil fuel
combustion, approximately 42 percent in 2010.  Methane and N2O from electricity generation represented 6 and 43
percent of emissions from CH4 and N2O emissions from fossil fuel combustion in 2010, respectively. 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).


Figure 3-9:  Electricity Generation Retail Sales by End-Use Sector


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  the production
of electricity,65 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 2010 increased approximately 6.3 percent and 1.7 percent, respectively. The trend in
the residential and commercial sectors can largely be attributed to warmer, more energy-intensive summer weather
conditions compared to 2009.  Electricity sales to the industrial sector in 2010 increased approximately 5.0 percent.
Overall, in 2010, the amount of electricity generated (inkWh) increased by 4.3 percent from the previous year.  This
increase was due to an increase in economic output, an increase in the carbon intensity of fuels used to generate
electricity due to fuel switching as the price of coal only slightly increased, and the price of petroleum and natural
gas increased significantly, and a slight decrease in the contribution of non-fossil fuel sources used to  generate
electricity. As a result, CO2 emissions from the electric power sector increased by 5.2 percent as the consumption of
coal and  natural gas for electricity generation increased by 5.0 percent and 7.3 percent, respectively, in 2010 and the
consumption of petroleum for electricity generation, decreased by 6.1 percent.

Industrial Sector

The industrial sector accounted for 15 percent of CO2 emissions from fossil fuel combustion, 17 percent of CH4
emissions from fossil fuel combustion, and 6 percent of N2O emissions from fossil fuel combustion. CO2,  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, Paper, Primary Metals, Food, and
Nonmetallic Mineral Products—represent the vast majority of the energy use (EIA 201 la and EIA 2009c).

In theory, emissions from the industrial sector should be highly correlated with economic growth and  industrial
"^ 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).


                                                                                             Energy    3-11

-------
output, but heating of industrial buildings and agricultural energy consumption are also affected by weather
conditions.66 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 effect on industrial emissions.

From 2009 to 2010, total industrial production and manufacturing output increased by 5.3 and 5.8 percent,
respectively (FRB 2011).  Over this period, output increased across all production indices for Food, Petroleum
Refineries, Chemicals, Paper, Primary Metals, and Nonmetallic Mineral Products (see Figure 3-10).


Figure 3-10: Industrial Production Indices (Index 2007=100)


Despite the growth in industrial output (45 percent) and the overall U.S. economy (63 percent) from 1990 to 2010,
CO2 emissions from fossil fuel combustion in the industrial sector decreased by 8.1 percent over that time. A
number of factors are believed to have caused this disparity between growth in industrial output and decrease in
industrial emissions, including: (1) more rapid growth in output from less energy-intensive industries relative to
traditional manufacturing industries, and (2) energy-intensive industries such as steel are employing new methods,
such as electric arc furnaces, that are less carbon intensive than the older methods.  In 2010, CO2, CH4, and N2O
emissions from fossil fuel combustion and electricity use within the industrial end-use sector totaled 1,424.9 Tg CO2
Eq., or approximately 6.6 percent above 2009 emissions.

Residential and Commercial Sectors

The residential and commercial sectors accounted for 6 and 4 percent of CO2 emissions from fossil fuel combustion,
43 and 11 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 2010, CO2, CH4, and N2O emissions from fossil fuel combustion and
electricity use within the residential and commercial end-use sectors were 1,195.2 Tg CO2 Eq. and 1,004.9 Tg CO2
Eq., respectively. Total CO2, CH4, and N2O emissions from the residential and commercial sectors increased by 5.2
and 2.0 percent from 2009 to 2010, respectively.

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 about 76 and 75 percent of the direct fossil fuel CO2 emissions
from the residential and commercial sectors, respectively.  In 2010, natural gas CO2 emissions from the residential
and commercial sectors remained relatively constant and decreased by 0.3 percent, respectively.

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 not
presented for U.S. Territories in the tables above, though the emissions will include some transportation and mobile
combustion sources.
66 Some commercial customers are large enough to obtain an industrial price for natural gas and/or electricity and are
consequently grouped with the industrial end-use sector in U.S. energy statistics. These misclassiiications of large commercial
customers likely cause the industrial end-use sector to appear to be more sensitive to weather conditions.


3-12   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Transportation Sector

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 emissions associated with the sector's electricity
consumption), please see Table 3-7.

    Transportation End-Use Sector

The transportation end-use sector accounted for 1,772.5 Tg CO2 Eq. in 2010, which represented 33 percent of CO2
emissions, 23 percent of CH4 emissions, and 48 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 127.8 Tg CO2 in
2010; 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 7 percent, and other sources 10 percent. Passenger car CO2 emissions increased by 20 percent
from 1990 to 2010, light-duty truck67 CO2 emissions decreased by 3 percent and medium- and heavy-duty trucks
increased by 74 percent. 68 General aviation aircraft CO2 emissions also increased by nearly 67 percent (6.5 Tg)
from 1990 to 2010.  CO2 from the domestic operation of commercial aircraft decreased by 16 percent (21.4 Tg) from
1990 to 2010. Across all categories of aviation69, CO2 emissions decreased by 20.6 percent (36.9 Tg) between
1990 and 2010. This includes a 64 percent (21.9 Tg) decrease in emissions from domestic military  operations.  For
further information on all greenhouse gas emissions from transportation sources, please refer to Annex 3.2. See
Table 3-12 for a detailed breakdown of CO2 emissions by mode and fuel type.

From 1990 to 2010, transportation emissions rose by 19 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 34 percent from 1990 to 2010, as a result of a
confluence of factors including population growth, economic growth, urban sprawl, and low fuel prices over much
of this period.

From 2009 to 2010, CO2 emissions from the transportation end-use sector increased 0.9 percent. The increase in
emissions can largely be attributed to increased economic activity in 2010 and an associated increase in the demand
for transportation. Modes such as medium- and heavy-duty trucks were impacted by the increase in freight transport.
In contrast, commercial  aircraft emissions continued to fall, having decreased 21 percent since 2007, with increased
jet fuel prices being a factor.

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 20 percent from 1990 to
2010. This rise in CO2 emissions, combined with an increase in HFCs from close to zero emissions in 1990 to 60.2
Tg CO2 Eq. in 2010, led to an increase in overall emissions from transportation activities of 20 percent.

    Transportation Fossil Fuel Combustion CO2 Emissions

Domestic transportation CO2 emissions increased by 18 percent (261.0 Tg) between 1990 and 2010, an annualized
increase of 0.8 percent.  The 1  percent increase in emissions between 2009 and 2010 contrasted with the previous
67 Includes "light-duty trucks" fueled by gasoline, diesel and LPG
68 In 2011 FHWA changed how they defined vehicle types for the purposes of reporting VMT for the years 2007-2010.  The old
approach to vehicle classification was based on body type and split passenger vehicles into "Passenger Cars" and "Other 2 Axle
4-Tire Vehicles". The new approach is a vehicle classification system based on wheelbase. Vehicles with a wheelbase less than
or equal to 121 inches are counted as "Light-duty Vehicles -Short Wheelbase".  Passenger vehicles with a Wheelbase greater
than 121 inches are counted as "Light-duty Vehicles - Long Wheelbase".  This change in vehicle classification has moved some
smaller trucks and sport utility vehicles from the light truck category to the passenger vehicle category in this emission inventory.
These changes are reflected in a large drop in light-truck emissions between 2006 and 2007.
69 Includes consumption of jet fuel and aviation gasoline. Does not include aircraft bunkers, which are not included in national
emission totals, in line with IPCC methodological guidance and UNFCCC reporting obligations.


                                                                                             Energy    3-13

-------
year's trend of decreasing emissions. Almost all of the energy consumed by the transportation sector is petroleum-
based, including motor gasoline, diesel fuel, jet fuel, and residual oil. 70 Transportation sources also produce CH4
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, N2O, CH4, and HFCs.
Carbon dioxide emissions from passenger cars and light-duty trucks totaled 1,073.5 Tg in 2010, an increase of 13
percent (123.1 Tg) from 1990. CO2 emissions from passenger cars and light-duty trucks peaked at 1,184.3 Tg in
2004, and since then have declined about 9 percent.  Over the 1990s through early this decade, growth in vehicle
travel substantially outweighed improvements in vehicle fuel economy; however, the rate of Vehicle Miles Traveled
(VMT) growth slowed considerably starting in 2005 (and declined rapidly in 2008) while average vehicle fuel
economy increased.  However, in 2010, fuel VMT grew by 0.3 percent, while  average fuel economy decreased
slightly.  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 44
percent and declined to 23 percent in 2010.
Figure 3-11:  Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2010
Figure 3-12:  Sales of New Passenger Cars and Light-Duty Trucks, 1990-2010
Table 3-12: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.)'
   Fuel/Vehicle Type
1990
2005
2006
2007'
2008
2009
2010
   Gasoline                  983.7        1,187.8   1,178.2    1,181.2   1,130.3   1,128.5   1,117.0
   Passenger Cars             621.4         658.0     635.0     800.2     765.5     762.4     753.8
   Light-Duty Trucks          309.1         478.8     491.5     315.5     298.9     304.1     302.2
   Medium- and Heavy-
    DutyTrucksb              38.7          34.9      35.5      46.6      47.2      43.6      43.4
   Buses                      0.3           0.4       0.4       0.7       0.8       0.8       0.7
   Motorcycles                 1.7           1.6       1.9       4.3       4.4       4.2       3.7
   Recreational Boats           12.4          14.1      14.0      13.9      13.5      13.3      13.1
   Distillate Fuel Oil
    (Diesel)                  262.9 I       458.1     470.3     476.3     443.5     402.9     418.9
   Passenger Cars               7.9           4.2       4.1       4.1       3.7       3.6       3.7
   Light-Duty Trucks           11.5          25.8      26.8      13.6      12.1      12.1      12.6
   Medium- and Heavy-
    DutyLrucksb             190.5         360.7     370.0     384.6     366.1     332.2     345.3
   Buses                      8.0          10.6      10.8      15.9      15.2      14.1      14.0
   Rail                       35.5          45.6      47.8      46.6      43.2      36.3      39.0
   Recreational Boats            2.0           3.1       3.2       3.3       0.9       3.5       3.5
   Ships and Other Boats         7.5           8.1       7.5       8.2       2.2       1.2       0.7
   International Bunker
    Fuels0                    11.7           9.4       8.8       8.2       9.0       8.3       8.8
   Jet Fuel                  176.2 I       194.2     169.5     168.7     155.1     139.6     140.5
   Commercial Aircraft        135.4         161.2     137.1     138.1     122.2     111.4     114.0
   Military Aircraft            34.4          18.1      16.3      16.1      16.2      14.1      12.5
   General Aviation             6.4          14.9      16.0      14.5      16.6      14.1      14.0
70 Biofuel estimates are presented for informational purposes only in the Energy chapter, in line with IPCC methodological
guidance and UNFCCC reporting obligations. Net carbon fluxes from changes in biogenic carbon reservoirs in croplands are
accounted for in the estimates for Land Use, Land-Use Change, and Forestry (see Chapter 7). More information and additional
analyses on biofuels are available at EPA's "Renewable Fuels: Regulations & Standards" web page:
http://www.epa.gov/otaq/fuels/renewablefuels/regulations.htm
3-14   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
    Aircraft
   International Bunker
    Fuels'                   46.4          56.8      74.6      73.8      75.5      68.6      72.5
   Aviation Gasoline            3.1           2.4       2.3       2.2       2.0       1.8       1.9
   General Aviation
    Aircraft                    3.1           2.4       2.3       2.2       2.0       1.8       1.9
   Residual Fuel Oil           22.6          19.3      23.0      29.0      19.9      15.4      25.3
   Ships and Other Boats       22.6          19.3      23.0      29.0      19.9      15.4      25.3
   International Bunker
    Fuels'                   53.7          43.6      45.0      45.6      49.2      45.4      46.5
   Natural Gas               36.0          33.1      33.1      35.2      36.7      37.9      40.1
   Passenger Cars                + I           +        +         +        +         +        +
   Light-Duty Trucks              + I           +        +         +        +         +        +
   Buses                        + I         0.8       0.8       1.0       1.1       1.3       1.3
   Pipeline                   36.0          32.2      32.3      34.2      35.6      36.6      38.8
   LPG                       1.4           1.7       1.7       1.4       2.5       1.7       1.8
   Light-Duty Trucks            0.6           1.3       1.2       1.0       1.8       1.2       1.2
   Medium- and Heavy-
Duty Trucksb
Buses
Electricity
Rail
0.8 1
+ 1
3.0 1
3.0
0.4
+
4.7
4.7
0.5
+
4.5
4.5
0.4
+
5.1
5.1
0.7
+
4.7
4.7
0.5
+
4.5
4.5
0.6
+
4.5
4.5
   Total
1,489.0
1,901.3    1,882.6   1,899.0   1,794.5   1,732.4   1,750.0
   Total (Including
    Bunkers) c
1,600.8
2,011.1    2,011.1   2,026.6   1,928.3   1,854.7   1,877.8
   a This 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.
   0 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.
   d Residual fuel oil data for ships and boats is based on EIA's December 2011 Monthly Energy Review
   e In 2011, FHWA changed how vehicles are classified, moving form a system based on body-type to one
   that is based on wheelbase.  This change in methodology in FHWA's VM-1 table resulted in large changes
   in fuel consumption data by vehicle class, thus leading to a shift in emissions among on-road vehicle
   classes in the 2007-2010 time period. Note: Totals may not sum due to independent rounding.
   Note: See section 3.10 of this chapter, in line with IPCC methodological guidance and UNFCCC reporting
   obligations, for more information on ethanol.
   + Less than 0.05 Tg CO2 Eq.
   - Unreported or zero
   Mobile Fossil Fuel Combustion CH4 andN2O Emissions

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 summary of all emissions from both transportation
and mobile sources.  Table 3-13 and Table 3-14 provide CH4 and N2O emission estimates in Tg CO2 Eq.71

Mobile combustion was responsible for a small portion of national CH4 emissions (0.3 percent) but was the second
largest source of U.S. N2O emissions (7 percent).  From 1990 to 2010, mobile source CH4 emissions declined by 59
percent, to 1.9 Tg CO2 Eq. (91 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 53 percent,
to 20.6 Tg CO2 Eq. (66 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
71 See Annex 3.2 for a complete time series of emission estimates for 1990 through 2010.
                                                                                                Energy    3-15

-------
later-generation emission control technologies have reduced N2O output, resulting in a 63 percent decrease in
mobile source N2O emissions from 1998 to 2010 (Figure 3-13).  Overall, CH4 and N2O emissions were
predominantly from gasoline-fueled passenger cars and light-duty trucks.
Figure 3-13:  Mobile Source CH4 and N2O Emissions


Table 3-13:  CH4 Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type3
Gasoline On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy-Duty
Trucks and Buses
Motorcycles
Diesel On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy-Duty
Trucks and Buses
Alternative Fuel On-Road
Non-Road
Ships and Boats
Rail
Aircraft
Agricultural Equipment15
Construction/Mining
Equipment0
Other4
Total
1990
4.2
2.6
1.4

0.2
•
+•
I
I

I
+•
0.4
+
0.1
0.2
0.1

•
0.1
4.7
2005
1.9
1.1
0.7

0.1
+
+
+
+

+
0.1
0.6
+
0.1
0.2
0.1

0.1
0.1
2.5
2006
1.7
1.0
0.6

0.1
+
+
+
+

+
0.1
0.6
+
0.1
0.1
0.1

0.1
0.1
2.4
2007 e
1.6
1.1
0.3

0.1
+
+
+
+

+
0.1
0.5
+
0.1
0.1
0.1

0.1
0.1
2.2
2008
1.4
1.0
0.3

0.1
+
+
+
+

+
0.1
0.5
+
0.1
0.1
0.1

0.1
0.1
2.1
2009
1.3
0.9
0.3

0.1
+
+
+
+

+
0.1
0.5
+
0.1
0.1
0.1

0.1
0.1
2.0
2010
1.2
0.9
0.3

0.1
+
+
+
+

+
0.1
0.4
+
0.1
0.1
+

0.1
0.1
1.9
  a See Annex 3.2 for definitions of on-road vehicle types.
  b Includes equipment, such as tractors and combines, as well as fuel consumption from trucks that are
  used off-road in agriculture.
  0 Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from
  trucks that are used off-road in construction.
  d "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and
  garden equipment, railroad equipment, airport equipment, commercial equipment, and industrial
  equipment, as well as fuel consumption from trucks that are used off-road for commercial/industrial
  purposes.
  e In 2011,  FHWA changed how vehicles are classified, moving from a system based on body-type to
  one that is based on wheelbase. This change in methodology in FHWA's VM-1 table resulted in large
  changes in VMT by vehicle class, thus leading to a shift in emissions among on-road vehicle classes in
  the 2007 to 2010 time period.
  Note: Totals may not sum due to independent rounding.
  + Less than 0.05 Tg CO2 Eq.


Table 3-14: N2O Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type3
Gasoline On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy-Duty
Trucks and Buses
Motorcycles
Diesel On-Road
Passenger Cars
Light-Duty Trucks
1990
40.1
25.4
•
0.6
+
0.2
+
+
2005
32.1
17.8
13.6
0.8
+
0.3
+
+
2006
29.0
15.7
12.6
0.7
+
0.3
+
+
2007 e
24.1
17.3
5.8
0.9
+
0.4
+
+
2008
20.7
14.6
5.2
0.9
+
0.4
+
+
2009
18.3
12.4
5.1
0.6
+
0.4
+
+
2010
16.1
10.8
4.6
0.6
+
0.4
+
+
3-16   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Medium- and Heavy-Duty
Trucks and Buses
Alternative Fuel On-Road
Non-Road
Ships and Boats
Rail
Aircraft
Agricultural Equipment*
Construction/Mining
Equipment0
Otherd
Total

0.2
0.1
3.6
0.6
!
0.4
43.9

0.3
0.2
4.3
0.6
0.4
1.9
0.4
0.5
0.6
37.0

0.3
0.2
4.2
0.7
0.4
1.6
0.4
0.5
0.6
33.7

0.4
0.2
4.3
0.8
0.4
1.6
0.4
0.5
0.6
29.0

0.4
0.2
3.8
0.5
0.3
1.5
0.4
0.5
0.6
25.2

0.4
0.2
3.6
0.5
0.3
1.3
0.4
0.5
0.6
22.5

0.4
0.2
3.8
0.6
0.3
1.3
0.4
0.6
0.6
20.6
  a See Annex 3.2 for definitions of on-road vehicle types.
  b Includes equipment, such as tractors and combines, as well as fuel consumption from trucks that
  are used off-road in agriculture.
  0 Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from
  trucks that are used off-road in construction.
  d "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and
  garden equipment, railroad equipment, airport equipment, commercial equipment, and industrial
  equipment, as well as fuel consumption from trucks that are used off-road for commercial/industrial
  purposes.
  e In 2011, FHWA changed how vehicles are classified, moving from a system based on body-type to
  one that is based on wheelbase.  This change in methodology in FHWA's VM-1 table resulted in
  large changes in VMT by vehicle class, thus leading to a shift in emissions among on-road vehicle
  classes in the 2007 to 2010 time period.
  Note: Totals may not sum due to independent rounding.
  + Less than 0.05 Tg CO2 Eq.


CCbfrom 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 in line with a Tier 2 method in the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories (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 201 Ib).  The EIA does not
         include territories in its national energy statistics, so fuel consumption data for territories were collected
         separately from Jacobs (2010).72

        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, and losses). 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
72 Fuel consumption by U.S. territories (i.e., American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other
U.S. Pacific Islands) is included in this report and contributed emissions of 42 Tg CO2 Eq. in 2010.


                                                                                             Energy    3-17

-------
        periodic 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.  73

        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).74
    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 (2004 through 2011), Coffeyville (2011), U.S. Census Bureau (2011), EIA (201 Ib), USGS
        (1991 through 2011), USGS (1994 through 2011), USGS (1995, 1998, 2000 through  2002), USGS (2007),
        USGS (2009a), USGS (2009b), USGS (2010a), USGS(2010b), USGS (2010c), USGS (2011), USGS (1991
        through 20lOa), USGS (1991 through 20lOb), USGS (2010) and USGS (2011).75
    3.  Adjust for conversion of fuels and exports ofCO2.  Fossil fuel consumption estimates are adjusted
        downward to exclude fuels created from other fossil fuels and exports of CO2.76  Synthetic natural gas is
        created from industrial coal, and is currently included in EIA statistics for both coal and natural gas.
        Therefore, synthetic natural gas is subtracted from energy consumption statistics.77 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 were collected from EIA
        (201 la), data for synthetic natural gas were collected from EIA (201 Ib), and data for CO2 exports were
        collected from the Eastman Gasification Services Company (2011), Dakota Gasification Company (2006),
        Fitzpatrick (2002), Erickson (2003), EIA (2007b) and DOE (2012).

    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 and motor gasoline
        consumption estimate from EIA are considered to be accurate at the national level, the distillate
        consumption totals for the residential, commercial, and industrial sectors were adjusted downward
        proportionately. The data sources used in the bottom-up analysis of transportation fuel consumption include
        AAR (2009 through 2011), Benson (2002 through 2004), DOE (1993 through 2011),  EIA (2009a), EIA
        (1991 through 2011), EPA (2009), and FHWA (1996 through 2012).78
73 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.
  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.
75 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.
76 Energy statistics from EIA (2012) are already adjusted downward to account for ethanol added to motor gasoline, and biogas
in natural gas.
77 These adjustments are explained in greater detail in Annex 2.1.
78 The source of VMT and fuel consumption is FHWA's VM-1 table. The data collection methodology has undergone
substantial revision for only years 2007 to 2010, while prior years have remain unchanged Several of the vehicle type categories
have changed.  For instance, passenger car has been replaced by "Light duty vehicle, short WB" and other 4 axle- 2 tire has been
replaced by "Light duty vehicle, long WB". With this change in methodology, there are substantial differences in activity data
among vehicle classes, even though overall VMT and fuel consumption is unchanged.  While this is the best data available on


3-18   Inventory of U.S. Greenhouse Gas  Emissions and Sinks: 1990-2010

-------
    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 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
        byEIA(2012).

    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).79 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
        2011) supplied data on military jet fuel and marine fuel use.  Commercial jet fuel use was obtained from
        FAA (2006,  2009, 2011, and 2012); residual and distillate fuel use for civilian marine bunkers was obtained
        from DOC (1991 through 2011) for 1990 through 2001 and 2007 through 2010, 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 2008 (EIA 2009a), and an EPA analysis of C content coefficients used in the mandatory
        reporting rule (EPA 2010a). A discussion of the methodology used to develop the  C content coefficients
        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 2012); for each vehicle category, the
            percent gasoline, diesel, and other (e.g., CNG, LPG) fuel consumption are estimated using data from
            DOE (1993 through 2011).

        •   For non-road vehicles, activity data  were obtained from AAR (2009 through 2011), APTA (2007
            through 2011), BEA (1991 through 2011), Benson (2002 through 2004), DOE (1993  through 2011),
            DESC (2011), DOC (1991 through 2011), DOT (1991 through 2011), EIA (2009a), EIA (201 la), EIA
            (2002), EIA (1991 through 2012), EPA (201 Ib), and Gaffney (2007).

        •   For jet fuel used by aircraft, CO2 emissions were calculated directly based on reported consumption of
vehicle activity, the time series reflects changes in the definition of vehicle classes between 2006- 2007 when this change in
methodology was implemented.
79 See International Bunker Fuels section in this chapter for a more detailed discussion.


                                                                                           Energy    3-19

-------
            fuel as reported by EIA, and allocated to commercial aircraft using flight-specific fuel consumption
            data from the Federal Aviation Administration's (FAA) Aviation Environmental Design Tool (AEDT)
            (FAA 2012). 80 Allocation to domestic general aviation was made using FAA Aerospace Forecast data
            (FAA 2011), and allocation to domestic military uses was made using DoD data (see Annex 3.7).

Heat contents and densities were obtained from EIA (201 la) and USAF (1998). 81


[BEGIN BOX]


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


Fossil fuels are the dominant source of energy in the United States, and CO2 is the dominant greenhouse gas emitted
as a product from their combustion. Energy-related CO2 emissions are impacted by not only  lower levels of energy
consumption 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 CO2 Eq./QBtu for natural gas to upwards of 95 Tg CO2 Eq./QBtu for coal and petroleum coke.82 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. 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. 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 CO2 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 CO2 Eq./QBtu)
Sector
Residential a
Commercial a
Industrial a
Transportation a
Electricity Generation b
U.S. Territories c
1990
57.4
59.2
64.3
71.1
87.3
73.0
2005
56.6
57.5
64.4
71.4
85.8
73.4
2006
56.5
57.2
64.5
71.6
85.4
73.5
2007
56.3
57.1
64.1
71.9
84.7
73.8
2008
56.0
56.7
63.6
71.6
84.9
73.3
2009
56.0
56.9
63.0
71.5
83.7
73.1
2010
56.0
56.9
63.3
71.5
83.5
73.1
8" Data for inventory years 2000 through 2005 were developed using the FAA's System for assessing Aviation's Global
Emissions (SAGE) model. That tool has been incorporated into the Aviation Environmental Design Tool (AEDT), which
calculates noise in addition to aircraft fuel bum and emissions for all commercial flights globally in a given year. Data for
inventory years 2006-2010 were developed using AEDT. The AEDT model dynamically models aircraft performance in space
and time to produce fuel bum, emissions and noise.  Full flight gate-to-gate analyses are possible for study sizes ranging from a
single flight at an airport to scenarios at the regional, national, and global levels. AEDT is currently used by the U.S. government
to consider the interdependencies between aircraft-related fuel burn, noise and emissions. Additional information available at:
http://www.faa.go v/about/oflice_org/headquarters_oflices/apl/research/models/
  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.
82 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.


3-20   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
   All Sectorsc	73.0	73.6     73.5     73.3    73.1    72.4     72.5
   a Does not include electricity or renewable energy consumption.
   b Does not include electricity produced using nuclear or renewable energy.
   0 Does not include nuclear or renewable energy consumption.
   Note: Excludes non-energy fuel use emissions and consumption.


Over the twenty-one-year period of 1990 through 2010, however, the C intensity of U.S. energy consumption has
been fairly constant, as the proportion of fossil fuels used by the individual sectors has not changed significantly.
Per capita energy consumption fluctuated little from 1990 to 2007, but in 2010 was approximately 8.0 percent below
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 CO2 emissions per
dollar of gross domestic product (GDP) have both declined since 1990 (BEA2011).


Figure 3-14:  U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP


C intensity estimates were developed using nuclear and renewable energy data from EIA (201 la), EPA (2010a), and
fossil fuel consumption data as discussed above and presented in Annex 2.1.


 [END BOX]
Uncertainty and Time Series Consistency

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 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.  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


                                                                                             Energy   3-21

-------
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 El A. Further
research is planned to improve the allocation into detailed transportation end-use sector emissions.

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 Stochastic Simulation technique, with @RISK software.
For this uncertainty estimation, the inventory estimation model for CO2 from fossil fuel combustion was integrated
with the relevant variables from the inventory estimation model for International Bunker Fuels, to realistically
characterize the interaction (or endogenous correlation) between the variables of these two models.  About 120 input
variables were modeled for CO2 from energy-related Fossil Fuel Combustion (including about 10 for non-energy
fuel consumption and about 20  for International Bunker Fuels).

In developing the uncertainty estimation model, uniform distributions were assumed for all activity-related input
variables and emission factors, based on the SAIC/EIA (2001) report.83  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.84
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).85 For purposes of this uncertainty analysis, each input variable was simulated 10,000 times  through Monte
Carlo Sampling.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-16. Fossil fuel combustion
CO2 emissions  in 2010 were estimated to be between 5,260.8 and  5,638.9 Tg CO2 Eq. at a 95 percent confidence
level. This indicates a range of 2 percent below to 5 percent above the 2010 emission estimate of 5,387.8 TgCO2
Eq.

Table 3-16:  Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related Fossil Fuel
Combustion by Fuel Type and Sector (Tg CO2 Eq. and Percent)


Fuel/Sector


Coal"
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
2010 Emission
Estimate
(Tg C02 Eq.)


1,933.2
0.7
5.5
96.2
NE
1,827.3
3.5

Uncertainty
(Tg CO,
Lower
Bound
1,868.0
0.6
5.2
92.6
NE
1,756.5
3.1



Range Relative to Emission Estimate3
Eq.)
Upper
Bound
2,114.1
0.8
6.3
112.2
NE
2,001.2
4.2
(°/0
Lower
Bound
-3%
-6%
-5%
-3%
NA
-4%
-12%
)
Upper
Bound
+9%
+15%
+15%
+17%
NA
+10%
+19%
83 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.
84 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.
8^ 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.


3-22   Inventory of U.S. Greenhouse Gas Emissions and Sinks:  1990-2010

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Natural Gas b
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum b
Residential
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
Total (excluding Geothermal)
Geo thermal
Total (including Geothermal) 'c
1,261.6
258.8
167.7
394.2
40.1
399.4
1.5
2,192.6
80.7
51.1
287.4
1,705.4
31.3
36.7
5,387.4
0.4
5,387.8
1,261.9
250.0
163.2
374.9
35.2
362.3
1.3
2,032.7
76.4
48.7
235.7
1,565.6
29.8
33.8
5,260.4
NE
5,260.8
1,332.5
275.2
179.7
412.7
38.8
392.0
1.7
2,291.3
84.9
53.2
335.0
1,791.4
33.7
40.9
5,638.5
NE
5,638.9
+0%
-3%
-3%
+3%
-3%
-3%
-12%
-7%
-5%
-5%
-18%
-8%
-5%
-8%
-2%
NE
-2%
+6%
+7%
+7%
+13%
+7%
+5%
+17%
+5%
5%
4%
17%
5%
8%
12%
+5%
NE
+5%
   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.
   0 Geothermal emissions added for reporting purposes, but an uncertainty analysis was not performed for CO2
   emissions from geothermal production.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

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

The Energy Information Administration (EIA 201 la) updated energy consumption statistics across the time series,
relative to the previous Inventory. These revisions primarily impacted the emission estimates from 2008 to 2009;
however revisions to industrial petroleum consumption impacted estimates across the time series. Overall, these
changes resulted in an average annual  decrease of 0.2 Tg CO2 Eq. (less than 0.1 percent) in CO2 emissions from
fossil fuel combustion for the period 1990 through 2009.

Planned  Improvements

To reduce uncertainty of CO2 from fossil fuel combustion estimates, efforts will be taken to work with EIA 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.

The availability of facility-level combustion emissions through EPA's Greenhouse Gas Reporting Program
(GHGRP) will be examined to help better characterize the industrial sector's energy consumption in the United
States,  and further classify business establishments according to industrial economic activity type. Most
methodologies used in EPA's GHGRP are consistent with IPCC, though for EPA's GHGRP, facilities collect


                                                                                           Energy    3-23

-------
detailed information specific to their operations according to detailed measurement standards, which may differ with
the more aggregated data collected for the Inventory to estimate total, national U.S. emissions. In addition, and
unlike the reporting requirements for this chapter under the UNFCCC reporting guidelines,86 some facility-level
fuel combustion emissions reported under the GHGRP may also include industrial process emissions. In line with
UNFCCC reporting guidelines, fuel combustion emissions are included in this chapter, while process emissions are
included in the Industrial Processes chapter of this report. In examining data from EPA's GHGRP that would be
useful to improve the emission estimates for the CO2 from fossil fuel combustion category, particular attention will
also be made to ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not
available for all inventory years as reported in this inventory. Additionally, analyses will focus on aligning reported
facility-level fuel types and IPCC fuel types per the national energy statistics, ensuring CO2 emissions from biomass
are separated in the facility-level reported data, and maintaining consistency with national energy statistics provided
by EIA. In implementing improvements and integration of data from EPA's GHGRP, the latest guidance from the
IPCC on the use of facility-level data in national inventories will be relied upon.87

CH4and N20 from  Stationary Combustion

Methodology

Methane and N2O emissions from stationary combustion were estimated by multiplying fossil fuel and wood
consumption data by emission factors (by sector and fuel type for industrial, residential, commercial, and U.S.
Territories; and by fuel and technology type for the electric power sector). Beginning with this year's Inventory, the
electric power sector utilizes a Tier 2 methodology, whereas all other sectors utilize a Tier 1 methodology. The
activity data and emission factors used are described in the following subsections.

   Industrial, Residential, Commercial, and U.S. Territories

National coal, natural gas, fuel oil, and wood consumption data were grouped by sector: industrial, commercial,
residential, and U.S. territories. For the CH4 and N2O estimates, wood consumption data for the United States  was
obtained from EIA's Annual Energy Review (EIA 201 la). 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 (EIA 201 Ib). Because the United States does not include territories in its national energy
statistics, fuel consumption data for territories were provided separately by Jacobs  (2010).88 Fuel consumption for
the industrial sector was  adjusted to subtract out construction and agricultural use, which is reported under mobile
sources.89  Construction and agricultural fuel use was obtained from EPA (20 lOa). 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. Tier 1 default emission factors for these three end-use sectors were provided by the
2006 IPCC 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.

   Electric Power Sector

In this year's Inventory, the emission estimation methodology for the electric power sector was revised from Tier 1
to Tier 2 as fuel consumption for the electricity generation sector by control-technology type was obtained from
EPA's Acid Rain Program Dataset (EPA 2011). This combustion technology- and fuel-use data was available by
facility from 1996 to 2010.

Since there was a difference between the EPA (2011) and EIA (201 la) total energy consumption estimates, the
86 See 
87 See
88 U.S. territories data also include combustion from mobile activities because data to allocate territories' energy use were
unavailable. For this reason, CH4 and N2O emissions from combustion by U.S. territories are only included in the stationary
combustion totals.
89 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.


3-24   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
remainder between total energy consumption using EPA (2011) and El A (201 la) was apportioned to each
combustion technology type and fuel combination using a ratio of energy consumption by technology type from
1996 to 2010.

Energy consumption estimates were not available from 1990 to 1995 in the EPA (2011) dataset, and as a result,
consumption was calculated using total electric power consumption from EIA (201 la) and the ratio of combustion
technology and fuel types from EPA (2011). The consumption estimates from 1990 to 1995 were estimated by
applying the 1996 consumption ratio by combustion technology type to the total EIA consumption for each year
from 1990 to 1995.  Emissions were estimated by multiplying fossil fuel and wood consumption by technology- and
fuel-specific Tier 2 IPCC emission factors.

Lastly, there were significant differences between wood biomass consumption in the electric power sector between
the EPA (2011) and EIA (201 la) datasets. The difference in wood biomass consumption in the electric power sector
was distributed to the residential, commercial, and industrial sectors according to their percent share of wood
biomass energy consumption calculated from EIA (201 la).
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 and Time-Series Consistency

Methane 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 Stochastic 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.  About 55 input variables
were simulated for the uncertainty analysis of this source category (about 20 from the CO2 emissions from fossil
fuel combustion inventory estimation model and about 35 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/EIA (2001) report.90 For these variables, the uncertainty
ranges were assigned to the input variables based on the data reported in SAIC/EIA (2001).91 However, the CH4
emission factors differ from those used by EIA.  Since these factors were obtained from IPCC/UNEP/OECD/IEA
(1997), uncertainty ranges were assigned based on IPCC default uncertainty estimates (IPCC 2000).

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-17.  Stationary  combustion
CH4 emissions in 2010 (including biomass) were estimated to be between 3.8 and 14.4 Tg CO2 Eq. at a 95 percent
confidence level. This indicates a range of 40 percent below to 128 percent above the 2010 emission estimate of 6.3
Tg CO2 Eq.92 Stationary combustion N2O emissions in 2010 (including biomass) were estimated to be between 9.9
and 38.8 Tg CO2 Eq. at a 95 percent confidence level.  This indicates a range of 56 percent below to 72 percent
above the 2010 emissions estimate of 22.6 Tg CO2 Eq.
90 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.
91 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.
92 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.


                                                                                            Energy   3-25

-------
Table 3-17: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Energy-Related Stationary
Combustion, Including Biomass (Tg CO2 Eq. and Percent)

   Source                Gas   2010 Emission  Uncertainty Range Relative to Emission Estimate3
                                 Estimate
                               (Tg C02 Eq.)        (Tg C02 Eq.)                 (%)

Stationary Combustion
Stationary Combustion

CH4
N2O

6.3
22.6
Lower
Bound
3.8
9.9
Upper
Bound
14.4
38.8
Lower
Bound
-40%
-56%
Upper
Bound
+128%
+72%
   1 Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
   interval.

The uncertainties associated with the emission estimates of CH4 and N2O are greater than those associated with
estimates of CO2 from fossil fuel combustion, which mainly rely on the carbon content of the fuel combusted.
Uncertainties in both CH4 and N2O estimates are due to the fact that emissions are estimated based on emission
factors representing only a limited subset of combustion conditions. For the indirect greenhouse gases, uncertainties
are partly due to assumptions concerning combustion technology types, age of equipment, emission factors used,
and activity data projections.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

QA/QC and Verification

A source-specific QA/QC plan for stationary 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 emission factor sources and methodology used for estimating
CH4, N2O, and 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 few of changes,
impacting the entire time series, relative to the previous Inventory. Slight changes to emission estimates for sectors
are due to revised data from El A (2011). Wood consumption data in El A (2011) were revised for the residential,
commercial, electric power,  and industrial sectors from 1990 to 2009. Additionally, a Tier 2 emission estimation
methodology was applied to estimate emissions from the electric power sector across the entire time series. This
primarily impacted N2O emission estimates, as the number of coal fluidized bed boilers increased significantly from
2000 through 2005. The combination  of the methodological and historical data changes resulted in an average
annual increase of less than 0.1 Tg CO2 Eq.  (0.5 percent) in CH4 emissions from stationary combustion and an
average annual increase of 1.9 Tg CO2 Eq. (13.7 percent) in N2O emissions from stationary combustion for the
period 1990 through 2009.

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 taken to work with EIA and other agencies to improve the quality of the U.S.
territories data.  Because these data are not broken out by stationary and 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.

Beginning in 2010, those facilities that emit over 25,000 tons of greenhouse gases (CO2 Eq.) from stationary
combustion across all sectors of the economy are required to calculate and report their greenhouse gas emissions to
EPA through its GHGPJ3. These data will be used in future inventories to improve the emission calculations through
3-26  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
the use of these collected higher tier methodological data.

Future improvements to the CH4 and N2O from Stationary Combustion category involve research into the
availability of CH4 and N2O from stationary combustion data, and analyzing data reported under EPA's GHGRP. In
examining data from EPA's GHGRP that would be useful to improve the emission estimates for CH4 and N2O from
Stationary Combustion  category, particular attention will be made to ensure time series consistency, as the facility-
level reporting data from EPA's GHGRP are not available for all Inventory years as reported in this inventory. In
implementing improvements and integration of data from EPA's GHGRP, the latest guidance from the IPCC on the
use of facility-level data in national inventories will be relied upon. 93

ChU 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)94 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 (CARD) and
Environment Canada laboratory test results of different vehicle and control technology types.  The EPA, CARD  and
Environment Canada tests were designed following the Federal Test Procedure (FTP), which covers three separate
driving segments, since vehicles emit varying amounts of greenhouse gases 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 emissions 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.95

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 2010 were obtained from the Federal Highway Administration's (FHWA)
Highway Performance Monitoring System database as reported in Highway Statistics (FHWA 1996 through
  See
  Alternative fuel and advanced technology vehicles are those that can operate using a motor fuel other than gasoline or diesel.
This includes electric or other bi-fuel or dual-fuel vehicles that may be partially powered by gasoline or diesel.
95 Additional information regarding the model can be found online at http://www.epa.gov/OMS/m6.htm.


                                                                                          Energy    3-27

-------
2012).96 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
2011) and information on total motor vehicle fuel consumption by fuel type fromFHWA (1996 through 2012).
VMT for AFVs were taken from Browning (2003).  The age distributions of the U.S. vehicle fleet were obtained
from EPA (201 la, 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).97 Activity
data were obtained from AAR (2009 through 2011), APTA (2007 through 2011), APTA (2006), BEA (1991 through
2005), Benson (2002 through 2004), DHS (2008), DOC (1991 through 2011), DOE (1993 through 2011), DESC
(2011), DOT (1991 through 2011), EIA (2008a,  2011, 2012 2002), EIA (2007 through 2011), EIA (1991 through
2012), EPA (2009), Esser (2003 through 2004), FAA (2012, 2011, and 2006), and Gaffney (2007). Emission factors
for non-road modes were taken from IPCC/UNEP/OECD/IEA (1997) and Browning (2009).

Uncertainty and Time-Series Consistency

A quantitative uncertainty analysis  was conducted for the mobile source sector using the IPCC-recommended Tier 2
uncertainty estimation methodology, Monte Carlo Stochastic Simulation technique, using @RISK software. The
uncertainty analysis was performed on 2010 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 four major sets of input variables: (1) vehicle miles traveled (VMT) data, by on-road
vehicle and fuel type and (2) emission factor data, by on-road vehicle, fuel, and control technology type, (3) fuel
consumption, data, by non-road vehicle and equipment type, and (4) emission factor data, by non-road vehicle and
equipment 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 CH4 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.

Mobile combustion CH4 emissions from all mobile  sources in 2010 were estimated to be between 1.7 and 2.1 Tg
CO2 Eq. at a 95 percent confidence level.  This indicates a range of 10 percent below to 9 percent above the
corresponding 2010 emission estimate of 1.9 Tg CO2 Eq. Also at a 95 percent confidence level, mobile combustion
N2O emissions from mobile sources in 2010 were estimated to be between 19.3 and 25.9 Tg CO2 Eq., indicating a
range of 6 percent below to 26 percent above the corresponding 2010 emission estimate of 20.6 Tg CO2 Eq.

Table 3-18:  Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Mobile Sources  (Tg CO2
Eq. and Percent)
96 The source of VMT and fuel consumption is FHWA's VM-1 table. The data collection methodology has undergone
substantial revision for only years 2007-2010, while prior years have remain unchanged  Several of the vehicle type categories
have changed. For instance, passenger car has been replaced by "Light duty vehicle, short WB" and other 4 axle- 2 tire has been
replaced by "Light duty vehicle, long WB". With this change in methodology, there are substantial differences in activity data
among vehicle classes, even though overall VMT and fuel consumption is unchanged. While this is the best data available on
vehicle activity, the time series reflects changes in the definition of vehicle classes between 2006- 2007 when this change in
methodology was implemented.
97 The consumption of international bunker fuels is not included in these activity data, but is estimated separately under the
International Bunker Fuels source category.


3-28  Inventory of U.S. Greenhouse Gas Emissions and  Sinks:  1990-2010

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  Source           Gas     2010 Emission     Uncertainty Range Relative to Emission Estimate3
                               Estimate3
                             (Tg C02 Eq.)         (Tg C02 Eq.)                 (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Mobile Sources
Mobile Sources
CH4
N2O
1.9
20.6
1.7
19.3
2.1
25.9
-10%
-6%
+9%
+26%
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
  interval.

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.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.

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. Each year, adjustments are made to the methodologies
used in calculating emissions in the current Inventory relative to previous Inventory reports.

In 2011, FHWA revised the  methodology of their VM-1 table, which provides the source data for on-road vehicle
VMT, fuel consumption, and miles per gallon.  FHWA's data collection methodology has undergone substantial
revision for only years 2007 to 2010, while prior years have remained unchanged.  With this revision, several of the
vehicle type  categories have changed. For instance, passenger car has been replaced by "Light duty vehicle, short
wheel-base" and other 4 axle- 2 tire has been replaced by "Light duty vehicle, long wheel-base".  With this change
in methodology, there are substantial differences in activity data among vehicle classes, even though overall VMT
and fuel consumption is unchanged.  While this is the best data available on vehicle activity, the time series reflects
changes in the definition of vehicle classes between 2006- 2007, when this  change in methodology was
implemented.

The underlying data used for calculating Alternative Fuel Vehicles VMT has changed substantially. This data is
supplied by the U.S. Energy Information Administration, Office of Energy  Consumption and Efficiency Statistics,
and the DOE/GSA Federal Automotive Statistical Tool (FAST). EIA changed its reporting methodology for 2005-
2010, and has provided more detail on alternative fuel vehicle use by vehicle class.  The fuel use breakdown by
vehicle class had previously been based on estimates of the distribution of fuel use by vehicle class, while  the new
data from EIA allowed actual data to be used for fuel use, and resulted in greater share of heavy-duty AFV VMT
estimated for 2005-2010.

