WORKING DRAFT
Quantifying
Greenhouse Gas Emissions
from Key Industrial Sectors
in the United States
May 2008
I
I.
    \
    UJ
    o
ectorStrategies

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1.      Introduction	1-1
2.      Alumina and Aluminum	2-1
3.      Cement	3-1
4.      Chemicals	4-1
5.      Construction	5-1
6.      Food and Beverages	6-1
7.      Forest Products	7-1
8.      Iron and Steel	8-1
9.      Lime	9-1
10.     Metal Casting	10-1
11.     Mining	11-1
12.     Oil and Gas	12-1
13.     Plastic and Rubber Products	13-1
14.     Semiconductors	14-1
15.     Textiles	15-1
References	R-1
Appendices:
A.1 Key Data Sources	A-2
A.2 Emission Factors for On-site Fossil Fuel Combustion	A-4
A.3 Emissions Estimation Methods for Electricity Purchases	A-5
A.4 General Conversion Factors & Global Warming Potentials	A-14
A.5 Energy Consumption Data	A-15
A.6 C02 Emissions for "Other" Fuels	A-20
A.7 Reporting Protocols	A-21
A.8 Economic Data	A-22
A.9 List of Acronyms	A-23
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        Introduction
                                                                         This report complements—and is not intended to
                                                                         replace or update—the official GHG emissions
                                                                         inventory submission of the United States, the
                                                                         Inventory of U.S. Greenhouse Gas Emissions and
                                                                         Sinks: 1990-2005, which is prepared according to
                                                                         the official reporting guidelines established by the
                                                                         United Nations Framework Convention on Climate
                                                                         Change (UNFCCC) and the Intergovernmental
                                                                         Panel on Climate Change (IPCC).
This report seeks to provide greenhouse gas (GHG) emission
profiles for key sectors of U.S. industry (including indirect
emissions from electricity consumption), which combined
accounted for 29% of total U.S. GHG emissions in 2002,1
more than any other economic sector (Figure 1-1). Emission
profiles are provided for 14 key industrial sectors.
Collectively, these sectors account for approximately 84% of
industrial GHG emissions in the United States  (Figure 1-2).

The emission estimates included in these initial industrial
sector GHG profiles may be useful to a wide array of current public and private sector GHG inventory and
reduction initiatives. They also may aid in the development of new ones. Individual companies or industry
groups could use this information as a reference for preparing more detailed GHG inventories and for
designing effective GHG reduction  strategies. To supply these companies and industries with knowledge of
emissions over which they have influence, the emission profiles provided in this report include, for the first
time, estimates of emissions from purchased electricity. Because many industrial sectors' energy profiles include
significant electricity purchases and because national electricity generation is carbon-intensive, these profiles
support holistic GHG management.

The emission estimates in this report are  provided for informational purposes. Due to differences in
methodologies and simplifying assumptions, emission estimates  in this report may vary from EPA emission
estimates for other purposes. Use of figures in this report does not connote that these estimates are preferred
to EPA estimates used in another context. Further, these emission estimates may be improved upon in the
future as more GHG emissions are reported, and other estimates may be developed to incorporate additional
life-cycle activities such as transport of materials into and out of the  sector.
        Figure 1-1: Total 2002 U.S. Greenhouse Gas Emissions by
        Sector (MMTC02E), Factoring in Purchased Electricity
                                                              Figure 1-2: Total 2002 U.S. Greenhouse Gas
                                                              Emissions from Industrial Sources, by Sector
                                                              (MMTC02E), Factoring in Purchased Electricity
                              Agriculture
             Residential
                17%
         Commercial
            17%
                                          US Territories
             Transportation
                27%
                                                                            Forest Products
                                                                                 6%
                                                                       Iron and Steel
                                                          Food and Beverages   6%    /
                                                                5%
                                                                 Mining
                                                          Cement    5%
                                                           4%

                                                     Alumina and Aluminum
                                                            3%
                                                       Plastic and Rubber
                                                          Products
                                                            2%
                                                        Textiles
                                                          2% ~
                                                                                                Construction
                                                                                                   6%
                          Total:
                          7,065 MMTC02E
                                                                                                         industrial Sectors
                                                                                                           16%
/Semiconductors
     1%

      Total:
2,047 MMTC02E
        Source: EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        Note: MMTC02E stands for million metric tons of carbon dioxide equivalent.
        Emissions from electricity have been distributed among economic sectors.
                                                              Source: Estimate based on methodology in Section 1.2. Note:
                                                              "other industrial sector" emissions represent the emissions
                                                              remaining within the industrial sector beyond those estimated for
                                                              the 14 sectors addressed in this report.
        1 Total 2002 industrial emissions (including emissions from purchased electricity) are 2,047 million metric tons of carbon dioxide equivalent (MMTC02E) as reported
        in the/ni/enforyofU.S. Greenhouse Gas Emissions and Sinks: 1990-2005, Table 2-16.
U.S. Environmental Protection Agency
                                             WORKING DRAFT (May 2008)
                             1-1

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Introduction
        Emissions of GHGs