As a result of these changes, estimates of CH4 emissions were slightly higher than previous Inventory years, while
N2O emissions were slightly higher for 2005 and 2006 and lower for 2007 through 2009.  CH4 emissions for 2006
increased the most, 2 percent (less than 0.1 Tg CO2 Eq.). N2O emissions for 2009 decreased 6 percent (1.4 Tg CO2
Eq.), the greatest decrease relative to the previous inventory.
                                                                                           Energy    3-29

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Planned Improvements

While the data used for this report represent the most accurate information available, four areas have been identified
that could potentially be improved in the short-term given available resources.
    1.   Develop updated emissions factors for diesel vehicles, motorcycle, and biodiesel vehicles.  Previous
        emission factors were based upon extrapolations from other vehicle classes and new test data from
        Environment Canada and other sources may allow for better estimation of emission factors for these
        vehicles.

    2.   Develop new emission 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.
    3.   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 and AEDT
        databases contain detailed data on takeoffs and landings for each calendar year starting in 2000, 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, the development
        of procedures  to develop comparable estimates for years prior to 2000, and the dynamic interaction of
        ambient air with aircraft exhausts is developed.  The feasibility of this approach will be explored.

    4.   Develop improved estimates of domestic waterborne fuel consumption. The inventory estimates for
        residual and distillate fuel used by ships and boats is based in part on data on bunker fuel use from the U.S.
        Department of Commerce.  Domestic fuel consumption is estimated by subtracting fuel sold for
        international use from the total sold in the United States. It may be possible to more accurately estimate
        domestic fuel  use and emissions by using detailed data on marine ship activity.  The feasibility of using
        domestic marine activity data to improve the estimates will be  investigated.

    5.   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.

3.2.    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 (metallurgical) coke (manufactured from coking coal).  The non-energy applications of these fuels are equally
diverse, including 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).

CO2 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 62 percent of the total C consumed for non-energy purposes was stored in products, and not released to
the atmosphere; the remaining 38 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 Incineration of Waste source
category. In addition, there is some overlap between fossil fuels consumed for non-energy uses and the fossil-


3-30  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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 the inventory calculations make adjustments to address the effect of net exports on the mass of C in
non-energy applications.

As shown in Table 3-19, fossil fuel emissions in 2010 from the non-energy uses of fossil fuels were 125.1 Tg CO2
Eq., which constituted approximately 2 percent of overall fossil fuel emissions.  In 2010, the consumption of fuels
for non-energy uses (after the adjustments described above) was 4,651.0 TBtu, an increase of 4.3 percent since 1990
(see Table 3-20). About 52.3 Tg of the C (191.7 Tg CO2 Eq.) in these fuels was stored, while the remaining 34.1  Tg
C (125.1 Tg CO2 Eq.) was emitted.

Table 3-19: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2 Eq.)
Year
Potential Emissions
C Stored
Emissions as a % of Potential
Emissions
1990
310.9
191.31
38%
119.6
2005
387.2
243.1
37%
144.1
2006
381.6
237.8
38%
143.8
2007
367.0
232.1
37%
134.9
2008
341.7
203.1
41%
138.6
2009
310.6
186.9
40%
123.7
2010
316.9
191.7
39%
125.1
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 (2011) (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 3-20
and Table 3-21 have been adjusted to subtract non-energy uses that are included in the source categories of the
Industrial Processes chapter.98  Consumption values were also adjusted to subtract net 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  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.

Table 3-20:  Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)

  Year                        1990         2005    2006     2007      2008     2009     2010
  Industry                  4,197.8       5,309.5   5,181.3    5,012.3   4,626.9   4,335.1   4,453.5
9% These source categories include Iron and Steel Production, Lead Production, Zinc Production, Ammonia Manufacture, Carbon
Black Manufacture (included in Petrochemical Production), Litanium Dioxide Production, Ferroalloy Production, Silicon
Carbide Production, and Aluminum Production.


                                                                                            Energy   3-31

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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
+
8.2

263.7B
1,170.2
1,168.7
186.3
84.9
326.2 1
662. ll
21.3I
27.2
100.9|
7.0
33.3
137.8B
176.0
176.0B
86.7
•
86.0
4,460.5
80.5
11.9

390.1
1,323.2
1,667.9
160.2
105.2
680.5
500.4
67.7
105.2
61.0
11.7
31.4
112.8
151.3
151.3
121.9
4.6
117.3
5,582.8
62.9
11.9

228.3
1,261.2
1,754.8
156.1
74.3
618.3
573.6
57.2
134.2
68.9
17.5
26.1
136.0
147.4
147.4
133.4
6.2
127.2
5,462.1
2.3
11.9

223.0
1,197.0
1,703.3
161.2
91.6
542.5
669.1
44.2
117.8
75.4
17.5
21.9
133.5
152.2
152.2
108.4
5.9
102.5
5,272.9
29.2
11.9

227.3
1,012.0
1,609.2
149.6
64.9
467.2
599.1
47.3
147.4
83.2
17.5
19.1
142.0
141.3
141.3
126.7
2.7
124.1
4,895.0
6.4
11.9

220.5
873.1
1,702.6
134.5
70.1
451.3
393.0
133.9
112.1
44.3
17.5
12.2
151.8
127.1
127.1
56.3
1.0
55.2
4,518.4
64.9
10.3

222.8
877.8
1,817.3
149.5
67.8
472.7
404.9
147.2
1.1
25.6
17.5
15.4
158.8
141.2
141.2
56.3
1.0
55.2
4,651.0
Table 3-21:  2010 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions
Adjusted Carbon
Non-Energy Content Potential Carbon Carbon Carbon
Use3 Coefficient Carbon Storage Stored Emissions Emissions
Sector/Fuel Type (TBtu) (Tg C/QBtu) (Tg C) Factor (Tg C) (Tg C) (Tg CO2 Eq.)
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
4,453.5
64.9
10.3

222.8
877.8
1,817.3
149.5
67.8
472.7
404.9
147.2
1.1
25.6
17.5
15.4
158.8
141.2
141.2
56.3
1.0

55.2
4,651.0
-
25.61
25.82

14.47
20.55
17.06
20.20
19.10
18.55
20.17
17.51
27.85
19.74
20.17
19.80
20.31
-
20.20
-
20.20

20.00

82.4
1.7
0.3

3.2
18.0
31.0
3.0
1.3
8.8
8.2
2.6
+
0.5
0.4
0.3
3.2
2.9
2.9
1.1
+

1.1
86.4
-
0.10
0.59

0.59
1.00
0.59
0.09
0.59
0.59
0.59
0.59
0.30
0.59
0.50
0.58
+
-
0.09
-
0.09

0.10

51.9
0.2
0.2

1.9
18.0
18.4
0.3
0.8
5.2
4.9
1.5
+
0.3
0.2
0.2
+
0.3
0.3
0.1
+

0.1
52.3
30.5
1.5
0.1

1.3
0.1
12.6
2.7
0.5
3.6
3.3
1.0
+
0.2
0.2
0.1
3.2
2.6
2.6
1.0
+

1.0
34.1
111.9
5.5
0.4

4.8
0.3
46.1
10.1
1.9
13.1
12.2
3.8
0.1
0.8
0.6
0.5
11.8
9.5
9.5
3.7
0.1

3.6
125.1
  + Does not exceed 0.05 Tg
  - Not applicable.
  a To avoid double counting, net exports have been deducted.
  Note: Totals may not sum due to independent rounding.

Lastly, emissions were estimated by subtracting the C stored from the potential emissions (see Table 3-19). More
detail on the methodology for calculating storage and emissions from each of these sources is provided in Annex
3-32   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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2.3.

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 energy recovery, Toxics Release
Inventory (TRI) releases, hazardous waste incineration, and volatile organic compound, solvent, and non-
combustion CO emissions. 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
2001), National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data (EPA 2010), Toxics Release
Inventory, 1998 (2000b), Biennial Reporting System (EPA 2004, 2009),  and pesticide sales and use estimates (EPA
1998, 1999, 2002, 2004, 2011); the  El A Manufacturer's Energy Consumption Survey (MECS) (EIA 1994, 1997,
2001, 2005, 2010); the National Petrochemical & Refiners Association (NPRA 2002); the U.S. Bureau of the
Census (1999, 2004, 2009); Bank of Canada (2011); Financial Planning  Association (2006); INEGI (2006); the
United States International Trade Commission (2011); Gosselin, Smith,  and Hodge (1984); the Rubber
Manufacturers' Association (RMA  2009a,b); the International Institute of Synthetic Rubber Products (IISRP 2000,
2003); the Fiber Economics Bureau (FEE 2011); and the American Chemistry Council (ACC 2003-2010, 2011).
Specific data sources are listed in full detail in Annex 2.3.

Uncertainty and Time-Series Consistency

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 Stochastic Simulation technique), provides for the specification of probability
density functions for key variables within a computational structure that mirrors the calculation of the inventory
estimate. The results presented below provide the 95 percent confidence interval, the range of values within which
emissions are likely to fall, for this source category.

As noted above, the non-energy use analysis is based on U.S.-specific storage factors for (1) feedstock materials
(natural gas, LPG, pentanes plus, naphthas, other oils, still gas,  special naphthas, and other industrial coal), (2)
asphalt, (3) lubricants, and (4) waxes. For the remaining fuel types (the  "other" category in Table 3-20 and Table
3-21), the storage factors were taken directly from the IPCC Guidelines for National Greenhouse Gas Inventories,
where available, and otherwise assumptions were made based on the potential fate of carbon in the respective NEU
products.  To characterize uncertainty, five separate analyses were  conducted, corresponding to each of the five
categories. In all cases, statistical analyses or expert judgments of uncertainty were not available directly from the
information sources for all the activity variables; thus, uncertainty estimates were determined using assumptions
based on source category knowledge.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-22 (emissions) and Table 3-23
(storage factors). Carbon emitted from non-energy uses of fossil fuels in 2010 was estimated to be between 103.8
and 154.0 Tg CO2 Eq. at a 95 percent confidence level.  This indicates a range of 17 percent below to 23 percent
above the 2010 emission estimate of 125.1 Tg CO2 Eq.  The uncertainty in the emission estimates is a function of
uncertainty in both the quantity of fuel used for non-energy purposes and the storage factor.

Table 3-22:  Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses of Fossil Fuels
(Tg CO2 Eq. and Percent)
Source
2010 Emission
Estimate
Gas (Tg CO2 Eq.)
Uncertainty Range Relative to
(Tg C02 Eq.)
Emission Estimate3
(%)

Lower Bound Upper Bound Lower Bound Upper Bound
Feedstocks
Asphalt
Lubricants
Waxes
Other
Total
CO2
C02
C02
CO2
C02
C02
83.1
0.3
19.6
0.5
21.7
125.1
65.2
0.1
16.2
0.3
13.9
103.8
114.0
0.6
22.8
0.8
24.5
154.0
-22%
-58%
-18%
-28%
-36%
-17%
37%
117%
16%
63%
13%
23%
    a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
    NA (Not Applicable)
                                                                                            Energy   3-33

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Table 3-23:  Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
(Percent)
Source

Feedstocks
Asphalt
Lubricants
Waxes
Other
2010 Storage
Gas Factor

CO2
C02
CO2
C02
CO2

59%
99.6%
9%
58%
16%
Uncertainty Range Relative to Emission Estimate3
(%) (%, Relative)
Lower
Bound
54%
99%
4%
49%
10%
Upper
Bound
61%
100%
17%
71%
44%
Lower
Bound
-10%
-1%
-59%
-15%
-39%
Upper
Bound
3%
0%
90%
23%
179%
    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).

In Table 3-23, 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.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more  detail in the Methodology section,
above.

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  2011 as well as their trends across
the time series.

Petrochemical input data reported by EIA will continue to be investigated in an attempt to address an input/output
discrepancy in the NEU model. Since 2001, the C accounted for in the feedstocks C balance outputs (i.e., storage
plus emissions) exceeds C inputs. Prior to 2001, the C balance inputs exceed outputs. EPA has reduced a portion of
this discrepancy (see Recalculations Discussion below) and has developed two strategies to address the remaining
portion (see Planned Improvements below).

Recalculations  Discussion

Relative to the previous Inventory, emissions from non-energy uses  of fossil fuels decreased by an average of 1.2 Tg
CO2 Eq. (0.7 percent) across the entire time series. Two competing changes contributed  to these recalculations.  The
3-34   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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larger of the two changes was a decrease in emissions caused by a change in petrochemical input data reported by
the Energy Information Administration in its Monthly Energy Review. In particular, a decline in EIA's estimate of
petroleum coke consumed for non-energy purposes across the time series explains the majority of the decrease. The
smaller of the two changes was an increase in emissions caused by EIA's revision of its methodology for calculating
LPG consumed for non-energy uses in consultation with EPA. These estimates had previously been based on the
assumption that the portion of LPG used for NEU remained constant at its 2004 level for the rest of the time series.
For this year's Inventory, EIA instead retrieved data describing the portion of LPG in NEU from Petroleum Supply
Annual for the entire 1990-2010 time series and revised the previous assumption accordingly. Because 2004 was an
uncharacteristically low year for non-energy consumption of LPG, this revision resulted in an overall increase in
estimates of LPG consumed for NEU and thus an increase in estimated emissions. Combined, the net effect of these
two changes was to decrease emission estimates across the time series slightly.

The revision to LPG calculations mentioned above also significantly reduced the input/output discrepancy in the
NEU model.  Specifically, this discrepancy was reduced by an average of 43% between 2000 and 2010, the years in
which the discrepancy had previously been the largest.

Planned Improvements

There are several improvements planned for the future:

•   More accurate accounting of C in petrochemical feedstocks.  EPA has worked with EIA to determine the cause
    of an input/output discrepancy in the carbon mass balance contained within the NEU model. In the future, EPA
    will continue to pursue two strategies to reduce or eliminate this discrepancy.  First, EPA will improve its
    accounting of C in imports and exports. EPA will examine its import/export adjustment methodology to ensure
    that net exports of intermediaries such as ethylene and propylene are fully accounted for. Second, EPA will
    reconsider its use of top-down C input calculation in estimating emissions. It will consider alternative
    approaches that rely more substantially on the bottom-up  C output calculation instead.

•   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).

•   Reviewing the trends in fossil fuel consumption for non-energy uses. Annual consumption for several fuel types
    is highly variable across the time series, including industrial coking coal and other petroleum (miscellaneous
    products). EPA plans to better understand these trends to  identify any mischaracterized or misreported fuel
    consumption for non-energy uses.

•   EPA recently researched updating the average carbon content of solvents, since the entire time series depends
    on one year's worth of solvent composition data. Unfortunately, the data on C emissions from solvents that
    were readily available do not  provide composition data for all categories of solvent emissions and also have
    conflicting definitions for volatile organic compounds, the source of emissive carbon in solvents. EPA plans to
    identify additional sources of solvents data in order to update the C content assumptions.

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
or deferring to more updated default storage factors from IPCC where available.

Finally improvements to this category will involve analysis of the data reported under EPA's GHGRP. In examining
data from EPA's GHGRP that would be useful to improve the emission estimates for the carbon emitted from non-
energy uses of fossil fuels category, particular attention will be made to ensure time series consistency, as the
facility-level reporting data from EPA's GHGRP are not available for all Inventory years as reported in this
inventory. In implementing improvements and integration of data from EPA's GHGRP, the latest guidance from the
                                                                                           Energy   3-35

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IPCC on the use of facility-level data in national inventories will be relied upon."

3.3.    Incineration of Waste (IPCC Source Category 1A1a)

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 2000, Goldstein
and Matdes 2001, Kaufman et al. 2004, Simmons et al. 2006, van Haaren et al. 2010). 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 or industrial 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. Estimates on emissions from  hazardous waste
incineration can be found in Annex 2.3 and are accounted for as part of the C mass balance for non-energy uses of
fossil  fuels.

Approximately 26.5 million metric tons of MSW was incinerated in the United States in 2010 (EPA 201 la). CO2
emissions from incineration of waste rose 51 percent since 1990, to an estimated 12.1  Tg CO2 Eq. (12,054 Gg) in
2010, as the volume of tires and other fossil  C-containing materials in waste increased (see Table 3-24 and Table
3-25). Waste incineration is also a source of N2O and CH4 emissions (De Soete 1993;  IPCC 2006). N2O emissions
from the incineration of waste were estimated to be 0.4 Tg CO2 Eq. (1 Gg N2O) in 2010, and have not changed
significantly since 1990. CH4 emissions from the incineration of waste were estimated to be less than 0.05 Tg CO2
Eq. (less than 0.5 Gg CH4) in 2010, and have not changed significantly since 1990.

Table 3-24: CO2 and N2O Emissions from the Incineration of Waste (Tg CO2 Eq.)
Gas/Waste Product
CO2
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in
MSW
Synthetic Fibers
N2O
CH,
Total
1990
8.0
5.6
1
0.4 1

0.9 1
0.8 1
05
+
8.5
2005
12.5
6.9
1.6
2.0

0.8
1.2
0.4
+
12.9
2006
12.5
6.7
1.7
2.1

0.8
1.2
0.4
+
12.9
2007
12.7
6.7
1.8
2.3

0.8
1.2
0.4
+
13.1
2008
11.9
6.1
1.7
2.1

0.8
1.2
0.4
+
12.3
2009
11.7
6.2
1.6
1.9

0.8
1.2
0.4
+
12.1
2010
12.1
6.6
1.6
1.9

0.8
1.2
0.4
+
12.4
   + Does not exceed 0.05 Tg CO2 Eq.


Table 3-25: CO2 and N2O Emissions from the Incineration of Waste (Gg)

   Gas/Waste Product	1990	2005    2006    2007    2008    2009     2010
   CO2                         7,989      12,468   12,531   12,727   11,888   11,703    12,054
   Plastics                      5,588  |     6,919    6,722    6,660    6,148    6,233     6,573
99
  See
3-36  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N2O
CH,
308
385
872
838
2
+





1,599
1,958
781
1,211
1
+
1,712
2,113
775
1,208
1
+
1,823
2,268
791
1,185
1
+
1,693
2,085
770
1,192
1
+
1,560
1,903
782
1,226
1
+
1,560
1,903
787
1,230
1
+
+ Does not exceed 0.5 Gg.
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 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 amount of scrap tires
used for fuel and the synthetic rubber and carbon black content of 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 specific materials discarded as municipal solid waste (i.e., the quantity generated minus the quantity
recycled) was taken from.Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts and
Figures (EPA 2000 through 2003, 2005 through 201 Ib) and detailed unpublished backup data for some years not
shown in the reports (Schneider 2007). The proportion of total waste discarded that is incinerated was derived from
data in BioCycle's "State of Garbage in America" (van Haaren et al. 2010). The most recent data provides the
proportion of waste incinerated for 2008, so the corresponding proportion in 2010 is assumed to be equal to the
proportion in 2008. For synthetic rubber and carbon black in scrap tires, information was obtained from U.S. Scrap
Tire Management Summary for 2005 through 2009 data (RMA 2011). For 2010, synthetic rubber mass in tires is
assumed to be equal to that in 2009 due to a lack of more recently available data.

Average C contents for the "Other" plastics category and synthetic rubber in municipal solid wastes were calculated
from 1998 and 2002 production statistics: carbon content for 1990 through 1998 is based on the 1998 value; content
for 1999 through 2001 is the average of 1998 and 2002 values; and content for 2002 to  date is based on the 2002
value. Carbon content for synthetic fibers was calculated from 1999 production statistics. Information about scrap
tire composition was taken from the Rubber Manufacturers' Association internet site (RMA 2012a).

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 2006).

Incineration of waste, including MSW, also results in emissions of N2O and CH4. These emissions were calculated
as a function of the total estimated mass of waste incinerated and an emission factor.  As noted above, N2O and CH4
emissions are a function of total waste incinerated in each year; for 1990 through 2008, these data were derived from
the information published in BioCycle (van Haaren et al. 2010). Data on total waste incinerated was not available
for 2009 or 2010, so this value was assumed to equal the most recent value available  (2008).

Table 3-26 provides data on municipal solid waste discarded and percentage combusted for the total waste stream.
According to Covanta Energy (Bahor 2009) and confirmed by additional research based on ISWA (ERC 2009), all
municipal solid waste combustors in the United States are continuously fed stoker units. The emission factors of
N2O and CH4 emissions per quantity of municipal solid waste combusted are default  emission factors for this
technology type and were taken from the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC
2006).
                                                                                           Energy    3-37

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Table 3-26: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted.
   Year
Waste Discarded
Waste Incinerated
 Incinerated (% of
	Discards)
   1990
  235,733,657
   30,632,057
       13.0
2005
2006
2007
2008
2009
2010
259,559,787
267,526,493
268,279,240
268,541,088
268,541,088a
268,541,088a
25,973,520
25,853,401
24,788,539
23,674,017
23,674,017 a
23,674,017 a
10.0
9.7
9.2
8.8
8.8a
8.8a
   a Assumed equal to 2008 value.
   Source: van Haaren et al. (2010).
Uncertainty and Time-Series Consistency

A Tier 2 Monte Carlo analysis was performed to determine the level of uncertainty surrounding the estimates of CO2
emissions and N2O emissions from the incineration of waste (given the very low emissions for CH4, no uncertainty
estimate was derived). 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 synthetk^iogenic 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 3-27. Waste incineration CO2
emissions in 2010 were estimated to be between 9.6and 14.9 Tg CO2 Eq. at a 95 percent confidence level. This
indicates a range of 21 percent below to 24 percent above the 2010 emission estimate of 12.1 Tg CO2 Eq. Also at a
95 percent confidence level, waste incineration N2O emissions in 2010 were estimated to be between 0.2 and 1.5 Tg
CO2 Eq. This indicates a range of 50 percent below to 320 percent above the 2010 emission estimate of 0.4 Tg CO2
Eq.

Table 3-27: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from the Incineration of Waste (Tg CO2 Eq.
and Percent)
2010
Emission
Estimate
Source Gas (Tg CO2 Eq.)

Incineration of Waste CO2 12.1
Incineration of Waste N2O 0.4
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower
Bound
9.6
0.2
Upper
Bound
14.9
1.5
Lower
Bound
-21%
-50%
Upper
Bound
+24%
+320%
   a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
3-38   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

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 calculations on incineration of waste.

Recalculations Discussion

Several changes were made to input variables compared to the previous Inventory, resulting in an overall decrease in
the total emissions from the incineration of waste. The emissions from carbon black and rubber in scrap tires in 2008
and 2009 were updated based on data obtained from the Rubber Manufacturers' Association U.S. Scrap Tire
Management Summary for 2005 through 2009 (RMA 2012b), because the report releases data every other year. The
2009 data was available in this report, so 2008 data was updated using linear interpolation from the 2007 and 2009
data. The change decreased the 2008 and 2009 emissions by 2 percent and 5 percent, respectively, relative to the
previous report.

Planned  Improvements

The availability of facility-level waste incineration through EPA's GHGRP will be examined to help better
characterize waste incineration operations in the United States. This characterization could include future
improvements as to the operations involved in waste incineration for energy, whether in the  power generation sector
or the industrial sector. Additional examinations will be necessary as, unlike the reporting requirements for this
chapter under the UNFCCC reporting guidelines, 10° some facility-level waste incineration emissions reported under
the GHGRP may also include industrial process emissions. In line with UNFCCC reporting  guidelines, emissions
for waste incineration with energy recovery are included in this chapter, while process emissions are included in the
industrial processes chapter of this report. In examining data from EPA's GHGRP that would be useful to improve
the emission estimates for the waste incineration category, particular attention will also  be made to ensure time
series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all inventory years
as reported in this inventory. Additionally, analyses will focus on ensuring CC>2 emissions from the biomass
component of waste are separated in the facility-level reported data, and on maintaining consistency with national
waste generation and fate statistics currently used to estimate total, national U.S. greenhouse gase emissions. In
implementing improvements and integration of data from EPA's GHGRP, the latest guidance from the IPCC on the
use of facility-level data in national inventories will be relied upon.101
3.4.    Coal Mining (IPCC Source Category 1B1a)
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 CH4
emissions. In 2010, 164 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 CH4 to the
atmosphere in low concentrations.  Additionally, 24 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 2010, 15 coal mines collected CH4 from
degasification systems and utilized this gas, thus reducing emissions to the atmosphere.  Of these mines, 14 coal
mines sold CH4 to the natural gas pipeline and one coal mine used CH4 from its degasification system to heat mine
100 See 
101 See
                                                                                          Energy   3-39

-------
ventilation air on site.  In addition, one of the coal mines that sold gas to pipelines also used CH4 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 CH4 retained in the coal after
mining is released during processing, storage, and transport of the coal.

Total CH4 emissions in 2010 were estimated to be 72.6 Tg CO2 Eq. (3,458 Gg), a decline of 14 percent since 1990
(see Table 3-28 and Table 3-29).  Of this amount, underground mines accounted for 71 percent, surface mines
accounted for 18 percent, and post-mining emissions accounted for 11 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 CH4 recovered and used. Since that time, underground coal production and the
associated CH4 emissions have remained fairly level, while surface coal production and its associated emissions
have generally increased.

Table 3-28: CH4 Emissions from Coal Mining (Tg CO2 Eq.)
Activity
UG Mining
Liberated
Recovered


&Used
Surface Mining
Post-Mining (UG)
Post-Mining (Surface)
Total

1990
62.3
67.9
(5.6)
12.0
7.7
2.0
84.1





2005
34.9
50.2
(15.2)
13.3
6.4
2.2
56.8
2006
34,
50,
(18.!
14,
6,
2,
56.
.9
.2
2007
35,
50,
.7
.9
*) (15.2)
.0
.3
.3
,8
13,
6,
2,
57.
.8
.1
.2
,8
2008
44.9
60.5
(16.3)
14.3
6.1
2.3
66.9
2009
49.6
66.1
(16.6)
12.9
5.6
2.1
70.1
2010
51.6
71.4
(19.6)
13.1
5.7
2.1
72.6
   Note: Totals may not sum due to independent rounding. Parentheses indicate negative values.
Table 3-29:  CH4 Emissions from Coal Mining (Gg)
Activity
UG Mining
Liberated
Recovered & Used
Surface Mining
Post-Mining (UG)
Post-Mining (Surface)
Total
1990
2,968
3,234
(265.9)
573.6
368.3
93.2
4,003
2005
1,663
2,389
(726.0)
633.1
305.9
102.9
2,705
2006
1,693
2,588
(894.7)
668.0
298.5
108.5
2,768
2007
1,698
2,422
(723.7)
658.9
289.6
107.1
2,754
2008
2,102
2,881
(778.5)
680.5
292.0
110.6
3,186
2009
2,360
3,149
(789.2)
614.2
266.7
99.8
3,340
2010
2,459
3,402
(942.9)
626.2
270.2
101.8
3,458
    Note: Totals may not sum due to independent rounding. Parentheses indicate negative values.
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.

Underground mines.  Total CH4 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
detectable102 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.
102 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.
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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 CH4 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 CH4 recovered by degasification systems and then used (i.e., not vented) was estimated.  In
2010, 14 active coal mines sold recovered CH4 into the local gas pipeline networks and one coal mine used
recovered CH4 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. Data was not available for CDX wells for 2010, thus underground emissions avoided were estimated for two
mines. Emissions avoided were estimated using a 10-year average for the Pinnacle Mine and a 2-year average for
the Road Fork 51 Mine.
Surface Mines and Post-Mining Emissions.  Surface mining and post-mining CH4 emissions were estimated by
multiplying basin-specific coal production, obtained from the Energy Information Administration's Annual Coal
Report (see Table 3-30) (EIA 2011), 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 CH4 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 3-30:  Coal Production (Thousand Metric Tons)
   Year   Underground    Surface	Total
   1990      384,244       546,808     931,052
2005
2006
2007
2008
2009
2010
334,398
325,697
319,139
323,932
301,241
305,862
691,448
728,447
720,023
737,832
671,475
693,732
1,025,846
1,054,144
1,039,162
1,061,764
972,716
999,594
Uncertainty and Time-Series Consistency

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 CH4 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 3-31. Coal mining CH4 emissions in 2009 were
                                                                                          Energy   3-41

-------
estimated to be between 63.0 and 84.4 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 13.2
percent below to 16.3 percent above the 2010 emission estimate of 72.6 Tg CO2 Eq.
Table 3-31: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
Percent)
Source
Gas
2010 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Coal Mining
CH4
72.6
63.0 84.4 -13.2% +16.3%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations Discussion

For the current inventory, updated mine maps were received for the Oak Grove and Jim Walter Resources (JWR)
mines, which provided a more accurate depiction of the dates that certain pre-drainage CMM wells were mined
through. As a result, the mined-through dates were adjusted for some wells based on updated mine plans, and
underground emissions avoided values changed slightly from 2005 to 2009.

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

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
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 CH4 that may find its way to surface structures through
overburden fractures.  As work stops within the  mines, the CH4 liberation decreases but it does not stop completely.
Following an initial decline, abandoned mines can liberate CH4 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
CH4 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;

•   CH4 flow capacity of the mine;

•   Mine flooding;

•   Presence of vent holes; and

•   Mine seals.

Gross abandoned mine CH4 emissions ranged from 6.0 to 9.1 Tg CO2 Eq. from 1990 through 2010, 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 2010, with only five closures in 2010. By 2010, gross abandoned mine emissions
decreased slightly to 7.6 Tg CO2 Eq. (see Table  3-32 and Table 3-33). Gross emissions are reduced by CH4


3-42  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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recovered and used at 38 mines, resulting in net emissions in 2010 of 5.0 Tg CO2 Eq.

Table 3-32:  CH4 Emissions from Abandoned Coal Mines (Tg CO2 Eq.)

   Activity                    1990        2005     2006    2007     2008     2009    2010
Abandoned Underground
Mines
Recovered & Used
Total
6.0 1 7.0
+ 1.5
6.0 5.5
7.6
2.2
5.5
8.9
3.6
5.3
9.0
3.7
5.3
8.1
3.0
5.1
7.6
2.7
5.0
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.


Table 3-33:  CH4 Emissions from Abandoned Coal Mines (Gg)
   Activity                    1990        2005     2006     2007    2008     2009    2010
Abandoned Underground
Mines
Recovered & Used
Total

288 1
+
288

334
70
264

364
103
261

425
172
254

429
177
253

388
143
244

364
126
237
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.


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 that depends on the interplay of a variety of natural physical 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 also 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 CH4 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 productivity index (PI) term is essentially
constant at the pressures of interest (atmospheric to 30 psia).  A rate-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:

                                            q =

where,
    q   = Gas rate at time t in mmcf/d
    q;   = Initial gas rate at time zero (t0) in million cubic feet per day mmcfd)
    b   = The hyperbolic exponent, dimensionless
    Di  = 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
                                                                                            Energy    3-43

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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 mcf/d
    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 * (i - (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 CH4 emissions. This same
relationship is assumed for abandoned mines.  It was determined that 469 abandoned mines closing after 1972
produced emissions  greater than 100 mcfd when active.  Further,  the status of 273 of the  469 mines (or 58 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 42 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).

Table 3-34:  Number of gassy abandoned mines occurring in U.S. basins grouped by class according to post-
abandonment state
Basin
Central Appl.
Illinois
Northern Appl.
Warrior Basin
Western Basins
Total
Sealed Vented Flooded Total Known Unknown Total Mines
25
30
42
0
27
124
25
3
22
0
3
53
48
14
16
16
2
96
98
47
80
16
32
273
129
26
36
0
10
196
227
73
116
16
42
474
Inputs to the decline equation require the average emission rate and the date of abandonment. Generally this data is
available for mines abandoned after 1972; however, such data are largely unknown for mines closed before  1972.
Information that is readily available such as coal production by state and county are helpful, but do not provide
enough data to directly employ the methodology used to calculate emissions from mines abandoned after 1971. It 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
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States, representing 78 percent of the emissions. State-specific, initial emission rates were used based on average
coal mine CH4 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.  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. CH4
degasification amounts were added to the quantity of CH4 ventilated for the total CH4 liberation rate for seventeen
mines that closed between  1992 and 2010. 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 2010, 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 CH4 recovery projects during that time.

Uncertainty and Time-Series Consistency

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. Once the low, mid, and high values are selected, they are applied to  a probability density function.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-35. Abandoned coal mines
CH4 emissions in 2010 were estimated to be between 3.88 and 6.05 Tg CO2 Eq. at a 95 percent confidence level.
This indicates a range of 22 percent below to 21 percent above the 2010 emission estimate of 4.98 TgCO2Eq. One
of the reasons for the relatively narrow range is that mine-specific data is used in the methodology.  The largest
degree of uncertainty is associated with the unknown status mines (which account for 42 percent of the mines), with
a ±51 percent uncertainty.

Table 3-35:  Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
Mines (Tg CO2 Eq. and Percent)
2010 Emission Uncertainty Range Relative to Emission Estimate3
Estimate
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Abandoned Underground Coal Mines CH4
4.98 3.88 6.05 -22% +21%
   1 Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.


Recalculations Discussion

After last year's submission of the 1990-2009 Inventory, a small error in the calculations spreadsheet for Abandoned


                                                                                           Energy   3-45

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Underground Coal Mines was discovered. This error was fixed in preparation of this year's Inventory and as a result
some of the emissions estimates for this source category in past years differ from last year's report. No new data or
methodologies were used to recalculate these values.
3.6.    Natural Gas Systems (IPCC Source Category 1B2b)

The U.S. natural gas system encompasses hundreds of thousands of wells, hundreds of processing facilities, and
over a million miles of transmission and distribution pipelines.  Overall, natural gas systems emitted 215.4 Tg CO2
Eq. (10,259 Gg) of CH4 in 2010, a 14 percent increase over 1990 emissions (see Table 3-36 and Table 3-37) and
32.3 Tg CO2 Eq. (32,301 Gg) of non-combustion CO2 in 2010, a 14 percent decrease over 1990 emissions (see
Table 3-38 and Table 3-39). Improvements in management practices and technology, along with the replacement of
older equipment, have helped to stabilize emissions. Methane emissions increased since 2008 due to an increase in
production and production wells.

CH4 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. Emissions from pneumatic devices, gas wells with liquids unloading, and gas well completions and re-
completions (workovers) with and without hydraulic fracturing  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 58 percent of CH4 emissions and about 34 percent of non-combustion CO2 emissions
from natural gas systems in 2010.

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 8 percent of CH4 emissions and approximately 66 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 power plants 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 CH4 emissions
from these compressor stations and from metering and regulating stations account for the majority of the emissions
from this stage.  Pneumatic devices and engine uncombusted exhaust are also sources of CH4 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. CH4 emissions from the transmission and storage sector account for approximately 20 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 1,202,000 miles of distribution mains in 2010, an increase of approximately 258,000 miles
since 1990 (OPS 2010b).  Distribution system emissions, which account for approximately 13 percent of CH4


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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 2010 were
15 percent lower than 1990 levels.

Table 3-36 and Table 3-37 show total CH4 emissions for the four major stages of natural gas systems, in Tg CO2 Eq
(Table 3-36) and Gg (Table 3-37). Table 3-38 gives more information on how the numbers in 3-36 were calculated.
Table 3-38 shows the calculated CH4 release (i.e. potential emissions before any controls are applied) from each
stage, and the amount of that CH4 that is estimated to have been flared, captured, or otherwise controlled, and
therefore not emitted to the atmosphere. Subtracting the CH4 that is controlled from the quantity of CH4 that was
calculated to be released results in the emissions totals.

Table 3-36: CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.)*
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
89.0
18.0 1
49.2 1
33.4
189.6
2005
105.2
14.6
41.4
29.3
190.5
2006
133.8
14.8
40.9
28.3
217.7
2007
117.8
15.5
42.5
29.4
205.3
2008
123.2
16.2
43.3
29.9
212.7
2009
129.4
17.8
44.7
29.1
220.9
2010
126.0
17.1
43.8
28.5
215.4
   These values represent CH4 emitted to the atmosphere.  CH4 that is captured (and not emitted to the atmosphere) has
   been calculated and removed from emission totals.
   Note:  Totals may not sum due to independent rounding.


Table 3-37: CH4Emissions from Natural Gas Systems (Gg)*
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
4,240 1
855
2,343
1,591
9,029
2005
5,011
694
1,971
1,395
9,071
2006
6,370
704
1,949
1,346
10,369
2007
5,611
737
2,024
1,402
9,774
2008
5,869
770
2,062
1,426
10,127
2009
6,161
837
2,127
1,384
10,519
2010
6,002
812
2,086
1,359
10,259
   * These values represent CH4 emitted to the atmosphere. CH4 that is captured (and not emitted to the atmosphere) has
   been calculated and removed from emission totals.
   Note: Totals may not sum due to independent rounding.


Table 3-38: Calculated Potential CH4 and Captured/Combusted CH4 from Natural Gas Systems (Tg CO2 Eq.)


Calculated PotentialJ
Field Production
Processing
Transmission and
Distribution
Storage
Captured/Combusted
Field Production
Processing
Transmission and
Distribution
Net Emissions
Field Production
Processing
Transmission and
Distribution
Storage

Storage
1990
189.4
88.9
17.9
49.2
33.4
(0.2)*
+
+
189.6
89.0
18.0
49.2
33.4







2005
240.2
141.0
17.3
51.9
30.0
49.7
35.8
2.7
10.5
0.7
190.5
105.2
14.6
41.4
29.3
2006
295.7
197.8
17.7
51.0
29.3
77.9
64.0
2.9
10.1
1.0
217.7
133.8
14.8
40.9
28.3
2007
274.2
173.7
18.2
52.0
30.2
68.9
55.9
2.8
9.5
0.8
205.3
117.8
15.5
42.5
29.4
2008
293.3
191.2
19.0
52.6
30.5
80.6
67.9
2.8
9.2
0.6
212.7
123.2
16.2
43.3
29.9
2009
288.5
186.9
19.3
52.5
29.9
67.6
57.5
1.5
7.8
0.9
220.9
129.4
17.8
44.7
29.1
2010
288.6
185.9
20.1
53.0
29.6
73.1
59.8
3.0
9.2
1.1
215.4
126.0
17.1
43.8
28.5
Note:  Totals may not sum due to independent rounding.
*Thebase year of the factors used is 1992; for reductions reported between 1990 and 1992, it is assumed that reductions
 are already taken into account in the Calculated Potential values and the reduction is added back into the estimate for the
                                                                                            Energy   3-47

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 appropriate year(s). For 1990, this table shows the value added back into the estimate.
+ Emissions are less than 0.1 Tg CO2 Eq.
J In this context, "potential" means the total emissions calculated before voluntary reductions/regulatory controls are
applied.


Table 3-39: Non-combustion CO2 Emissions from Natural Gas Systems (Tg CO2 Eq.)
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
9.7
27.8 1
0.1 1
+ H
37.6
2005
8.0
21.7
0.1
+
29.9
2006
9.4
21.2
0.1
+
30.8
2007
9.7
21.2
0.1
+
31.0
2008
11.3
21.4
0.1
+
32.8
2009
10.9
21.2
0.1
+
32.2
2010
10.8
21.3
0.1
+
32.3
   Note: Totals may not sum due to independent rounding.
   + Emissions are less than 0.1 Tg CO2 Eq.


Table 3-40: Non-combustion CO2 Emissions from Natural Gas Systems (Gg)
Stage
Field Production
Processing
Transmission and Storage
Distribution
Total
1990
9,703
27,763
62
46
37,574





2005
8,049
21,746
64
41
29,901
2006
9,437
21,214
63
40
30,754
2007
9,745
21,199
64
41
31,049
2008
11,335
21,385
65
42
32,826
2009
10,875
21,188
65
41
32,169
2010
10,848
21,346
65
41
32,301
   Note: Totals may not sum due to independent rounding.


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 and EPA (EPA/GRI1996).  The EPA/GRI study developed
over 80 CH4 emission factors to characterize emissions from the various components within the operating stages of
the U.S. natural gas system. The same factors were used to estimate both CH4 and non-combustion CO2 emissions.
CO2 factors were developed using the CH4 emission factors and average CO2 and CH4 content of gas.  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 factors and activity data
drivers from the study, 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 data
drivers was developed that can be used to update activity data, where such data is not directly available.  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.

Although the inventory primarily uses EPA/GRI emission factors, significant improvements were made to the
emissions estimates for three sources with last year's inventory: gas wells with liquids unloading, condensate
storage tanks and centrifugal compressors. In addition, data for two sources not included in the EPA/GRI study -
gas well completions and gas well workovers (re-completions) with hydraulic fracturing- were added.  In the case of
gas wells with liquids unloading, the methodology was revised to use a large sample of well and reservoir
characteristics from the HPDI database (HPDI2009) along with an engineering statics equation (EPA 2006a) to
estimate the volume of natural gas necessary to expel a liquid column choking the well production. See Annex 3.4
for more information on the methodology for gas wells with liquids unloading. For condensate storage tanks,
sample E&P Tank runs were used as was the case in previous inventories; however, the factor was improved by
using a large sample distribution of condensate production by gravity from the HPDI database (HPDI 2009) to
weigh the sample simulation flashing emissions rather than assuming a uniform distribution of condensate gravities.
Additionally, TERC (TERC 2009) data representing two regions was used in the emission factors for those two
regions to estimate the effects of separator dump valves malfunctioning and allowing natural gas to vent through the
downstream condensate storage tanks. The EPA/GRI emission factor for centrifugal compressors (used in earlier


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inventories) was derived from sampled emissions at the seal face of wet seal compressors. A World Gas Conference
publication (WGC 2009) on the seal oil degassing vents was used to update this factor and to also account for the
emergence of dry seal centrifugal compressors (EPA 2006b), which eliminates seal oil degassing vents and reduces
overall emissions. For more information on this factor, see Annex 3.4. Previous Inventories did not differentiate
between wells without hydraulic fracturing and with hydraulic fracturing for completions and workovers.  Gas well
completions and workovers with hydraulic fracturing were not common at the time the EPA/GPJ survey was
conducted. Since then, these activities have become more prevalent and emissions data on this activity has become
available through a number of sources. Using this data, an emission factor was developed for gas well completions
and workovers with hydraulic fracturing. See Annex 3.4 for more detailed information on the methodology and data
used to calculate CH4 and non-combustion CO2 emissions from natural gas systems.

The emissions factors described above represent expected emissions from an activity, and do not take into account
use of technologies that reduce emissions.  To take into account use of such technologies, data is collected on
regulatory and voluntary reductions. For more information on these reductions, please see the Annex. The numbers
presented in tables 3-36 and 3-37 are the CH4 that is emitted to the atmosphere (i.e., net emissions), not potential
emissions without capture or flaring.

Activity data were taken from the following sources: American  Gas Association (AGA 1991-1998); Bureau of
Ocean Energy Management, Regulation and Enforcement (previous Minerals and Management Service) (BOEMRE
2010a-d); Monthly Energy Review (EIA 2010f); Natural Gas Liquids Reserves Report (EIA 2005); Natural Gas
Monthly (EIA 2010b,c,e); the Natural Gas STAR Program annual emissions savings (EPA 2010); Oil and Gas
Journal (OGJ 1997-2010); Office of Pipeline Safety (OPS 2010a-b); Federal Energy Regulatory Commission
(FERC 2010) and other Energy Information Administration publications (EIA 2001, 2004, 2010a,d); World Oil
Magazine (2010a-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 2009) and the Alabama State Oil and Gas Board (Alabama 2010).  Other state well data was taken from:
American Association of Petroleum Geologists (AAPG 2004); Brookhaven College (Brookhaven 2004); Kansas
Geological Survey (Kansas 2010); Montana Board of Oil and Gas Conservation (Montana 2010); Oklahoma
Geological Survey (Oklahoma 2010); Morgan Stanley (Morgan Stanley 2005); Rocky Mountain Production Report
(Lippman 2003); New Mexico Oil Conservation Division (New Mexico 2010, 2005); Texas Railroad Commission
(Texas 20 lOa-d); Utah Division of Oil, Gas and Mining (Utah 2010). Emission factors were taken from EPA/GRI
(1996). GTFs Unconventional Natural Gas and Gas Composition Databases (GTI 2001) were used to adapt the CH4
emission factors into non-combustion related CO2 emission factors and adjust CH4 emission factors from the
EPA/GRI survey. Methane compositions from GTI 2001 are adjusted year to year using gross production by NEMS
for oil and gas supply regions from the EIA. Therefore, emission factors may vary from year to year due to slight
changes in the CH4 composition for each NEMS oil and gas supply module region.  Additional information about
CO2 content in transmission quality natural gas was obtained from numerous U.S. transmission companies to help
further develop the non-combustion CO2 emission factors.

Uncertainty and Time-Series Consistency

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 @RISK model utilizes 1992  (base year) emissions to quantify the uncertainty associated with the emissions
estimates using the top twelve emission sources for the year 2010.

The results presented below provide with 95 percent certainty the range within which emissions from this source
category are likely to fall for the year 2010. 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 3-41.  Natural gas systems CH4 emissions in 2010 were
estimated to be between 174.5 and 280.0 Tg CO2 Eq. at a 95 percent confidence level. Natural gas systems non-
energy CO2 emissions in 2010 were estimated to be between 26.2 and 42.0 Tg CO2 Eq. at 95 percent confidence
level.
                                                                                         Energy   3-49

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Table 3-41: Tier 2 Quantitative Uncertainty Estimates for CH4 and Non-energy CO2 Emissions from Natural Gas
Systems (Tg CO2 Eq. and Percent)
2010 Emission
Estimate
Source Gas (Tg CO2 Eq.)°
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound0 Bound0 Bound0 Bound0
Natural Gas Systems CH4 215.4
Natural Gas Systems'5 CO2 32.3
174.5 280.0 -19% +30%
26.2 42.0 -19% +30%
   a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
   b An uncertainty analysis for the non-energy CO2 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 CO2
   emissions.
   0 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.

QA/QC and Verification  Discussion

The natural gas inventory is continually being reviewed and assessed to determine whether emission factors and
activity factors accurately reflect current industry practice. A QA/QC analysis was performed for data gathering and
input, documentation, and calculation. In addition, through regulations, public webcasts, and the Natural Gas STAR
Program, EPA performs a QA/QC check to determine the assumptions in the Inventory are consistent with current
industry practices. Finally, QA/QC checks are  consistently conducted to minimize human error in the model
calculations.

As a result of the QA/QC checks, two corrections were made in the current Natural Gas Systems estimates. First,
the calculation for the CH4 content was corrected. The CH4 content is adjusted for each year by the gross production
of natural gas in each state as reported by the EIA. In the previous Inventory, the CH4 content was adjusted
incorrectly by including state production totals for which there was no CH4 content data. The current Inventory
correctly makes a minor adjustment to the CH4 content using only state productions for which CH4 content is
available. Second, emission factors for fugitive emissions from gas wells (i.e., equipment leaks from valves,
connectors, and open ended lines on or associated with the wellhead) were corrected. For several NEMS regions
these fugitive emission factors from the 1996 GRI study were missing or inconsistent with the study.

Recalculations  Discussion

EPA has received information and data related to the emissions estimates through the inventory preparation process
and the formal public notice and comment process of the proposed oil and gas new source performance standards
(NSPS) for VOCs.  EPA plans to carefully evaluate this and all other relevant information provided. Subsequently,
all relevant updates will then be incorporated, as applicable, in the next cycle of the  Inventory.  See Planned
Improvements below.  In light of this current review  of information and data, for the current Inventory, emissions
for the natural gas sector were calculated using the same methodologies, emission factors, and sources of activity
data as the 1990-2009 Inventory report.  Additionally, EPA has used the estimates for emissions from completions
and workovers hydraulically fractured wells from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2009 (i.e., maintained the same activity  data and voluntary reductions for hydraulically fractured gas well
completions and existing hydraulically fractured gas  wells), holding constant the 2009 value for the 2010 estimate.
Note that the estimates provided in the public review draft were changed because several values for hydraulically
fractured well completions  had  been updated over the time series.  Removing these updates  resulted in a change of
in total sector CH4 emissions of 0.3 percent over the  time series from the public review draft.

Some of the calculated emissions for the 1990 through 2009 times series have changed  from the previous Inventory
report due to corrections noted above in QA/QC and  Verification Discussion.

Planned  Improvements

EPA is considering a number of potential improvements for the Natural Gas Systems inventory.

For the production sector, EPA  intends to evaluate additional data on emission reductions, particularly those related


3-50  Inventory of U.S. Greenhouse Gas Emissions  and Sinks: 1990-2010

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to gas wells with liquids unloading, and voluntary and regulatory reductions from well completions and, if
appropriate, will incorporate revisions into future inventories.  Evaluation of reductions associated with liquids
unloading will include review of data on controls such as plunger lifts and other artificial lift technologies as
appropriate.  Additionally, accounting for the uncertainty of emission reductions to more accurately provide upper
and lower bounds within the 95 percent confidence interval will be investigated.  EPA also intends to investigate
improvements to its estimates of emissions from hydraulic fracturing, including revisiting the estimates for
workover frequency and the number of well completions.  The current method for determining hydraulically
fractured gas well completion counts relies on data from state websites. Using this method, gas well counts are
limited to those  that are published online and, therefore, the number of wells is  not entirely complete. Subsequently,
an underestimate of the number of gas well completions is expected.

In the storage sector, the emission factors in the Inventory account for flashing emissions from condensate tanks.
Measurement studies and anecdotal evidence suggest that, in some cases, produced gas from the separator will
bypass the liquid dump valve and vent through the storage tank, which is not taken into account in the current
estimates. New data on this source will be reviewed as it becomes available and emissions will be updated, as
appropriate.
Data collected through EPA's Greenhouse Gas Reporting Program (40 CFR Part 98, Mandatory Reporting of
Greenhouse Gases; Final Rule, Subpart W) will be reviewed for potential improvements to the natural gas systems
emission estimates. The rule will  collect actual activity data using improved quantification methods from those used
in several of the studies which form the basis of the Natural Gas Systems emission estimates.  Data collection for
Subpart W began January 1, 2011  with emissions reporting beginning in 2012. These data will be reviewed for
inclusion into a future Inventory to improve the accuracy and reduce the uncertainty of the emission estimates.

As discussed above, EPA has received information and data related to the emissions estimates through the
inventory preparation process and the formal public notice and comment process of the proposed oil and gas new
source performance standards (NSPS) for VOCs. EPA plans to carefully evaluate this and all other relevant
information provided to us. Subsequently, all relevant updates will then be incorporated, as applicable, in the next
cycle of the Inventory.
Finally, EPA is also considering improvements to the documentation of the Natural Gas  Systems source category.
EPA is considering including a table matching each emission factor and activity factor with its source or calculation
methodology. The purpose of this improvement would be to make the calculation methodologies more transparent.
In addition, EPA is considering adding additional tables to Annex 3.4 to  show activity data and emission factors for
previous years.  EPA also plans on revising the emissions tables in Annex 3.4 to show voluntary reductions broken
out for key emission sources.

3.7.    Petroleum Systems (IPCC Source Category 1B2a)
Methane 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 refining
operations but are negligible in transportation operations. Combustion CO2 emissions from fuels 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 CH4 and CO2 emissions from petroleum systems in 2010 were 31.1 Tg
CO2 Eq. (1,478  Gg CH4) and 0.3 Tg CO2 (337 Gg), respectively. Since 1990, CH4 emissions have declined by 11.8
percent, due to industry efforts to reduce emissions and a decline in domestic oil production (see
Table 3-42 and Table 3-43). CO2  emissions have also declined by 14.4 percent since 1990 due to similar reasons
(see Table 3-44  and Table 3-45).
Production Field Operations. Production field operations account for 98.4 percent of total CH4 emissions from
petroleum systems. Vented CH4 from field operations account for approximately 90 percent of the emissions  from
the production sector, uncombusted CH4 emissions (i.e. unburned fuel) account for 6.4 percent, fugitive emissions
are 3.5 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 high bleed
pneumatic devices, oil tanks, natural-gas powered low bleed pneumatic devices, gas engines, deep water offshore
platforms, and chemical injection pumps. These seven sources alone emit about 94 percent of the production field
operations emissions. Offshore platform emissions are a combination of fugitive, vented, and uncombusted fuel


                                                                                          Energy    3-51

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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 oil tanks occur when the CH4 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 of such pumps that use associated gas to drive pneumatic pumps.  The remaining six 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 CH4 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 production field operations, while fugitive and process upsets together account for  less than 1
percent of the emissions. The most dominant sources of vented emissions are oil tanks, high bleed pneumatic
devices, shallow water offshore oil platforms, low bleed pneumatic devices, and chemical injection pumps. These
five sources together account for 98.5 percent of the non-combustion CC>2 emissions from production field
operations, while the remaining 1.5 percent of the 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 0.5 percent of total CH4
emissions from the oil industry. Venting from tanks and marine vessel loading operations accounts for 60.3 percent
of CH4 emissions from crude oil transportation. Fugitive emissions, almost entirely from floating roof tanks, account
for 18.5 percent. The remaining 21 percent is 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 less than 1.5 percent of total CH4
emissions from the oil industry because most of the CH4 in crude oil is removed or escapes before the crude oil is
delivered to the refineries. There is an insignificant amount of CH4 in all refined products. Within  refineries, vented
emissions account for about 81 percent of the emissions, while fugitive and combustion emissions account for
approximately nine and nine and half percent respectively. Refinery system blowdowns for maintenance and the
process of asphalt blowing—with air, to harden the asphalt—are the primary venting contributors.  Most of the
fugitive CH4 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.

Asphalt blowing from crude oil refining accounts for 4.5 percent of the total non-combustion CO2 emissions in
petroleum systems.

Table 3-42: CH4 Emissions from Petroleum Systems  (Tg CO2 Eq.)
Activity
Production Field Operations
Pneumatic device venting
Tank venting
Combustion & process upsets
Misc. venting & fugitives
Wellhead fugitives
Crude Oil Transportation
Refining
Total
1990
34.7
10.3
5.3 1
1.9 1
16.8 1
0.6 1
0.1 1
0.4
35.2
2005
28.7
8.3
3.9
1.5
14.5
0.4
0.1
0.4
29.2
2006
28.7
8.3
3.9
1.5
14.5
0.4
0.1
0.4
29.2
2007
29.3
8.4
4.0
1.5
15.0
0.4
0.1
0.4
29.8
2008
29.5
8.7
3.8
1.6
14.8
0.5
0.1
0.4
30.0
2009
30.2
8.8
4.3
2.0
14.6
0.5
0.1
0.4
30.7
2010
30.6
8.8
4.5
2.0
14.7
0.5
0.1
0.4
31.0
   Note: Totals may not sum due to independent rounding.

Table 3-43:  CH4 Emissions from Petroleum Systems (Gg)
   Activity	1990	2005     2006    2007     2008    2009     2010
   Production Field Operations          1,653        1,365    1,365    1,396     1,404    1,437     1,455
    Pneumatic device venting              489         397      396     398      416     419      420
    Tank venting                        250         187      188     192      182     206      214
    Combustion & process upsets            88          71       71      72       75       94       97
    Misc. venting & fugitives              799         690      692     714      706     693      700
3-52  Inventory of U.S. Greenhouse Gas Emissions and Sinks:  1990-2010

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Wellhead fugitives
Crude Oil Transportation
Refining
Total
26
7 1
18
1,677
119
5
1 19
1,389
17
5
19
1,389
20
5
19
1,420
24
5
19
1,427
24
5
18
1,460
24
5
19
1,478
   Note: Totals may not sum due to independent rounding.
Table 3-44:  CO2 Emissions from Petroleum Systems (Tg CO2 Eq.)
   Activity
1990
2005   2006   2007    2008    2009    2010
   Production Field
    Operations
    Pneumatic device venting
    Tank venting
    Misc. venting & fugitives
    Wellhead fugitives
   Crude Refining	
 0.4

 0.3
  0.3     0.3

  0.2     0.2
0.3

0.3
0.3

0.2
0.3

0.3
   Total
0.39
 0.31    0.31    0.31     0.30     0.33    0.34
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.


Table 3-45:  CO2 Emissions from Petroleum Systems (Gg)
Activity
Production Field
Operations
Pneumatic device venting
Tank venting
Misc. venting & fugitives
Wellhead fugitives
Crude Refining
Total
1990

376
27
328
18
1
18
394









2005

285
22
246
16
1
20
305
2006

285
22
246
16
1
20
306
2007

292
22
252
16
1
18
310
2008

280
23
239
16
1
16
297
2009

311
23
270
16
1
14
325
2010

322
23
281
16
1
15
337
   Note: Totals may not sum due to independent rounding.
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 negligible.

The methodology for estimating CH4 emissions from the 64 oil industry activities employs emission factors initially
developed by EPA (1999). Activity data for the years 1990 through 2010 were collected from a wide variety of
statistical resources. Emissions are estimated for each activity by multiplying emission factors (e.g., emission rate
per equipment item or per activity) by the corresponding activity data (e.g., equipment count or frequency of
activity). EPA (1999) provides emission 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, BOEMRE 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 2010.  The number of platforms in shallow  water and the number of platforms
in deep water are used as activity data and are taken from Bureau of Ocean Energy Management, Regulation, and
Enforcement (BOEMRE) (formerly Minerals  Management Service) statistics (BOEMRE 2011a-c). For oil storage
tanks, the emissions factor was calculated as the total emissions per barrel of crude charge from  E&P Tank data
weighted by the distribution of produced crude oil gravities from the HPDI production database  (EPA 1999, HPDI
2010).
                                                                                           Energy    3-53

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For some years, complete activity data were not available.  In such cases, one of three approaches was employed.
Where appropriate, the activity data was calculated from related statistics using ratios developed for EPA (1996).
For example, EPA (1996) found that the number of heater treaters (a source of CH4 emissions) is related to both
number of producing wells and annual production. To estimate the activity data for heater treaters, reported
statistics for wells and production were used, along with the ratios developed for EPA (1996). In other cases, the
activity data was held constant from 1990 through 2010 based on EPA (1999).  Lastly, the previous year's data were
used when data for the current year were unavailable. The CH4 and CO2 sources in the production sector share
common activity data. See Annex 3.5 for additional detail.

Key references used to obtain activity data are the Energy Information Administration annual and monthly reports
(EIA 1990 through 2010, 1995 through 2010, 1995 through 2010a-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, BOEMRE reports (BOEMRE 2005,
2010a-c), analysis of BOEMRE data  (EPA 2005, BOEMRE 2004), the Oil & Gas Journal (OGJ 2011a,b), the
Interstate Oil and Gas Compact Commission (IOGCC 2009, and the United States Army Corps of Engineers (1995-
2009).

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 and one activity from petroleum
refining.  Emissions are estimated for each activity by multiplying emission factors by their corresponding activity
data. 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 methane content in produced associated gas. The only exceptions to this
methodology are the emission factors for crude oil storage tanks, which are obtained from E&P Tank simulation
runs, and the emission factor for asphalt blowing, which was derived using the methodology and sample data from
API (2009).

Uncertainty and Time-Series Consistency

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 Stochastic 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 92
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 3-46. Petroleum systems CH4
emissions in 2010 were estimated to be between 23.64 and 77.31 Tg CO2 Eq., while CO2 emissions were estimated
to be between 0.26 and 0.85 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 24 percent
below to 149 percent above the 2010  emission estimates of 31.05 and  0.34 Tg CO2 Eq. for CH4 and CO2,
respectively.
3-54  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 3-46:  Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
Percent)
2010 Emission
Estimate
Source Gas (Tg CO2 Eq.)b
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound" Bound" Bound" Bound"
Petroleum Systems CH4 31.05
Petroleum Systems CO2 0.34
23.64 77.31 -24% 149%
0.26 0.85 -24% 149%
   a Range of 2010 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.
   Note: Totals may not sum due to independent rounding

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

QA/QC and Verification Discussion

The petroleum inventory is continually being reviewed and assessed to determine whether emission factors and
activity factors accurately reflect current industry practice.  A QA/QC analysis was performed for data gathering and
input, documentation, and calculation. The primary focus of the QA/QC checks is determining if the assumptions in
the Inventory are consistent with current industry practices through regulations, public webcasts, and the Natural
Gas STAR Program.  Finally, QA/QC checks are consistently conducted to minimize human error in the model
calculations.

A webcast was held by EPA for industry to comment on the ratio of high-bleed to low-bleed pneumatics, among
other topics. Two of the top seven emission sources, high-bleed and low-bleed pneumatic devices, use the earlier
mentioned industry peer review panel activity source (EPA/GRI 1996c). The Inventory assumes four pneumatic
devices per well-site with a heater-treater and separator, and three pneumatic devices per well-site with a separator
but without a heater-treater. EPA requested industry' s views on the assumption that, for each year of the time series
(1990 to 2010), 35 percent of devices are high-bleed pneumatic devices. No new information was raised, nor
concerns expressed, about this factor during the webcast and therefore this factor has not changed in the current
inventory.

Additionally,  the webcast discussed the emission factor for a refinery source, asphalt blowing. EPA requested
comment on the current CH4 emission factor for asphalt blowing (derived from a Radian International  Study) versus
the 2009 API Compendium's CH4 emission factor. The emission factor from the current Inventory was not modified
as a result of these comments; however, the activity for asphalt blowing was modified by applying a 10 percent
factor to the activity obtained through EIA's Petroleum Supply Annual. This was based on asphalt market analysis.
                                                                                           Energy   3-55

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Recalculations Discussion

Most revisions for the current Inventory relative to the previous report were due to updating previous years' data
with revised data from existing data sources.  Well completion venting, well drilling, and offshore platform activity
factors were updated with revised data from existing data sources from 1990 onward.  Updating the activity data for
asphalt blowing reduced CH4 and CO2 emissions for this source by a factor of 10, which has a relatively large
impact on fugitive emissions from petroleum refineries, but due to the small contribution of refineries to the overall
fugitive emissions, a relatively small impact on the overall  greenhouse gas emission estimates from petroleum
systems.

In addition, when activity data updates are made for a particular emissions source the entire time series is revised or
corrected, which may result in slight changes in estimated emissions from past years..

Planned  Improvements

In 2010, all U.S. petroleum refineries were required to collect information on their greenhouse gas emissions. This
data was reported to EPA through its GHGRP in 2011. Data collected under this program will be evaluated for use
in future inventories to improve the calculation of national  emissions from petroleum systems. In particular, whether
certain emissions sources currently accounted for in the Energy sector should be separately accounted for in the
petroleum systems source category estimates  (e.g., CO2 process emissions from hydrogen production) will be
investigated.

Improvements to the documentation of the Petroleum Systems source category is also being considered. A table
matching each emission factor and activity factor with its source or calculation methodology is being considered.
The purpose of this improvement would be to make the calculation methodologies more transparent.


[BEGIN BOX]


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 CO2 is produced from both naturally-occurring CO2
reservoirs and from industrial sources such as natural gas processing plants and ammonia plants. In the current
Inventory, emissions from naturally-produced CO2 are estimated based on the application.

In the current Inventory report, the CO2 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 CO2 used in EOR
operations is assumed to be fully sequestered. Additionally, all anthropogenic CO2 emitted from natural gas
processing and ammonia plants is assumed to be emitted to the atmosphere, regardless of whether the CO2 is
captured or not. These emissions are currently included in  the Natural Gas Systems and the Ammonia Production
sections of the Inventory report, respectively.

IPCC (IPCC 2006) included, for the first time, methodological guidance to estimate emissions from the capture,
transport, injection, and geological storage of CO2. 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 CO2 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 (IPCC 2006) notes that if a national regulatory process exists, emissions
information available through that process may support development of CO2 emissions estimates for geologic
storage.

As of January 1, 2011, facilities that conduct geologic sequestration of CO2 and all other facilities that inject CO2
underground are required to calculate and report greenhouse gas data annually to EPA through its GHGRP. EPA's
GHGRP requires greenhouse gas reporting from facilities that inject CO2underground for geologic sequestration,


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and requires greenhouse gas reporting from all other facilities that inject CO2 underground for any reason, including
enhanced oil and gas recovery. Facilities conducting geologic sequestration of CO2 are required to develop and
implement an EPA-approved site-specific monitoring, reporting and verification (MRV) plan, and to report the
amount of CO2 sequestered using a mass balance approach. Data from this program, which will be reported to EPA
starting in 2012, for the 2011 calendar year, will provide additional facility-specific information about the carbon
capture, transport and storage chain. That information will be evaluated closely and opportunities for improving the
emission estimates will be considered.

Preliminary estimates indicate that the amount of CO2 captured from industrial and natural sites is 46.2 Tg CO2
(46,198 Gg CO2) (see Table 3-47and Table 3-48).  Site-specific monitoring and reporting data for CO2 injection
sites (i.e., EOR operations) were not readily available, therefore, these estimates assume all CO2 is emitted.
Table 3-47: Potential Emissions from CO2 Capture and Transport (Tg CO2 Eq.)
Year
Acid Gas Removal Plants
Naturally Occurring CO2
Ammonia Production Plants
Pipelines Transporting CO2
Total
1990
4.8
20.8 1
+
+
25.6
2005
5.8
28.3
0.7
| +
34.7
2006
6.2
30.2
0.7
+
37.1
2007
6.4
33.1
0.7
+
40.1
2008
6.6
36.1
0.6
+
43.3
2009
7.0
39.7
0.6
+
47.3
2010
11.6
34.0
0.7
+
46.2
   + Does not exceed 0.05 Tg CO2 Eq.
   Note; Totals may not sum due to independent rounding.


Table 3-48: Potential Emissions from CO2 Capture and Transport (Gg)
Year
Acid Gas Removal Plants
Naturally Occurring CO2
Ammonia Production Plants
Pipelines Transporting CO2
Total
1990
4,832
20,811
8
25,643
2005
5,798
28,267
676
7
34,742
2006
6,224
30,224
676
7
37,124
2007
6,088
33,086
676
7
40,141
2008
6,630
36,102
580
8
43,311
2009
7,035
39,725
580
8
47,340
2010
11,554
33,967
677
8
46,198
   + Does not exceed 0.5 Gg.
   Note: Totals do not include emissions from pipelines transporting CO2
   Note; Totals may not sum due to independent rounding.


[END BOX]
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-CH4 volatile
organic compounds (NMVOCs) from energy-related activities from 1990 to 2010 are reported in Table 3-49.
Table 3-49: NOX, CO, and NMVOC Emissions from Energy-Related Activities (Gg)
Gas/Source
NOX
Mobile Combustion
Stationary Combustion
Oil and Gas Activities
Incineration of Waste
International Bunker
Fuels*
CO
Mobile Combustion
Stationary Combustion
1990
21
10
10



,106
,862
,023
139
82

2005
15,319





2,020
125
119
5
,640
,360
,000


9
5



1
69
62
4
,012
,858
321
129

,703
,062
,692
,649
2006
14,473
8,488
5,545
319
121

1,794
65,399
58,972
4,695
2007
13,829
7,965
5,432
318
114

1,791
61,739
55,253
4,744
2008
13,012
7,441
5,148
318
106

1,917
58,078
51,533
4,792
2009
10,887
6
4



1
49
43
4
,206
,159
393
128

,651
,647
,355
,543
2010
10,887
6,206
4,159
393
128

1,812
49,647
43,355
4,543
                                                                                         Energy   3-57

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   Incineration of Waste         978       1,403     1,412     1,421     1,430     1,403     1,403
   Oil and Gas Activities        302         318       319      320      322      345      345
   International Bunker
    Fuels*                    130         132       161      160      165      149      152
   NMVOCs                12,620 I     7,798     7,702     7,604     7,507     5,333     5,333
   Mobile Combustion        10,932 I     6,330     6,037     5,742     5,447     4,151     4,151
   Stationary Combustion        912         716       918     1,120     1,321      424      424
   Oil and Gas Activities        554         510       510      509      509      599      599
   Incineration of Waste         222         241       238      234      230      159      159
   International Bunker
    Fuels*	61	54       59       59       62       57       58
   * These values are presented for informational purposes only and are not included in totals.
   Note: Totals may not sum due to independent rounding.


Methodology

Due to the lack of data available at the time of publication, emission estimates for 2010 rely on 2009 data as a proxy.
Emission estimates for 2009 were obtained from preliminary data (EPA 2010, EPA 2009), and disaggregated based
on EPA (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air
Pollutant Emission Trends web site. Emissions were calculated either for individual categories or for many
categories combined, using basic activity data (e.g., the amount of raw material processed) as an indicator of
emissions.  National activity data were collected for individual categories from various agencies.  Depending on the
category, these basic activity data may include data on production, fuel deliveries, raw material processed, etc.

Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
activity.  Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997).  The EPA currently derives the overall emission control efficiency of a source category from a
variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA databases.

Uncertainty and Time-Series Consistency

Uncertainties in these estimates are partly due to the accuracy of the emission factors used and accurate estimates of
activity data.  A quantitative uncertainty analysis was not performed.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

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

Emissions resulting from the  combustion of fuels used for international transport activities, termed international
bunker fuels under the UNFCCC, are 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.103 These decisions are reflected in the IPCC methodological
guidance, including 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 2006).104

Greenhouse gases emitted from the combustion of international bunker fuels,  like other fossil fuels, include CO2,
103 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).
104 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil
Aviation Organization.


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CH4 and N2O. Two transport modes are addressed under the IPCC definition of international bunker fuels: aviation
and marine.105 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.106

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. Methane may be
emitted by gas turbines during idle and by older technology engines, but recent data suggest that little or no CH4 is
emitted by modern engines (Anderson et al. 2011).  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., U.S. Navy), fishing, and
miscellaneous support ships (e.g., tugboats). For the purpose of estimating greenhouse gas emissions, international
bunker fuels are solely related to cargo and passenger carrying vessels, which is the largest of the  four categories,
and military vessels.  Two main types of fuels are used on sea-going vessels: distillate diesel fuel  and residual fuel
oil. CO2 is the primary greenhouse gas emitted from marine shipping.

Overall, aggregate greenhouse gas emissions in 2010 from the combustion of international bunker fuels from both
aviation and marine activities were 129.2 Tg CO2 Eq., or 14 percent above emissions in 1990 (see Table 3-50 and
Table 3-51). Emissions from international flights and international shipping  voyages departing from the United
States have increased by 56 percent and decreased by 15 percent, respectively, since 1990. The majority of these
emissions were in the form of CO2; however, small amounts of CH4 and N2O were also emitted.

Table 3-50:  CO2, CH4, and N2O Emissions from International Bunker Fuels  (Tg CO2 Eq.)
Gas/Mode
CO2
Aviation
Marine
CH,
Aviation
Marine
N20
Aviation
Marine
Total
1990
111.8
46.4
65.4
0.2 1
+
0,
1.1 1
0.5 1
0.5
113.0
2005
109.8
56.8
53.0
0.1
+
0.1
1.0
0.6
0.4
110.9
2006
128.4
74.6
53.8
0.2
+
0.1
1.2
0.8
0.4
129.8
2007
127.6
73.8
53.9
0.2
+
0.1
1.2
0.8
0.4
129.0
2008
133.7
75.5
58.2
0.2
+
0.1
1.2
0.8
0.5
135.1
2009
122.3
68.6
53.7
0.1
+
0.1
1.1
0.7
0.4
123.6
2010
127.8
72.5
55.3
0.2
+
0.1
1.2
0.7
0.4
129.2
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
105 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).
106 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines.


                                                                                             Energy    3-59

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Table 3-51:  CO2, CH4 and N2O Emissions from International Bunker Fuels (Gg)
Gas/Mode
C02
Aviation
Marine
CH,
Aviation
Marine
N2O
Aviation
Marine
1990
111,828
46,399
65,429
8
2
7
3
2
2








2005
109,765
56,751
53,014
7
2
5
3
2
1
2006
128
74
53




,413
,581
,832
8
?
5
4
2
1
2007
127,643
73,788
53,856
8
2
5
4
2
1
2008
133,730
75,534
58,196
8
2
6
4
2
1
2009
122,338
68,614
53,723
7
2
5
4
2
1
2010
127,841
72,542
55,299
8
2
6
4
2
1
   Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.


Methodology

Emissions of CO2 were estimated by applying C content and fraction oxidized factors to fuel consumption activity
data.  This approach is analogous to that described under CO2 from Fossil Fuel Combustion. C content and fraction
oxidized factors for jet fuel, distillate fuel oil, and residual fuel oil were taken directly from EIA and are presented in
Annex 2.1, Annex 2.2, and Annex 3.7 of this inventory. Density conversions were taken from Chevron (2000),
ASTM (1989), and USAF (1998). Heat content for distillate fuel oil and residual fuel oil were taken from EIA
(2010) and USAF (1998), and heat content for jet fuel was taken from EIA (2010a).  A complete description of the
methodology and a listing of the various factors employed can be found in Annex 2.1.  See Annex 3.7 for a specific
discussion on the methodology used for estimating emissions from international bunker fuel use by the  U.S.
military.

Emission estimates for CH4 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 CH4 and N2O emissions were
obtained from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) and the 2006  IPCC Guidelines
(IPCC 2006). For aircraft emissions, the following values, in units of grams of pollutant per kilogram of fuel
consumed (g/kg), were employed: 0.09 for CH4 and 0.1 for N2O (IPCC 2006). For marine vessels consuming either
distillate diesel or residual fuel oil the following values (g/MJ), were employed: 0.32 for CH4 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 for inventory years 2000 through 2005 were developed using the FAA's
System for assessing Aviation's Global Emissions (SAGE) model (FAA 2006).  That tool has been incorporated into
the Aviation Environmental Design  Tool (AEDT), which calculates noise in addition to aircraft fuel burn and
emissions for all commercial flights globally in a given year (FAA 2010). Data for inventory years 2006 through
2010 were developed using AEDT.  Activity data on commercial aircraft fuel consumption for years 2000 through
2009 were developed with "domestic" defined as only the 50 states and "international bunkers" as departures from
the 50 states to a destination outside of the 50 states. For year 2010 the data was provided both with domestic
defined as the 50 states -and- separately as the 50 states and U.S. Territories.  The 2010 data formats will be
produced for future inventories and  recalculations of prior inventories.

International aviation bunker fuel consumption from 1990 to 2010 was calculated by assigning the difference
between the sum of domestic activity data (in Tbtu) from SAGE and the AEDT, and the reported EIA transportation
jet fuel consumption to the international bunker fuel category for jet fuel from EIA (2010a).  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 2011).  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.


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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 2011) for 1990 through 2001, 2007, through 2010, 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 (2011). 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
U.S. and Foreign Carriers
U.S. Military
Total
1990
4,934
862
5,796
2005
5,944
464
6,408
2006
7,812
403
8,215
2007
7,729
413
8,142
2008
7,912
389
8,301
2009
7,187
370
7,557
2010
7,598
359
7,957
   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
617
522
5,920
2005
3,881
444
471
4,796
2006
4,004
446
414
4,864
2007
4,059
358
444
4,861
2008
4,373
445
437
5,254
2009
4,040
426
384
4,850
2010
4,141
476
377
4,994
   Note: Totals may not sum due to independent rounding.


Uncertainty and Time-Series Consistency

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.107  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
107
   See uncertainty discussions under Carbon Dioxide Emissions from Fossil Fuel Combustion.
                                                                                           Energy   3-61

-------
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, emissions 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 estimate 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 2006 IPCC Guidelines is to use data by specific
aircraft type, number of individual flights and, ideally, movement data to better differentiate between domestic and
international aviation and to facilitate estimating the effects of changes in technologies. 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 CO2.108

There is also concern regarding the reliability of the existing DOC (2011) data on marine vessel fuel consumption
reported at U.S. customs stations due to the significant degree of inter-annual variation.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.

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

Slight changes to emission estimates are due to revisions made to historical activity data for aviation jet fuel
consumption using the FAA's AEDT. These historical data changes resulted in changes to the  emission estimates for
1990 through 2009 relative to the previous inventory, which averaged to an annual decrease in emissions from
international bunker fuels of 0.03 Tg CO2 Eq. (less than 0.1 percent) in CO2 emissions, an annual decrease of less
than 0.01 Tg CO2 Eq. (0.01 percent) in CH4 emissions, and an annual decrease of less than 0.01 Tg CO2 Eq. (0.01
percent) in N2O emissions.

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

The combustion of bio mass fuels such as wood, charcoal, and wood waste and biomass-based fuels such as ethanol
from corn and woody crops generates CO2 in addition to CH4 and N2O already covered in this  chapter. In line with
the reporting requirements for inventories submitted under the UNFCCC, CO2 emissions from biomass combustion
have been estimated separately from fossil fuel CO2 emissions and are not directly included in the energy sector
contributions to U.S. totals.  In accordance with IPCC methodological guidelines, any such emissions are calculated
by accounting for net carbon (C) fluxes from changes in biogenic C reservoirs in wooded or crop lands.  For a more
108 U.S. aviation emission estimates for CO, NOX, 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, NOX, and NMVOC emissions by including landing and
take-off (LTO) cycles by aircraft on international flights, but underestimate because they do not include emissions from aircraft
on domestic flight segments at cruising altitudes. The estimates in Mobile Combustion are also likely to include emissions from
ocean-going vessels departing from U.S. ports on international voyages.


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complete description of this methodological approach, see the Land Use, Land-Use Change, and Forestry chapter
(Chapter 7), which accounts for the contribution of any resulting CO2 emissions to U.S. totals within the Land Use,
Land-Use Change and Forestry sector's approach.
In 2010, total CO2 emissions from the burning of woody biomass in the industrial, residential, commercial, and
electricity generation sectors were approximately 191.6 Tg CO2 Eq. (191,591 Gg) (see Table 3-54 and Table 3-55).
As the largest consumer of woody biomass, the industrial sector was responsible for 70 percent of the CO2 emissions
from this source. Emissions from this sector increased from 2009 to 2010 due to a corresponding increase in wood
consumption. The residential sector was the second largest emitter, constituting 25 percent of the total, while the
commercial and electricity generation sectors accounted for the remainder.
Table 3-54: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
143.2
63.3
7.2 1
0.7
214.4
2005
148.4
48.3
7.8
1.2
205.7
2006
150.0
43.7
7.2
1.7
202.7
2007
143.9
48.1
7.8
2.4
202.2
2008
136.3
50.1
8.1
2.8
197.4
2009
122.9
48.4
8.2
2.4
181.8
2010
133.9
47.3
7.9
2.6
191.6
   Note: Totals may not sum due to independent rounding.


Table 3-55: CO2 Emissions from Wood Consumption by End-Use Sector (Gg)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
143,21 1
9 1
63,286
7,173
733 I
214,41
0 1
2005
148,386
48,283
7,821
I 1,182
205,671
2006
150,033
43,657
7,246
1,744
202,680
2007
143,929
48,113
7,768
2,394
202,204
2008
136,324
50,147
8,133
2,754
197,358
2009
122,851
48,440
8,160
2,355
181,806
2010
133,871
47,260
7,908
2,552
191,591
   Note: Totals may not sum due to independent rounding.

Biomass-derived fuel consumption in the United States transportation sector consisted primarily of ethanol use.
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.
In 2010, the United States  consumed an estimated 1,089 trillion Btu of ethanol, and as a result, produced
approximately 74.5 Tg CO2 Eq. (74,519 Gg) (see Table 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.

Table 3-56:  CO2 Emissions from Ethanol Consumption (Tg CO2 Eq.)
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
4.1
"•:
4.2
2005
22.4
0.5
0.1
22.9
2006
30.2
0.7
0.1
31.0
2007
38.1
0.7
0.1
38.9
2008
53.8
0.8
0.1
54.7
2009
61.2
0.9
0.2
62.3
2010
73.2
1.1
0.2
74.5
   + Does not exceed 0.05 Tg CO2 Eq.


Table 3-57: CO2 Emissions from Ethanol Consumption (Gg)
End-Use Sector
Transportation*
Industrial
Commercial
1990
4,136 1
56
34
2005
22,414
468
60
2006
30,237
662
86
2007
38,116
674
135
2008
53,796
797
146
2009
61,191
888
194
2010
73,225
1,062
232
                                                                                         Energy    3-63

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   Total
4,227
22,943    30,985    38,924    54,739    62,272    74,519
   a See Annex 3.2, Table A-88 for additional information on transportation consumption of these fuels.
Methodology

Woody biomass emissions were estimated by applying two EIA gross heat contents (Lindstrom 2006) to U.S.
consumption data (see Table 3-58), provided in energy units. This year woody biomass consumption data for the
industrial, residential, and commercial sectors were obtained from EIA 2011, while woody biomass consumption
data for the electricity generation sector was estimated from EPA's Clean Air Market Acid Rain Program dataset
(EPA 2011). The bottom-up analysis of woody biomass consumption based on EPA's Acid Rain Program dataset
indicated that the amount of woody biomass consumption allocated in the EIA statistics should be adjusted.
Therefore, for these estimates, the electricity generation sector's woody biomass consumption was adjusted
downward to match the value obtained from the bottom-up analysis based on EPA's Acid Rain Program dataset. As
the total woody biomass consumption estimate from EIA is considered to be accurate at the national level, the
woody biomass consumption totals for the industrial, residential, and commercial sectors were adjusted upward
proportionately.

One heat content (16.95 MMBtu/MT wood and wood waste) was applied to the industrial sector's consumption,
while the other heat content (15.43 MMBtu/MT wood and wood waste) was applied to the consumption data for the
other sectors.  An EIA 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 emission factor of
18.67 Tg C/QBtu (EPA 2010) to U.S. ethanol consumption estimates that were provided in energy units (EIA 2011)
(see Table 3-59).

Table 3-58: Woody Biomass Consumption by Sector (Trillion Btu)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
1,525.8
613. ?•
69.6
7.lB
2,216.2
2005
1,580.8
468.2
75.8
1 11.5
2,136.4
2006
1,598.4
423.4
70.3
16.9
2,108.9
2007
1,533.3
466.6
75.3
23.2
2,098.5
2008
1,452.3
486.3
78.9
26.7
2,044.2
2009
1,308.8
469.8
79.1
22.8
1,880.5
2010
1,426.2
458.3
76.7
24.7
1,985.9
Table 3-59: Ethanol Consumption by Sector (Trillion Btu)
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
60.4
0.8 1
0.5
61.7
2005
327.4
6.8
1 0.9
335.1
2006
441.7
9.7
1.3
452.6
2007
556.8
9.8
2.0
568.6
2008
785.8
11.6
2.1
799.6
2009
893.9
13.0
2.8
909.7
2010
1,069.7
15.5
3.4
1,088.6
Uncertainty and Time-Series Consistency

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.
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
3-64  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
above.

Recalculations Discussion

Wood and ethanol consumption values were revised relative to the previous Inventory for 2009 based on updated
information from EIA's Annual Energy Review (EIA 2011). Additionally, the change in methodology for
calculating emissions from woody biomass led a decrease in emissions from the electricity generation sector and an
increase in emissions for the other sectors over the time series. This adjustment of historical data for wood biomass
consumption resulted in an average annual decrease in emissions from wood biomass consumption of about 1.0 Tg
CO2 Eq. (0.5 percent) from 1990 through 2009. Slight adjustments were made to ethanol consumption based on
updated information from EIA (2011), which slightly increased estimates for ethanol consumed. As a result of
adjustments to historical EIA data, average annual emissions from ethanol consumption increased by less than 0.05
Tg CO2 Eq. (less than 0.05 percent) relative to the previous Inventory.

Planned Improvements

The availability of facility-level combustion emissions through EPA's GHGRP will be examined to help better
characterize the industrial sector's energy consumption in the United States, and further classify business
establishments according to industrial economic activity type. Most methodologies used in EPA's GHGRP are
consistent with IPCC, though for EPA's GHGRP, facilities collect detailed information specific to their operations
according to detailed measurement standards, which may differ with the more aggregated data collected for the
Inventory to estimate total, national U.S. emissions. In addition, and unlike the reporting requirements for this
chapter under the UNFCCC reporting guidelines,109 some facility-level fuel combustion emissions reported under
the GHGRP may also include industrial process emissions. In line  with UNFCCC reporting guidelines, fuel
combustion emissions are included in this chapter, while process emissions are included in the Industrial Processes
chapter of this report. In examining data from EPA's GHGRP that would be useful to improve the  emission
estimates for the CO2 from biomass combustion category, particular attention will also be made to ensure time series
consistency, as the facility-level reporting data from EPA's GHGRP are not available for all inventory years as
reported in this inventory. Additionally, analyses will focus on aligning reported facility-level fuel types and IPCC
fuel types per the national energy statistics, ensuring CO2 emissions from biomass are separated in the facility-level
reported data, and maintaining consistency with national energy statistics provided by EIA. In implementing
improvements and integration of data from EPA's GHGRP, the latest guidance from the IPCC on the use of facility-
level data in national inventories will be relied upon.no
109 See 
110 See 
                                                                                          Energy    3-65

-------

-------
                        Fossil Fuel Combustion

                          Natural Gas Systems

                       Non-Energy Use of Fuels

                                 Coal Mining

                           Petroleum Systems  •

                        Stationary Combustion  H

                           Mobile Combustion  I

                         Incineration of Waste  I

             Abandoned Underground Coal Mines  |
Energy as a Portion
  of all Emissions
                        5,388
                                            0
                                                    50
                                                            100
                                                                    150     200

                                                                 Tg C02 Eq.
                                                                                     250
                                                                                             300
Figure 3-1:  2010 Energy Chapter Greenhouse Gas Sources

-------
                                                                                                                           NEU Emissions 5
                                                                                                                                      Natural Gas Emissions
                                                                                                                                      1,266
                                                                                                                                      NEU Emissions 60
                                                                                                                                   Non-Energy Use
                                                                                                                                   Carbon Sequestered
                                                                                                                                   192
                                                                                               Note: Totals may not sum due to independent rounding.
                                                                                                    The "Balancing Item" above accounts for the statistical imbalances
                                                                                                    and unknowns in the reported data sets combined here.
3-2 2010 U.S.                                   (Tg  C02  Eq.)

-------
                    Nuclear
                 Electric Power
                     8.8%
Renewable
  Energy
   5.9%
Figure 3-3:  2010 U.S. Energy Consumption by Energy Source

-------
     m
     O1
     a
      g;
          120 -i
          100 -
80 -
           60 -
40 -
           20 -
                                                                         Total Energy
                                                         Fossil Fuels
                                                          Renewable & Nuclear
Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)

Note: Expressed as gross calorific values.
2,500  -,


2,000  -


1,500  -


1,000  -


  500  -


    0  -
          Relative Contribution
              by Fuel Type
                        42
                         |
                                        224
                                                        Petroleum

                                                       • Coal

                                                       • Natural Gas




                                                        340
                                                                            1,745
                                                             778
                                                                                                       2,258
Figure 3-5:  2010 C02 Emissions from Fossil Fuel Combustion  by Sector and Fuel Type
Note:  The electricity generation sector also includes emissions of less than 0.5 Tg C02 Eq. from geothermal-based electricity generation.

-------
         20 -i
 15 E
                             Normal
                    (4,524 Heating Degree Days)
                                           99% Confidence
  ! -2    -10 -
        -20 J

             cScScScScSc^c^c^c^c^o^c^c^c^c^cncncncncnc^c^c^c^c^

Figure 3-6: Annual Deviations from Normal Heating  Degree Days for the United States (1950-2010)
Note: Climatological normal data are highlighted.
     Statistical confidence interval for "normal" climatology period of 1971 through 2000.
                                                    99% Confidence
                            Normal
                   (1,242 Cooling Degree Days)
         -20
Figure 3-7:  Annual Deviations from Normal Cooling Degree Days for the United States (1950-2010)
Note: Climatological normal data are highlighted.
     Statistical confidence interval for "normal" climatology period of 1971 through 2000.

-------
         100

          90

          80 -

          70 -

      |  60

      .&•  50

       I  40
      u
          30 -

          20

          10
                                                                        Nuclear
                                                                                  Hydroelectric
                                                                       Wind
                   T-I         CT>     CT>    O^    (
                                         CT>    CT>     CT>    CT>    (
             i—IT—IT—IT—IT—iTHiHTHiHi




Figure 3-8:  Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2010)
          1,500 -,


          1,400


          1,300 -


      §   1,200 -


      I   1,100
      CD

          1,000 -


           900 -


           800 -
                                                                                                   Industrial
                                                        8888888888
Figure 3-9:  Electric Generation Retail Sales by End-Use Sector
Note:  The transportation end-use sector consumes minor quanties of electricity.

-------
  110
  100
   90
   80
   70
   60
   50
   120
   110
   100
   90
   80
   70
   110
   100
   90
   80
   70
   60
   110
   100
   90
   80
   70
   60
        Total excluding Computers,
      Communications Equipment, and
            Semiconductors
Paper
Figure 3-10: Industrial Production Indexes (Index 2007=100)
     23.0 -|
     22.5 -
     22.0 -
     21.5 -
     21.0 -
     20.5 -
     20.0 -
     19.5 -
     19.0 -
     18.5 -
     18.0 -
                 oioiaiaiaiaiaiaioooooooooo
                 aiaiaiaiaiaiaiaioooooooooo
                                          Model Year
Figure 3-11: Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2010

-------
    10,000  -i
     8,000  -
  £  6,000  -
     4,000  -
     2,000  J
              Passenger Cars
                                                oooooooooon
                                                (N(N(N(N(N(N(N(N(N(N(N
Figure 3-12: Sales of New Passenger Cars and Light-Duty Trucks, 1990-2010
     60 n
     50

   .  40 -
  8  30 H
     20 -

     10 -

      0
                                       N2O
                                      CH4
8
                        s
                                               8
                                                   O   O   O
883
Figure 3-13:  Mobile Source CH4 and N20 Emissions
           Energy Consumption/capita
 7  90 -
 §  85 -
 Oi
 & 80 -
 |75
    70 -
    65 -
                                                         CCycapita
                                         Energy s
                                         Consumption/$GDP
           in   rsi   m
           CT>   CT>   CT>
                           §!§!§!§!§!8888888888S
       i—IT—IT—IT—IT—IT—IT—IT—IT—IT—I(N(N(N(N(N(N(N(N(N(N(N

Figure 3-14:  U.S. Energy Consumption and Energy-Related C02 Emissions Per Capita and Per Dollar GDP

-------
4.           Industrial Processes

Greenhouse gas emissions are produced as the by-products 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), and
nitrous oxide (N2O).  The processes addressed in this chapter include iron and steel production and metallurgical
coke production, cement production, lime production, ammonia production and urea consumption, limestone and
dolomite consumption (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).


Figure 4-1: 2010 Industrial Processes Chapter Greenhouse Gas Sources


In addition to the three greenhouse gases listed above, there are also industrial sources of man-made fluorinated
compounds called hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (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 is growing
rapidly since 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, and SF6 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 2010, industrial processes generated emissions of 303.4 teragrams of CO2  equivalent (Tg CO2 Eq.), or 4.4 percent
of total U.S. greenhouse gas emissions. Carbon dioxide emissions from all industrial processes were 139.7 Tg CO2
Eq. (139,726 Gg) in 2010, or 2.4 percent of total U.S. CO2 emissions. Methane emissions from industrial processes
resulted in emissions of approximately 1.5 Tg CO2 Eq. (69 Gg) in 2010, which was less than 1 percent of U.S. CH4
emissions.  N2O emissions from adipic acid and nitric acid production were 19.5 Tg CO2 Eq. (63 Gg) in 2010, or 6.4
percent of total U.S. N2O emissions. In 2010 combined emissions of HFCs, PFCs, and SF6 totaled 142.7 Tg CO2
Eq. Total emissions from Industrial Processes in 2010 were 3.4 percent less than 1990 emissions.

The slight decrease in overall Industrial Processes emissions since 1990 reflects a range of emission trends among the
industrial process emission sources. Emissions resulting from most types of metal production have declined significantly
since 1990 but largely due to production shifting to other countries, but also due to transitions to less-emissive
methods of production (in the case of iron and steel) and to improved practices (in the case of PFC emissions from
aluminum production). Emissions from mineral sources have either increased or not changed significantly since
1990 but largely track economic cycles, while CO2 and CH4 emissions from chemical sources have either decreased
or not changed significantly. HFC emissions from the substitution of ozone depleting substances have increased
drastically since  1990, while the emission trends of HFCs, PFCs, and SF6 from other sources are mixed. Trends are
explained further within each emission category throughout the chapter.


Table 4-1 summarizes emissions for the Industrial Processes chapter in 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.
                                                                                Industrial Processes    4-1

-------
Table 4-1:  Emissions from Industrial Processes (Tg CO2 Eq.)
Gas/Source
C02
Iron and Steel Production and
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Cement Production
Lime Production
Limestone and Dolomite Use
Ammonia Production
Urea Consumption for Non-
Agricultural Purposes
Soda Ash Production and
Consumption
Petrochemical Production
Aluminum Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
Zinc Production
Phosphoric Acid Production
Lead Production
Silicon Carbide Production and
Consumption
CH,
Petrochemical Production
Iron and Steel Production and
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Ferroalloy Production
Silicon Carbide Production and
Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone Depleting
Substances*
HCFC-22 Production
Semiconductor Manufacturing
HFCs
PFCs
Semiconductor Manufacturing
PFCs
Aluminum Production
SF6
Electrical Transmission and
Distribution
Magnesium Production and
Processing
Semiconductor Manufacturing SF6
Total
+ Does not exceed 0.05 Tg CO2 Eq.
1990
188.5

99.6 1
97.1
2.5 1
33.3 1

5.1 1
13.0 1
;:
4.1 1
3.3 1
6.8 1
1.4
12 1
2.2 1
0.6 1
5
0.5 1

0.4
1.9 1
0.9 1

1.0 1
1.0 1
I-"

l/.U
15.8 1
36.9 1

0.3 1
36.4 1

0.2 1
20.6 1
18.4
32.6 1

26.7 1
5.4 1
0.5
313.9

2005
165.4

66.0
64.0
2.0
45.2
14.4
6.8
9.2
3.7
4.2
4.2
4.1
1.3
1.8
1.4
1.0
1.4
0.6

0.2
1.8
1.1

0.7
0.7
+
+
+
23.9
16.4
7.4
115.0

99.0
15.8

0.2
6.2
3.2
3.0
17.8

13.9
2.9
1.0
330.1

2006
169.9

68.9
66.9
1.9
45.8
15.1
8.0
8.8
3.5
4.2
3.8
3.8
1.7
1.8
1.5
1.0
1.2
0.6

0.2
1.7
1.0

0.7
0.7
+
+
+
25.0
16.1
8.9
116.0

101.9
13.8

0.3
6.0
3.5
2.5
16.8

13.0
2.9
1.0
335.5

2007
172.6

71.1
69.1
2.1
44.5
14.6
7.7
9.1
4.9
4.1
3.9
4.3
1.9
1.9
1.6
1.0
1.2
0.6

0.2
1.7
1.0

0.7
0.7
+
+
+
29.8
19.2
10.7
120.0

102.7
17.0

0.3
7.5
3.7
3.8
15.6

12.2
2.6
0.8
347.3

2008
159.5

66.1
63.8
2.3
40.5
14.3
6.3
7.9
4.1
4.1
3.4
4.5
1.8
1.8
1.6
1.2
1.2
0.5

0.2
1.6
0.9

0.6
0.6
+
+
+
18.9
16.4
2.6
117.5

103.6
13.6

0.3
6.7
4.0
2.7
15.0

12.2
1.9
0.9
319.1

2009
118.1

42.1
41.2
1.0
29.0
11.2
7.6
7.9
3.4
3.6
2.7
3.0
1.8
1.6
1.5
0.9
1.0
0.5

0.1
1.2
0.8

0.4
0.4
+
+
+
17.3
14.5
2.8
112.0

106.3
5.4

0.3
5.6
4.0
1.6
13.9

11.8
1.1
1.0
268.2

2010
139.7

54.3
52.2
2.1
30.5
13.2
10.0
8.7
4.4
3.7
3.3
3.0
2.2
1.9
1.7
1.2
1.0
0.5

0.2
1.5
0.9

0.5
0.5
+
+
+
19.5
16.7
2.8
123.0

114.6
8.1

0.3
5.7
4.1
1.6
14.0

11.8
1.3
0.9
303.4

Note: Totals may not sum due to independent rounding.
a Small amounts of PFC emissions also
result from this
source.





4-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
Table 4-2: Emissions from Industrial Processes (Gg)
Gas/Source
CO2
Iron and Steel Production and
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Cement Production
Lime Production
Limestone and Dolomite Use
Ammonia Production
Urea Consumption for Non-
Agricultural Purposes
Soda Ash Production and
Consumption
Petrochemical Production
Aluminum Production
Carbon Dioxide Consumption
Titanium Dioxide Production
Ferroalloy Production
Zinc Production
Phosphoric Acid Production
Lead Production
Silicon Carbide Production and
Consumption
CH,
Petrochemical Production
Iron and Steel Production and
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Ferroalloy Production
Silicon Carbide Production and
Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone Depleting
Substances*
HCFC-22 Production
Semiconductor Manufacturing
HFCs
PFCs
Semiconductor Manufacturing PFCs
Aluminum Production
SF6
Electrical Transmission and
Distribution
Magnesium Production and
Processing
Semiconductor Manufacturing SF6
+ Does not exceed 0.5 Gg
M (Mixture of gases)
1990
188,460

99,593
97,123
2,470
33,278
11,533
5,127
13,047

3,784

4,141
3,311
6,831
1,416
1,195
2,152
632
1,529
516

375 1
88
41 1

46 1
46
+ 1
1

1
108
57 1
51 1
M

M
3 1

+ I
M
M
M 1
1 1

1

M
+ |


2005
165,402

66,000
63,957
2,043
45,197
14,379
6,768
9,196

3,653

4,228
4,181
4,142
1,321
1,755
1,392
1,030
1,386
553

219
86
51

34
34
+
+

+
77
53
24
M

M
1

+
M
M
M
1

1

M
| +


2006
169,895

68,854
66,934
1,919
45,792
15,100
8,035
8,781

3,519

4,162
3,837
3,801
1,709
1,836
1,505
1,030
1,167
560

207
83
48

35
35
+
+

+
81
52
29
M

M
1

+
M
M
M
1

1

M
+


2007
172,609

71,138
69,083
2,055
44,538
14,595
7,702
9,074

4,944

4,140
3,931
4,251
1,867
1,930
1,552
1,025
1,166
562

196
82
48

33
33
+
+

+
96
62
34
M

M
1

+
M
M
M
1

1

M
+


2008
159,457

66,092
63,758
2,334
40,531
14,330
6,276
7,883

4,065

4,099
3,449
4,477
1,780
1,809
1,599
1,159
1,187
547

175
74
43

31
31
+
+

+
61
53
8
M

M
1

+
M
M
M
1

1

M
+


2009
118,105

42,113
41,157
956
29,018
11,225
7,649
7,855

3,415

3,554
2,735
3,009
1,784
1,648
1,469
943
1,018
525

145
58
39

17
17
+
+

+
56
47
9
M

M
+

+
M
M
M
1

+

M
+


2010
139,726

54,276
52,192
2,084
30,509
13,151
10,017
8,678

4,365

3,735
3,336
3,009
2,203
1,876
1,663
1,168
1,017
542

181
69
44

25
25
+
+

+
63
54
9
M

M
1

+
M
M
M
1

+

M
+


                                                                               Industrial Processes   4-3

-------
   Note:  Totals may not sum due to independent rounding.
   a Small amounts of PFC emissions also result from this source.
[BEGIN BOX]

Box 4-1: Industrial Processes Data from EPA's Greenhouse Gas Reporting Program
On October 30, 2009, the U.S. EPA published a rule for the mandatory reporting of greenhouse gases from large
GHG emissions sources in the United States. Implementation of 40 CFR Part 98 is referred to as EPA's Greenhouse
Gas Reporting Program (GHGRP). 40 CFR part 98 applies to direct greenhouse gas emitters, fossil fuel suppliers,
industrial gas suppliers, and facilities that inject CO2 underground for sequestration or other reasons and requires
reporting by 41 industrial categories. Reporting is at the facility level, except for certain suppliers of fossil fuels and
industrial greenhouse gases. In general, the threshold for reporting is 25,000 metric tons or more of CO2 Eq. per
year. For calendar year 2010, the first year in which data were reported, facilities in 29 categories provided in 40
CFR part 98 were required to report their 2010 emissions by the September 30, 2011 reporting deadline.

EPA's GHGRP dataset and the data presented in this inventory report are complementary and, as indicated in the
respective planned improvements sections for source categories in this chapter, EPA is analyzing how to use
facility-level GHGRP data to improve the national estimates presented in this inventory. Most methodologies used
in EPA's GHGRP are consistent with IPCC, though for EPA's  GHGRP, facilities collect detailed information
specific to their operations according to detailed measurement standards. This may differ with the more aggregated
data collected for the inventory to estimate total, national U.S. emissions. In addition, it should be noted that the
definitions and provisions for reporting fuel types in EPA's GHGRP may differ from those used in the national
inventory in meeting the UNFCCC reporting guidelines. In line with the UNFCCC reporting guidelines1l1, the
inventory report is a comprehensive accounting of all emissions from fuel types identified in the IPCC guidelines
and provides a separate reporting of emissions from biomass. Further information on the reporting categorizations in
EPA's GHGRP and specific data caveats associated with monitoring methods in EPA's GHGRP has been provided
on the EPA's GHGRP website.1 u

EPA presents the data collected by EPA's GHGRP through a data publication tool113 that allows data to be viewed
in several formats including maps, tables, charts and graphs for individual facilities or groups  of facilities.

[END BOX]
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.114 CO2 emitted from the chemical
process of cement production is the second largest source of industrial CO2 emissions in the United States. Cement
is produced in 36 states and Puerto Rico. Texas, California, Missouri, Pennsylvania, Alabama, and Michigan were
the six largest (in descending order) cement-producing states in 2011 and accounted for approximately half of U. S.
production (USGS 2011).
During the cement production process, 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
111 See http://unfccc.int/resource/docs/2006/sbsta/eng/09.pdf
112 See
.
   See .
114 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.


4-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
calcining.  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.115

In 2010, U.S. clinker production—including Puerto Rico—totaled 59,000 thousand metric tons (USGS 2011). The
resulting CO2 emissions were estimated to be 30.5 Tg CO2 Eq. (30,509 Gg) (see Table 4-3).

Table 4-3: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg)
    Year    Tg CO2 Eq.	Gg
    1990       33.3         33,278
2005
2006
2007
2008
2009
2010
45.2
45.8
44.5
40.5
29.0
30.5
45,197
45,792
44,538
40,531
29,018
30,509
Greenhouse gas emissions from cement production grew every year from 1991 through 2006, but have decreased
since. Emissions since 1990 have decreased by eight percent.  Emissions decreased significantly between 2008 and
2009, due to the economic recession and associated decrease in demand for construction materials. Although
emissions increased slightly from 2009 levels in 2010, they remain 25 percent below 2008 levels, again due to the
ongoing contraction of the housing market. Cement continues to be a critical component of the construction
industry; therefore, the availability of public and private construction funding, as well as overall economic
conditions, have considerable influence on cement production.

Methodology

CO2 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 CaCOs (i.e., limestone) heated in the clinker kiln
forms one mole of lime (CaO) and one mole of CO2:

                                      CaCO3 + heat -> CaO + CO2
CO2 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 and a constant reflecting the mass of CO2 released per unit of lime (van Oss 2008).
This calculation yields an emission factor of 0.51 tons of CO2 per ton of clinker produced, which was determined as
follows:
                EF       = 0.6460 CaO x
                   Clinker
44.01 g/moleCO

56.08 g/moleCaO
= 0.5070 tons CO  Aon 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 are not accounted for by the clinker emission factor. The IPCC recommends that these additional CKD CO2
H-5 Approximately three percent of total clinker production is used to produce masonry cement, which is produced using
plasticizers (e.g., ground limestone, lime) and portland cement (USGS 2011).  Carbon dioxide emissions that result from the
production of lime used to create masonry cement are included in the Lime Manufacture source category.


                                                                                Industrial Processes    4-5

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emissions should be estimated as two percent of the CO2 emissions calculated from clinker production (when data on
CKD generation are not available).116  Total cement production emissions were calculated by adding the emissions
from clinker production to the emissions assigned to CKD (IPCC 2006).

Furthermore, small amounts of impurities (i.e., not calcium carbonate) may exist in the raw limestone used to
produce clinker.  The proportion of these impurities is generally minimal, although a small (one to two percent)
amount of magnesium oxide (MgO) may be desirable as a flux.  Per the IPCC Tier 2 methodology, a correction for
magnesium oxide is not used, since the amount of magnesium oxide from carbonate is likely very small and the
assumption of a 100 percent carbonate  source of CaO already yields an overestimation of emissions (IPCC 2006).
The  1990 through 2010  activity data for clinker production (see Table 4-4) were obtained from USGS (US Bureau
of Mines 1990 through 1993, USGS  1995 through 2011). The data were compiled by USGS through questionnaires
sent to domestic clinker and cement manufacturing plants.

Table 4-4: Clinker Production (Gg)
    Year	Clinker
    1990      64,355
2005
2006
2007
2008
2009
2010
87,405
88,555
86,130
78,382
56,116
59,000
Uncertainty and Time-Series Consistency

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 materials are 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; 65 percent is used as a
representative value (van Oss 2008). 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 calcium carbonate.  This reaction only occurs in roughly the outer 0.2
inches of surface area.  Because the amount of CO2 reabsorbed is thought to be minimal, it was not estimated.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-5. Based on the uncertainties
associated with total U.S. clinker production, the CO2 emission factor for clinker production, and the emission factor
for additional CO2 emissions from CKD, 2010 CO2 emissions from cement production were estimated to be between
26.5 and 34.7 Tg CO2 Eq. at the 95 percent confidence level. This confidence level indicates a range of
approximately 13 percent below and 14 percent above the emission estimate of 30.5 Tg CO2 Eq.

Table 4-5: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Cement Production (Tg CO2 Eq. and
Percent)
116 Default IPCC clinker and CKD emission factors were verified through expert consultation with the Portland Cement
Association (PCA 2008) and van Oss (2008).


4-6  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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                         2010 Emission Estimate        Uncertainty Range Relative to Emission Estimate3
   Source	Gas	(Tg CO2 Eq.)	(Tg CO2 Eq.)	(%)	
 	Lower Bound     Upper Bound   Lower Bound   Upper Bound
   Cement Production  CO2	30.5	26.5	34.7	-13%	+14%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations Discussion

Activity data for the time series was revised for the current Inventory. Specifically, clinker production data for 2006
through 2009 were revised to reflect updated USGS data. Details on the emission trends through time are described
in more detail in the Methodology section, above.

Planned  Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Cement Production source category. Particular attention will be made to
ensure time series consistency, as the facility-level reporting data from EPA's GHGPJ3 are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGPJ3, the latest guidance from the  IPCC on the use of facility-level data in national inventories will be relied
upon.117

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 systems at coal-fired electric power plants, construction, and
water purification. Lime is also used as a CO2 scrubber, and there has been experimentation on the use of lime to
capture CO2 from electric power plants.  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.118

Lime production in the United States—including Puerto Rico—was reported to be 18,259 thousand metric tons in
2010 (USGS 2011).  This production resulted in estimated CO2 emissions of 13.2 TgCO2Eq. (13,151 Gg) (see
Table 4-6 and Table 4-7).

Table 4-6:  CO2 Emissions from Lime Production (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.	Gg
   1990       11.5          11,533
   See 
118 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.


                                                                               Industrial Processes    4-7

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   2005
   2006
   2007
   2008
   2009
   2010
  14.4
  15.1
  14.6
  14.3
  11.2
  13.2
  14,379
  15,100
  14,595
  14,330
  11,225
  13,151
Table 4-7: Potential, Recovered, and Net CO2 Emissions from Lime Production (Gg)
   Year
Potential
Recovered
Net Emissions
   1990
 12,004
   471
   11,533
2005
2006
2007
2008
2009
2010
15,131
15,825
15,264
14,977
11,913
13,795
752
725
669
647
688
644
14,379
15,100
14,595
14,330
11,225
13,151
    For sugar refining and PCC production.
   Note: Totals may not sum due to rounding

Lime production in 2010 rebounded from a 21 percent decline in 2009 to 18,259 thousand metric tons, which is still
eight percent below 2008 levels.  Lime production declined in 2009 mostly due to the economic recession and the
associated significant downturn in major markets such as construction and steel.  The surprising rebound in 2010 is
primarily due to increased consumption in steelmaking, chemical and industrial uses, and in flue gas desulfurization.
The contemporary lime market is approximately distributed across five end-use categories as follows: metallurgical
uses, 35 percent; environmental uses, 32 percent; chemical and industrial uses, 23 percent; construction uses, nine
percent; and refractory dolomite, one percent. Consumption for metallurgical uses, which accounted for 57 percent
of the overall decrease in lime consumption in 2009, recorded the most significant (62 percent) gains of 2010
(USGS2011).

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 using the Tier 2 approach from the 2006 IPCC Guidelines (IPCC 2006).  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 (0.9500 CaO/lime) = 0.7455 g CO2/g lime
For dolomitic lime:
                [(88.02 g/mole CO2) - (96.39 g/mole CaO)] x (0.9500 CaO/lime) = 0.8675 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 27.2 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).
4-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Lime emission estimates were further adjusted to account for PCC producers and sugar refineries that recover CO2
emitted by lime production facilities for use 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 outreach by state agencies,
sugar refineries use captured CO2 for 100 percent of their CO2 input (Lutter 2009). 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 based on the amount of purchased CO2 by PCC manufacturers
(Prillaman 2008 through 2010).  As data were only available starting in 2007, CO2 recovery for the period 1990
through 2006 was extrapolated by determining a ratio of PCC production at lime facilities to lime consumption for
PCC (USGS 1992 through 2008).

Lime production data (high-calcium- and dolomitic-quicklime, high-calcium- and dolomitic-hydrated, and dead-
burned dolomite) for 1990 through 2010 (see Table  4-8) were obtained from USGS (1992 through 2011). Natural
hydraulic lime, which is produced from CaO and hydraulic calcium silicates, is not produced in the United States
(USGS 2010). 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, and is presented in Table 4-9 (IPCC 2000).
The CaO and CaOMgO contents of lime were obtained from the IPCC (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.

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
   1990
              11,166
                    2,234
                  1,781
                    319
                   342
2005
2006
2007
2008
2009
2010
14,100
15,000
14,700
14,900
11,800
13,800
2,990
2,950
2,700
2,310
1,830
2,110
2,220
2,370
2,240
2,070
1,690
1,910
474
409
352
358
261
239
200
200
200
200
200
200
Table 4-9: Adjusted Lime Production3 (Gg)
   Year    High-Calcium
                  Dolomitic
   1990
              12,514
                    2,809
2005
2006
2007
2008
2009
2010
15,781
16,794
16,396
16,467
13,079
15,246
3,535
3,448
3,156
2,771
2,220
2,484
   ' Minus water content of hydrated lime
Uncertainty and Time-Series Consistency
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,
                                                                              Industrial Processes    4-9

-------
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 precipitated calcium carbonate reacts with CO2; whereas most of the lime used in steel making
reacts with impurities such as silica, sulfur, and aluminum compounds. Quantifying the amount of CO2 that is
reabsorbed would require a detailed accounting of lime use in the United States and additional information about
the associated processes where both the lime and byproduct CO2 are  "reused" are required to quantify the amount of
CO2 that is reabsorbed. Research conducted thus far has not yielded the necessary information to quantify CO2
reabsorbtion rates.119

In some cases, lime is generated from calcium carbonate byproducts  at pulp mills and water treatment plants. 12°
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 the industrial processes totals (Miner and Upton 2002). In accordance with IPCC methodological
guidelines, any such emissions are calculated by accounting for net carbon (C) fluxes from changes in biogenic C
reservoirs in wooded or crop lands (see Chapter 7).

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 2010). This analysis  assumes that all sugar refineries located on-site
at lime plants also use 100 percent recovered CO2.  The recovery rate for PCC producers located on-site at lime
plants is based on the 2009 value for PCC manufactured at commercial lime plants,  given by the National Lime
Association (Prillaman 2010).

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-10.  Lime CO2 emissions  were
estimated to be between 12.1 and 14.4 Tg CO2 Eq. at the 95 percent confidence level.  This confidence level
indicates a range of approximately 8 percent below and 9 percent above the emission estimate of 13.2 Tg CO2 Eq.
   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).
1^0 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.


4-10   Inventory of U.S. Greenhouse Gas  Emissions and Sinks: 1990-2010

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Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Production (Tg CO2 Eq. and
Percent)


                          2010 Emission Estimate       Uncertainty Range Relative to Emission Estimate3
   Source	Gas	(Tg CO2 Eq.)	(Tg CO2 Eq.)	(%)	
  	Lower Bound     Upper Bound   Lower Bound   Upper Bound
   Lime Production	CO2	13.2	12.1	14.4	-8%	+9%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Methodological recalculations were applied  to the entire time-series to ensure time-series consistency from  1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations Discussion

Data on lime consumption for sugar refining in 2009 was revised by USGS from 733 to 731 metric tons.  This
revision resulted in an increase of emissions from 11,223 to 11,225 Gg CO2 Eq., an increase of 0.02 percent.

Planned  Improvements

Future improvements involve evaluating and analyzing data reported under EPA's  GHGRP that would be useful to
improve the emission estimates for the Lime Production source category. Particular attention will be made to ensure
time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all Inventory
years as required for this inventory. In implementing improvements and integration of data from EPA's GHGRP, the
latest guidance from the IPCC on the use of  facility-level data in national inventories will be relied upon.121
Future improvements to the lime source category will also involve continued research into CO2 recovery associated
with lime use during sugar refining and precipitate calcium carbonate (PCC) production. Currently, two sugar
refining facilities in California have been identified to capture CO2 produced in lime kilns located on the same site
as the sugar refinery (Lutter 2010). 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)122 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 heated sufficiently enough to calcine the
material and generate 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 (FGD) systems for utility and industrial
plants, and as a raw material for the production of glass, lime, and cement.
In 2010, 21,004 thousand metric tons of limestone and 2,624 thousand metric tons of dolomite were consumed for
these emissive  applications (USGS 201 la).  Usage of limestone and dolomite resulted in aggregate CO2 emissions
of 10.0 Tg CO2 Eq. (10,017 Gg) (see Table 4-1 land Table 4-12). Overall,  emissions have increased 95 percent from
1990 through 2010.
   See
122 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom
distinguished.


                                                                              Industrial Processes   4-11

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Table 4-11: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.)
    Year    Flux Stone    Glass Making
                             FGD
                        Magnesium
                         Production
                           Other Miscellaneous
                                   Uses
                                   Total
    1990
  2.6
   0.2
      1.4
     0.1
                  5.1
2005
2006
2007
2008
2009
2010
2.7
4.5
2.0
1.0
1.8
1.6
0.4
0.7
0.3
0.4
0.1
0.4
3.0 +
2.1 +
3.2 +
3.8 +
5.4 +
7.1 +
0.7
0.7
2.2
1.1
0.4
0.9
6.8
8.0
7.7
6.3
7.6
10.0
    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.
    + Emissions are less than 0.1 Tg CO2 Eq.
Table 4-12: CO2 Emissions from Limestone & Dolomite Use (Gg)
    Year  Flux Stone  Glass Making  FGD
                                Magnesium
                                 Production
                                  Other Miscellaneous
                                         Uses
                                             Total
    1990
2,593
217
1,433
64
    + Emissions are less than 0.1 Tg CO2 Eq.
819
5,127
2005
2006
2007
2008
2009
2010
2,650
4,492
1,959
974
1,785
1,572
425
747
333
387
61
440
2,975 +
2,061 +
3,179 +
3,801 +
5,406 +
7,068 +
718
735
2,231
1,114
396
938
6,768
8,035
7,702
6,276
7,649
10,017
Methodology

CO2 emissions were calculated based on the IPCC 2006 Guidelines Tier 2 method by multiplying the quantity of
limestone or dolomite consumed by the average C content, 12.0 percent for limestone and 13.0 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 (USGS  20 lib).

Consumption data for 1990 through 2010  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 (1995
through 201 la) and the U.S. Bureau of Mines (1991 and 1993a). The production capacity data for 1990 through
2010 of dolomitic magnesium metal also came from the USGS (1995 through 20 lib) and the U.S. Bureau of Mines
(1990 through 1993b). During 1990 and 1992, the USGS did not conduct a detailed survey of limestone and
dolomite  consumption by end-use.  Consumption for 1990 was estimated by applying the 1991 percentages of total
limestone and 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.
4-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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 uses fraction of total
consumption in that year.123

Table 4-13:  Limestone and Dolomite Consumption (Thousand Metric Tons)
Activity
Flux Stone

Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Other Miscellaneous Uses
Total
1990
6,737

5,804
933
489
430
59
3,258
1,835
12,319











2005
7,022

3,165
3,857
962
920
43
6,761
1,632
16,377
2006
11,030

5,208
5,822
1,693
1,629
64
4,683
1,671
19,078
2007
5,305

3,477
1,827
757
757
+
7,225
5,057
18,344
2008
3,253

1,970
1,283
879
879
+
8,639
2,531
15,302
2009
4,623

1,631
2,992
139
139
+
12,288
898
17,948
2010
4,441

1,921
2,520
1,000
1,000
+
16,064
2,122
23,628
  + Emissions are less than 0.1 Lg CO2 Eq.
  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.
Uncertainty and Time-Series Consistency

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 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 4-14. Limestone and Dolomite
Use CO2 emissions were estimated to be between 8.7 and 11.8 Tg CO2 Eq.  at the 95 percent confidence level.  This
indicates a range of approximately 13 percent below and 18 percent above the emission estimate of 10.0 Tg CO2 Eq.

Table 4-14: Tier 2 Quantitative Uncertainty Estimates for  CO2 Emissions from Limestone and Dolomite Use (Tg
CO2 Eq. and Percent)
123This approach was recommended by USGS.
                                                                                Industrial Processes    4-13

-------
                          2010 Emission Estimate        Uncertainty Range Relative to Emission Estimate3
   Source	Gas	(Tg CO2 Eq.)	(Tg CO2 Eq.)	(%)	
  	Lower Bound	Upper Bound   Lower Bound   Upper Bound
   Limestone and
    Dolomite Use      CO2	10.0	8/7	11.8	-13%	+18%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Limestone and Dolomite Use source category. Particular attention will be
made to ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for
all Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.124 Additionally, future improvements include revisiting the methodology to distribute withheld data across
emissive end-uses for all years to improve consistency of calculations.

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.125
During the production process used in Wyoming, trona ore is calcined to produce crude soda ash.  Carbon dixoide 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 2010, CO2 emissions from the production of soda ash from trona were approximately 1.5 Tg CO2 Eq. (1,548 Gg).
Soda ash consumption in the United States generated 2.2 Tg CO2Eq. (2,187 Gg) in 2010. Total emissions from
soda ash production and consumption in 2010 were 3.7 Tg CO2 Eq. (3,735 Gg) (see Table 4-15 and Table 4-16).
Total emissions in 2010 increased by approximately 5 percent from emissions in 2009, and  have decreased overall
by approximately  9.8 percent since 1990.
   See
   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.


4-14   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Emissions have remained relatively constant over the time series with some fluctuations since 1990. In general,
these fluctuations were related to the behavior of the export market and the U.S. economy. Specifically, the extended
downturn in residential and commercial construction and automotive industries between 2008 and 2010 resulted in
reduced consumption of glass products, causing a drop in global demand for soda ash and a corresponding decrease
in emissions. Furthermore, the glass container sector is one of the leading soda ash consuming sectors in the United
States. Some commercial food and beverage package manufacturers are shifting from glass containers towards
lighter and more cost effective polyethylene terephthalate (PET) based containers, putting downward pressure on
domestic consumption of soda ash (USGS 2010 and 2011).

Table 4-15: CO2 Emissions from Soda Ash Production and Consumption (Tg CO2 Eq.)
   Year    Production	Consumption	Total
   1990        1.4             2.7           4.1
2005
2006
2007
2008
2009
2010
1.7
1.6
1.7
1.7
1.5
1.5
2.6
2.5
2.5
2.4
2.1
2.2
4.2
4.2
4.1
4.1
3.6
3.7
   Note: Totals may not sum due to independent
   rounding.
Table 4-16:  CO2 Emissions from Soda Ash Production and Consumption (Gg)
   Year    Production	Consumption	Total
   1990       1,431           2,710         4,141
2005
2006
2007
2008
2009
2010
1,655
1,626
1,675
1,733
1,470
1,548
2,573
2,536
2,465
2,366
2,083
2,187
4,228
4,162
4,140
4,099
3,554
3,735
   Note: Totals may not sum due to independent
   rounding.
The United States represents about one-fourth of total world soda ash output.  Based on final 2010 reported data, the
estimated distribution of soda ash by end-use in 2010 was glass making, 48 percent; chemical production, 29
percent; soap and detergent manufacturing, 10 percent; distributors, 5 percent; flue gas desulfurization, 4 percent;
other uses and pulp and paper production, 2 percent each; and water treatment, less than 1 percent (USGS 2011).

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 (USGS 2008).

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(C03)(HC03)'2H20) -> 3Na2CO3 + 5H2O + CO2


                                                                               Industrial Processes   4-15

-------
                                  [trona]              [soda ash]
Based on this formula, which is consistent with an IPCC Tier 1 approach, 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 15.9 million metric tons of trona mined in 2010 for soda ash production (USGS 2011)
resulted in CO2 emissions of approximately 1.5 Tg CO2 Eq. (1,548 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 4-17) between 1990 and 2010 were
taken from USGS Minerals Yearbook for Soda Ash (1994 through 2011).  Soda ash production and consumption
data were collected by the USGS from voluntary surveys  of the U.S. soda ash industry.
4-16  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 4-17: Soda Ash Production and Consumption (Gg)


   Year    Production'    Consumption
   1990      14,700          6,530
2005
2006
2007
2008
2009
2010
17,000
16,700
17,200
17,800
15,100
15,900
6,200
6,110
5,940
5,700
5,020
5,270
    Soda ash produced from trona ore only.


Uncertainty and Time-Series Consistency

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 emission factors for each end-use are not available, so a Tier 1 defaultemission
factor is used for all end uses. 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 4-18. Soda Ash Production and
Consumption CO2 emissions were estimated to be between 3.Sand 4.0 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 3.7 Tg
C02Eq.

Table 4-18: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Production and
Consumption (Tg CO2 Eq. and Percent)

  Source                Gas    2010 Emission Estimate     Uncertainty Range Relative to Emission Estimate3
 	(TgCO;Eq.)	(Tg CO; Eq.)	[%)	
 	Lower Bound   Upper Bound    Lower Bound     Upper Bound
  Soda Ash Production
   and Consumption	CO2	3/7	3.5	40	-7%	+7%	
  a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations

Trona production data was updated for 2009 and soda ash consumption data was updated for 2008 and 2009 based
on newly available data from the USGS Minerals Yearbook Soda Ash 2010 (USGS 2011). This resulted in a
decrease of total emissions from soda ash production and consumption for 2008 and 2009 by approximately 0.3
percent and 17 percent, respectively.

Planned  Improvements

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.
In examining data from EPA's GHGPJ3 that would be useful to improve the emission estimates for Soda Ash and
                                                                             Industrial Processes   4-17

-------
Consumption category, particular attention will be made to ensure time series consistency, as the facility-level
reporting data from EPA's GHGRP are not available for all inventory years as reported in this inventory. In
implementing improvements and integration of data from EPA's GHGRP, the latest guidance from the IPCC on the
use of facility-level data in national inventories will be relied upon.126

4.5.    Ammonia Production (IPCC Source Category 2B1)

Emissions of CO2 occur during the production of synthetic ammonia, primarily through the use of natural gas,
petroleum coke, or naphtha 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 synthetic
ammonia production plant located in Kansas is producing ammonia from petroleum coke feedstock; other synthetic
ammonia production plants in the U.S. are using natural gas feedstock.  In some plants some of the CO2 produced by
the process is captured and used to produce urea rather than being emitted to the atmosphere. 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 in this step of the process.  The
secondary reforming step converts the 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
from the solution.

The conversion process for conventional steam reforming of  CH4, including the primary and secondary reforming
and the shift conversion processes, is approximately as follows:
                                                   (catalyst)
                       0.88 CH4 + 1.26 Air + 1.24 H2O	>  0.88 CO2 + N2 + 3 H2

                                          N2 + 3 H2 -» 2 NH3

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 during the production of ammonia is emitted directly to the atmosphere.   Some of the
ammonia and some of the CO2 produced by the synthetic ammonia process are used as raw materials in the
production of urea [CO(NH2)2], which has a variety of agricultural and  industrial applications.

The chemical reaction that produces urea is:

                            2NH3 + CO2Hx NH2COONH4 -» CO(NH2)2 + H2O

Only the CO2 emitted directly to the atmosphere from the synthetic ammonia production process are accoutned for in
determining emissions from ammonia production.  The CO2 that is captured during the ammonia production process and
used to produceurea does not contribute to the CO2 emission estimates for ammonia production presented in this section.
Instead, CO2 emissions resulting from the consumption of urea are attributed to the urea consumption or urea application
category (under the assumption that the C stored in the urea during its manufacture is released into the environment
during its consumption or application).  Emissions of CO2 resulting from agricultural applications of urea are
accounted for in the Cropland Remaining Cropland section of the Land-use, Land-use Change, and Forestry chapter.
Emissions of CO2 resulting from non-agricultural applications of urea (e.g., use as a feedstock in chemical
production processes) are accounted for in the Urea Consumption for Non-Agricultural Purposes section of the
Industrial Process chapter.

Total emissions  of CO2 from ammonia production in 2010 were 8.7 Tg CO2 Eq. (8,678 Gg), and are summarized in
126 See


4-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 4-19 and Table 4-20. The observed decrease in ammonia production and associated CO2 emissions between
2007 and 2009 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 natural gas prices (EEA 2004). The 2010 increase in ammonia production (and
associated CO2 emissions) is largely attributable to dramatically lower natural gas prices in the U.S. after 2009 (EIA
2011).

Table 4-19:  CO2 Emissions from Ammonia Production (Tg CO2 Eq.)


   Source                  1990         2005    2006     2007     2008     2009    2010~
   Ammonia Production       13.0	9.2      8.8      9.1       7.9      7.9      8.7
   Total                   13.0          9.2      8.8      9.1       7.9      7.9      8.7
Table 4-20: CO2 Emissions from Ammonia Production (Gg)
Source
Ammonia Production
Total
1990
13,047
13,047
2005
9,196
9,196
2006
8,781
8,781
2007
9,074
9,074
2008
7,883
7,883
2009
7,855
7,855
2010
8,678
8,678
Methodology

The calculation methodology for non-combustion CO2 emissions from production of synthetic ammonia from
natural gas feedstock is based on the 2006IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006).
The method utilizes a CO2 emission factor published by the European Fertilizer Manufacturers Association (EFMA)
that is based on natural gas-based ammonia production technologies that are similar to those employed in the United
States. 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. The CO2 emissions reported for ammonia
production are reduced by a factor of 0.733 multiplied by total annual domestic urea production.  This corresponds
to a stochiometric CO2/urea factor of 44/60, assuming complete conversion of NHs and CCh to urea (IPCC 2006,
EFMA 2000).

All synthetic 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 for the petroleum coke
feedstock process (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
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 U.S. for use of natural gas as a feedstock.  The EFMA reference
also indicates that more than 99 percent of the CH4 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


                                                                              Industrial Processes   4-19

-------
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 4-21) was  obtained from Coffeyville Resources (Coffeyville 2005, 2006,
2007a, 2007b, 2009, 2010, and 2011) and the Census Bureau of the U.S. Department of Commerce (U.S. Census
Bureau 1991 through 1994, 1998 through 2011) 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, 2007b, 2009, 2010, 2011).  Urea production data for 1990 through 2008
were obtained from the Minerals Yearbook: Nitrogen (USGS 1994 through 2009). Urea production data for 2009
through 2010 were obtained from the U.S. Bureau of the Census (2011).

Table 4-21: Ammonia Production and Urea Production (Gg)
   Year   Ammonia Production    Urea Production
   1990          15,425              7,450
2005
2006
2007
2008
2009
2010
10,143
9,962
10,393
9,570
9,372
10,084
5,270
5,410
5,590
5,240
5,084
5,122
Uncertainty and Time-Series Consistency

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. Uncertainty is also associated with the representativeness of the emission factor
used for the petroleum coke-based ammonia process.  It is also assumed that ammonia and urea are produced at
collocated plants from the same natural gas raw material.

Recovery of CO2 from ammonia production plants for purposes other than urea production (e.g., commercial sale)
has not been considered in estimating the CO2 emissions from ammonia production, as data concerning the
disposition of recovered CO2 are not available. 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.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-22.  Ammonia Production CO2
emissions were estimated to be between 7.8 and 10.9 Tg CO2 Eq. at the 95 percent confidence level. This indicates
a range of approximately 10 percent below and 25 percent above the emission estimate of 8.7 Tg CO2 Eq.

Table 4-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Production (Tg CO2 Eq.
and Percent)


                             2010 Emission Estimate      Uncertainty Range Relative to Emission Estimate3
   Source	Gas     (Tg CO2 Eq.)	(Tg CO2 Eq.)	(%)	
  	Lower Bound    Upper Bound     Lower Bound    Upper Bound
   Ammonia Production	CO2	8/7	7.8	10.9	-10%	+25%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4-20  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations Discussion

For the current Inventory, emissions resulting from non-agricultural urea consumption have been transferred from
the Ammonia Production section to a new section within the Industrial Process chapter titled Urea Consumption for
Non-Agricultural Purposes. From 1990 to 2009, urea consumption for non-agricultural purposes accounted for an
average of 27 percent of the combined emissions from ammonia production and non-agricultural urea consumption
each year.

Planned  Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Ammonia Production source category. Particular attention will be made to
ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.127 Specifically, the planned improvements include assessing data to update the emission factors to include
both fuel and feedstock CO2 emissions and incorporate 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.

4.6.    Urea Consumption for Non-Agricultural Purposes

Urea is used as a nitrogenous fertilizer for agricultural applications and also in a variety of industrial applications.
Urea's industrial applications include its use as adhesives, binders, sealants, resins, fillers, analytical reagents,
catalysts, intermediates, solvents, dyestuffs, fragrances, deodorizers, flavoring agents, humectants and dehydrating
agents, formulation components, monomers, paint and coating additives, photosensitive agents, and surface
treatments agents. In addition, urea is used for abating nitrous oxide emissions from coal-fired power plants and
diesel transportation motors.

Urea is produced using ammonia and CO2 as raw materials. All urea produced in the U.S. is assumed to be produced
at ammonia production facilities where both ammonia and CO2 are generated. The chemical reaction that produces
urea is:

                            2 NH3 + CO2 ->  NH2COONH4 -» CO(NH2)2 + H2O

This section accounts for CO2 emissions associated with urea consumed exclusively for non-agricultural purposes.
CO2 emissions associated with urea consumed for fertilizer  are accounted for in the Cropland Remaining Cropland
section of the Land Use, Land-Use Change, and Forestry chapter.

Emissions of CO2 from urea consumed for non-agricultural  purposes in 2010 were estimated to be 4.4 Tg CO2 Eq.
(4,365 Gg), and are summarized in Table 4-23 and Table 4-24.
127 See
                                                                              Industrial Processes   4-21

-------
Table 4-23: CO2 Emissions from Urea Consumption for Non-Agricultural Purposes (Tg CO2 Eq.)


   Source                 1990        2005     2006    2007     2008    2009     2010~
   Urea Consumption	3.8	3.7      3.5      4.9      4.1     3.4      4.4
   Total                    3.8          3.7      3.5      4.9      4.1     3.4      4.4
Table 4-24: CO2 Emissions from Urea Consumption for Non-Agricultural Purposes (Gg)
Source
Urea Consumption
Total
1990
3,784
3,784
2005
3,653
3,653
2006
3,519
3,519
2007
4,944
4,944
2008
4,065
4,065
2009
3,415
3,415
2010
4,365
4,365
Methodology

Emissions of CO2 resulting from urea consumption for non-agricultural purposes are estimated by multiplying the
amount of urea consumed in the U.S. for non-agricultural purposes by a factor representing the amount of CO2 used
as a raw material to produce the urea. This method is based on the assumption that all of the C in urea is released
into the environment as CO2 during use.

The amount of urea consumed for non-agricultural purposes in the U.S. 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 4-25, from the total domestic supply of urea.  The domestic supply of urea
is estimated based on the amount of urea produced plus the sum of net urea imports and exports. A factor of 0.73
tons of CO2 per ton of urea consumed is then applied the resulting supply of urea for non-agricultural purposes to
estimate CO2 emissions from the amount of urea consumed for non-agricultural purposes. The 0.733 tons of CO2 per
ton of urea emission factor is based on the stoichiometry of producing urea from ammonia and CO2. This
corresponds to a stochiometric CO2/urea factor of 44/60, assuming complete conversion of NH3 and CO2 to urea
(IPCC 2006, EFMA 2000).

Urea production data for 1990 through 2008 were obtained from the Minerals Yearbook: Nitrogen (USGS 1994
through 2009). Urea production data for 2009 through 2010 were obtained from the U.S. Bureau of the Census
(2011). 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 2010 (U.S. Census Bureau 1998
through 2011), The Fertilizer Institute (TFI2002) 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 4-25).  Urea
export data for  1990 through 2010 were taken from U.S. Fertilizer Import/Exports from USDA Economic Research
Service Data Sets (U.S. Department of Agriculture 2011).
4-22  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 4-25: Urea Production, Urea Applied as Fertilizer, Urea Imports, and Urea Exports (Gg)

   Year    Urea Production   Urea Applied   Urea Imports   Urea Exports
                             as Fertilizer
   1990
7,450
3,296
1,860
854
2005
2006
2007
2008
2009
2010
5,270
5,410
5,590
5,240
5,084
5,122
4,779
4,985
5,097
4,925
4,925
4,925
5,026
5,029
6,546
5,459
4,727
6,631
536
656
271
230
289
152
Uncertainty and Time-Series Consistency

The amount of urea used for non-agricultural purposes is estimated based on estimates of urea production, urea
imports, urea exports, and the amount of urea used as fertilizer. The primary uncertainties associated with this
source category are associated with the accuracy of these estimates as well as the fact that each estimate is obtained
from a different data source. There is also uncertainty associated with the assumption that all of the C in urea is
released into the environment as CO2 during use.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-26. CO2 emissions associated
with urea consumption for non-agricultural purposes were estimated to be between 2.3 and 5.0 Tg CO2 Eq. at the 95
percent confidence level. This indicates a range of approximately 47 percent below and 15 percent above the
emission estimate of 4.4 Tg CO2 Eq.

Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Urea Consumption for Non-
Agricultural Purposes (Tg CO2 Eq. and Percent)
   Source
             2010 Emission Estimate
          Gas    (Tg CO2 Eq.)
                       Uncertainty Range Relative to Emission Estimate3
                        (Tg CO; Eq.)	(%)	
                                       Lower Bound    Upper Bound     Lower Bound    Upper Bound
   Urea Consumption for
   Non-Agricultural
   Purposes	
          CO,
     4.4
 2.3
  5.0
-47%
+15%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned  Improvements

Future improvements to the urea consumption for non-agricultural purposes source category involve continuing to
research obtaining data on how much urea is consumed for specific applications in the United States and whether C
is released to the environment fully during each application.

4.7.    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.
                                                                             Industrial Processes    4-23

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Currently, the nitric acid industry controls for emissions of NO and NO2 (i.e., NOX). As such, the industry in the US
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. As of 2010,
approximately 32 percent of nitric acid plants use NSCR, representing 17.3 percent of estimated national production
(EPA 2010). The remaining 82.7 percent of production occurs using SCR or extended absorption, neither of which
is known to reduce N2O emissions.

N2O emissions from this source were estimated to be 16.7 Tg CO2 Eq. (54 Gg) in 2010 (see Table 4-27).  Emissions
from nitric acid production have decreased by 5.1 percent since 1990, with the trend in the time series closely
tracking the changes in production. Emissions increased 15.3 percent between 2009 and 2010.  Emissions have
decreased by 20 percent since 1997, the highest year of production in the time series.

Table 4-27: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.     Gg
   1990       17.6         57
2005
2006
2007
2008
2009
2010
16.4
16.1
19.2
16.4
14.5
16.7
53
52
62
53
47
54
Methodology

N2O 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 two known emission factors: 2 kg
N2O/metric ton HNO3 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.

In 2009, several nitric acid production facilities that did not have NSCR abatement systems installed were closed
(Desai 2012). As a result, as of 2010 approximately 32 percent of HNO3 plants in the United States are equipped
withNSCR representing 17.3 percent of estimated national production (EPA 2010).

Hence, the emission factor used for 2010 is equal to the production-weighted emission factor based on the
production at facilities with and without NSCR and the associated emission factors, equating to:

 (2 kg N2O/metric ton HNO3 produced x 0.173) + (9 kg N2O/metric ton HNO3 produced x 0.827) = 7.8 kg N2O per
metric ton HNO3.

The emission factor used for years prior to the plant closures (i.e., 1990-2009) is equal to:

 (2 kg N2O/metric ton HNO3 produced * 0.153) + (9 kg N2O/metric ton HNO3 produced * 0.847) = 7.9 kg N2O per
metric ton HNO3

Nitric acid production data for the U.S. for 1990 through 2002 were obtained from the U.S. Census Bureau (2010b);
2003 production data were obtained from the U.S. Census Bureau (2008); 2004 through 2007 production data were
obtained from the U. S. Census Bureau (2009); 2008 and 2009 production data were obtained from the U. S. Census
Bureau (2010a); and 2010 production data were obtained from the U.S. Census Bureau (2011) (see Table 4-28).

Table 4-28: Nitric Acid Production (Gg)
4-24  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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    Year      Gg
    1990     7,195
2005
2006
2007
2008
2009
2010
6,711
6,572
7,827
6,686
5,924
6,931
 Uncertainty and Time-Series Consistency

 Uncertainty associated with the parameters used to estimate N2O emissions includes that of production data, the
 share of U.S. nitric acid production attributable to each emission abatement technology over the time series, and the
 emission factors applied to each abatement technology type. While some information has been obtained through
 outreach with industry associations, limited information is readily available over the time series for a variety of
 facility level variables, including plant specific production levels, abatement technology type and installation date
 and accurate destruction and removal efficiency rates.  Some information will be available through EPA's reporting
 program, but this data is not available over the time series.

 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-29. N2O emissions from nitric
 acid production were estimated to be between 10.1 and 23.9 Tg CO2 Eq. at the 95 percent confidence level. This
 indicates a range of approximately 39 percent below to 40 percent above the 2010 emissions estimate of 16.7 Tg
 C02Eq.

 Table 4-29: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
 and Percent)
                                2010 Emission           Uncertainty Range Relative to Emission Estimate3
        Source           Gas      Estimate   	(Tg CO2 Eq.)	(%)	
	(Tg CO2 Eq.)   Lower Bound   Upper Bound    Lower Bound    Upper Bound
  Nitric Acid Production    N2O        16.7           10.1           23.9           -39%           +40%
 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
 through 2010. Details on the emission trends through time are  described in more detail in the Methodology section,
 above.

 Planned Improvements

 Future improvements to the Nitric Acid Production category involve research into the availability of facility level
 nitric acid production data, abatement technology type and installation dates, more accurate destruction and removal
 efficiency percentages, the current and past share of nitric acid  production attributable to various abatement
 technologies, as well as efforts to analyze data reported under EPA's GHGPJ3. These research efforts are especially
 important given the cancellation of the U.S. Census Bureau's Current Industrial Reports data series, from which
 national Nitric Acid production data are derived. Furthermore,  in examining data from EPA's GHGRP that would be
 useful to improve the emission estimates for nitric acid production category, particular attention will be made to
 ensure time series consistency, as the facility-level reporting data from EPA's GHGPJ3 are not available for all
 inventory years as reported in this inventory. In implementing improvements and integration of data from EPA's
                                                                                Industrial Processes   4-25

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GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.128

4.8.    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. In 2010, the United States had two companies with a total of
three adipic acid production facilities, two of which were operational (CW 2007; Desai 2010; VA DEQ 2009). The
United States accounts for the largest share of global adipic acid production capacity (30 percent),  followed by the
European Union (29 percent) and China (22 percent) (SEI 2010).  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.
84 percent of all adipic acid produced in the United States is used in the production of nylon 6,6; nine percent is
used in the production of polyester polyols; four percent is used in the production of plasticizers; and the remaining
four 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.  N2O 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). One small plant, which last operated in April 2006 and represented  approximately two percent
of production, did not control for N2O (VA DEQ 2009; ICIS 2007; VA DEQ 2006).

Very little information on annual trends in the activity data exist for adipic acid. Primary production data is derived
from the American Chemistry Council (ACC) Guide to the Business of Chemistry, which does not provide source
specific trend information. The USGS does not currently publish a Minerals Yearbook for adipic acid, and it is not
included in the general USGS Minerals Commodity Summary.

N2O emissions from adipic acid production were estimated to be 2.8 Tg CO2  Eq. (9.1 Gg) in 2010  (see Table 4-30).
National adipic acid production has increased by approximately 4 percent over the period of 1990 through 2010, to
roughly 760,000 metric  tons. Over the same period, emissions have been reduced by 82 percent due to both the
widespread installation of pollution control measures in the late 1990s and plant idling in  the late 2000s.  In April
2006, the smallest of the four facilities ceased production of adipic acid (VA  DEQ 2009); furthermore, one of the
major adipic acid production facilities was not operational in 2009 or 2010(Desai 2010). Due to  a lack of data, 2010
emissions from adipic acid production were assumed to be equal to 2009 estimates.

Table 4-30: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg)
   Year     Tg CO2 Eq.      Gg
   1990        15.8          51
2005
2006
2007
2008
2009
2010
7.4
8.9
10.7
2.6
2.8
2.8
24
28.7
34.4
8.3
9.1
9.1
128 See


4-26  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Methodology

Due to confidential business information, plant names are not provided in this section. The four adipic acid-
producing plants will henceforth be referred to as Plants 1 through 4.

For Plants 1 and 2, 1990 to 2009 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 (Desai 2010). These estimates were
based on continuous process monitoring equipment installed at the two facilities. In 2009 and 2010, no adipic acid
production occurred at Plant 1. For Plant 4, 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 for plants lacking emissions monitoring data were 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])

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 (Plants 1 and 2), one plant employs thermal destruction (Plant 3), and the smallest plant that
closed in 2006 used no N2O abatement equipment (Plant 4).

For Plant 3, 2005 through 2009 emissions were obtained directly from the plant engineer (Desai 2012). For 1990
through 2004, emissions were estimated using plant-specific production data and IPCC  factors as described above
for Plant 4. Production data for 1990 through 2003 was estimated by allocating national adipic acid production data
to the plant level using the ratio of known plant capacity to total national capacity for all U.S. plants. For 2004,
actual plant production data were obtained and used for emission calculations (CW 2005).

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 Reporter, "Chemical Profile: Adipic Acid"
(CMR 2001). For 2001 through 2003, the plant capacities for three plants were kept the same as the year 2000
capacities.  Plant capacity for 1999 to 2003 for the one remaining plant was kept the same as  1998.  For Plant 4,
which last operated in April 2006 (VA DEQ 2009), plant-specific production data were obtained across the time
series from 1990 through 2008 (VA DEQ 2010).  Since the plant has not operated since 2006, production through
2010 was assumed to be zero. The plant-specific production data were then used for calculating emissions as
described above.

National adipic acid production data (see Table 4-31) from 1990 through 2010 were obtained from the American
Chemistry Council (ACC 2011).

Table 4-31: Adipic Acid Production  (Gg)
   Year      Gg
   1990735~

   2005      903
   2006      964
   2007      930
   2008      869
   2009      819
   2010      764
                                                                               Industrial Processes   4-27

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Uncertainty and Time-Series Consistency

Uncertainty associated with N2O emission estimates included that of the methods used by companies to monitor and
estimate emissions and the use of 2009 emissions data as a proxy for 2010.

The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-32. N2O emissions from
adipic acid production for 2010 were estimated to be between 2.6 and 3.1 Tg CO2 Eq. at the 95 percent confidence
level. These values indicate a range of approximately 9 percent below to 9 percent above the 2010 emission
estimate of 2.8 Tg CO2 Eq.

Table 4-32: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
Eq. and Percent)

                        2010 Emission Estimate       Uncertainty Range Relative to Emission Estimate3
   Source	Gas    (Tg CO2 Eq.)       (Tg CO2 Eq.)	(%)	
 	Lower Bound    Upper Bound    Lower Bound    Upper Bound
   Adipic Acid Production     N2O      2.8	2.6	3.1	-9%	+9%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Adipic Acid Production source category. Particular attention will be made to
ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.129 Specifically, the planned improvements include assessing data to update the N2O emission factors and
update abatement utility and destruction factors based on actual performance of the latest catalytic and thermal
abatement equipment at plants with continuous process and emission monitoring equipment.

Recalculations

For the current Inventory, plant specific N2O emissions data for Plant 3 were obtained directly from the plant
engineer for 2005 through 2009.  In the previous Inventory, 2005 through 2009 estimates of N2O emissions from
adipic acid production at Plant 3 were developed using plant production data. For the 1990 through 2009 inventory,
Plant 3 emissions for, which uses thermal destruction, the N2O abatement system destruction factor was assumed to
be 98.5 percent, and the abatement system utility factor was assumed to be 97 percent (IPCC 2006).  This
recalculation resulted in an 84 percent increase in average annual estimated N2O emissions from adipic acid
production between 2005 and 2009, relative to the previous report.

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

Carbon dioxide and CH4 are emitted from the production130 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)
129 See
13° 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.


4-28  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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 2006a).Markets for manufactured abrasives, including
SiC, are heavily influenced by activity in the U.S. manufacturing sector, especially in the aerospace, automotive,
furniture, housing, and steel manufacturing sectors. As a result of the economic downturn in 2008 and 2009, demand
for SiC decreased in those years.  Low cost imports, particularly from China, combined with high relative operating
costs for domestic producers, continue to put downward pressure on the production of SiC in the United States.
However, demand for SiC consumption in the United States has recovered somewhat from its lows in 2009 (USGS
201 la).

Carbon dioxide emissions from SiC production and consumption in 2010 were 0.18 Tg CO2 Eq. (181 Gg).
Approximately 51  percent of these emissions resulted from SiC production while the remainder resulted from SiC
consumption. Methane emissions from SiC production in 2010 were 0.01 Tg CO2 Eq.  CH4 (0.4 Gg) (see Table 4-33
and Table 4-34).

Table 4-33: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Tg CO2 Eq.)
Year
C02
CH4
Total
1990
0.4
+
0.4
2005
0.2
+
0.2
2006
0.2
+
0.2
2007
0.2
+
0.2
2008
0.2
+
0.2
2009
0.1
+
0.2
2010
0.2
+
0.2
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.
Table 4-34: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Gg)
Year
C02
CH4
1990
375
i H
2005
219
+
2006
207
+
2007
196
+
2008
175
+
2009
145
+
2010
181
+
   + Does not exceed 0.5 Gg.
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 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 for metallurgical uses were calculated by multiplying the
annual utilization of SiC for metallurgical uses (reported annually in the USGS Minerals Yearbook for Silicon) by
the C content of SiC (31.5 percent), which was determined according to the molecular weight ratio of SiC.

Emissions of CO2from silicon carbide consumption for other non-abrasive uses were calculated by multiplying the
remaining annual SiC consumption (total SiC consumption minus SiC utilization for metallurgical uses) by the
emissive utilization percentage for SiC utilization for other non-abrasive uses (50 percent) (USGS 2009).

Production data for 1990 through 2009 were obtained from the Minerals Yearbook: Manufactured Abrasives (USGS
1991a through 2010a and 201 Ib).  Production data for 2010 was taken from the Minerals Commodity Summary:
Abrasives (Manufactured) (201 la). Silicon carbide consumption by major end use was obtained from the Minerals
Yearbook: Silicon (USGS 1991b through 2010b and 201 Ic) (see Table 4-35) foryears 1990 through 2009. Silicon
carbide consumption for 2010 is proxied using 2009 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 2011).
                                                                             Industrial Processes    4-29

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Table 4-35: Production and Consumption of Silicon Carbide (Metric Tons)
   Year    Production    Consumption
   1990      105,000         172,465
   2005      35,000         220,149
2006
2007
2008
2009
2010
35,000
35,000
35,000
35,000
35,000
199,937
179,741
144,928
92,280
154,540
Uncertainty and Time-Series Consistency

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 CH4, there is also uncertainty associated with the hydrogen-containing volatile
compounds in the petroleum coke (IPCC 2006). There is also uncertainty associated with the use or destruction of
methane generated from the process in addition to uncertainty associated with levels of production, net imports,
consumption levels, and 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 4-36. Silicon carbide production
and consumption CO2 emissions were estimated to be between 9 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 were
estimated to be between 9 percent below and 9 percent above the emission estimate of 0.01 Tg CO2 Eq. at the 95
percent confidence level.

Table 4-36: Tier 2 Quantitative Uncertainty Estimates for CH4 and CO2 Emissions from Silicon Carbide Production
and Consumption (Tg CO2 Eq. and Percent)

                             2010 Emission Estimate    Uncertainty Range Relative to Emission Estimate3
   Source	Gas  (Tg CO2 Eq.)      (Tg CO2 Eq.)	(%)	
 	Lower Bound    Upper Bound    Lower Bound   Upper Bound
   Silicon Carbide Production
    and Consumption          CO2      0.2       0.2         0.2            -9%          +10%
   Silicon Carbide Production    CH4	+	+	+	-9%	+9%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
   + Does not exceed 0.05 Tg CO2 Eq. or 0.5 Gg.

Methodological recalculations were applied to the entire time-series  to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Silicon Carbide Production source category. Particular attention will be made
to  ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
4-30  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.13! In addition, improvements will involve 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. Additionally, as future improvement to the silicon carbide uncertainty
analysis, USGS Mineral Commodity Specialists will be contacted to verify the uncertainty range associated with
silicon carbide emissive utilization.

4.10.  Petrochemical Production (IPCC Source Category 2B5)

The production of some petrochemicals results in the release of small amounts of CH4 and CO2 emissions.
Petrochemicals are chemicals isolated or derived from petroleum or natural gas. Methane emissions are presented
here from the production of carbon black, ethylene, ethylene dichloride, and methanol, while CO2 emissions are
presented here for only carbon black production. The CO2 emissions  from petrochemical processes other than
carbon black are currently included in the Carbon Stored in Products from Non-Energy Uses of Fossil Fuels Section
of the Energy chapter.  The CO2 from carbon 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 carbon black produced in the United States is added to rubber to impart strength and abrasion
resistance, and the tire industry is by far the largest consumer.  Ethylene is consumed in the production processes of
the plastics industry including polymers such as high, low, and linear  low density polyethylene (HDPE, LDPE,
LLDPE), polyvinyl chloride (PVC), ethylene dichloride, ethylene oxide, and ethylbenzene. Ethylene dichloride is
one of the first manufactured chlorinated hydrocarbons with reported  production as early as 1795. In addition to
being an important intermediate in the synthesis of chlorinated hydrocarbons, ethylene dichloride is used as an
industrial solvent and as a fuel additive. 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 2010  were 3.3 Tg CO2 Eq.  (3,336 Gg) and 0.9 Tg CH4
Eq. (44 Gg), respectively (see Table 4-37 and Table 4-38), totaling  4.3 Tg CO2 Eq. There has been an overall
increase in CO2 emissions from carbon black production of one percent since 1990. Methane emissions from
petrochemical production have increased by approximately seven percent since 1990.

Table 4-37: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.)
Year
C02
CH4
Total
1990
3.3
0.9
4.2
2005
4.2
1.1
5.3
2006
3.8
1.0
4.8
2007
3.9
1.0
4.9
2008
3.4
0.9
4.3
2009
2.7
0.8
3.6
2010
3.3
0.9
4.3
   Note: Totals may not sum due to independent rounding.


Table 4-38: CO2 and CH4 Emissions from Petrochemical Production (Gg)


   Year       1990          2005      2006      2007       2008      2009      2010
   CO2        3,311         4,181      3,837      3,931      3,449     2,735      3,336
   CH4	41	51	48	48	43	39	44
Methodology
Emissions of CH4 were calculated by multiplying annual estimates of chemical production by the appropriate
emission factor, as follows: 11 kg CHVmetric ton carbon black, 1 kg CH4/metric ton ethylene, 0.4 kg CH4/metric ton
131 See 
                                                                              Industrial Processes    4-31

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ethylene dichloride, ^2 ancj 2 kg CH4/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 4-39) were obtained from the American Chemistry Council's Guide to the Business of
Chemistry (ACC 2002, 2003, 2005 through 2011) and the International Carbon Black Association (Johnson 2003
and 2005 through 2011). Methanol production data for 1990 through 2007 were obtained from the ACC Guide to
the Business of Chemistry (ACC 2002, 2003, 2005 through 2011). The ACC discontinued its data series for
Methanol after 2007, so methanol production data for 2008 through 2010 was obtained through the Methanol
Institute (Jordan 201 la and 201 Ib).

Table 4-39:  Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Bichloride
Methanol
1990
1,307
16,541
6,282
3,785
• 2005
1,651
23,954
11,260
| 2,336
2006
1,515
25,000
9,736
1,123
2007
1,552
25,392
9,566
1,068
2008
1,362
22,539
8,981
810
2009
1,080
22,596
8,131
810
2010
1,317
23,961
8,820
903
Almost all carbon black in the United States is produced from petroleum-based or coal-based feedstocks using the
"furnace black" process (European IPPC Bureau 2004).  The furnace black process is a partial combustion process
in which a portion of the carbon black feedstock is combusted to provide energy to the process.  Carbon black is also
produced in the United States by the thermal cracking of acetylene-containing feedstocks ("acetylene black
process") and by the thermal cracking of other hydrocarbons ("thermal black process").  One U.S carbon black plant
produces carbon black using the thermal black process, and one U.S. carbon black plant produces carbon black
using the acetylene black process (The Innovation Group 2004).

The furnace black process produces carbon black from "carbon black feedstock" (also referred to as "carbon black
oil"), which is a heavy aromatic oil that may be derived as a byproduct of either the petroleum refining process or
the metallurgical (coal) coke production process.  For the production of both petroleum-derived and coal-derived
carbon black, the "primary feedstock" (i.e., carbon black feedstock) is injected into a furnace that is heated by a
"secondary feedstock" (generally natural gas). Both the  natural gas secondary feedstock and a portion of the carbon
black feedstock are oxidized to provide heat to the production process and pyrolyze the remaining carbon black
feedstock to carbon black. The "tail gas" from the furnace black process contains CC>2, carbon monoxide, sulfur
compounds, CH4, and non-CH4 volatile organic compounds. A portion of the tail gas is generally burned for energy
recovery to heat the downstream carbon black product dryers. The remaining tail gas may also be burned for energy
recovery, flared, or vented uncontrolled to the atmosphere.

The calculation of the C lost during the production process is the basis for determining the amount of CO2 released
during the process.  The C content of national carbon black production is subtracted from the total amount of C
contained in primary and secondary carbon 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 CH4 or CO2.  The C
content of the CH4 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 carbon black feedstock
consumed in the process (see Table 4-40) is estimated using a primary feedstock consumption factor and a
secondary feedstock consumption factor estimated from  U.S. Census Bureau (1999, 2004, and 2007) data. The
average carbon black feedstock consumption factor for U.S. carbon black production is 1.69 metric tons of carbon
black feedstock consumed per metric ton of carbon black produced. The average natural gas consumption factor for
U.S. carbon black production is 321 normal cubic meters of natural gas consumed per metric ton of carbon 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).
132 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).


4-32  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 4-40:  Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
Consumption (Thousand Metric Tons)


   Activity                   1990        2005     2006    2007    2008    2009    2010
   Primary Feedstock         2,213 I      2,794    2,564   2,627   2,305   U£82,230
   Secondary Feedstock        284         359      329    337    296    235     286
For the purposes of emissions estimation, 100 percent of the primary carbon black feedstock is assumed to be
derived from petroleum refining byproducts.  Carbon black feedstock derived from metallurgical (coal) coke
production (e.g., creosote oil) is also used for carbon black production; however, no data are available concerning
the annual consumption of coal-derived carbon black feedstock. Carbon black feedstock derived from petroleum
refining byproducts is assumed to be 89 percent elemental C (Srivastava et al. 1999).  It is assumed that 100 percent
of the tail gas produced from the carbon black production process is combusted and that none of the tail gas is
vented to the atmosphere uncontrolled.  The furnace black process is assumed to be the only process used for the
production of carbon black because of the lack of data concerning the relatively small amount of carbon black
produced using the acetylene black and thermal black processes. The carbon black produced from the furnace black
process is assumed to be 97 percent elemental C (Othmer et al. 1992).

Uncertainty and Time-Series Consistency

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 carbon black production calculation
are based on feedstock consumption, import and export data, and carbon black production data. The composition of
carbon black feedstock varies depending upon the specific refinery production process, and therefore the assumption
that carbon black feedstock is 89 percent C gives rise to uncertainty.  Also, no data are available concerning the
consumption of coal-derived carbon 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 carbon black production may be underreported by the U.S. Census Bureau. Finally, the
amount of carbon 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 carbon black is produced using the furnace black process.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-41. Petrochemical production
CO2 emissions were estimated to be between 2.5 and 4.3 Tg CO2 Eq. at the 95 percent confidence level.  This
indicates a range of approximately 26 percent below to 29 percent above the emission estimate of 3.3 Tg CO2 Eq.
Petrochemical production CH4 emissions were estimated to be between 0.7 and 1.2 Tg CO2 Eq. at the 95 percent
confidence level. This indicates a range of approximately 29 percent below to 30 percent above the emission
estimate of 0.9 Tg CO2 Eq.

Table 4-41: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
Emissions from Carbon Black Production (Tg CO2 Eq. and Percent)

   Source               Gas    2010 Emission Estimate          Uncertainty Range Relative to Emission Estimate3
                                 (Tg CO, Eq.)	(Tg CO, Eq.)	(%)
Lower Bound Upper Bound
Petrochemical
Production
Petrochemical
Production
C02
CH4
3.3
0.9
2.5
0.7
4.3
1.2
Lower Bound
-26%
-29%
Upper Bound
+29%
+30%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
                                                                               Industrial Processes   4-33

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Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations

Methanol production data for 2008 and 2009 was updated relative to the previous report based on correspondence
with Jim Jordan of Jordan Associates (Jordan 201 la and 20 lib). This resulted in a decrease of total CO2 and CH4
emissions from petrochemical production of less than 1 percent.

Planned  Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Petrochemical Production source category. Particular attention will be made
to ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.133 Additional future improvements involve updating the methodology to use CH4 emission factors for
petrochemical production from the IPCC 2006 guidelines rather than the IPCC 1996 guidelines and assessing the
data EPA obtains to update data sources for acrylonitrile production in the United States.

4.11.  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:

                            2 FeTiOs + 7 C12 + 3 C -» 2 TiCl4 + 2 FeCl3 + 3 CO2

                                     2 TiCl4 + 2 O2 -» 2 TiO2 + 4 C12

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 2010 were  1.9 Tg CO2 Eq. (1,876 Gg), which represents an increase of 57 percent since 1990
(see Table 4-42).

Table 4-42: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.	Gg
   1990        1.2         1,195
2005
2006
2007
2008
2009
2010
1.8
1.8
1.9
1.8
1.6
1.9
1,755
1,836
1,930
1,809
1,648
1,876
133 See


4-34  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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; therefore, 100 percent of post-2004 production uses 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).

The emission factor for the TiO2 chloride process was taken from the 2006IPCC 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 2009 (see Table 4-43) were obtained through the
Minerals Yearbook: Titanium Annual Report (USGS 1991 through 201 Ib).  Production data for 2010 was obtained
from the Minerals Commodity Summary: Titanium and Titanium Dioxide (USGS 201 la). Due to lack of available
2010 capacity data at the time of publication, the 2009 capacity estimate is used as a proxy for 2010. Percentage
chloride-process data were not available for  1990 through 1993, so 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).

Table 4-43: Titanium Dioxide Production (Gg)
    Year       Gg
    1990       979
2005
2006
2007
2008
2009
2010
1,310
1,370
1,440
1,350
1,230
1,400
Uncertainty and Time-Series Consistency

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 (since, as of 2004, the last remaining sulfate-process plant in the United States
closed). 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
                                                                               Industrial Processes    4-35

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process; however, this composition information was not available.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-44. 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 13 percent below and 13 percent above the emission estimate of 1.9
Tg C02 Eq.

Table 4-44: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
CO2 Eq. and Percent)


   Source                     Gas     2010 Emission Estimate   Uncertainty Range Relative to Emission Estimate3
 	(Tg CO; Eq.)	(Tg C02 Eq.)	(%)	
 	Lower Bound   Upper Bound   Lower Bound   Upper Bound
   Titanium Dioxide Production    CO2	L9	L6	211	-13%	+13%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from  1990
through 2010. Details on the emission trends  through time are described in more detail in the Methodology section,
above.

Recalculations

Production data for 2009 were updated relative to the previous Inventory based on recently published data in the
USGS Minerals Yearbook: Titanium 2009 (USGS 2011). This resulted in a 7 percent decrease in 2009 CO2
emissions from TiO2 production relative to the previous report.

Planned Improvements

Future improvements involve  evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Titanium Dioxide source category. Particular attention will be made  to
ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.134 In addition, the planned improvements 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.

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

CO2 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.

CO2 is produced from naturally occurring CO2 reservoirs, as a byproduct from the 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
134 See


4-36  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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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.

CO2 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 three facilities (one in Mississippi and two 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). A fourth facility in Colorado is producing CO2 from naturally occurring CO2 reservoirs for
commercial applications only. There are other naturally occurring CO2 reservoirs, mostly located in the western
United States, that produce CO2 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 2010, the amount of CO2 produced by the Colorado, Mississippi, and New Mexico facilities for commercial
applications and subsequently emitted to the atmosphere was 2.2 Tg CO2Eq. (2,203 Gg) (see Table 4-45).  This is
an increase of 23 percent from the previous year and an increase of 56 percent since 1990. This increase was largely
due to an in increase in production at the Mississippi facility, despite the low percentage (13 percent) of the facility's
total reported production that was used for commercial applications in 2010.

Table 4-45:  CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.      Gg
   1990        1.4         1,416
2005
2006
2007
2008
2009
2010
1.3
1.7
1.9
1.8
1.8
2.2
1,321
1,709
1,867
1,780
1,784
2,203
Methodology
CO2 emission estimates for 1990 through 2010 were based on production data for the four 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.
CO2 production data for the Jackson Dome, Mississippi facility and the percentage of production that was used for
non-EOR applications were obtained from Advanced Resources International (ARI 2006, 2007) for 1990 to 2000
1^5 There are currently four known electric power plants operating in the U.S. that capture CO2 for use as food-grade CO2 or
other industrial processes; however, insufficient data prevents estimating emissions from these activities as part of CO2
Consumption.


                                                                               Industrial Processes    4-37

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and from the Annual Reports of Denbury Resources (Denbury Resources 2002 through 2011) for 2001 to 2010 (see
Table 4-46). Denbury Resources reported the average CO2 production in units of MMCF CO2 per day for 2001
through 2010 and reported the percentage of the total average annual production that was used for EOR. Production
from 1990 to 2000 was set equal to 2001 production. Carbon dioxide production data for the Bravo Dome, New
Mexico facilities were obtained from ARI (ARI 1990 through 2011). Data for the West Bravo Dome facility was
only available for 2009 and 2010. The percentage of total production that was used for 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). Production data for the McCallum Dome, Colorado facility were
obtained from the Colorado Oil and Gas  Conservation Commission (COGCC) for 1999 through 2010 (COGCC
2011). Production data for 1990 to 1998 and percentage of production used for EOR were assumed to be the same
as for 1999.

Table 4-46: CO2 Production (Gg CO2) and the Percent Used for Non-EOR Applications
   Year   Jackson Dome CO2
            Production (Gg)
             (% Non-EOR)
          Bravo Dome CO2
           Production (Gg)
            (% Non-EOR)
West Bravo Dome
 CO2 Production
  (Gg) (% Non-
      EOR)
 McCallum Dome
  CO2 Production
   (Gg)  (% Non-
      EOR)
   1990
2005
2006
2007
2008
2009
2010
4,677 (27%)
6,610 (25%)
9,529 (19%)
12,312(14%)
13,201 (13%)
16,487(13%)
5,798 (1%)
5,605 (1%)
5,605 (1%)
5,605 (1%)
4,639 (1%)
4,832 (1%)
-
-
-
-
2,126 (1%)
870 (1%)
0.06(100%)
0.06(100%)
0.07(100%)
0.07(100%)
0.02(100%)
0.05(100%)
Uncertainty and Time-Series Consistency

Uncertainty is associated with the number of facilities that are currently producing CO2from 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.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-47. Carbon dioxide
consumption CO2 emissions were estimated to be between 1.6 and 2.9 Tg CO2 Eq. at the 95 percent confidence
level.  This indicates a range of approximately 25 percent below to 30 percent above the emission estimate of 2.2 Tg
C02Eq.

Table 4-47: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and
Percent)
   Source
Gas   2010 Emission Estimate
      (Tg C02 Eq.)	
         Uncertainty Range Relative to Emission Estimate3
 (Tg C02 Eq.)	(3Q	
                                            Lower Bound    Upper Bound   Lower Bound   Upper Bound
   CO2 Consumption   CO2
           2.2
     1.6
2.9
-25%
+30%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
4-38  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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above.

Recalculations Discussion

For the current Inventory, two new facilities, the West Bravo and McCallum domes, were added to the time series.
The impact of these facilities upon emission estimates for the time series, relative to the previous report, is
negligible.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Carbon Dioxide Consumption source category. Particular attention will be
made to ensure time series consistency, as the facility -level reporting data from EPA's GHGPJ3 are not available for
all Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGPJ3, the latest guidance from the IPCC on the use of facility -level data in national inventories will be relied
upon. 136

4. 13.  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 My

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(P04)2 + 4H3P04 -> 3Ca(H2P04)2

                        3Ca(H2PO4)2 + 3H2SO4 + 6H2O -> 3CaSO4 • 6H2O + 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:

                             CaCO3 + H2SO4 +H2O -> CaSO4 • 2H2O + CO2

Total marketable phosphate rock production in 2010 was 25.8 million metric tons (USGS 201 1).  Approximately
87 percent of domestic phosphate rock production was mined in Florida and North Carolina, while approximately 13
percent of production was mined in Idaho and Utah.  Total imports of phosphate rock in 2010 were 2.4 million
metric tons (USGS 20 1 1). 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
stayed relatively flat between 2009 and 2010, decreasing by 2.3 percent between 2009 and 2010. Over the 1990 to
2010 period, domestic production has decreased by nearly 48 percent. Total CO2 emissions from phosphoric acid
production were 1.0 Tg CO2 Eq. (1,017 Gg)  in 2010 (see Table 4-48). After experiencing weak market conditions
136 See
                                                                            Industrial Processes   4-39

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due to the global economic downturn in 2008 and 2009, demand for and trade in phosphate rock increased in 2010
(USGS2011).

Table 4-48: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg)
    Year     Tg CO2 Eq.      Gg
    1990         1.5         1,529
2005
2006
2007
2008
2009
2010
1.4
1.2
1.2
1.2
1.0
1.0
1,386
1,167
1,166
1,187
1,018
1,017
Methodology

CO2 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 USGSMineral 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 4-49). For the years 1990, 1991,
1992, and 2005 through 2010, 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 average share of U.S. production in those states from 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 2010 were obtained from USGS Minerals Yearbook: Phosphate
Rock (USGS 1994 through 2011). From 2004 through 2010, the USGS reported no exports of phosphate rock from
U.S. producers (USGS 2005 through 2011).
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 4-50).

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.
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Table 4-49: Phosphate Rock Domestic Production, Exports, and Imports (Gg)
Location/Year
U.S. Production3
FL&NC
ID&UT
Exports— FL & NC
Imports — Morocco
1990
49,800
42,494
7,306
6,240
451
2005
36,100
31,227
4,874
2,630
2006
30,100
26,037
4,064
2,420
2007
29,700
25,691
4,010
2,670
2008
30,200
26,123
4,077
2,750
2009
26,400
22,836
3,564
2,000
2010
25,800
22,317
3,483
2,400
   Total U.S.
    Consumption	44,011	38,730    32,520   32,370     32,950     28,400     28,200
   a USGS does not disaggregate production data regionally (FL & NC and ID & UT) for 1990 and 2005 through
   2010. Data for those years are estimated based on the remaining time series distribution.
   - Assumed equal to zero.
Table 4-50: Chemical Composition of Phosphate Rock (percent by weight)
Composition
Total Carbon (as C)
Inorganic Carbon (as C)
Organic Carbon (as C)
Inorganic Carbon (as CO2)
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
   Source: FIPR 2003
   - Assumed equal to zero.


Uncertainty and Time-Series Consistency

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 2010.  For previous years in the time series,
USGS provided the data disaggregated regionally; however, beginning in 2006 only total U.S. phosphate rock
production were reported. Regional production for 2010 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 2010 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
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
                                                                               Industrial Processes    4-41

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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 4-51. Phosphoric acid
production CO2 emissions were estimated to be between 0.8 and 1.2 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 1.0 TgCO2
Eq.

Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
CO2 Eq. and Percent)

   Source                  Gas   2010 Emission Estimate   Uncertainty Range Relative to Emission Estimate3
 	(Tg CO, Eq.)       (Tg CO, Eq.)	(^	
 	Lower Bound  Upper Bound   Lower Bound    Upper Bound
   Phosphoric Acid Production   CO2	LO	0.8	L2	-18%	+18%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence  interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations

Phosphate rock import and production values for 2008 and 2009 were updated relative to the previous Inventory
based on recently published data (USGS 2011). This resulted in a decrease in 2008 and 2009 emissions by less than
1 percent and approximately 2 percent, respectively, relative to the previous report.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Phosphoric Acid Production source category. Particular attention will be
made to ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are  not available for
all Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.137 Additionally, as a future improvement to the phosphoric acid uncertainty analysis, USGS  Mineral
Commodity Specialists will be contacted to verify uncertainty ranges associated with phosphate rock imports and
exports.

4.14.  Iron and Steel Production (IPCC Source Category 2C1) and Metallurgical
Coke Production

The production of iron and steel is an energy-intensive activity that also generates process-related emissions of CO2
and CH4. Process emissions occur at each step of steel production from the production of raw materials to the
refinement of iron to the making of crude steel.  In the United States, steel is produced through both primary and
secondary processes.  Historically, primary production—using a basic oxygen furnace (EOF) with pig iron as the
primary feedstock—has been the  dominant method.  But secondary production through the use scrap steel and
electric arc furnaces (EAFs) has increased significantly in recent years due to the economic advantages of steel
recycling, which has been driven by the increased availability of scrap steel. Total production of crude steel in the
137 See


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United States in the time period between 2000 and 2008 ranged from a low of 99,320,000 tons to a high of
109,879,000 tons (2001 and 2004, respectively). Due to the decrease in demand caused by the global economic
downturn, especially from the automotive industry, crude steel production in the United States decreased to
65,460,000 tons in 2009.  In 2010, crude steel production rebounded to 88,730,000 tons as economic conditions
improved (AISI 201 la).

Metallurgical coke is an important input in the production of iron and steel.  Coke is used to produce iron or pig iron
feedstock from raw iron ore.  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) and light oil. Coke oven gas is recovered and used as fuel for underfiring the coke ovens and as process gas
and fuel within the iron and steel mill. Small amounts of coke oven gas are also sold as synthetic natural gas outside
of 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 is 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.  Iron can be
introduced into the blast furnace in the form of raw iron ore, taconite pellets (9-16mm iron-containing spheres),
briquettes, or sinter. In addition to metallurgical coke and iron, other 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. This pig iron or crude iron that is produced from this process contains about 3 to
5 percent carbon by weight.  The pig iron production process in a blast furnace produces CO2 emissions and fugitive
CH4 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 CH4 emissions through
the consumption of carbonaceous inputs (e.g., coke breeze) during the sintering process.

Steel is produced from varying levels of pig iron and scrap steel in specialized EOF and EAF steel-making furnaces.
Carbon inputs to EOF steel-making furnaces include pig iron and scrap steel as well as natural gas, fuel oil, and
fluxes (e.g., limestone, dolomite). In a EOF, 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 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, annealing, and electricity generation. 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
lesser amounts emitted from the use of flux and from the removal of carbon from pig iron used to produce steel.
                                                                               Industrial Processes    4-43

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Some carbon is also stored in the finished iron and steel products.

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. Therefore, the Guidelines suggest that emissions
from the production of metallurgical coke should be reported separately in the Energy source, while emissions from
coke consumption in iron and steel production should be reported in the industrial process source. However, the
approaches and emission estimates for both metallurgical coke production and iron and steel production are both
presented 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 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 the use of
conventional fuels (e.g., natural gas and fuel oil) for electricity generation, heating and annealing, or other
miscellaneous purposes downstream of the iron and steelmaking furnaces are reported in the Energy chapter.

Metallurgical Coke Production

Emissions of CO2 and CH4 from metallurgical coke production in 2010 were 2.1 Tg CO2 Eq. (2,084 Gg) and less
than 0.00003 Tg CO2 Eq. (less than 0.001 Gg), respectively (see Table 4-52 and Table 4-53), totaling 2.1 Tg CO2
Eq. Emissions increased in 2010 yet have decreased overall since 1990. In 2010, domestic coke production
increased by 35 percent but has decreased overall since 1990.  Coke production in 2010 was 28 percent lower than
in 2000 and 46 percent below 1990.  Overall, emissions from metallurgical coke production have declined by 16
percent (0.4 Tg CO2 Eq.) from 1990 to 2010.

Table 4-52:  CO2 and CH4 Emissions from Metallurgical Coke Production (Tg CO2 Eq.)

  Year          1990          2005      2006       2007      2008       2009      2010
                                          1.9        2.1         2.3        1.0        2.1

  Total	2.5	2.0        1.9        2.1         2.3        1.0        2.1
  + Does not exceed 0.05 Tg CO2 Eq.


Table 4-53:  CO2 and CH4 Emissions from Metallurgical Coke Production (Gg)

  Year          1990           2005      2006       2007       2008       2009       2010"
  C02          2,470          2,043      1,919      2,055       2,334        956      2,084
  CH4	+	+	+	+	+	+	+_
  + Does not exceed 0.5 Gg


Iron and Steel Production

Emissions of CO2 and CH4 from iron and steel production in 2010 were 52.2 Tg CO2 Eq. (52,192 Gg) and 0.5 Tg
CO2 Eq. (24.5 Gg), respectively (see Table 4-54 through Table 4-57), totaling approximately 52.7 Tg CO2 Eq.
Emissions increased in 2010—largely due to increased steel production associated with improved economic
conditions—but have decreased overall since 1990 due to restructuring of the industry, technological improvements,
and increased scrap steel utilization.  Carbon dioxide emission estimates include emissions from the consumption of
carbonaceous materials in the blast furnace, EAF, and EOF as well as blast furnace gas and coke oven gas
consumption for other activities at the steel mill.

In 2010, domestic production of pig iron increased by 41 percent from 2009 levels.  Overall, domestic pig iron
production has declined since the  1990s. Pig iron production in 2010 was 44 percent lower than in 2000 and 46
percent below  1990. Carbon dioxide emissions from steel production have increased by 5 percent (0.4 Tg CO2 Eq.)
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since 1990, while overall CO2 emissions from iron and steel production have declined by 46 percent (44.9 Tg CO2
Eq.) from 1990 to 2010.

Table 4-54:  CO2 Emissions from Iron and Steel Production (Tg CO2 Eq.)
Year
Sinter Production
Iron Production
Steel Production
Other Activities3
Total
1990
2.4
47.9
7.5
39.3
97.1
2005
1.7
19.6
8.5
34.2
64.0
2006
1.4
24.0
8.9
32.6
66.9
2007
1.4
27.3
9.4
31.0
69.1
2008
1.3
25.8
7.5
29.1
63.8
2009
0.8
16.0
6.6
17.8
41.2
2010
1.0
19.0
7.8
24.3
52.2
  Note: Totals may not sum due to independent rounding.
  a 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.
Table 4-55:  CO2 Emissions from Iron and Steel Production (Gg)
Year
Sinter Production
Iron Production
Steel Production
Other Activities a
Total
1990
2,448
47,944
7,476
39,256
97,123



2005
1,663
19,645
8,489
34,160
63,957
2006
1,418
24,010
8,924
32,583
66,934
2007
1,383
27,353
9,384
30,964
69,083
2008
1,299
25,773
7,540
29,146
63,758
2009
763
15,995
6,585
17,815
41,157
2010
1,045
19,042
7,844
24,260
52,192
  Note: Totals may not sum due to independent rounding.
  a 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.
Table 4-56:  CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.)
Year
Sinter Production
Iron Production
Total
1990
+
0.9H
1.0
2005
+
0.7
0.7
2006
+
0.7
0.7
2007
+
0.7
0.7
2008
+
0.6
0.6
2009
+
0.4
0.4
2010
+
0.5
0.5
  + Does not exceed 0.05 Tg CO2 Eq.
  Note: Totals may not sum due to independent rounding.
Table 4-57:  CH4 Emissions from Iron and Steel Production (Gg)
Year
Sinter Production
Iron Production
Total
1990
0.9
44.7
45.6
2005
0.6
33.5
34.1
2006
0.5
34.1
34.6
2007
0.5
32.7
33.2
2008
0.4
30.4
30.8
2009
0.3
17.1
17.4
2010
0.4
24.2
24.5
  Note: Totals may not sum due to independent rounding.


Methodology
Emission estimates presented in this chapter are largely based on Tier 2 methodologies provided by the 2006IPCC
Guidelines for National Greenhouse Gas Inventories (IPCC 2006). These Tier 2 methodologies 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. Tier 1 methods are used for certain iron and steel production processes (e.g.
DRI production) for which available data are insufficient for utilizing a Tier 2 method.
                                                                                Industrial Processes    4-45

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Metallurgical Coke Production

Coking coal is used to manufacture metallurgical (coal) coke that is used primarily as a reducing agent in the
production of iron and steel, but is also used in the production of other metals including lead and zinc (see Lead
Production and Zinc Production in this chapter). Emissions 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 2006IPCC
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 4-58). 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.

Table 4-58: Material Carbon Contents for Metallurgical Coke Production
  Material	kg C/kg	
  Coal Tar                        0.62
  Coke                           0.83
  Coke Breeze                     0.83
  Coking Coal	0.73	
  Material	kg C/GJ
  Coke Oven Gas                   12.1
  Blast Furnace Gas	70.8	
  Source: IPCC 2006, Table 4.3. Coke Oven Gas and
  Blast Furnace Gas, Table 1.3.


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 Tier 1 emission factors (0.1 g CH4 per metric ton) taken from the
2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006) for metallurgical coke production.

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 201 Id)  (see Table 4-59). 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 201 la) and through personal communications with AISI (2008b) (see Table 4-60). 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 C
content for coke breeze was assumed to equal the C content of coke.
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Table 4-59: Production and Consumption Data for the Calculation of CO2 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 Breeze Production
Coal Tar Production
1990
35,2691
25,054
2,645 •
1,058
2005
21,259
15,167
1,594
638
2006
20
14
1
,827
,882
,562
625
2007
20,607
14,698
1,546
618
2008
20,022
14,194
1,502
601
2009
13,904
10,109
1,043
417
2010
19,135
13,628
1,435
574
Table 4-60: Production and Consumption Data for the Calculation of CO2 Emissions from Metallurgical Coke
Production (million ft3)
Source/Activity Data
Metallurgical Coke Production
Coke Oven Gas Production*
Natural Gas Consumption
Blast Furnace Gas Consumption
1990
250,767
599l
24,602
2005 2006 2007 2008 2009 2010
114,213 114,386 109,912 103,191 66,155 95,405
2,996 3,277 3,309 3,134 2,121 3,108
4,460 5,505 5,144 4,829 2,435 3,181
  a Includes coke oven gas used for purposes other than coke oven underfiring only.


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 4-61). Because estimates of sinter production and direct reduced iron production were not available,
production was assumed to equal consumption.

Table 4-61:  CO2 Emission Factors for Sinter Production and Direct Reduced Iron Production
  Material Produced            Metric Ton
 	CO2/Metric Ton
  Sinter                           0.2
  Direct Reduced Iron	0/7	
  Source: IPCC 2006, Table 4.1.

To estimate emissions from pig iron production in the blast furnace, the amount of C contained in the produced pig
iron and blast furnace gas were deducted from the amount of C contained in inputs (i.e., metallurgical coke, sinter,
natural ore, pellets, natural gas, fuel oil, coke oven gas, direct coal injection).  The C contained in the pig iron, blast
furnace gas, and blast furnace inputs was estimated by multiplying the material-specific C content by each material
type (see Table 4-62).  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 C 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 C from
direct reduced iron, pig iron, and flux additions to the EAFs were also included in the EAF calculation.  For BOFs,
estimates of C contained in EOF steel were deducted from carbon contained in inputs such as natural gas, coke oven
gas, fluxes, and pig iron. In each case, the C  was calculated by multiplying material-specific carbon contents by
each material type (see Table 4-62). 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 steel manufacture was deducted from the Limestone and Dolomite Use source category to
avoid double-counting.
                                                                               Industrial Processes   4-47

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CO2 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 4-62).
CO2 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 4-54and Table 4-55).

Table 4-62:  Material Carbon Contents for Iron and Steel Production
  Material	kg C/kg	
  Coke                           0.83
  Direct Reduced Iron               0.02
  Dolomite                        0.13
  EAF Carbon Electrodes            0.82
  EAF Charge Carbon               0.83
  Limestone                       0.12
  Pig Iron                         0.04
  Steel	0.01	
  Material	kg C/GJ
  Coke Oven Gas                   12.1
  Blast Furnace Gas	70.8	
  Source: IPCC 2006, Table 4.3. Coke Oven Gas and
  Blast Furnace Gas, Table 1.3.

The production processes for sinter and pig iron result 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 Tier 1 emission factors taken from the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC 2006) for sinter production and the 1995 IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1995) (see Table 4-63) 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.
4-48   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Table 4-63: CH4 Emission Factors for Sinter and Pig Iron Production

  Material Produced	Factor	Unit	
  Pig Iron                         0~9g CH4/kg
  Sinter	0.07	kg CH4/metric ton
  Source: Sinter (IPCC 2006, Table 4.2), Pig Iron (IPCC/UNEP/OECD/IEA
  1995, Table 2.2)

Sinter consumption and direct reduced iron consumption data were obtained from AISFs Annual Statistical Report
(AISI 2004 through 201 la) and through personal communications with AISI (2008b) (see Table 4-64). Data on
direct reduced iron consumed in EAFs were not available for the years 1990, 1991, 1999, 2006, 2007, 2008, 2009,
and 2010.  EAF direct reduced iron consumption in 1990 and 1991 were assumed to equal consumption in 1992, and
consumption in 1999 was assumed to equal the average of 1998 and 2000. EAF consumption in 2006, 2007, 2008,
2009, and 2010 were calculated by multiplying the total DRI consumption for all furnaces as provided in the 2010
AISI Annual Statistical Report by the EAF share of total DRI consumption in 2005 (the most recent year that data
was available for EAF vs. EOF consumption of DRI). Data on direct reduced iron consumed in BOFs were not
available for the years 1990 through 1994, 1999, 2006, 2007, 2008, 2009, and 2010. EOF direct reduced iron
consumption in 1990 through 1994 was assumed to equal consumption in 1995, and consumption in 1999 was
assumed to equal the average of 1998 and 2000. EOF consumption in 2006, 2007, 2008, 2009, and 2010 were
calculated by multiplying the total DRI consumption for all furnaces as provided in the USGS Mineral Industry
Survey: Iron and Steel  Scrap in December 2010 (USGS 2011) by the EOF share of total DRI consumption in 2005
(the most recent year that data was available from the AISI Annual Statistical Reports for EAF vs. EOF
consumption of DRI).138

The Tier 1 CO2 emission factors for sinter production and direct reduced iron production were  obtained through the
2006 IPCC 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 AISFs Annual Statistical Report (AISI 2004 through 201 la) and through personal communications
with AISI (2008b) (see Table 4-65).

Data for EAF steel production, flux, EAF charge carbon, direct reduced iron, pig iron, scrap steel, and natural gas
consumption were obtained from AISFs Annual Statistical Report (AISI 2004 through 201 la)  and through personal
communications with AISI (201 Ib and 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 EOF steel production were obtained
from AISFs Annual Statistical  Report (AISI 2004 through 201 la) and  through personal communications with AISI
(2008b). Because data on pig iron consumption in BOFs and EAFs were not available for 2006, 2007, and 2008
while scrap steel consumption data in BOFs and EAFs were not available for 2006 and 2007, values for these years
were calculated by multiplying the total pig iron and scrap steel consumption for all furnaces as provided in the
USGS Minerals Survey: Iron and Steel Scrap in December 2010  (USGS 2011) by the EOF and EAF shares of total
pig iron and scrap consumption in 2005 (the most recent year that data was available from the AISI Annual
Statistical Reports for EAF vs.  EOF consumption of pig iron and scrap steel).139 Because data for 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, EOF, or blast furnace were obtained from AISFs Annual Statistical Report (AISI 2004 through 2011a) 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 from EIA's Natural
Gas Annual 2010 (EIA 20lib). C contents for direct reduced iron, EAF carbon electrodes, EAF charge carbon,
138 2010 DRI consumption values were not yet available when the 2010 AISI Annual Statistical Report was published, so the
USGS Minerals Survey was used as a proxy.
139 2010 pig iron and scrap steel consumption values were not yet available when the 2010 AISI Annual Statistical Report was
published, so the USGS Minerals Survey was used as a proxy.


                                                                              Industrial Processes    4-49

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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 were obtained from EIA
201 Ic and EPA 2010. Heat contents for the same fuels were obtained from EIA (1992, 201 la). 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).

Table 4-64: Production and Consumption Data for the Calculation of CO2 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
EOF Steel Production
Pig Iron Consumption
Scrap Steel Consumption
Flux Consumption
EOF Steel Production
1990

12,239

936

24,946
49,669

1,485


67
35,743
319
33,511
46,564
14,548
576
43,973
• 2005







8


,315

1,633

13

,832
37,222













2


1
37

52
32
11

42

,573


,127
,558
695
,194
,115
,612
582
,705
2006

7,088

1,497

14,684
37,904

2,526


1,245
38,033
671
56,071
32,638
11,759
610
42,119
2007

6,914

2,087

15,039
36,337

2,734


1,214
40,845
567
57,004
33,773
12,628
408
41,099
2008

6,497

1,769

14,251
33,730

2,578


1,109
40,824
680
52,791
29,322
8,029
431
39,105
2009

3,814

1,243

8,572
19,019

1,674


845
35,472
476
36,725
24,404
6,641
318
22,659
2010

5,225

1,343

10,883
26,844

2,279


1,189
36,560
640
49,339
28,214
8,881
408
31,158
Table 4-65: Production and Consumption Data for the Calculation of CO2 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 Production
EAF Steel Production
Natural Gas Consumption
EOF Steel Production
Coke Oven Gas Consumption
Other Activities
Coke Oven Gas Consumption
Blast Furnace Gas
Consumption
1990

56,2731

163,397
22,033
1,439,380

15,90sB

3,85lB
224,883

1,414,778
2005

59,844

16,170
16,557
1,299,980

19,985

524
97,132

1,295,520
2006

58,344

87,702
16,649
1,236,526

21,897

559
97,178

1,231,021
2007

56,112

84,498
16,239
1,173,588

28,077

525
93,148

1,168,444
2008

53,349

55,552
15,336
1,104,674

10,826

528
87,327

1,099,845
2009

35,933

23,179
9,951
672,486

7,848

373
55,831

670,051
2010

47,814

27,505
14,233
911,180

10,403

546
80,626

907,999
4-50  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Uncertainty and Time-Series Consistency

The estimates of CO2 and CH4 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
production because coal tar and coke breeze production data were not available. Since merchant coke plant data is
not included in the estimate of other carbonaceous materials consumed at coke plants, the mass balance equation for
CO2 from metallurgical coke production cannot be reasonably completed. Therefore, for the purpose  of this
analysis, uncertainty parameters are applied to primary data inputs to the calculation (i.e, coking coal consumption
and metallurgical coke production) only.

The estimates of CO2 emissions from iron and steel production are based on material production and consumption
data and average C 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 C contents for pellets, sinter, and natural ore, which are assumed to
equal the C contents of direct reduced iron.  For EAF steel production there is uncertainty associated with the
amount of EAF anode and charge C consumed due to inconsistent data throughout the time series. Also for EAF
steel production, there is uncertainty associated with the assumption that 100 percent of the natural gas attributed to
"steelmaking furnaces" by AISI is process-related and nothing is combusted for energy purposes.  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 C contents produce a relatively accurate estimate of CO2 emissions. However, there are uncertainties associated
with each.

For the purposes of the CH4 calculation from iron and steel production it is assumed that all of the CH4 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 and CH4.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-66 for metallurgical coke
production and iron and steel production. Total CO2 emissions from metallurgical coke production and iron and
steel production were estimated to be between 45.5 and 63.2 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 54.3 Tg CO2 Eq.
Total CH4 emissions from metallurgical coke production and iron and steel production were estimated to be 0.5 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 0.5 Tg CO2 Eq.

Table 4-66:  Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
and Metallurgical Coke Production (Tg. CO2 Eq. and Percent)

                                                              Uncertainty Range Relative to Emission
    Source                   Gas   2010 Emission Estimate                     Estimate3
   	(Tg C02 Eq.)        (Tg C02 Eq.)	0Q	
                                          Lower Bound    Upper Bound   Lower Bound   Upper Bound
Metallurgical Coke & Iron
and Steel Production
Metallurgical Coke & Iron
and Steel Production
C02
CH4
54.3
0.5
45.5
0.4
63.2
0.6
-16%
-21%
+17%
+22%
    a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
                                                                                Industrial Processes    4-51

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above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Iron and Steel Prodcution source category. Particular attention will be made
to ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon. 14°

Additional improvements include accounting for 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.  Other potential 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 identifying
information to better characterize emissions from the use of process gases and fuels within the  Energy and Industrial
Processes chapters.

Recalculations Discussion

The average heat content of natural gas consumed in the United States is obtained directly from EIA and varies
slightly each year (from 1024 to 1030 MMBTU/million cubic feet). In the previous Inventory,  the 2009 heat content
of natural gas was incorrectly applied to all historical years, so the year-to-year variation in the heat content of
natural gas was not captured. This issue has been corrected for years 1990 through 2009 and decreased emissions for
iron and steel production by less than 0.2 percent each year relative to the previous report.

4.15.  Ferroalloy Production (IPCC Source Category 2C2)

Carbon dioxide and CH4 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.  Subsequently, 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 CH4 and other volatiles. The amount of CH4 that is released is dependent on furnace efficiency,
operation technique, and control technology.
Emissions of CO2 from ferroalloy production in 2010 were 1.7 Tg CO2 Eq. (1,663 Gg) (see Table 4-67 and Table
4-68), which is a 23 percent reduction since 1990.  Emissions of CH4 from ferroalloy production in 2010 were 0.01
Tg CO2 Eq. (0.466 Gg), which is a 31 percent decrease since 1990.

Table 4-67: CO2 and CH4 Emissions from Ferroalloy Production (Tg CO2 Eq.)

  Year         1990          2005     2006      2007      2008     2009      2010
140
   See
4-52  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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   CO2            2.2            1.4        1.5       1.6        1.6       1.5        1.7
   CH4	+	+	+	+	+	+	j_
   Total	2.2	L4	1.5	L6	L6	1.5	1.7
   + Does not exceed 0.05 Tg CO2 Eq.
   Note: Totals may not sum due to independent rounding.


Table 4-68:  CO2 and CH4 Emissions from Ferroalloy Production (Gg)

   Year         1990           2005      2006      2007      2008      2009      2010
   CO2          2,152 I        1,392      1,505      1,552      1,599      1,469      1,663
   CH4	1	+	+	+	+	+	+_
   + Does not exceed 0.5 Gg.


Methodology

Emissions of CO2 and CH4 from ferroalloy production were calculated using a Tier 1 method from the 2006IPCC
Guidelines for National Greenhouse Gas Inventories (IPCC 2006), specifically by  multiplying annual ferroalloy
production by material-specific default emission factors provided by IPCC (2006). 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 CH4 (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
biomass, 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 (Onder and Bagdoyan 1993).

Ferroalloy production data for 1990 through 2010 (see Table 4-69) were obtained from the USGS through personal
communications with the USGS Silicon Commodity Specialist (Corathers 2011, Corathers 2012) and through the
Minerals Yearbook: Silicon Annual Report (USGS 1991 through 2010). Because USGS does not provide estimates
of silicon metal production for 2006-2010, 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
4-69).  The composition data for petroleum coke was obtained from Onder and Bagdoyan (1993).

Table 4-69:  Production of Ferroalloys (Metric Tons)
   Year    Ferrosilicon    Ferrosilicon    Silicon Metal      Misc. Alloys
  	25%-55%     56%-95%	32-65%
   1990      321,385        109,566         145,744          72,442

   2005      123,000        86,100         148,000           NA
   2006      164,000        88,700         148,000           NA
   2007      180,000        90,600         148,000           NA
   2008      193,000        94,000         148,000           NA
   2009      123,932        104,855         148,000           NA
   2010      153,000	135,000	148,000	NA
   NA (Not Available)


Uncertainty and Time-Series Consistency

Although some ferroalloys may be produced using wood or other biomass as a C source, information and data


                                                                              Industrial Processes   4-53

-------
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.141 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, and are also often considered confidential business information.

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 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 4-70. Ferroalloy production CO2
emissions were estimated to be between 1.3 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 1.5 TgCO2Eq.  Ferroalloy
production CH4 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.

Table 4-70:  Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
and Percent)
   Source                  Gas   2010 Emission Estimate      Uncertainty Range Relative to Emission Estimate3
 	(Tg C02 Eq.)	(Tg CO; Eq.)	[%)	

 	Lower Bound    Upper Bound    Lower Bound    Upper Bound
   Ferroalloy Production      CO2            1.7            1.5             1.9           -12%           +12%
   Ferroalloy Production      CH4	+	+	+	-12%	+12%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
   + Does not exceed 0.05 Tg CO2 Eq.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Ferroalloy Production source category. Particular attention will be made to
ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory. In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.142 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.
141 Emissions and sinks of biogenic carbon are accounted for in the Land Use, Land-Use Change, and Forestry chapter.
142 See


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4.16.  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 fifth
largest producer of primary aluminum, with approximately four percent of the world total (USGS 2011). 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).

CO2 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 carbon lining that serves as the
cathode.  Carbon is also contained in the anode, which can be a carbon mass of paste, coke briquettes, or prebaked
carbon blocks from petroleum coke. During reduction, most of this carbon is oxidized and released to the
atmosphere as CO2.
Process emissions of CO2 from aluminum production were estimated to be 3.0 Tg CO2 Eq. (3,009 Gg) in 2010 (see
Table 4-71).  The carbon anodes consumed during aluminum production consist of petroleum coke and, to a minor
extent, coal tar pitch.  The petroleum coke portion of the total 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 for here.
Table 4-71: CO2 Emissions from Aluminum Production (Tg CO2 Eq.  and Gg)
   Year  Tg CO2 Eq.    Gg
   1990      6.8       6,831
2005
2006
2007
2008
2009
2010
4.1
3.8
4.3
4.5
3.0
3.0
4,142
3,801
4,251
4,477
3,009
3,009
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 92 percent and 89 percent, respectively, to 1.3 Tg CO2 Eq.
of CF4 (0.19 Gg) and 0.3 Tg CO2 Eq. of C2F6 (0.033 Gg) in 2010, as shown in Table 4-72 and Table 4-73. 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.  Since 1990, aluminum production has declined by
57 percent, while the combined CF4 and C2F6 emission rate (per metric ton of aluminum produced) has been reduced
by 80 percent.
Table 4-72: PFC Emissions from Aluminum Production (Tg CO2 Eq.)
     Year      CF4       C2F6      Total
     1990      15.8       2.7        18.4
                 ^^^
     2005      2.5       0.4        3.0
     2006      2.1       0.4        2.5
     2007      3.2       0.6        3.8
     2008      2.2       0.5        2.7
                                                                             Industrial Processes    4-55

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     2009        1.3       0.3        1.6
     2010	L3	03	1.6
  Note: Totals may not sum due to independent rounding.
Table 4-73: PFC Emissions from Aluminum Production (Gg)
   Year    CF4   C;F6
   1990    2.4     0.3
2005
2006
2007
2008
2009
2010
0.4
0.3
0.5
0.3
0.2
0.2
+
+
0.1
0.1
+
+
  + Does not exceed 0.05 Gg.
In 2010, U.S. primary aluminum production totaled approximately 1.7 million metric tons, less than half a percent
increase from 2009 production levels (USAA 201 la). In 2010, five companies managed production at nine
operational primary aluminum smelters. Two smelters were permanently closed in 2010. An additional five
smelters were temporarily idled in 2010 (USGS 2011). During 2010, monthly U.S. primary aluminum production
was less in January through April, and greater from June through December when compared to the corresponding
month in 2009 (USAA 201 la).

For 2011, total production was approximately 2.0 million metric tons compared to 1.7 million metric tons for the
same period in 2010, a 15 percent increase (USAA 2012).  Based on the increase in production, process CO2 and
PFC emissions are likely to be greater in 2011 compared to 2010 given no significant changes in process controls at
operational facilities.

Methodology

Process CO2 Emissions from Anode Consumption and Anode Baking

CO2 emissions released during aluminum production were  estimated by combining individual facility reported data
with process-specific emissions modeling. These estimates are based on information gathered from EPA's
Voluntary Aluminum Industrial Partnership (VAIP) program, U.S. Geological Survey (USGS) Mineral Commodity
reviews, and The Aluminum Association (USAA) statistics, among other sources.

Most of the CO2 emissions released during aluminum production occur during the electrolysis reaction of the carbon
anode, as described by the following reaction:

                                      2A12O3 + 3C HX 4A1 + 3CO2

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.

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 C 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 approach 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
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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 Sederberg 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, 2007, 2008, and 2009.  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, 13 out of 14 operating smelters in 2006, 5 out of 14 operating smelters in, 2007 and 2008, and 3
out of 13 operating smelters in 2009.  For years where CO2 process data were not reported by these companies,
estimates were developed through linear interpolation, and/or assuming representative (e.g., previously reported or
industry default) values.

In the absence of any previous historical smelter specific process data (i.e., 1 out of 9 smelters in 2010, 1 out of 13
smelters in 2009, 1 out of 14 smelters in 2006, 2007, and 2008, 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 Sederberg and/or Prebake
emission factors (metric ton of CO2 per metric ton of aluminum produced) from IPCC (2006).

Process  RFC  Emissions from Anode Effects

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 Minutes/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 2010,
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 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 2009, smelter-specific anode effect data
were available for smelters representing between 80 and 100  percent of U.S. primary aluminum production.  For
2010, no reported smelter-specific anode effect data were available. Where  smelter-specific anode effect data were
not available, representative values (e.g., previously reported or 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 2009, 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.)  For 2010, no reported smelter-specific production data was available. 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 USAA, 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.

Between 1990 and 2009, production data were provided under the VAIP 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 (USAA 201 la), with allocation to specific
                                                                               Industrial Processes    4-57

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smelters based on reported production capacities (USGS 2011).

National primary aluminum production data for 2010 were obtained via The Aluminum Association (USAA 201 la).
For 1990 through 2001, and 2006 (see Table 4-74) data were obtained from USGS, Mineral Industry Surveys:
Aluminum Annual Report (USGS 1995, 1998, 2000, 2001, 2002, 2007). For 2002 through 2005, and 2007 through
2009 national aluminum production data were obtained from the USAA's Primary Aluminum Statistics (USAA
2004, 2005, 2006, 2008, 2009, 2010).

Table 4-74: Production of Primary Aluminum (Gg)
Year
1990
2005
2006
2007
2008
2009
2010
Gg
4,048
2,478
2,284
2,560
2,659
1,727
1,727
Uncertainty and Time Series Consistency

For CO2, uncertainty was assigned to each of the parameters used to estimate CO2 emissions. Uncertainty
surrounding estimated production data was assumed to have a triangular distribution with a minimum value of zero
and a maximum value corresponding to the reported production capacity (USGS 2011). 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 Tier 2 quantitative uncertainty analysis are summarized in Table 4-75. Aluminum production-
related CO2 emissions were estimated to be between 1.5 and 3.1 Tg CO2 Eq. at the 95 percent confidence level.
This indicates a range of approximately 49 percent below to 2 percent above the emission estimate of 3.0 Tg CO2
Eq. Also, production-related CF4 emissions were estimated to be between 0.6 and 1.3 Tg CO2 Eq. at the 95 percent
confidence level. This indicates a range of approximately 50 percent below to 6 percent above the emission estimate
of 1.3 TgCO2Eq. Finally, aluminum production-related C2F6 emissions were estimated to be between 0.1 and 0.4
Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of approximately 62 percent below to 15
percent above the emission estimate of 0.3 Tg CO2 Eq.

Table 4-75: Tier 2 Quantitative Uncertainty Estimates for CO2 and PFC Emissions from Aluminum Production (Tg
CO2 Eq. and Percent)
2010 Emission TT , . , _ _ , ,. , -„,„„ . . _ ,. , a
_ . Uncertainty Range Relative to 2010 Emission Estimate
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)

Aluminum Production CO2
Aluminum Production CF4
Aluminum Production C2F6

3.0
1.3
0.3
Lower Bound
1.5
0.6
0.1
Upper Bound
3.1
1.3
0.4
Lower Bound
-49%
-50%
-62%
Upper Bound
+2%
+6%
+15%
 Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.


The 2010 emission estimate was developed using either company-wide or site-specific PFC slope coefficients for all


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but 1 of the 9 operating smelters where default IPCC (2006) slope data was used.  In some cases, where smelters are
owned by one company, data have been reported on a company-wide basis as totals or weighted averages.
Consequently, in the Monte Carlo analysis, uncertainties in anode effect minutes per cell day, slope coefficients, and
aluminum production have been applied to the company as a whole and not to each smelter. This probably
overestimates the uncertainty associated with the cumulative emissions from these smelters, because errors that were
in fact independent were treated as if they were correlated. It is therefore likely that the uncertainties calculated
above for the total U.S. 2010 emission estimates for CF4 and C2F6 are also overestimated.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Recalculations

In 2010, reported production data for one smelter was updated for the years 1990, 2000, and 2003. These data were
used to recalculate emissions, and revised total PFC emissions by less than one percent for each of those years.

Planned  Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Aluminum Production source  category. Particular attention will be made to
ensure time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all
Inventory years as required for this inventory.  In implementing improvements and integration of data from EPA's
GHGRP, the latest guidance from the IPCC on the use of facility-level data in national inventories will be relied
upon.  143

4.17.   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. Sulfur hexafluoride has been used in this application
around the world for more than twenty-five years. 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 considered to be negligible and thus all SF6 used
is assumed to be emitted into the atmosphere.  Although alternative cover gases, such as AM-cover™ (containing
HFC-134a), Novec™ 612 and dilute SO2 systems can be used, many  facilities in the United States are still using
traditional SF6 cover gas systems.
The magnesium industry emitted 1.3Tg CO2 Eq. (0.05 Gg) of SF6 in 2010, representing an increase of
approximately 21 percent from 2009 emissions (See Table 4-76). The increase can be attributed to: increased
demand for magnesium for use in iron and steel desulfurization as U.S. steel production recovered from the
economic downturn (USGS 201 Ib); increased production and processing due to improving economic conditions
and increased demand from the automotive industry (USGS 201 Ib). The increase  was mitigated in part by
continuing industry efforts to utilize SF6 alternatives, such as Novec™612 and sulfur dioxide, as part of the EPA's
SF6 Emission Reduction Partnership for the Magnesium Industry.
Table 4-76:  SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg)
Year
1990
2005
2006
2007
2008
2009
TgC02Eq.
5.4
2.9
2.9
2.6
1.9
1.1
Gg
0.2
0.01
0.1
0.1
0.1
0.04
143 See
                                                                             Industrial Processes    4-59

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   2010        1.3         0.05
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 2010 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. When it was determined a Partner is no longer in production,
their metal production and emissions rates were set to zero if no activity information was available.

Emission factors for 2002 to 2006 for sand casting activities were also acquired through the Partnership. For 2007,
2008, 2009 and 2010, 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 2010 emissions from casting operations (other than die)
were estimated by multiplying emission factors (kg SF6 per metric ton of metal produced or processed) by the
amount of metal produced or consumed.  The emission factors for casting activities are provided below in Table
4-77.  The emission 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 2010, which accounted for 15 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 2010, 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.

Table 4-77:  SF6 Emission Factors (kg SF6  per metric ton of magnesium)

  Year    Die Casting	Permanent Mold	Wrought    Anodes
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2.14a
0.72
0.72
0.71
0.81
0.81
0.79
0.86
0.67
1.15
1.77
2.51
2
2
2
2
2
2
2
2
2
2
2
2
1 1
1 1
1 1
1 1
1 1
1 1
1 1
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.

Data used to develop SF6 emission estimates were provided by the Magnesium Partnership participants and the
USGS. U.S. magnesium consumption (casting) data from 1990 through 2010 were available from the USGS (USGS
2002, 2003, 2005, 2006, 2007, 2008, 2010, 2011).  Emission factors from 1990 through 1998 were based on a


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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 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 2010 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
4-77.

Uncertainty

To estimate the uncertainty surrounding the estimated 2009 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 Magnesium 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 factor 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 for each year of
extrapolation. The lone sand casting partner did not report in the past two reporting years and its activity and
emission factor were held constant at 2005 levels due to a reporting anomaly in 2006 because of malfunctions at the
facility. The uncertainty associated with the SF6 usage for the sand casting partner was  52 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 4-77).  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 that are not addressed in this methodology, 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 4-78.  SF6 emissions associated
with magnesium production and  processing were estimated to be between 1.01 and 1.10 Tg CO2 Eq. at the 95
percent confidence level. This indicates a range of approximately 6 percent below to 5 percent above the 2008
emission estimate of 1.05 Tg CO2 Eq. The uncertainty estimates for 2009 are lower relative to the 2008 reporting
year which is likely due to the fact that emission estimates for this year are based more on actual reported data than
last year with two emission sources using projected (highly uncertain) estimates.
                                                                               Industrial Processes   4-61

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Table 4-78: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
Processing (Tg CO2 Eq. and Percent)
Source

Magnesium
Production
2010 Emission
Gas Estimate Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
SF6 1.3 1.23
Upper
Bound
1.33
Lower
Bound
-4%
Upper
Bound
+4%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
   interval.
Recalculations Discussion

The USGS 2010 Mineral Yearbook for Magnesium showed a revision in its estimate of sand casting production of
magnesium for 2009 in the United States, revising its previous estimate of 44 metric tons in 2009 to 107 metric tons.

Planned  Improvements

Cover gas research conducted over the last decade has found that SF6 used for magnesium melt protection can have
degradation rates on the order of 20 percent in die casting applications (Bartos et al. 2007). Current emission
estimates assume (per the 2006 IPCC Guidelines, IPCC 2006) that all SF6 utilized is emitted to the atmosphere.
Additional research may lead to a revision of IPCC Guidelines to reflect this phenomenon and until such time,
developments in this sector will be monitored for possible application to the inventory methodology. 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 degrade during their exposure  to the molten metal.
Magnesium producers and processors have already begun using these cover gases for 2006 through 2010 in a limited
fashion; because the amounts being used by companies on the whole are low enough that they have a minor effect
on the overall emissions from the industry, these emissions are only being monitored and recorded at this time.

4.18.  Zinc Production (IPCC Source Category 2C5)

Zinc production in the United States consists of both primary and secondary processes. Primary production in the
United States is conducted through the electrolytic process while secondary techniques include the electrothermic
and Waelz kiln processes as  well as a range of other 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, only the electrothermic and Waelz kiln secondary processes result in
non-energy CC>2 emissions (Viklund-White 2000).

During one  secondary technique, the electrothermic process, roasted zinc concentrate and 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.

In the other secondary technique or 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 metric ton of zinc is produced for every
metric ton of EAF dust treated (Viklund-White 2000).

In 2010, U.S. primary and secondary refined zinc production were estimated to total 249,000 metric tons (USGS
2012), which was larger than 2009 levels, likely due to the general improvement in the U.S. economy in 2010 (see
Table 4-75). This was despite an explosion at one of the biggest secondary refined zinc facilities in the United States
(Horsehead Corporation's Monaca facility), which resulted in a temporary shutdown at the facility (Horsehead Corp.
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2010b).
Emissions of CO2 from zinc production in 2010 were estimated to be 1.2 Tg CO2 Eq. (1,168 Gg) (see Table 4-80).
All 2010 CO2 emissions resulted from secondary zinc production processes. Emissions from zinc production in the
U.S. have increased overall since 1990 due to a gradual shift from non-emissive primary production to emissive
secondary production.  In 2010, emissions were estimated to be 85 percent higher than they were in 1990.

Table 4-79: Zinc Production (Metric Tons)
   Year    Primary	Secondary
   1990    262,704       95,708
2005
2006
2007
2008
2009
2010
191,120
113,000
121,000
125,000
94,000
120,000
156,000
156,000
157,000
161,000
109,000
129,000
Table 4-76: CO2 Emissions from Zinc Production (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.     Gg
   1990        0.6         632
2005
2006
2007
2008
2009
2010
1.0
1.0
1.0
1.2
0.9
1.2
1,030
1,030
1,025
1,159
943
1,168
Methodology

Non-energy CO2 emissions from zinc production result from the electrothermic and Waelz kiln secondary
production processes, which both use metallurgical coke or other C-based materials as reductants.  The methods
used to estimate emissions from these processes are based on Tier 1 methods from the 2006IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC 2006).  The Tier 1 emission factors provided by IPCC (2006) for
Waelz kiln-based secondary production were derived from coke consumption factors and other data presented in
Vikland-White (2000). These coke consumption factors as well as other inputs used to develop the Waelz kiln
emission factors are shown below. IPCC (2006) does not provide an emission factor for electrothermic processes
due to limited information; therefore, the Waelz kiln-specific emission factors were applied to zinc produced from
electrothermic processes.

For Waelz kiln-based production, IPCC (2006) recommends the use of emission factors based on EAF dust
consumption if possible rather than the amount of zinc produced since the amount of reduction materials used is
more directly dependent on the amount of EAF dust consumed. Since only a portion of emissive zinc production
facilities consume EAF dust, the emission factor based on zinc production is applied to the non-EAF dust
consuming facilities while the emission factor based on EAF dust consumption is applied to EAF dust consuming
facilities.

The 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:
                                                                              Industrial Processes   4-63

-------
                    1.19 metric tons coke   0.85 metrie torn C    151 metric tons CO     3.70 metric tons CO
    EF          =	x	x
       Waelz Kiln      metric tons zinc      metric tons coke       metric tons C         metric tons zinc

The Waelz kiln 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:

               Q A metric tons coke    0.85 metric tons C   3 .67 metric tons CO^    1 .24 metric torn CO^
   EAF Dust    metric tons EAF dust    metric tons coke       metric tons C      metric tons EAF Dust
The only companies in the United States that use emissive technology to produce secondary zinc products are
Horsehead, PIZO, and Steel Dust Recycling. For Horsehead, EAF dust is recycled in Waelz kilns at their
Beaumont, TX; Calumet, IL; Palmerton, PA; Rockwood, TN; and Barnwell, SC facilities. These Waelz kiln
facilities produce intermediate zinc products (crude zinc oxide or calcine), most of which is transported to their
Monaca, PA facility where the products are smelted into refined zinc using electrothermic technology. Some of
Horsehead's intermediate zinc products that are not smelted at Monaca are instead exported to other countries
around the world (Horsehead Corp. 2010a). PIZO and Steel Dust Recycling recycle EAF dust into  intermediate zinc
products using Waelz kilns, and then sell the intermediate products to companies who smelt it into refined products.

The total amount of EAF dust consumed by Horsehead at their Waelz kilns was available from Horsehead financial
reports for years 2006 through 2010 (Horsehead Corp. 2008, 2010a, and 2011).  Consumption levels for 1990
through 2005 were extrapolated using the percentage change in annual refined zinc production at secondary smelters
in the United States as provided by USGS Minerals Yearbook: Zinc (USGS 1994 through 2011). The EAF dust
consumption values for each year were then multiplied by the 1.24 metric tons CO2/metric ton EAF dust consumed
emission factor to develop CO2 emission estimates for Horsehead's Waelz kiln facilities.

The amount of EAF dust consumed by PIZO's facility in 2009 and 2010 and Steel Dust Recycling's facility for
2008, 2009, and 2010 (the only years these facilities have been in operation) was not publically available.
Therefore, these consumption values were estimated by calculating the 2008, 2009, and 2010 capacity utilization of
Horsehead's Waelz kilns and multiplying this utilization ratio by the capacities of the PIZO and Steel Dust
Recycling facilities, which were available from the companies (PIZO 2011 and Steel Dust Recycling LLC 2011).
The 1.24 metric tons CO2/metric ton EAF dust consumed emission factor was then applied to PIZO's and Steel Dust
Recycling's estimated EAF dust consumption to develop CO2 emission estimates for those Waelz kiln facilities.

Refined zinc production levels for Horsehead's Monaca, PA facility (utilizing electrothermic technology) were
available from the company for years 2005 through 2010 (Horsehead Corp. 2008 and 2011). Production levels for
1990 through 2004 were extrapolated using the percentage changes in annual refined zinc production at secondary
smelters in the United States as provided by USGS Minerals Yearbook: Zinc (USGS 1994 through 2011). The 3.70
metric tons CO2/metric ton zinc emission factor was then applied to the Monaca facility's production levels to
estimate CO2 emissions for the facility.  The Waelz kiln production emission factor was applied in this case rather
than the EAF dust consumption emission factor since  Horsehead's Monaca facility did not consume EAF dust.

Uncertainty and Time-Series Consistency

The uncertainties contained in these estimates are two-fold, relating to activity data and emission factors used.

First, there is uncertainty associated with the amount of EAF dust consumed in the United States to produce
secondary zinc using emission-intensive Waelz kilns.  The estimate for the total amount of EAF dust consumed in
Waelz kilns is based on (1) an EAF dust consumption value reported annually by Horsehead Corporation as part of
its financial reporting to the Securities and Exchange Commission (SEC), and (2) an estimate of the amount of EAF
dust consumed at a Waelz kiln facility operated in Alabama by Steel Dust Recycling LLC.  Since actual EAF dust
consumption information is not available for the Steel Dust Recycling LLC facility, the amount is estimated by
multiplying the EAF dust recycling capacity of the facility (available from the company's Web site) by the capacity
utilization factor for Horsehead Corporation (which is available from Horsehead's financial reports).  Therefore,
there is uncertainty  associated with the assumption that the capacity utilization of Steel Dust Recycling LLC's
Waelz kiln facility is equal to the capacity utilization of Horsehead's Waelz kiln facility.


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Second, there are uncertainties associated with the emission factors used to estimate CO2 emissions from secondary
zinc production processes. The Waelz kiln emission factors are based on materials balances for metallurgical coke
and EAF dust consumed as provided by Viklund-White (2000). Therefore, the accuracy of these emission factors
depend upon the accuracy of these materials balances.  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. The results of the Tier 2 quantitative uncertainty analysis are
summarized in Table 4-80. Zinc 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 17 percent below and 19 percent above the
emission estimate of 1.2 Tg CO2 Eq.

Table 4-80: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Zinc Production (Tg CO2 Eq. and
Percent)

   Source          Gas   2010 Emission Estimate            Uncertainty Range Relative to  Emission Estimate3
 	(Tg CO, Eq.)	(Tg C02 Eq.)	(%)	
 	Lower Bound   Upper Bound   Lower Bound   Upper Bound
   Zinc Production  CO2	L2	LO	1.4	-17%	+19%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Zinc Production source category. Particular attention will be made to ensure
time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all Inventory
years as required for this inventory. In implementing improvements and integration of data from EPA's GHGRP, the
latest guidance from the IPCC on the use of facility-level data in national inventories will be relied upon.144

Recalculations Discussion

In 2009, PIZO Technologies LLC commissioned an EAF dust consuming secondary production facility. The 2009
EAF dust consumption from this facility was not captured in the previous inventory. In addition, the EAF dust
consumption data provided from Horsehead Corp for years 2006 through 2009 were incorrectly considered to be in
metric tons in the previous Inventory when the data were actually provided in short tons (this also impacted 1990
through 2005  EAF dust consumption data that are  estimated based on the 2006 estimate). Both of these issues have
been corrected and decreased 1990 through 2009 emissions from zinc production by an average of 5.2 percent per
year.

4.19.   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, occurs at a just a single plant in Missouri.
Secondary production largely involves the recycling of lead acid batteries at approximately 20 separate smelters in
the United States. Fourteen of those secondary smelters have annual capacities of 15,000 tons or more and were
collectively responsible for 99 percent of secondary lead production in 2011(USGS 2012a).  Secondary lead
production has increased in the United States over the past decade while primary lead production has decreased. In
2009, secondary lead production accounted for approximately 92 percent of total lead production (USGS 2012b).

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
144 See
                                                                              Industrial Processes    4-65

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increased by 24 percent from 2009 to 2010, and has decreased by 72 percent since 1990 (USGS 1995, 2012b).
Similar to primary lead production, CO2 emissions from secondary production result when a reducing agent, usually
metallurgical coke, is added to the smelter to aid in the reduction process. Carbon dioxide emissions from secondary
production also occur through the treatment of secondary raw materials (Sjardin 2003).  U.S. secondary lead
production increased from 2009 to 2010 by 3 percent, and has increased by 24 percent since 1990 (USGS 1995 and
2012b).
In 2010, U.S. primary and secondary lead production totaled 1,255,000 metric tons (USGS 2012b). The resulting
emissions of CO2 from 2010 production were estimated to be 0.5 Tg CO2 Eq. (542 Gg) (see Table 4-81).  The
majority of 2010 lead production is from secondary processes, which accounted for 95 percent of total 2010 CO2
emissions. At last reporting, the United States was the third largest mine producer of lead in the world, behind
China and Australia, accounting for 9 percent of world production in 2010 (USGS 2012b).

Table 4-81:  CO2 Emissions from Lead Production (Tg CO2 Eq. and  Gg)
   Year    Tg CO2 Eq.     Gg
   1990        0.5        516
2005
2006
2007
2008
2009
2010
0.6
0.6
0.6
0.5
0.5
0.5
553
560
562
547
525
542
After a steady increase in total emissions from 1995 to 2000, total emissions have gradually decreased since 2000
but were still 5 percent greater in 2010 than in 1990. Although primary production has decreased significantly (75
percent since 1990), secondary production has increased by about 20 percent over the same time period. Since
secondary production is more emissions-intensive, the increase in secondary production since 1990 has resulted in a
net increase in emissions despite the sharp decrease in primary production (USGS 1994 and 2012b).

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.  The methods used to estimate emissions for lead
production are based on Tier 1 methods from the 2006IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC 2006).  For primary lead production using direct smelting, Sjardin (2003) and the IPCC (2006) provide an
emission factor of 0.25 metric tons CO2/metric ton lead. For secondary lead production, Sjardin (2003) and IPCC
(2006) provide an emission factor of 0.25 metric tons CO2/metric ton lead for direct smelting as well as an emission
factor of 0.2 metric tons CO2/metric ton lead produced for the treatment of secondary raw materials (i.e.,
pretreatment of lead acid batteries). The direct smelting factor (0.25) and the sum of the direct smelting and
pretreatment emission factors (0.45) are multiplied by total U.S. primary and secondary lead production,
respectively, to estimate CO2 emissions.
The 1990 through 2010 activity data for primary and secondary lead production (see Table 4-82) were obtained
through the USGS Mineral Yearbook: Lead (USGS 1994 through 2012b).

Table 4-82: Lead Production (Metric Tons)
   Year   Primary	Secondary
   1990     404,000       922,000

   2005     143,000      1,150,000
   2006     153,000      1,160,000
   2007     123,000      1,180,000
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   2008      135,000      1,140,000
   2009      103,000      1,110,000
   2010      115,000      1,140,000
Uncertainty and Time-Series Consistency

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) 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 4-83. Lead production CO2
emissions were estimated to be between 0.5 and 0.6 Tg CO2 Eq. at the 95 percent confidence level.  This indicates a
range of approximately 15 percent below and 15 percent above the emission estimate of 0.5 Tg CO2 Eq.

Table 4-83: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lead Production (Tg CO2 Eq. and
Percent)

   Source            Gas    2010 Emission Estimate        Uncertainty Range Relative to Emission Estimate3
 	(Tg CO; Eq.)	(Tg C02 Eq.)	(%)	
 	Lower Bound   Upper Bound   Lower Bound    Upper Bound
   Lead Production    CO2	0.5	0.5	0.6	-15%	+15%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.

Planned Improvements

Future improvements involve  evaluating and analyzing data reported under EPA's GHGRP that would be useful to
improve the emission estimates for the Lead Production source category. Particular attention  will be made to  ensure
time series consistency, as the facility-level reporting data from EPA's GHGRP are not available for all Inventory
years as required for this inventory. In implementing improvements and  integration of data from EPA's GHGRP, the
latest guidance from the IPCC on the use of facility-level data in national inventories will be relied upon.145

Recalculations Discussion

Activity data for the time series was revised for the current Inventory. Specifically, secondary production data for
2008 were revised to reflect updated USGS data, which resulted in a lowering of the emission estimate for 2008 by
less than one percent. Details on the emission trends through time are described in more detail in the Methodology
section,  above.

4.20.  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. Between 2000 and 2007, U.S.
145 See
                                                                             Industrial Processes   4-67

-------
production fluctuated but generally remained above 1990 levels. In 2008 and 2009, U.S. production declined
markedly before increasing slightly in 2010. Because HCFC-22 depletes stratospheric ozone, its production for non-
feedstock uses is scheduled to be phased out by 2020 under the U.S. Clean Air Act.146 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, SbCl5.  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.

Three facilities produced HCFC-22 in the U.S. in 2010. Emissions of HFC-23 in 2010 were estimated to be 8.1 Tg
CO2 Eq. (0.7 Gg) (see Table 4-84). This quantity represents a 50 percent increase from 2009 emissions but a 78
percent decline from 1990 emissions. The increase from 2009 emissions was caused by a 10 percent increase in
HCFC-22 production and a 36 percent increase in the HFC-23  emission rate. The decline from 1990 emissions is
due to a 27 percent decrease in HCFC-22 production and a 69 percent decrease in the HFC-23 emission rate since
1990. The decrease in the emission rate is primarily attributable to five 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, and (e) another plant began destroying HFC-23.

Table 4-84: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg)
   Year     TgCO2Eq.      Gg
   1990        36.4         3
2005
2006
2007
2008
2009
2010
15.8
13.8
17.0
13.6
5.4
8.1
1
1
1
1
0.4
1
Methodology

To estimate HFC-23 emissions for five of the eight HCFC-22 plants that have operated in the United States since
1990, methods comparable to the Tier 3 methods in the 2006IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC 2006) were used. For the other three plants, the last of which closed in 1993, methods
comparable to the Tier 1 method in the 2006 IPCC Guidelines were used. Emissions from these three plants have
been calculated using the recommended emission factor for unoptimized plants operating before 1995 (0.04 kg
HCFC-23/kg HCFC-22 produced).

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
146 As construed, interpreted, and applied in the terms and conditions of fas. Montreal Protocol on Substances that Deplete the
Ozone Layer. [42 U.S.C. §7671m(b), CAA §614]


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estimate HFC-23 emissions.

To estimate 1990 through 2009 emissions, EPA relied on reports from an industry association that aggregated
HCFC-22 production and HFC-23 emissions from all U.S. HCFC-22 producers and reported them to EPA (ARAP
1997, 1999, 2000, 2001, 2002, 2003, 2004, 2005, 2006, 2007, 2008, 2009, 2010). To estimate 2010 emissions, EPA
analyzed facility-level data (including both HCFC-22 production and HFC-23 emissions) reported through the
Greenhouse Gas Reporting Program (ICF, 2012). In 1997 and 2008, EPA (through a contractor) performed
comprehensive reviews of plant-level estimates of HFC-23 emissions and HCFC-22 production (RTI1997; RTI
2008). The 1997 and 2008 reviews enabled EPA to review, update, 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 4-85.

Table 4-85: HCFC-22 Production (Gg)
   Year
   1990
   •
   2005
   2006
   2007
   2008
   2009
   2010
 139
•
 156
 154
 162
 126
 91
 101
Uncertainty and Time Series Consistency

The uncertainty analysis presented in this section was based on a plant-level Monte Carlo Stochastic 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.

The relative errors yielded by the Monte Carlo Stochastic Simulation for 2006 were applied to the U.S. emission
estimate for 2010. The resulting estimates of absolute uncertainty are likely to be reasonably accurate because (1)
the methods used by the three plants to estimate their emissions are not believed to have changed significantly since
2006, and (2) although the distribution of emissions among the plants may have changed between 2006 and 2010
(because both HCFC-22 production and the HFC-23 emission rate declined significantly), the two plants that
contribute significantly to emissions were estimated to have similar relative uncertainties in their 2006 (as well as
2005) emission estimates. Thus, changes in the relative contributions of these two plants to total emissions are not
likely to have a large impact on the uncertainty of the national emission estimate.

The results of the Tier 2 quantitative  uncertainty analysis are summarized in Table 4-86. HFC-23 emissions from
HCFC-22 production were estimated to be between 7.5 and 8.9 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 8.1 Tg CO2 Eq.
Table 4-86: Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and
Percent)
Source
2010 Emission
Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
HCFC-22 Production
HFC-23 8.1
7.5 8.9 -7% +10%
   a Range of emissions reflects a 95 percent confidence interval.
                                                                              Industrial Processes   4-69

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Details on the emission trends through time are described in more detail in the Methodology section, above.

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

Hydrofluorocarbons (HFCs) and perfluorocarbons (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 1990.147 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
4-87 and Table 4-88.

Table 4-87: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF4
Others*
Total
1990
+
!
0.3
0.3
2005
+
0.3
8.5
74.9
8.7
0.8
+
5.6
99.0
2006
+
0.6
10.0
74.8
9.5
0.8
+
6.0
101.9
2007
+
1.0
12.0
72.2
10.3
0.9
+
6.3
102.7
2008
+
1.3
14.3
69.3
11.1
0.9
+
6.7
103.6
2009
+
1.7
17.3
66.7
12.6
0.9
+
7.0
106.3
2010
+
2.5
22.2
66.8
14.7
0.9
+
7.4
114.6
   + Does not exceed 0.05 Tg CO2 Eq.
   * 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. For estimating purposes, the GWP value used for PFC/PFPEs was based
   upon C6F14.
   Note: Totals may not sum due to independent rounding.


Table 4-88: Emissions of HFCs and PFCs from ODS Substitution (Mg)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF4
Others*
1990
+ 1
+
1
+
M
2005
1
505
3,053
57,637
2,290
125
2
M
2006
1
970
3,584
57,572
2,511
131
2
M
2007
1
1,489
4,297
55,517
2,718
136
2
M
2008
2
2,025
5,119
53,274
2,911
141
2
M
2009
2
2,609
6,175
51,333
3,325
144
2
M
2010
2
3,845
7,920
51,423
3,861
146
3
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.148  In 1993, the use of HFCs
147 [42 U.S.C § 7671, CAA § 601]
148 R.4Q4A contains HFC-125, HFC-143a, and HFC-134a.
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in foam production began, and in 1994 ODS substitutes for halons entered widespread use in the United States as
halon production was phased-out. In 1995, these compounds also found applications as solvents.

The use and subsequent emissions of HFCs and PFCs as ODS substitutes has been increasing from small amounts in
1990 to 114.6 TgCO2Eq. in2010.  This increase was in large part the result of efforts to phase out CFCs and other
ODSs in the United States. In the short term, this trend is expected to continue, and will likely continue 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 4-89 presents emissions of HFCs and PFCs as ODS substitutes by end-use sector for 1990 through 2010.  The
end-use sectors that contributed the  most toward emissions of HFCs  and PFCs as ODS substitutes in 2010 include
refrigeration and air-conditioning (97.6 Tg CO2 Eq., or approximately 85 percent), aerosols (9.3 Tg CO2 Eq., or
approximately 8 percent), and foams (5.4 Tg CO2 Eq., or approximately 5 percent). Within the refrigeration and air-
conditioning end-use sector, motor vehicle air-conditioning was the highest emitting end-use (44.1 Tg CO2 Eq.),
followed by refrigerated retail food and transport. Each of the end-use sectors is described in more detail below.
Table 4-89: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.) by Sector
Gas
Refrigeration/Air Conditioning
Aerosols
Foams
Solvents
Fire Protection
Total
1990
0.3
+
+
+
0.3






2005
87.9
7.3
1.9
1.3
0.5
99.0
2006
90.1
7.7
2.1
1.3
0.6
101.9
2007
90.3
8.2
2.3
1.3
0.7
102.7
2008
90.4
8.6
2.5
1.3
0.7
103.6
2009
91.3
9.1
3.9
1.3
0.8
106.3
2010
97.6
9.3
5.4
1.3
0.9
114.6
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 and 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-410A149, R-404A, and R-507A. 15°  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 replaced
the use of CFCs with HFC-propellant alternatives. The earliest ozone-friendly MDIs were produced with HFC-
134a, but the industry has started to use HFC-227ea as well. Conversely, since the use of CFC propellants was
banned in 1978, most non-medical consumer aerosol products have not transitioned to HFCs, but to "not-in-kind"
technologies, such as solid 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.
149 R-410A contains HFC-32 and HFC-125.
150 R-507A, also called R-507, contains HFC-125 and HFC-143a.
                                                                               Industrial Processes    4-71

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Foams

CFCs and HCFCs have traditionally been used as foam blowing agents to produce polyurethane (PU), polystyrene,
polyolefm, 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, polyolefm, 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, 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, HFC-134a and CO2 are 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 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-236fa 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 HFCs, such as HFC-23 and HFC-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 occur.

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 it tracks the use and emissions of various compounds for the annual "vintages" of new equipment that enter
service in each end-use. The 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 nearly 60 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,


4-72  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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equipment characteristics, and end-use emissions profiles that were used to estimate annual emissions for the
various compounds.

The Vintaging Model estimates emissions from 60 end-uses. The uncertainty analysis, however, quantifies the level
of uncertainty associated with the aggregate emissions resulting from the top 21 end-uses, comprising over 95
percent of the total emissions, and 5 other end-uses. These 26 end-uses comprise 97 percent of the total emissions.
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. 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 95 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 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 retail food equipment 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 4-90.  Substitution of ozone
depleting substances HFC and PFC emissions were estimated to be between 111.8 and 129.3 Tg CO2 Eq. at the 95
percent confidence level. This indicates a range of approximately 7 percent below to 8 percent above the emission
estimate of 120.0 Tg CO2 Eq.

Table 4-90:  Tier 2 Quantitative Uncertainty Estimates for HFC  and PFC Emissions from ODS Substitutes (Tg CO2
Eq. and Percent)
Source

Substitution of
Ozone Depleting
Substances
2010 Emission
Gases Estimate
(Tg CO, Eq.)a

HFCs
and
PFCs 112.2
Uncertainty Range Relative to Emission
Estimate1"
(Tg C02 Eq.) (%)
Lower
Bound
110.5
Upper
Bound
127.1
Lower
Bound
-1.5%
Upper
Bound
+13.3%
   a 2010 emission estimates and the uncertainty range presented in this table correspond to selected end-uses
   within the aerosols, foams, solvents, fire extinguishing agents, and refrigerants sectors, but not for other
   remaining categories. Therefore, because the uncertainty associated with emissions from "other" ODS
   substitutes was 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.
Recalculations Discussion

A review of the window units and residential unitary air conditioning end-uses led to minor revisions in the assumed
transition scenarios. Overall, these changes to the Vintaging Model had negligible effects on estimates of
greenhouse gas emissions across the time series. An update to the retail food refrigeration end-uses resulted in the
replacement of the medium retail food end-use with small condensing units and large condensing units. In addition,
updates were made to the charge sizes, leak rates, and equipment transitions for each end-use. These changes to the
Vintaging Model had a significant impact on the estimates of greenhouse gas emissions for the retail food
refrigeration sector.
                                                                                 Industrial Processes   4-73

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4.22.  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, or more than 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 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 by-product. Besides dielectric film
etching and PECVD chamber cleaning, much smaller quantities of fluorinated gases are used to etch polysilicon
films and refractory metal films like tungsten.

For 2010, total weighted emissions of all fluorinated greenhouse gases by the U.S. semiconductor industry were
estimated to be 5.4 Tg CO2 Eq. Combined emissions of all fluorinated greenhouse gases are presented in Table 4-91
and Table 4-92 below for years 1990and the period 2005 to 2010. The rapid growth of this industry and the
increasing complexity (growing number of layers)151 of semiconductor products led to an increase in emissions of
148 percent between 1990 and 1999, when emissions peaked at 7.2 Tg CO2 Eq.  The emissions growth rate began to
slow after 1998, and emissions declined by 26 percent between 1999 and 2010.  Together, industrial growth and
adoption of emissions reduction technologies, including but not limited to abatement technologies, resulted in a net
increase in emissions of 85 percent between 1990 and 2010.

Table 4-91: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.)
Year
CF4
C2F6
C3F8
C4F8
HFC-23
SF6
NF3*
Total
1990
0.7
1.5 1
0.0 1
0.0 1
£
0.0
2.9
2005
1.1
2.0
0.0
0.1
0.2
1.0
0.4
4.4
2006
1.2
2.2
0.0
0.1
0.3
1.0
0.7
4.7
2007
1.3
2.3
0.0
0.1
0.3
0.8
0.5
4.8
2008
1.4
2.4
0.1
0.1
0.3
0.9
0.6
5.1
2009
1.5
2.5
0.0
0.0
0.3
1.0
0.5
5.3
2010
1.6
2.4
0.0
0.0
0.3
0.9
0.5
5.4
   Note: Totals may not sum due to independent rounding.
   * NF3 emissions are presented for informational purposes, using the AR4 GWP of 17,200, and are not included
   in totals.

Table 4-92: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)

   Year             1990           2005        2006        2007        2008     2009    2010
151 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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CF4
C2F6
C3F8
C4F8
HFC-23
SF6
NF3
115
160 1
°l
°l
15 1
22
3
168
216
5
13
18
40
26
181
240
5
13
22
40
40
198
249
6
7
23
34
30
216
261
13
7
25
36
33
226
271
5
4
28
40
29
245
264
5
4
29
40
31
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).152 The availability and applicability of
Partner data differs across the 1990 through 2010 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 through 2010.

1990 through 1994

From 1990 through 1994, Partnership data was unavailable and emissions were modeled using the PEVM (Burton
and Beizaie 2001).153  1990 to 1994 emissions are assumed to be uncontrolled, since reduction strategies such as
chemical substitution and abatement were yet to be 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 feature size), 154 and (2) product type (discrete, memory or
logic).155  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. 2010).

The emission factor in PEVM is the average of four historical emission factors, each derived by dividing the total
   A Partner refers to a participant in the U.S. EPA PFC Reduction/Climate Partnership for the Semiconductor Industry.
Through a Memorandum of Understanding (MoU) with the EPA, Partners voluntarily report their PFC emissions to the EPA by
way of a third party, which aggregates the emissions.
   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.
   By decreasing features of Integrated Circuit components, more components can be manufactured per device, which increases
its functionality.  However, as those individual components shrink it requires more layers to interconnect them to achieve the
functionality. For example, a microprocessor manufactured with the smallest feature sizes (65 nm) might contain as many as 1
billion transistors and require as many as 11 layers of component interconnects to achieve functionality while a device
manufactured with 130 nm feature size might contain a few hundred million transistors and require 8 layers of component
interconnects (ITRS 2007).
155 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.


                                                                                 Industrial Processes   4-75

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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 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 2011).

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.156'157  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 industry (see ITRS 2008 and Semiconductor Equipment and Materials Industry  2011).158> 159> 16°
156 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.
157 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.
158 Special attention was given to the manufacturing capacity of plants that use wafers with 300 mm diameters because the actual
capacity of these plants is ramped up to design capacity, typically over a 2-3 year period.  To prevent  overstating estimates of
partner-capacity shares from plants using 300 mm wafers, design capacities contained in WFW were replaced with estimates of
actual installed capacities for 2004 published by Citigroup Smith Barney (2005). Without this correction, the partner share of
capacity would be overstated, by approximately 5 percent. For perspective, approximately 95 percent of all new capacity
additions in 2004 used 300 mm wafers, and by year-end those plants, on average, could operate at approximately 70 percent of
the design capacity.  For 2005, actual installed capacities were estimated using an entry in the World Fab Watch database (April
2006 Edition) called "wafers/month, 8-inch equivalent," which denoted the actual installed capacity instead of the fully-ramped
capacity.  For 2006, actual installed capacities of new fabs were estimated using an average monthly ramp rate of 1100 wafer
starts per month (wspm) derived from various sources such as semiconductor fabtech, industry analysts, and articles in the trade
press. The monthly ramp rate was applied from the first-quarter of silicon volume (FQSV) to determine the average design
capacity over the 2006 period.
159 In 2006, the industry trend in co-ownership of manufacturing facilities continued.  Several manufacturers, who are Partners,
now operate fabs with other manufacturers, who in some cases are also Partners and in other cases are not Partners.  Special
attention was given to this occurrence when estimating the Partner and non-Partner shares of U.S. manufacturing capacity.
16° Two versions of PEVM are used to model non-Partner emissions during this period. For the years 2000 to 2003 PEVM
v3.2.0506.0507 was used to estimate non-Partner emissions. During this time, discrete devices did not use PFCs during


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2007 through 2010

For the years 2007 through 2010, 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 through 2010 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.161  Second, the
scope of the 2007 through 2010 estimates is expanded relative to the estimates for the years 2000 through 2006 to
include emissions from Research and Development (R&D) 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 through 2010 was used for production fabs while for R&D
fabs a 20 percent figure was assumed (SIA 2009).

In addition, publicly available actual utilization data was used to  account for differences in fab utilization for
manufacturers of discrete and 1C products for the emissions in 2010 for non-partners. PEVM estimates were
adjusted using technology weighted capacity shares that reflect relative influence of different utilization.

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 made by semiconductor manufacturers during this period and the application of
IPCC default emission factors for each gas (Burton and Beizaie 2001). For the 2000 through 2010 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 2010 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 2010, 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).  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 2010)
(e.g.,  Semiconductor Materials and Equipment Industry, 2011). Actual world capacity utilizations for 2010 were
obtained from Semiconductor International Capacity Statistics (SICAS) (SIA, 2010). Estimates of silicon consumed
by linewidth from 1990 through 2010 were derived from information from VLSI Research, Inc. (2010), 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 and Time Series Consistency

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
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.
161 EPA considered applying this change to years before 2007, but found that it would be difficult due to the large amount of
data (i.e., technology-specific global and non-Partner TMLA) that would have to be examined and manipulated for each year.
This effort did not appear to be justified given the relatively small impact of the improvement on the total estimate for 2007 and
the fact that the impact of the improvement would likely be lower for earlier years because the estimated share of emissions
accounted for by non-Partners is growing as Partners continue to implement emission-reduction efforts.


                                                                               Industrial Processes    4-77

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                                          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 2010 is
about ±10 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 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.162  A relative
uncertainty of approximately ±10 percent was estimated for the PEVM emission factor, based on the standard
deviation of the 1996 to 1999 emission factors.163 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 by 0.12 layers or 2.9
percent.164 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 4-4-93. The emissions estimate
for total U.S. PFC emissions from semiconductor manufacturing were estimated to be between 4.8 and 5.9 Tg CO2
Eq. at a 95 percent confidence level. This range represents 10 percent below to 10 percent above the 2010 emission
estimate of 5.4 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.
Table 4-4-93: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
Manufacture  (Tg CO2 Eq. and Percent)
Source

Semiconductor
Manufacture
2010 Emission
Gas Estimate3 Uncertainty Range Relative to Emission Estimate1"
(Tg CO, Eq.) (Tg C02 Eq.) (%)

HFC,
PFC, and
SF6 5.4
Lower
Bound0
4.8
Upper
Bound0
5.9
Lower
Bound
-10%
Upper
Bound
10%
   a Because the uncertainty analysis covered all emissions (including NF3), the emission estimate presented here
   does not match that shown in Table 4-91.
   b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
   interval.
   0 Absolute lower and upper bounds were calculated using the corresponding lower and upper bounds in
   percentages.


Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.
162 Error propagation resulted in Partnership gas-specific uncertainties ranging from 17 to 27 percent
163 The average of 1996 to 1999 emission factor is used to derive the PEVM emission factor.
164This is based on an analysis of 2004 data.
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Planned  Improvements

One point of consideration for future national emissions estimates is the inclusion of PFC emissions from heat
transfer fluid (HTF) loss to the atmosphere. 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 fluorinated emissions (EPA 2006).

4.23.  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 11.8 Tg CO2 Eq. (0.5 Gg) in 2010.  This quantity represents a 56 percent decrease from the
estimate for 1990 (see Table 4-94 and Table 4-95). Two trends contributed to this decrease: 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.

Table 4-94:  SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Tg CO2 Eq.)
    Year     Electric Power     Electrical Equipment        Total
   	Systems	Manufacturers	
    1990          26.3                  0.3                26.7
2005
2006
2007
2008
2009
2010
13.1
12.2
11.5
11.1
11.3
11.0
0.8
0.8
0.7
1.1
0.6
0.8
13.9
13.0
12.2
12.2
11.8
11.8
  Note: Totals may not sum due to independent rounding.


Table 4-95: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Gg)
    Year	Emissions
    1990           1.1
2005
2006
2007
2008
2009
2010
0.6
0.5
0.5
0.5
0.5
0.5
Methodology
The estimates of emissions from Electrical 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  2010 Emissions from Electric Power Systems
Emissions from  electric power systems from 1999 to 2010 were estimated based on: (1) reporting from utilities


                                                                             Industrial Processes    4-79

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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,
2007, and 2010 Utility Data Institute (UDI) Directories of Electric Power Producers and Distributors (UDI2001,
2004, 2007, 2010). (Transmission miles are defined as the miles of lines carrying voltages above 34.5 kV.) Over
the period from 1999 to 2010, Partner utilities, which for inventory purposes are defined as utilities that either
currently are or previously have been part of the Partnership, represented between 43 percent and 48 percent of total
U.S. transmission miles. For each year, the emissions reported by or estimated for Partner utilities were added to the
emissions estimated for utilities that have never participated in the Partnership (i.e., non-Partners).165
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 2010, non-reporting
Partners accounted for approximately 16 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
indicated 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 above 34.5 kV.  The equations were developed based on the 1999 SF6 emissions reported by a
subset of 42 Partner utilities (representing approximately 23 percent of U.S. transmission miles) and 2000
transmission mileage data obtained from the 2001 UDI Directory of Electric Power Producers and Distributors (UDI
2001). 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 (fewer 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, 2006, and 2009 were obtained from
the 2001, 2004, 2007, and 2010 UDI Directories of Electric Power Producers and Distributors, respectively (UDI
2001, 2004, 2007, 2010).  The U.S. transmission system grew by over 25,000 miles between 2000 and 2003 and by
over 52,000 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 1.3 percent between 2000 and 2003
and 2.6 percent between 2003 and 2006. This growth rate slowed to 0.2% from 2006 to 2009 as transmission miles
increased by just 4,400 miles (approximately).

As a final step, total electric power system 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 utilities participating in the Partnership reported emissions only for 1999 through 2010, 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 global emissions from this source during
the 1990  to 1999 period. To estimate global emissions, the RAND 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
165 Partners in EPA's SF6 Emission Reduction Partnership reduced their emissions by approximately 62% from 1999 to 2010.


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emissions (Volume 3, Equation 7.3) in the IPCC Guidelines for National Greenhouse Gas Inventories (IPCC
2006). 166 (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.)

Emissions (kilograms SF6) = SF6 purchased to refill existing equipment (kilograms) + nameplate capacity of retiring
                                        equipment (kilograms)  167

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 15.0 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 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
averaging to utility SF6 sales data.  The other factor that may affect the relationship between the RAND sales trends
and actual global emissions is the level of imports from and exports to Russia and China.  SF6 production in these
countries is not included  in the RAND survey and is not accounted for in any another 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 2010 Emissions from Manufacture of Electrical Equipment

The 1990 to 2010 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 2010 were estimated using Partner reported data and the total industry SF6 nameplate
capacity estimate (141.1  TgCO2Eq. in 2010). 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 2010 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
166 Ideally, sales to utilities in the U.S. between 1990 and 1999 would be used as a model. However, this information was not
available. Two U.S. manufacturers of SF6 were operating during this time period, consequently, concealingl sensitive sales
information by aggregation was not feasible.
167 Nameplate capacity is defined as the amount of SF6 within fully charged electrical equipment.


                                                                               Industrial Processes    4-81

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under the auspices of the International Council on Large Electric Systems (CIGRE) in February 2002 (O'Connell et
al. 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 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 5.3 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 2010
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 57 percent of
U.S. transmission miles in 2010) 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 (1) 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 (2) the manufacturers' SF6 emissions rate.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-96.  Electrical Transmission
and Distribution SF6 emissions were estimated to be between 9.2 and 14.7 Tg CO2 Eq. at the 95 percent confidence
level. This indicates a range of approximately 22 percent below and 25 percent above the emission estimate of 11.8
Tg C02 Eq.

Table 4-96: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg CO2 Eq. and percent)

                                  2010 Emission
   Source                  Gas       Estimate        Uncertainty Range Relative to 2010 Emission Estimate3
                                   (Tg C02 Eq.)            (Tg C02 Eq.)                    (%)
                                                                                                 Upper
 	Lower Bound   Upper Bound   Lower Bound	Bound
   Electrical Transmission
    and Distribution	SF«	11.8	92	14.7	-22%	+25%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

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 is similar to 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 (RAND 2004), and emissions based
on atmospheric measurements declined by 17 percent over the same period (Levin et al. 2010).
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

SF6 emission estimates for the period 1990 through 2009 were updated based on 1) new data from EPA's SF6


4-82  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Emission Reduction Partnership; 2) revisions to interpolated and extrapolated non-reported Partner data; and 3) a
correction made to 1999-2001 reported emissions data for a Partner. Correcting the reported emissions not only
directly impacted overall emissions for 1999-2001, but also impacted the regression coefficient used to estimate
emissions for non-Partners, which is based on the relationship between transmission miles and emissions for
Partners that reported emissions in 1999. Specifically, the regression coefficient for utilities with fewer than 10,000
transmission miles decreased from 1.001 kg of emissions per transmission mile to 0.89 kg of emissions per
transmission mile. Based on the revisions listed above, SF6 emissions from electrical transmission and distribution
decreased between 6 and 9 percent for each year from 1990 through 2009.

4.24.  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 2010 are reported in Table 4-97.

Table 4-97: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
   Gas/Source
1990
2005    2006   2007    2008    2009   2010
   NOX                            591
   Other Industrial Processes           343
   Chemical & Allied Product
    Manufacturing                   152
   Metals Processing                  88
   Storage and Transport                3
   Miscellaneous*                     5
   CO                            4,125
   Metals Processing                2,395
   Other Industrial Processes           487
   Chemical & Allied Product
    Manufacturing                  1,073
   Storage and Transport               69
   Miscellaneous*                   101
   NMVOCs                       2,422
   Storage and Transport             1,352
   Other Industrial Processes           364
   Chemical & Allied Product
    Manufacturing                   575
   Metals Processing                 111
   Miscellaneous*                    20
              569
              437
         553
         418
537
398
55
60
15
2
1,555
752
484
57
61
15
2
1,597
788
474
59
62
16
2
1,640
824
464
520
379

 61
 62
 16
  2
 568
 436

  55
  60
  15
   2
568
436

 55
 60
 15
  2
                                    1,682   1,549   1,549
                                      859    752     752
                                      454    484     484
189
97
32
1,997
1,308
415
206
100
30
1,933
1,266
398
223
103
27
1,869
1,224
383
240
104
25
1,804
1,182
367
                                             187
                                              97
                                              29
                                       187
                                        97
                                        29
              213
               44
               17
         211
          44
          14
210
 43
 10
207
 42
  7
1,322    1,322
 662     662
 395     395

 206     206
  44      44
  15      15
   * Miscellaneous includes the following categories: catastrophic/accidental release, other combustion,
    health services, cooling towers, and fugitive dust. It does not include agricultural fires or slash/prescribed
    burning, which are accounted for under the Field Burning of Agricultural Residues source.
   Note: Totals may not sum due to independent rounding.

Methodology

Due to the lack of data available at the time of publication, emission estimates for 2010 rely on 2009 data as a proxy.
Emission estimates for 2009 were obtained from preliminary data (EPA 2010, EPA 2009), and disaggregated based
on EPA (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air
Pollutant Emission Trends web site. Emissions were calculated either for individual categories or for many
categories combined, using basic activity data (e.g., the amount of raw material processed) as an indicator of
emissions. National activity data were collected for individual categories from various agencies.  Depending on the
category, these basic activity data may include data on production, fuel deliveries, raw material processed, etc.

Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
activity.  Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a
variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA databases.
                                                                                Industrial Processes   4-83

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Uncertainty and Time-Series Consistency

Uncertainties in these estimates are partly due to the accuracy of the emission factors and activity data used. A
quantitative uncertainty analysis was not performed.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010. Details on the emission trends through time are described in more detail in the Methodology section,
above.
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               Substitution of Ozone Depleting Substances
            Iron and Steel Prod. & Metallurgical Coke Prod.
                                    Cement Production
                                  Nitric Acid Production
                                       Lime Production
                   Electrical Transmission and Distribution
                            Limestone and Dolomite Use
                                   Ammonia Production
                                   HCFC-22 Production
                             Semiconductor Manufacture  ^B
                                  Aluminum Production  ^H
           Urea Consumption for Non-Agricultural Purposes  ^|
                               Petrochemical Production  ^|
                   Soda Ash Production and Consumption  ^|
                                 Adipic Acid Production  |
                            Carbon  Dioxide Consumption  |
                            Titanium Dioxide Production  |
                                   Ferroalloy Production  |
                    Magnesium Production and Processing  |
                                       Zinc Production  |
                             Phosphoric Acid Production  |
                                       Lead Production  |
               Silicon Carbide Production and Consumption   < 0.5
                                                                                                              115
    Industrial Processes
as a Portion of all Emissions
             4.4%
                                                      0        10        20       30       40
                                                                             TgC02Eq.
                                                                                                   50
                                                                                                            60
Figure 4-1:  2010 Industrial  Processes Chapter Greenhouse Gas Sources

-------
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 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 CO2 equivalent
basis in 2010 (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: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg)
Gas/Source
N2O from Product Uses
Tg CO2 Eq.
Gg
1990
4.4
14


2005
4.4
14
2006
4.4
14
2007
4.4
14
2008
4.4
14
2009
4.4
14
2010
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 2010 was approximately 15 Gg (Table 5-2).

Table 5-2: N2O Production (Gg)
Year
1990
2005
2006
2007
2008
2009
2010
Gg
16
15
15
15
15
15
15
N2O emissions were 4.4 Tg CO2 Eq. (14 Gg) in 2010 (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

-------
Table 5-3: N2O Emissions from N2O Product Usage (Tg CO2 Eq. and Gg)
   Year    Tg CO2 Eq.    Gg
   1990        4.4        14
2005
2006
2007
2008
2009
2010
4.4
4.4
4.4
4.4
4.4
4.4
14
14
14
14
14
14
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 = Zi [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 2010, 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 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 (15.9 to 18.1 thousand metric tons) for 1996 that falls within the production bounds described by
Heydorn (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
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example, in 2003, CGA (2003) estimates N2O production to range between 13.6 and 15.9 thousand metric tons. Due
to unavailable data, production estimates for years 2004 through 2010 were held at the 2003 value.

The 1996 share of the total quantity of N2O used by each subcategory was obtained from SRI Consulting'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 years 2004 through 2010 was assumed to equal
the 2003 value. The emissions rate for the food processing propellant industry was obtained from SRI Consulting'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 2006 IPCC
Guidelines.

Uncertainty and Time-Series Consistency

The overall uncertainty associated with the 2010 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 include 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 4.1 and 4.7 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range  of approximately 8 percent below to 8 percent above the emissions estimate of 4.4 Tg CO2 Eq.

Table 5-4: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from N2O Product Usage (Tg CO2 Eq. and
Percent)

  Source             Gas   2010 Emission     Uncertainty Range Relative to Emission Estimate3
                              Estimate
                            (Tg C02 Eq.)         (Tg C02 Eq.)                 (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
N2O Product N2O 4.4
Usage
4.1 4.7 -8% +8%
   ' Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
   interval.

Furthermore, methodological recalculations were applied to the entire time-series to ensure time-series consistency
from 1990 through 2010. Details on the emission trends through time-series are described in more detail in the
Methodology section, above.

Planned Improvements

Planned improvements include a continued evaluation of alternative production statistics for cross verification, a
reassessment of N2O product use subcategories to accurately represent trends, 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).168 Non-CH4 volatile organic compounds (NMVOCs), commonly referred to as "hydrocarbons,"
168 Solvent usage in the United States also results in the emission of small amounts of hydrofluorocarbons (HFCs) and
                                                                        Solvent and Other Product Use 5-3

-------
are the primary gases emitted from most processes employing organic or petroleum based solvents. As some of
industrial applications also employ thermal incineration as a control technology, combustion by-products, such as
carbon monoxide (CO) and nitrogen oxides (NOX), are also reported with this source category.  In the United States,
emissions from solvents are primarily the result of solvent evaporation, whereby the lighter hydrocarbon molecules
in the solvents escape into the atmosphere.  The evaporation process varies depending on different solvent uses and
solvent types.  The major categories of solvent uses include: degreasing, graphic arts, surface coating, other
industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and non-industrial uses (i.e., uses of paint thinner,
etc.).

Total emissions of NOX, NMVOCs, and CO from 1990 to 2010 are  reported in Table 5-5.
Table 5-5: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
Activity
NOX
Surface Coating
Graphic Arts
Degreasing
Dry Cleaning
Other Industrial
Processes*
Non-Industrial
Processes'5
Other
CO
Surface Coating
Other Industrial
Processes*
Dry Cleaning
Degreasing
Graphic Arts
Non-Industrial
Processes'5
Other
NMVOCs
Surface Coating
Non-Industrial
Processes'5
Degreasing
Dry Cleaning
Graphic Arts
Other Industrial
Processes*
Other
1990
1 |


















NA 1
5,216
2,289

1,724
675
195 1
249 1
85 1
+
2005
3
3
+
+
+

+

+
+
2
2

+
+
+
+

+
+
3,851
1,578

1,446
280
230
194
88
36
2006
4
4
+
+
+

+

+
+
2
2

+
+
+
+

+
+
3,846
1,575

1,444
280
230
193
88
36
2007
4
4
+
+
+

+

+
+
2
2

+
+
+
+

+
+
3,839
1,573

1,441
280
229
193
87
36
2008
4
4
+
+
+

+

+
+
2
2

+
+
+
+

+
+
3,834
1,571

1,439
279
229
193
87
36
2009
3
3
+
+
+

+

+
+
2
2

+
+
+
+

+
+
2,583
1,058

970
188
154
130
59
24
2010
3
3
+
+
+

+

+
+
2
2

+
+
+
+

+
+
2,583
1,058

970
188
154
130
59
24
   * Includes rubber and plastics manufacturing, and other miscellaneous applications.
   b Includes cutback asphalt, pesticide application adhesives, consumer solvents, and other
   miscellaneous applications.
   Note: Totals may not sum due to independent rounding.
   + Does not exceed 0.5 Gg.
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
hydrofluoroethers (HFEs), which are included under Substitution of Ozone Depleting Substances in the Industrial Processes
chapter.


5-4  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
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.

Due to the lack of data available at the time of publication, emission estimates for 2010 rely on 2009 data as a proxy.
Emission estimates for 2009 were obtained from preliminary data (EPA 2010, 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 and Time-Series Consistency

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.

Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.
                                                                          Solvent and Other Product Use 5-5

-------

-------
6.
Agriculture
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 liming of agricultural soils and 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.
Figure 6-1: 2010 Agriculture Chapter Greenhouse Gas Emission Sources
In 2010, the Agriculture sector was responsible for emissions of 428.4 teragrams of CO2 equivalents (Tg CO2 Eq.),
or 6.3 percent of total U.S. greenhouse gas emissions.  Methane (CH4) and nitrous oxide (N2O) were the primary
greenhouse gases emitted by agricultural activities. Methane emissions from enteric fermentation and manure
management represent about 21 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 CH4. Rice
cultivation and field burning of agricultural residues were minor sources of CH4.  Agricultural soil management
activities such as fertilizer application and other cropping practices were the largest source of U.S. N2O emissions,
accounting for 68 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 2010, CH4
emissions from agricultural activities increased by 14.5 percent, while N2O emissions fluctuated from year to year,
but overall increased by 5.0 percent.

Table 6-1: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH,
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N2O
Agricultural Soil Management
Manure Management
Field Burning of Agricultural
Residues
Total
1990
172.9
133.8
31.7
7.1
0.2
214.9
200.0
14.8

0.1
387.8
2005




193.
139,
47,
6,
0,
,9
.0
.9
.8
.2
230.7





213,
17,

0,
424.
.1
.6

.1
6
2006
195.9
141.4
48.4
5.9
0.2
229.6
211.1
18.4

0.1
425.4
2007
202.9
143.8
52.7
6.2
0.2
229.7
211.1
18.5

0.1
432.6
2008
202
.6
143.4
51
7
0
231
212
18

0
433
.8
.2
.2
.3
.9
.3

.1
.8
2009
200.8
142.6
50.7
7.3
0.2
225.6
207.3
18.2

0.1
426.4
2010
202.2
141.3
52.0
8.6
0.2
226.2
207.8
18.3

0.1
428.4
   Note: Totals may not sum due to independent rounding.
Table 6-2: Emissions from Agriculture (Gg)
Gas/Source
CH,
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural Residues
N20
Agricultural Soil Management
Manure Management
1990
8,234
6,373
1,511
339
10
693
645
48
• 2005





9
6
2



,232
,618
,280
326
8
744
687
57
2006
9,327
6,731
2,303
282
11
741
681
59
2007
9
6
2



,663
,850
,508
295
11
741
681
60
2008
9,647
6,829
2,465
343
11
746
687
59
2009
9,564
6,788
2,416
349
11
728
669
59
2010
9,627
6,728
2,478
410
11
730
670
59
                                                                                       Agriculture    6-1

-------
    Field Burning of Agricultural Residues
  + Less than 0.5 Gg.
  Note: Totals may not sum due to independent rounding.


6.1.    Enteric Fermentation (IPCC Source Category 4A)

Methane is produced as part of normal digestive processes in animals. During digestion, microbes resident in an
animal's digestive system ferment food consumed by the animal.  This microbial fermentation process, referred to as
enteric fermentation, produces CH4 as a byproduct, which can be exhaled or eructated by the animal. The amount of
CH4 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 CH4 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 affect 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 2010 were  141.3 Tg CO2 Eq. (6,728 Gg). Beef cattle  remain the largest
contributor of CH4 emissions from enteric fermentation, accounting for 72 percent in 2010.  Emissions from dairy
cattle in 2010 accounted for 23 percent, and the remaining emissions were from horses, sheep, swine, goats,
American bison, mules, burros, and donkeys.

From 1990 to 2010, emissions from enteric fermentation have increased by 5.6 percent. Generally, emissions
decreased from 1996 to 2003, though with a slight increase in 2002.  This trend was mainly  due to decreasing
populations of both beef and dairy cattle and increased digestibility of feed for feedlot cattle. Emissions increased
from 2004 through 2007, as both dairy and beef populations have undergone increases and the literature for dairy
cow diets indicated a trend toward a decrease in feed digestibility for those years. Emissions decreased again in
2008 to 2010 as beef cattle populations again decreased.  During the timeframe of this analysis, populations of sheep
have decreased 51 percent while  horse populations have increased over 87 percent, mostly between 2001  and 2006.
Goat and swine populations have increased 25 percent and 20 percent, respectively, during this timeframe, though
with slight decreases from 2009 to 2010, while the populations of American bison and mules, burros, and donkeys
have more than quadrupled.

Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.)
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Swine
Sheep
Goats
American Bison
Mules, Burros, and
Donkeys
Total
1990
96.2
31.8
I

133.8
2005
101.4
30.4
3.5
1.9
1.0
0.3
0.4
+
139.0
2006
103.0
31.1
3.6
1.0
1.9
0.3
0.4
0.1
141.4
2007
104.0
32.4
3.6
2.1
1.0
0.3
0.3
0.1
143.8
2008
103.1
32.9
3.6
2.1
1.0
0.3
0.4
0.1
143.4
2009
102.0
33.2
3.6
2.1
1.0
0.3
0.3
0.1
142.6
2010
101.1
33.0
3.6
2.0
0.9
0.3
0.3
0.1
141.3

6-2  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
   Notes: + Does not exceed 0.05 Tg CO2 Eq. Totals may not sum due to independent rounding.

Table 6-4:  CH4 Emissions from Enteric Fermentation (Gg)
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Swine
Sheep
Goats
American Bison
Mules, Burros, and
Donkeys
Total
1990
4,581
1,513
91
81
91
13


1 •
6,373
2005
4,829
1,449
166
92
49
14
17

2
6,618
2006
4,904
1,479
171
93
50
15
17

2
6,731
2007
4,953
1,544
171
98
49
16
16

3
6,850
2008
4,909
1,564
171
101
48
16
17

3
6,829
2009
4,857
1,581
171
99
46
16
17

3
6,788
2010
4,812
1,569
171
97
45
16
16

3
6,728
   Note: Totals may not sum due to independent rounding.

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. Emission estimates for other domesticated animals (horses, sheep,
swine, goats, American bison, and mules, burrow, and donkeys) 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
             o    Calves
             o    Heifer Replacements
             o    Cows
•   Beef Cattle
             o    Calves
             o    Heifer Replacements
             o    Heifer and Steer Stackers
             o    Animals in Feedlots (Heifers and Steers)
             o    Cows
             o    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 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
                                                                                          Agriculture    6-3

-------
Agricultural Statistics Service (NASS) QuickStats database (USDA 2011).

Diet characteristics were estimated by region for U. S. dairy, foraging beef, and feedlot beef cattle. These estimates
were used to calculate Digestible Energy (DE) values (expressed as the percent of gross energy intake digested by
the animal) and CH4 conversion rates (Ym) (expressed as the fraction of gross energy converted to CH4) for each
population category. The IPCC recommends Ym ranges 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.  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 and scientific literature,
expert opinion, and modeling of animal physiology.

The diet characteristics for dairy cattle were based on Donovan (1999) and an extensive review of nearly 20 years of
literature from 1990 through 2009. Estimates of DE were national averages based on the feed components of the
diets observed in the literature for the following year groupings: 1990-1993,  1994-1998, 1999-2002, 2003, 2004-
2006, 2007, and 2008 onwards. Base year Ym values by region were estimated using Donovan (1999).  A ruminant
digestion model (COWPOLL, as selected in Kebreab et al. 2008) was used to evaluate Ym for each diet evaluated
from the literature, and a function was developed to adjust regional values over time based on the national trend.
Dairy replacement heifer diet assumptions were based on the observed relationship in the literature between dairy
cow and dairy heifer diet characteristics.

For feedlot animals, the DE  and Ym values used for 1990 were recommended by Johnson (1999).  Values for DE
and Ym for 1991 through 1999 were linearly extrapolated based on the 1990 and 2000 data. DE and Ym values for
2000 onwards were based on survey data in Galyean and Gleghorn (2001) and Vasconcelos and Galyean (2007).

For grazing beef cattle, Ym values were based on Johnson (2002), DE values for 1990 through 2006 were based on
specific diet components estimated from Donovan (1999),  and DE values from 2007 onwards were developed from
an analysis by Archibeque (2011), based on diet information in USD A (2010). Weight and weight gains for cattle
were estimated from Holstein (2010), Doren et  al. (1989), Enns (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 calves younger than 7 months,169 the population was divided
into state, age, sub-type (i.e., dairy cows and replacements, beef cows and replacements, heifer and steer stackers,
heifers and steers in feedlots, and bulls), 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 CH4 emission factors for the  following cattle types: dairy cows, beef cows, dairy replacements,
beef replacements, steer stackers,  heifer stackers, steer feedlot animals, heifer feedlot  animals, and bulls. 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 2010. 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 sheep and swine were obtained for all years
from USD A NASS (USDA 2011). Horse population data were obtained from the Food and Agriculture
Organization of the United Nations (FAO) FAOSTAT database (FAO 2011), because USDA does not estimate U.S.
horse populations annually.  Goat and mule, burro, and donkey population data were available for 1987, 1992, 1997,
2002, and 2007 (USDA 1992, 1997, 2011); the remaining years between 1990 and 2010 were interpolated and
extrapolated from the available estimates. American bison population estimates were available from USDA for
2002 and 2007 (USDA 2011) and from the National Bison Association (1999) for 1997 through 1999. Additional
years were based on observed trends from the National Bison Association (1999), interpolation between known data
169 Because calves younger than 7 months consume mainly milk and the IPCC recommends the use of a 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: 1990-2010

-------
points, and ratios of population to slaughter statistics (USDA 2011), as described in more detail in Annex 3.9.
Methane emissions from sheep, goats, swine, horses, American bison, and mules, burros, and donkeys 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. For American
bison the emission factor for buffalo was used and adjusted based on the ratio of live weights to the 0.75 power.
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 and Time-Series Consistency

A quantitative uncertainty analysis for this source category was performed using 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. There have been no
significant changes to the methodology, although the source of some input variables have been updated, at this time
there are not better estimates available for the uncertainty ranges around the 2010 activity data and emission factor
input variables used in the current submission.  Consequently, these uncertainty estimates were directly applied to
the 2010 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 ensure only positive values would be simulated. 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 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 are summarized in Table 6-5.
Based on this analysis, enteric fermentation CH4 emissions in 2010 were estimated to be between  125.8 and 166.7
Tg CO2 Eq. at a 95 percent confidence level, which indicates a range of 11 percent below to 18 percent above the
2010 emission estimate of 141.3 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 emission estimates.
Among non-cattle, horses account for the largest degree of uncertainty in the  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. American bison, mules, burros, and donkeys were excluded from the
initial uncertainty estimate because they were not included in the estimate of  emissions at that time, although
because of their small populations they would not significantly increase the uncertainty estimate ranges of the
overall emissions from enteric fermentation.

Table 6-5:  Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg  CO2 Eq. and
Percent)
Source Gas 2010 Emission
Estimate
(TgC02Eq.)

Enteric Fermentation CH4 141.3
Uncertainty Range Relative to Emission Estimate3' ' c
(TgC02Eq.) (%)
Lower
Bound
125.8
Upper
Bound
166.7
Lower
Bound
-11%
Upper
Bound
+18%
   a Range of emissions 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 2010 estimates.
   c The overall uncertainty calculated in 2003, and applied to the 2010 emission estimate, did not include uncertainty
   estimates for American bison, mules, burros, and donkeys, and was based on the Tier 1 methodology for bulls.
   Consequently, there was more uncertainty with bull emissions than with other cattle types.
                                                                                          Agriculture    6-5

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Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section.

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 emission estimates.  Recent updates to the foraging
portion of the diet values for cattle made this the area of emphasis for QA/QC this year, with specific attention to the
data sources and comparisons of the current estimates with previous estimates.

In addition, over the past few years, particular importance has been placed on harmonizing the data exchange
between the enteric fermentation and manure management source categories.  The current inventory submission now
utilizes the transition matrix from the CEFM for estimating cattle populations and weights for both source
categories, and the CEFM is used to output volatile solids and nitrogen (N) excretion estimates using the diet
assumptions in the model in conjunction with the energy balance equations from the IPCC (2006).  This approach
facilitates the QA/QC process for both of these source categories.

Recalculations  Discussion

There were several modifications  to the methodology that had an effect on emission estimates, including the
following:

•   Emissions from bulls were estimated using Tier 2 methodology.  This resulted in an increase of emissions from
    bulls by an average of approximately 79 percent per year compared to the previous Inventory estimates which
    used a Tier 1 methodology, such that bulls represent 3.4 percent of total enteric fermentation emissions from
    cattle.

•   Revisions to the DE values for foraging cattle diets were applied to 1990-2010, resulting in an average change
    of less than 0.1 percent for foraging beef cattle emissions estimates for 1990 through 2006 and an average
    increase of 0.4 percent for 2007 through 2009.  Details on the current dietary assumptions are discussed in
    Annex 3.9.

•   During the QA/QC process, it was realized that the one data point from 1988 (total births) had been revised by
    USDA since its original download. Therefore, the data point was corrected from 39,318.0 to 39,317.9 thousand
    births. This is a very minor change, but it is noted in detail specifically because it affects 1990 base year
    emissions by trickling through the transition matrix in the growing populations for 1989 and 1990.

•   The equations used to  distribute end-of-year remaining populations for feedlot cattle to the individual state
    populations were updated so that the population proportions reflect the current year rather than the following
    year populations. This did not affect total populations, but there were minor changes to the populations by state
    for feedlot cattle for all years.

•   Previously, American bison and mules, burros, and donkeys were excluded from this source category. Emission
    estimates are now included for these animal types for all years, and contribute an average of 0.2 percent of total
    emissions from enteric fermentation across the time series.

•   The USDA published revised estimates in several categories that affected historical emissions estimated for
    cattle, including slight revisions in 2009 cattle on feed population estimates for "other states" (aggregated data
    for states with small populations of cattle on feed), dairy cow milk production for several states, and steer and
    heifer placement and slaughter statistics. Additionally, calf births were revised for both the 2008 and 2009
    estimates. These changes had an insignificant impact on the overall results.

•   There were additional  population changes for goats from 2003 through 2006, sheep for 2004, 2006, and 2009,
    and swine in 2009, as discussed in the  recalculations discussion for manure management.  Historical emission
    estimates for goats increased  an average of 12.1 percent per year compared to the previous emission estimates
    for the years mentioned above. All other population changes resulted in a decrease in emissions of less than 1
    percent for the animal  type and year noted.
6-6  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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As a result of these changes, overall methane emissions from enteric fermentation increased an average of 111 Gg
(1.7 percent) peryear for 1990 through 2009.

Planned Improvements

Continued research and regular updates are necessary to maintain an emissions inventory that reflects the current
base of knowledge.  Ongoing revisions for enteric fermentation could include some of the following options:

•   Updating input variables that are from older data sources, such as beef births by month and beef cow lactation
    rates;

•   Investigation of the availability of annual data for the DE and crude protein values of specific diet and feed
    components for foraging and feedlot animals;

•   Given the many challenges in characterizing dairy diets, further investigation will be conducted on additional
    sources or methodologies for estimating DE for dairy. For example, the current method causes  some significant
    shifts in data between years that may not mimic actual feeding conditions. Regional trend lines may be used to
    smooth the transition.

•   The possible breakout of other animal types (i.e., sheep, swine, goats, horses) from national estimates to state-
    level estimates or updating to Tier 2 methodology; and

•   The investigation of methodologies for including enteric fermentation emission estimates from poultry.

In addition, recent changes that have been implemented to the CEFM warrant an assessment of the current
uncertainty analysis; therefore, 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 anthropogenic 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 dung and urine. 17° Indirect N2O emissions are produced
as result of the volatilization of N as NH3 and 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 CH4produced.  In general, the greater the energy
content of the feed, the greater the potential for CH4 emissions. However, 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 ammonia (NH3) or organic N is
converted to nitrates and nitrites (nitrification), and then handled anaerobically where the nitrates and nitrites are
reduced to dinitrogen 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
170 Direct and indirect N2O emissions from dung and urine spread onto fields either directly as daily spread or after it is removed
from manure management systems (e.g., lagoon, pit, etc.) and from livestock dung and urine deposited on pasture, range, or
paddock lands are accounted for and discussed in the Agricultural Soil Management source category within the Agriculture
sector.


                                                                                        Agriculture    6-7

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N excreted is expected to convert to N2O in the waste management system (WMS). Indirect N2O emissions are
produced when nitrogen 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 is exposed 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 2010 were  52.0 Tg CO2 Eq. (2,478 Gg), 64 percent higher than in 1990. Emissions
increased on average by 1.0 Tg CO2 Eq. (3.0 percent) annually over this period.  The majority of this increase was
from swine and dairy cow manure, where  emissions increased 20 and 107 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 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,
2002, and 2007 farm-size distribution data reported in the Census of Agriculture (USDA 2009a).  Methane
emissions from sheep have  decreased significantly since 1990 (a 56 percent decrease from 1990 to 2010); however,
this is mainly due  to  population changes.  Overall, sheep contribute less than one percent of CH4 emissions from
animal manure management.  From 2009 to 2010, there was a 2.6 percent increase in total CH4 emissions, mainly
due to minor shifts in the animal populations and the resultant effects on manure management system allocations.

In 2010, total N2O emissions were estimated to be 18.3 Tg CO2 Eq.  (59 Gg); in 1990, emissions were 14.8 Tg CO2
Eq. (48 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 24
percent increase from 1990 to 2010 and a  less than 1 percent increase from 2009 through 2010.

Table 6-6 and Table  6-7 provide estimates of CH4 and N2O emissions from manure management by animal
category.

Table 6-6: CH4 and  N2O Emissions from  Manure Management (Tg CO2 Eq.)
Gas/Animal Type
CH,"
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N2Ob
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
1990
31.7
12.6
2.7
13.1
«
2.8
0.5
14.8
5.3
6.5
1.2
«
1.5
0.2
2005
47.9
22.4
2.8
19.2
0.1
2.7
0.6
17.6
5.7
7.8
1.8
0.4
1.7
0.3
2006
48.4
23.1
2.9
18.9
0.1
2.7
0.6
18.4
5.8
8.3
1.8
0.4
1.7
0.3
2007
52.7
25.7
2.9
20.6
0.1
2.8
0.6
18.5
5.9
8.2
2.0
0.4
1.7
0.3
2008
51.8
26.0
2.8
19.7
0.1
2.7
0.5
18.3
5.8
8.1
2.0
0.4
1.7
0.3
2009
50.7
25.9
2.7
18.8
0.1
2.7
0.5
18.2
5.8
8.1
2.0
0.3
1.6
0.3
2010
52.0
26.0
2.8
19.9
0.1
2.7
0.5
18.3
5.9
8.2
1.9
0.3
1.6
0.3
6-8  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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  Total
46.5
65.5    66.7    71.1
70.0    68.9   70.4
  + Less than 0.05 Tg CO2 Eq.
  aAccounts for CH4 reductions due to capture and destruction of CH4 at facilities using
  anaerobic digesters.
  Includes both direct and indirect N2O emissions.
  Note: Totals may not sum due to independent rounding.
Table 6-7: CH4 and N2O Emissions from Manure Management (Gg)
Gas/ Animal Type
CH/
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N20b
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
1990 2005
1,511 2,280
599 1069
128 135
624 914
7
1
131
22
48
17
21
4
+
+
5
3
1
129
28
57
18
25
6
1
+
5
IM I
2006
2,303
1101
138
901
3
1
131
27
59
19
27
6
1
+
5
1
2007
2,508
1224
136
982
3
1
134
27
60
19
27
6
1
+
5
1
2008
2,465
1238
132
938
3
1
129
24
59
19
26
6
1
+
5
1
2009
2,416
1233
131
896
3
1
128
24
59
19
26
6
1
+
5
1
2010
2,478
1239
134
948
3
1
129
24
59
19
27
6
1
+
5
1
  + Less than 0.5 Gg.
  aAccounts for CH4 reductions due to capture and destruction of CH4 at facilities using
  anaerobic digesters.
  Includes both direct and indirect N2O emissions.
  Note: Totals may not sum due to independent rounding.
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 from manure
management. 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 CH4 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 United States);
    •   Methane producing potential (B0) of the volatile solids (by animal type); and
    •   Methane conversion factors (MCF), the extent to which the CH4 producing potential is realized for each
        type of WMS (by state and manure management system, including the impacts of any biogas collection
        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 2010 for all livestock types, except horses and goats were
        obtained from USDA NASS. For cattle, the USD A populations were utilized in conjunction with birth
        rates, detailed feedlot placement information, and slaughter weight data to create the transition matrix in the
                                                                                        Agriculture    6-9

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        CEFM that models cohorts of individual animal types and their specific emission profiles. The key
        variables tracked for each of the cattle population categories are described in Section 6.1 and in more detail
        in Annex 3.9.  Horse population data were obtained from the FAOSTAT database (FAO 2010).  Goat
        population data for 1992, 1997, 2002, and 2007 were obtained from the Census of Agriculture (USD A
        2009a).

    •   The TAM is an annual average weight which was obtained for animal types other than cattle from
        information in USD A' sAgricultur al Waste Management Field Handbook (USD A 1996a), the American
        Society of Agricultural Engineers, Standard D384.1 (ASAE  1999) and others (EPA 1992, Safley 2000,
        ERG 2010a). For a description of the TAM used for cattle, please see section 6.1, Enteric Fermentation.

    •   WMS usage was estimated for swine and dairy cattle for different farm size categories using data from
        USDA (USDA 1996b, 1998b, 2000a, 2009a) and EPA (ERG 2000a, EPA 2002a, 2002b). For beef cattle
        and poultry, 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 by head for each state and
        animal type in the CEFM. VS production rates by animal mass for all other animals were determined using
        datafromUSDA's^gr/cMtora/ Waste Management Field Handbook (USDA 1996a, 2008 andERG2010b
        and 20 lOc) and data from the American Society of Agricultural Engineers, Standard D384.1 (ASAE 1998).

    •   The maximum CH4 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, 2003, 2006) and the AgSTAR project database (EPA 2011).
        Anaerobic digester emissions were calculated based on estimated methane production and collection and
        destruction efficiency assumptions (ERG 2008).

To estimate CH4 emissions for cattle, the estimated amount of VS (kg per animal-year) managed in each WMS for
each animal type, state, and year were taken from the CEFM. For animals other than cattle, the annual amount of VS
(kg per year) from manure excreted in each WMS was calculated for  each animal type, state, and year. 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 (365.25).

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) were 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 CH4per m3 CH4). The
CH4 emissions for each WMS, state, and animal type were summed to determine the total U.S. CH4 emissions.

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 volitalization (EFvolltallzatlon);
    •   Indirect N2O emission factor for runoff and leaching (EF^o^-/^^);
    •   Fraction of N loss from volitalization of NH3 and NOX  (Fracgas); and
    •   Fraction of N loss from runoff and leaching (FraCrunoff/ieach)-


6-10  Inventory of U.S. Greenhouse Gas Emissions and Sinks:  1990-2010

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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:

    •   Nex rates for all cattle except for bulls and calves were calculated by head for each state and animal type in
        the CEFM. Nex rates by animal mass for all other animals were determined using data from USDA's
        Agricultural Waste Management Field Handbook (USDA 1996a, 2008 and ERG 2010b and 2010c) and
        data from the American Society of Agricultural Engineers, Standard D384.1 (ASAE 1998).

    •   All N2O emission factors (direct and indirect) were taken from IPCC (2006).

    •   Country-specific  estimates for the fraction of N loss from volatilization (Fracgas) and runoff and leaching
        (FraCrunoff/ieach) were developed. FraCgas values were based on WMS-specific volatilization values as
        estimated from EPA's National Emission Inventory - Ammonia Emissions from Animal Agriculture
        Operations (EPA 2005). FraCrunoff/kachmg values were based on regional cattle runoff data from EPA's
        Office of Water (EPA 2002b; see Annex 3.1).

To estimate N2O emissions for cattle, the estimated amount of N excreted (kg per animal-year) managed in each
WMS for each animal type, state, and year were taken from the CEFM. For animals other than cattle, the amount of
N excreted (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
nitrogen 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 N excreted (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).

Next, 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 (Fractas) divided by 100, and the
emission factor for volatilization (EFvoiatiiiZation, in kg N2O per kg N), and the conversion factor of N2O-N to N2O.
Indirect N2O emissions from runoff and leaching (kg N2O per year) were then calculated by multiplying the amount
of N excreted (kg per year) in each WMS by the fraction of N lost through runoff and leaching (FraCmnofFieach)
divided by 100, and the emission factor for runoff and leaching (EFrunofMeach, 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 and Time-Series Consistency

An analysis (ERG 2003) was conducted for the manure management emission estimates presented in the 1990
through 2001 Inventory report 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.  These uncertainty estimates were directly applied to the 2010 emission estimates.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 6-8. Manure management CH4
emissions in 2010 were estimated to be between 42.7 and 62.5 Tg CO2 Eq. at a 95 percent confidence level, which
indicates a range of 18 percent below to 20 percent above the actual 2010 emission estimate of 52.0 Tg CO2 Eq.  At
the 95 percent confidence  level, N2O emissions were estimated to be between 15.4 and 22.7 Tg CO2 Eq. (or
approximately 16 percent below and 24 percent above the actual 2010 emission estimate of 18.3 Tg CO2 Eq.).
                                                                                      Agriculture    6-11

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Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O (Direct and Indirect) Emissions from Manure
Management (Tg CO2 Eq. and Percent)
Source
Gas
2010 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Manure Management
Manure Management
CH4
N2O
52.0
18.3
42.7 62.5 -18% +20%
15.4 22.7 -16% +24%
    aRange 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 N2O emissions from managed systems and CH4
emissions from livestock manure. 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.

The U.S. specific values for TAM, Nex, VS, B0, MCF, and the resulting implied emission factors were also
compared to the IPCC default values. Although significant differences exist in some instances, these differences are
due to the use of U.S. specific data and the differences in U.S. agriculture as compared to other countries. The U.S.
manure management emission estimates use the most reliable country-specific data, which are more representative
of U.S. animals and systems than the IPPC default values. For example, the U.S. implied CH4 emission factor for
dairy cattle is significantly higher than the IPCC default implied CH4 emission factor. This is because U.S. dairy
manure is most commonly managed in liquid systems, which produce more CH4.

Recalculations Discussion

The CEFM produces population, VS and Nex data for cattle that are used in the manure management inventory.  As
a result, all changes to the CEFM described in Section 6.1 Enteric Fermentation contributed to changes in the
population, VS and Nex data used for calculating CH4 and N2O cattle emissions from manure management.

Data from the 2007 Census of Agriculture were incorporated into the inventory. Census farm size distribution data
were used to update the WMS distributions for dairy and swine  in 2007. The dairy and swine WMS distributions
between 2002 and 2007 were extrapolated based on the 2002  and 2007 data; WMS distributions after 2007 were
assumed to be equal to 2007 values.  The dairy and swine WMS update caused changes in dairy and swine emission
estimates from 2003 on.

In addition, census county-level population data were used to update the county-level population estimates.  These
estimates are used as input to the Agricultural Soil Management calculations, and to determine population-weighted
state temperatures which are used to calculate MCFs for liquid systems. The county-level population update caused
minor changes in methane emissions for all animals throughout the timeseries.

State animal populations were updated to reflect updated USDA NASS datasets. Population changes occurred for
all animals in 2009. Sheep populations experienced changes in 2004 to 2006 and 2008 estimates due to a change in
the  "other states" reported by USDA NASS.

Temperature data were updated to incorporate  the most recent available data. The temperature data are used to
estimate MCFs for liquid systems; this update caused minor changes in CH4 emission estimates from dairy, swine,
beef, and poultry from 2007 to 2009.

Planned  Improvements

Tier 1 emission estimates for mules, donkeys, burros, and American bison will be incorporated into future
6-12  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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inventories.  Although these animal groups are considered very minor sources of emissions and will not contribute
significantly to the overall U.S. emissions from manure management, they will be included for completeness and
consistency across source categories.

The uncertainty analysis will be updated in the future to more accurately assess uncertainty of emission calculations.
This update is necessary due to the extensive changes in emission calculation methodology, 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 CH4 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 CH4 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 CH4
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 CH4 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 CH4 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 CH4 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,171 and cultivation  practices) are the most important variables influencing the
amount of CH4 emitted over the growing season;  the total amount of CH4 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 CH4 production.  However, although temperature controls the
amount of time it takes to convert a given amount of organic material to CH4, 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 CH4 emissions; in particular, both nitrate and
sulfate fertilizers (e.g., ammonium nitrate and ammonium sulfate) appear to inhibit CH4  formation.

Rice is cultivated in eight states: Arkansas, California,  Florida, Louisiana, Mississippi, Missouri, Oklahoma, and
Texas.172 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 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
171 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.
172 A very small amount of rice is grown on about 20 acres in South Carolina; however, this amount was determined to be too
insignificant to warrant inclusion in national emission estimates.


                                                                                       Agriculture    6-13

-------
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 (Table 6-9 and Table 6-10). In 2010, CH4 emissions
from rice cultivation were 8.6 Tg CO2 Eq. (410 Gg).  Annual emissions fluctuated unevenly between the years 1990
and 2010, ranging from an annual decrease of 14 percent to an annual increase of 17 percent. There was an overall
decrease of 17 percent between 1990 and 2006, due to an overall decrease in primary crop area.173 However,
emission levels increased again by 45 percent between 2006 and 2010 due to an increase in rice crop area in all
states except Oklahoma, which reported no rice production in 2009 and 2010.  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.
Table 6-9:  CH4 Emissions from Rice Cultivation (Tg CO2 Eq.)

    State	1990	2005     2006      2007      2008     2009     2010
    Primary              5.1            6.0       5.1       4.9        5.3       5.6       6.5
     Arkansas             2.1            2.9       2.5       2.4        2.5       2.6       3.2
     California            0.7            0.9       0.9       1.0        0.9       1.0       1.0
     Florida               + I            ++         +         +        +        +
     Louisiana            1.0            0.9       0.6       0.7        0.8       0.8       1.0
     Mississippi           0.4            0.5       0.3       0.3        0.4       0.4       0.5
     Missouri             0.1            0.4       0.4       0.3        0.4       0.4       0.4
     Oklahoma             + I            ++         +         +        +        +
     Texas               0.6            0.4       0.3       0.3        0.3       0.3       0.3
    Ratoon               2.1            0.8       0.9       1.3        1.9       1.8       2.1
     Arkansas              + I            ++         +         +        +        +
     Florida               + I            ++         +         +        +        +
     Louisiana            1.1            0.5       0.5       0.9        1.2       1.1       1.4
     Texas	0.9	0.4       0.4	0.3	0.6       0.7       0.7
    Total	XI	6.8       5.9       6.2        7.2       7.3       8.6
    + Less than 0.05 Tg CO2 Eq.
    Note:  Totals may not sum due to independent rounding.

Table 6-10: CH4 Emissions from Rice Cultivation (Gg)

    State	1990	2005      2006     2007      2008      2009      2010
    Primary              241             287       241      235       254        265       308
     Arkansas             102             139       119      113       119        125       152
     California             34               45       44       45        44         47        47
     Florida                I  I            111         1          1          1
     Louisiana             46               45       29       32        39         39        45
     Mississippi            21               22        16       16        19         21         26
     Missouri               7  I            18        18       15        17         17        21
     Oklahoma              +  I            +        +        +         +          +         +
     Texas                30               17        13       12        15         14        16
    Ratoon                98               39       41       60        89         84       101
     Arkansas               +  I            1        +        +         +          +         +
     Florida                2  I            +11         1          2         2
     Louisiana             52               22       22       42        59         51         68
173 The 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: 1990-2010

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     Texas
    Total
 45
339
 17
326
 18
282
    + Less than 0.5 Gg
    Note: Totals may not sum due to independent rounding.
 16
295
 29
343
 31
349
 32
410
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. To that end, the recommended methodology and Tier 2 U.S.-specific emission factors derived from rice
field measurements were used.  Average U.S. seasonal emission factors were applied since state-specific and daily
emission factors were not available. 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).

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
2010 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 2011). 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 2010 (Guethle 1999 through 2010;
Lee 2003 through 2007; Mutters 2002  through 2005; Street  1999 through 2003; Walker 2005, 2007 through 2008;
Buehring 2009 through 2011).

Table 6-11: Rice Areas Harvested  (Hectares)
State/Crop
Arkansas
Primary
Ratoona
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Oklahoma
Texas
Primary
Ratoon
Total Primary
Total Ratoon
Total
1990

485,633
-
159,854

4,978
2,489

220,558
66,168
101,174
32,376
617

142,857
57,143
1,148,047
125,799
1,273,847
2005

661,675
662
212,869

4,565
+

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

6,242
1,873

152,975
53,541
76,487
72,036
+

58,681
21,125
1,118,343
76,544
1,194,887
2008

564,549
6
209,227

5,463
1,639

187,778
75,111
92,675
80,534
77

69,607
36,892
1,209,911
113,648
1,323,559
2009

594,901
6
225,010

5,664
2,266

187,778
65,722
98,341
80,939
+

68,798
39,903
1,261,431
107,897
1,369,328
2010

722,380
7
223,796

5,330
2,275

216,512
86,605
122,622
101,578
+

76,083
41,085
1,468,300
129,971
1,598,271
  a Arkansas ratooning occurred only in 1998, 1999, and 2005 through 2010.
  + Emissions are less than 0.1 Tg CO2 Eq.
  - No reported value
  Note: Totals may not sum due to independent rounding.
                                                                                      Agriculture    6-15

-------
Table 6-12:  Ratooned Area as Percent of Primary Growth Area
  State
1990
1997 1998  1999 2000  2001 2002  2003  2004   2005   2006   2007  2008   2009   2010
  Arkansas
  Florida
  Louisiana
  Texas
    0%
                            0%
0.1%
      50%         65% 41%  60%  54%  100%  77%   0%    28%   30%    30%   40%   43%
         30%           40%  30%  15%  35%  30%  13%   20%   35%    40%   35%   40%
         40%           50%  40%  37%  38%  35%  27%   39%   36%    53%   58%   54%
  + Indicates ratooning rate less than 0.1 percent.
Table 6-13:  Non-USD A Data Sources for Rice Harvest Information
   State/Crop    1990     2000    2001   2002   2003
                                          2004
                                           2005   2006  2007   2008   2009   2010
                                                Arkansas
   Ratoon
                               Wilson (2002 - 2007,2009 - 2011)
Florida
Primary
Ratoon
Scheuneman
(1999-2001)
Scheuneman
(1999)
Deren
(2002)
Deren
(2002)
Kirstein (2003, 2006)
Kirstein Cantens
(2003-2004) (2005)
Gonzales (2006
Gonzales (2006
-2011)
-2011)
                                                Louisiana
Ratoon
Bollich
(2000)
Linscombe( 1999, 2001 -2011)
Oklahoma
Primary
Lee (2003-2007)
Anderson (2008 -
2011)
Texas
Ratoon
Klosterboer(1999
-2003)
Stansel (2004 -
2005)
Texas Ag Experiment Station (2006
-2011)
To determine what CH4 emission factors should be used for the primary and ratoon crops, CH4 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 results174 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 et al. 1992; Sass et al.
1991a, 1991b) 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 to derive
an emission factor for the ratoon crop.  The resultant emission factor for the primary crop is 210 kg QVhectare-
season, and the resultant emission factor for the ratoon crop is 780 kg CH4/hectare-season.

Uncertainty and Time-Series Consistency

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, particularly 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
174 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.
6-16   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

-------
used to derive the emission factors applied here, primary emissions ranged from 22 to 479 kg CHVhectare-season
and ratoon emissions ranged from 481 to 1,490 kg CH4/hectare-season. The uncertainty distributions around the
primary and ratoon emission factors 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 uncertainty estimates were calculated for the practice of flooding outside of the normal
rice season because CH4 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 CH4 emissions in 2010 were estimated to be between 3.0 and 21.8 Tg
CO2 Eq. at a 95 percent confidence level, which indicates a range of 65 percent below to  153 percent above the
actual 2010 emission estimate of 8.6 Tg CO2 Eq.

Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
Percent)
Source Gas 2010 Emission Uncertainty Range Relative to Emission Estimate3
Estimate
(TgC02Eq.) (TgC02Eq.) (%)

Rice Cultivation CH4 8.6
Lower
Bound
3.0
Upper
Bound
21.8
Lower
Bound
-65%
Upper
Bound
+153%
   a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence
   interval.

Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
through 2010.  Details on the emission trends through time are described in more detail in the Methodology section,
above.

QA/QC and Verification

A source-specific QA/QC plan for rice cultivation was developed and implemented.  This effort included a Tier 1
analysis,  as well as portions of a Tier 2 analysis. The Tier 2 procedures focused on comparing trends across years,
states, and cropping  seasons to attempt to identify any outliers or inconsistencies. No problems were found.

Planned  Improvements

A possible future improvement is to create region-specific emission factors for rice cultivation. The current
methodology uses a  nationwide average emission factor, derived from several studies done in a number of states.
The prospective improvement would take the same studies and average them by region, presumably resulting in
more spatially  specific emission factors.

6.4.    Agricultural Soil Management (IPCC Source Category 4D)

Nitrous oxide is produced naturally in soils through the microbial processes of nitrification and denitrification.175 A
175 Nitrification and denitrification are driven by the activity of microorganisms in soils. Nitrification is the aerobic microbial
oxidation of ammonium (NH4+) to nitrate (NO3~), and denitrification is the anaerobic microbial reduction of nitrate to N2. Nitrous


                                                                                      Agriculture    6-17

-------
number of agricultural activities increase mineral N availability in soils, thereby increasing the amount available for
nitrification and denitrification, and ultimately the amount of N2O emitted. These activities increase soil mineral N
either directly or indirectly (see Figure 6-2).  Direct increases occur through a variety of management practices that
add or lead to greater release of mineral N to the soil, including fertilization; application of managed livestock
manure and other organic materials such as sewage sludge; deposition of manure on soils by domesticated animals
in pastures, rangelands, and paddocks (PRP) (i.e., by grazing animals and other animals whose manure is not
managed); production of N-fixing crops  and forages; retention of crop residues; and drainage and cultivation of
organic cropland soils (i.e., soils with a high organic matter content, otherwise known as histosols).176 Other
agricultural soil management activities, including irrigation, drainage, tillage practices, and fallowing of land, can
influence N mineralization in soils and thereby affect direct emissions. Mineral N is also made available in soils
through decomposition of soil organic matter and plant litter, as well as asymbiotic fixation of N from the
atmosphere,177 and these processes are influenced by agricultural management through impacts on moisture and
temperature regimes in soils. These additional sources of mineral N are included at the recommendation of IPCC
(2006) for complete accounting of management impacts on greenhouse gas emissions, as discussed in the
Methodology section. Indirect emissions of N2O occur through two pathways: (1) volatilization and subsequent
atmospheric deposition of applied/mineralized N,178 and (2) surface runoff and leaching of applied/mineralized N
into groundwater and surface water. Direct emissions from agricultural lands (i.e., cropland and grassland)  are
included in this section, while direct emissions from forest lands and settlements are presented in the Land Use,
Land-Use Change, and Forestry chapter. However, indirect N2O emissions from all land-uses (cropland, grassland,
forest lands, and settlements) are reported in this  section.


Figure 6-2: Sources and Pathways of N that Result in N2O Emissions from Agricultural Soil Management


Agricultural soils produce the majority of N2O emissions in the United States.  Estimated emissions from this source
in 2010 were 207.8 Tg CO2 Eq. (670 Gg N2O) (see Table  6-15 and Table 6-16). Annual N2O emissions from
agricultural soils fluctuated between 1990 and 2010, although overall emissions were almost 4 percent higher in
2010 than in  1990. Year-to-year fluctuations are largely a reflection of annual variation in weather patterns,
synthetic fertilizer use, and crop production.  On average,  cropland accounted for approximately 70 percent of total
direct emissions, while grassland accounted for approximately 30 percent. These percentages are about the  same for
indirect emissions since forest lands and settlements account for such a small percentage of total indirect emissions.
Estimated direct and indirect N2O emissions by sub-source category are shown in Table 6-17 and Table 6-6-18.

Table 6-15: N2O Emissions from Agricultural Soils (Tg CO2 Eq.)
Activity
Direct
Cropland
Grassland
Indirect
(All Land-
Use
Types)
Cropland
Grassland
Forest
1990
155.8
103.0
52.8 1


44.1 1
37.4 1
6.4 1
+
2005
169.1
118.0
51.1


43.9
36.7
6.5
0.1
2006
165.6
115.7
49.9


45.5
38.7
6.0
0.1
2007
166.8
117.8
49.0


44.3
37.5
6.1
0.1
2008
168.5
118.0
50.5


44.4
37.6
6.1
0.1
2009
162.2
112.4
49.9


45.0
37.9
6.4
0.1
2010
162.3
112.4
49.9


45.5
38.5
6.4
0.1
oxide is a gaseous intermediate product in the reaction sequence of denitriiication, which leaks from microbial cells into the soil
and then into the atmosphere.  Nitrous oxide is also produced during nitrification, although by a less well-understood mechanism
(Nevison 2000).
    Drainage and cultivation of organic soils in former wetlands enhances mineralization of N-rich organic matter, thereby
increasing N2O emissions from these soils.
177 Asymbiotic N fixation is the fixation of atmospheric N2 by bacteria living in soils that do not have a direct relationship with
plants.
178 These processes entail volatilization of applied or mineralized N as NH3 and NOX, transformation of these gases within the
atmosphere (or upon deposition), and deposition of the N primarily in the form of particulate NH4+, nitric acid (HNO3), and NOX.


6-18  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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    Land
     Settlemen
    ts
0.3
0.6
0.6
0.6
0.6
0.6
0.6
   Total
                   200.0
           213.1
        211.1
        211.1
        212.9
        207.3
        207.8
   + Less than 0.05 Tg CO2 Eq.
   Note: The cropland and grassland estimates for 2010 are based on the emissions from 2009. Due to
   limited changes in management of agricultural soils between the two year, the estimate for 2009 is
   expected to be representative of emissions in 2010. See the Planned Improvement section for
   additional details.s.

Table 6-16: N2O Emissions from Agricultural Soils (Gg)
Activity
Direct
Cropland
Grassland
Indirect (All Land-Use
Types)
Cropland
Grassland
Forest Land
Settlements
Total
1990
503
332
170

142
121
21
0
1
645








2005
546
381
165

142
118
21
+
2
687
2006
534
373
161

147
125
19
+
2
681
2007
538
380
158

143
121
20
+
2
681
2008
544
381
163

143
121
20
+
2
687
2009
523
362
161

145
122
21
+
2
669
2010
523
363
161

147
124
21
+
2
670
   + Less than 0.5 Gg N2O

   Note: The cropland and grassland estimates for 2010 are based on the emissions from
   2009. Due to limited changes in management of agricultural soils between the two
   years, the estimate for 2009 is expected to be representative of emissions in 2010. See
   the Planned Improvement section for additional details.

Table 6-17: Direct N2O  Emissions from Agricultural Soils by Land Use Type and N Input Type (Tg CO2 Eq.)
Activity
Cropland
Mineral Soils
Mineralization and Asymbiotic Fixation
Synthetic Fertilizer
Residue N°
Organic Amendments
Organic Soils
Grassland
Residue N°
PRP Manure
Synthetic Fertilizer
Managed Manured
Sewage Sludge
Mineralization and Asymbiotic Fixation
Total
1990
103.0
100
44.
32.
12.
10.
1
.1
.6
.5
.4
.6
.9

2005
118.
115,
0
.1
50.5
38.8



52.8 |
12
21
2
0
16
.0
.6
.7
.3
.3




155.8
13.
12.
2,
51.
11
21
2,
0,
15,
169.
7
.1
.9
1
.1
.6
.8
.5
.1
1
2006
115.
112.
49.
,7
,8
7
36.8
13.
.8
12.4
2.
49.
10,
21
2.
0.
14,
165.
,9
,9
.8
.2
,8
,5
.6
6
2007
117.8
114.9
50.9
37.6
13.9
12.5
2.9
49.0
10.7
20.6
2.7
0.5
14.5
166.8
2008
118.0
115.1
50.9
37.6
14.3
12.4
2.9
50.5
11.0
21.0
2.8
0.5
15.1
168.5
2009
112.4
109.5
47.1
37.1
13.1
12.2
2.9
49.9
10.8
20.6
2.8
0.5
15.1
162.2
2010
112.4
109.5
47.1
37.2
13.1
12.2
2.9
49.9
10.8
20.6
2.8
0.5
15.1
162.3
   ' Cropland residue N inputs include N in unharvested legumes as well as crop residue N.
   b Organic amendment inputs include managed manure amendments, daily spread manure amendments, and
   commercial organic fertilizers (i.e., dried blood, dried manure, tankage, compost, and other).
   0 Grassland residue N inputs include N in ungrazed legumes as well as ungrazed grass residue N
   d Accounts for managed manure and daily spread manure amendments that are applied to grassland soils.
   + Less than 0.05 Tg CO2 Eq.
   Note: The cropland and grassland estimates for 2010 are based on the emissions from 2009. Due to limited
   changes in management of agricultural soils between the two years, the estimate for 2009 is expected to be
   representative of emissions in 2010. See the Planned Improvement section for additional details.
                                                                                              Agriculture    6-19

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Table 6-6-18: Indirect N2O Emissions from all Land-Use Types (Tg CO2 Eq.)
Activity
Cropland
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Grassland
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Forest Land
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Settlements
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Total
1990
37.4
11.5
25.9
6.4 1
5.3 1
1.0 1
+ 1
+
+
0.3 1
0.1 1
0.2
44.1
2005
36.7
13.0
23.7
6.5
5.0
1.5
0.1
+
0.1
0.6
0.2
0.4
43.9
2006
38.7
14.3
24.4
6.0
5.0
1.1
0.1
+
0.1
0.6
0.2
0.4
45.5
2007
37.5
12.6
24.9
6.1
4.9
1.2
0.1
+
0.1
0.6
0.2
0.4
44.3
2008
37.6
13.0
24.6
6.1
4.9
1.2
0.1
+
0.1
0.6
0.2
0.4
44.4
2009
37.9
13.7
24.2
6.4
4.9
1.5
0.1
+
0.1
0.6
0.2
0.4
45.0
2010
38.5
13.9
24.5
6.4
4.8
1.5
0.1
+
0.1
0.6
0.2
0.4
45.5
   + Less than 0.05 Tg CO2 Eq.
   Note: The cropland and grassland estimates for 2010 are based on the emissions from 2009. Due
   to limited changes in management of agricultural soils between the two years, the estimate for
   2009 is expected to be representative of emissions in 2010. See the Planned Improvement
   section for additional  details.

Figure 6-3 through Figure 6-6 show regional patterns in direct N2O emissions, and also show N losses from
volatilization, leaching, and runoff that lead to indirect N2O emissions.  Average annual emissions and N losses are
shown for croplands that produce major crops and from grasslands in each state. Direct N2O emissions from
croplands tend to be high in the Corn Belt (Illinois, Iowa, Indiana, Ohio, southern Minnesota, southern Wisconsin,
and eastern Nebraska), where a large portion of the land is used for growing highly fertilized corn and N-fixing
soybean crops. Direct emissions are also high in Missouri, Kansas, and Texas, primarily from irrigated cropping in
western Texas, dryland wheat in Kansas, and hay cropping in eastern Texas and Missouri.  Direct emissions are low
in many parts of the eastern United States because a small portion of land is cultivated, and also low in many
western states where rainfall and access to irrigation water are limited.

Direct emissions (Tg CO2 Eq./state/year) from grasslands are highest in the central and western United States
(Figure 6-4) where a high proportion of the land is used for cattle grazing. Some areas in the Great Lake states, the
Northeast, and Southeast have moderate to low emissions even though emissions from these areas tend to be high on
a per unit area basis, because the total amount of grassland is much lower than in the central and western United
States.

Indirect emissions from croplands and grasslands (Figure 6-5 and Figure 6-6) show patterns similar to direct
emissions, because the factors that control direct emissions (N inputs, weather, soil type) also influence indirect
emissions.  However, there are some exceptions, because the processes that contribute to indirect emissions (NO3~
leaching, N volatilization) do not respond in exactly the same manner as the processes that control direct emissions
(nitrification and denitrification).  For example, coarser-textured soils facilitate relatively high indirect emissions in
Florida grasslands due to high rates  of N volatilization and NO3" leaching, even though they have only moderate
rates of direct N2O emissions.


Figure 6-3: Major Crops, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-
2010(TgCO2Eq./year)


Figure 6-4: Grasslands, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-2010
(Tg C02 EqVyear)


Figure 6-5: Major Crops, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
DAYCENT Model,  1990-2010 (GgN/year)
6-20   Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010

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Figure 6-6: Grasslands, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
DAYCENT Model, 1990-2010 (GgN/year)
Methodology

The 2006IPCC Guidelines (IPCC 2006) divide the Agricultural Soil Management source category into four
components:  (1) direct emissions due to N additions to cropland and grassland mineral soils, including synthetic
fertilizers, sewage sludge applications, crop residues, organic amendments, and biological N fixation associated with
planting of legumes on cropland and grassland soils; (2) direct emissions from drainage and cultivation of organic
cropland soils; (3) direct emissions from soils due to the deposition of manure by livestock on PRP grasslands; and
(4) indirect emissions from soils and water due to N additions and manure deposition to soils that lead to
volatilization, leaching, or runoff of N and subsequent conversion to N2O.

The United States has adopted recommendations from IPCC (2006) on methods for agricultural soil management.
These recommendations include (1) estimating the contribution of N from crop residues to indirect soil N2O
emissions; (2) adopting a revised emission factor for direct N2O emissions to the extent that Tier 1 methods are used
(described later in this section); (3) removing double counting of emissions from N-fixing crops associated with the
biological N fixation and crop residue N input categories; (4) using revised crop residue statistics to compute N
inputs to soils based on harvest yield data to the extent that Tier 1 methods are used; (5) accounting for indirect as
well as direct emissions from N made available via mineralization of soil organic matter and litter, in addition to
asymbiotic fixation179 (i.e., computing total emissions from managed land); and (6) reporting all emissions from
managed lands, largely because management affects all processes leading to soil N2O emissions.  One
recommendation from IPCC (2006) that has not been adopted is the accounting of emissions from pasture renewal,
which involves occasional plowing to improve forage production.  This practice is not common in the United States,
and is not estimated.

The methodology used to estimate emissions from agricultural soil management in the United States is based on a
combination of IPCC Tier 1 and 3 approaches. A Tier 3, process-based model (DAYCENT) was used to estimate
direct emissions from major crops on mineral (i.e., non-organic) soils; as well as most of the direct emissions from
grasslands. The Tier 3 approach has been specifically designed and tested to estimate N2O emissions in the United
States, accounting for more of the environmental and management influences on soil N2O emissions than the IPCC
Tier 1 method (see Box 6-1 for further elaboration). The Tier 1 IPCC (2006) methodology was used to estimate (1)
direct emissions from non-major crops on mineral soils (e.g., barley, oats, vegetables, and other crops); (2) the
portion of the grassland direct emissions that were not estimated with the Tier 3 DAYCENT model (i.e., federal
grasslands); and (3) direct emissions from drainage and cultivation of organic cropland soils. Indirect emissions
were also estimated with a combination of DAYCENT and the IPCC Tier 1 method.

EPA considered subtracting "background" emissions that would presumably  occur if the lands were not managed.
However, this approach is not used since (1) it is likely to be inaccurate for estimating the anthropogenic influence
on soil N2O emissions, and (2) if background emissions could be measured or modeled based on processes
unaffected by anthropogenic activity, they would be a very small portion of the total emissions, due to the high
inputs of N to agricultural soils from fertilization and legume cropping.  Given the recommendation from IPCC
(2006) and the influence of management on all processes leading to N2O emissions from soils in agricultural
systems, the decision was made to report total emissions from managed lands for this source category.  Annex  3.11
provides more detailed information on the methodologies and data used to calculate N2O emissions from each
component.


[BEGIN BOX]
179 N inputs from asymbiotic N fixation are not directly addressed in 2006 IPCC Guidelines, but are a component of the total
emissions from managed lands and are included in the Tier 3 approach developed for this source.


                                                                                      Agriculture    6-21

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Box 6-1. Tier 1 vs. Tier 3 Approach for Estimating N2O Emissions


The IPCC (2006) Tier 1 approach is based on multiplying activity data on different N inputs (e.g., synthetic
fertilizer, manure, N fixation, etc.) by the appropriate default IPCC emission factors to estimate N2O emissions on
an input-by-input basis. The Tier 1 approach requires a minimal amount of activity data, readily available in most
countries (e.g., total N applied to crops); calculations are simple; and the methodology is highly transparent. In
contrast, the Tier 3 approach employs a process-based model (i.e., DAYCENT) that represents the interaction of N
inputs and the environmental conditions at specific locations. Consequently, the Tier 3 approach is likely to produce
more accurate estimates; it accounts more comprehensively for land-use and management impacts and their
interaction with environmental factors (i.e., weather patterns and soil characteristics), which will enhance or dampen
anthropogenic influences. However, the Tier 3 approach requires  more detailed activity data (e.g., crop-specific N
amendment rates), additional data inputs (e.g., daily weather, soil types, etc.), and considerable computational
resources and programming expertise. The Tier 3 methodology is less transparent, and thus it is critical to evaluate
the output of Tier 3 methods against measured data in order to  demonstrate the adequacy of the method for
estimating emissions (IPCC 2006). Another important difference between the Tier 1 and Tier 3 approaches relates
to assumptions regarding N  cycling. Tier 1 assumes that N added to a system is subject to N2O emissions only
during that year and cannot be stored in soils and contribute to  N2O emissions in subsequent years.  This  is a
simplifying assumption that is likely to create bias in estimated N2O emissions for a specific year. In contrast, the
process-based model used in the Tier 3 approach includes such legacy effects when N added to soils is re-
mineralized from soil organic matter and emitted as N2O during subsequent years.


[END BOX]
Direct N2O Emissions from Cropland Soils

   Major Crop Types on Mineral Cropland Soils

The DAYCENT ecosystem model (Del Grosso et al. 2001, Parton et al. 1998) was used to estimate direct N2O
emissions from mineral cropland soils that are managed for production of major crops—specifically corn, soybeans,
wheat, alfalfa hay, other hay, sorghum, and cotton—representing approximately 90 percent of total croplands in the
United States.  For these croplands, DAYCENT was used to simulate crop growth, soil organic matter
decomposition, greenhouse gas fluxes, and key biogeochemical processes affecting N2O emissions, and the
simulations were driven by model input data generated from daily weather records (Thornton et al.  1997, 2000;
Thornton and Running 1999), land management surveys (see citations below), and soil physical properties
determined from national  soil surveys (Soil Survey Staff 2005). Note that the influence of land-use change on soil
N2O emissions was not addressed in this analysis, but is a planned improvement.

DAYCENT simulations were conducted for each major crop at the county scale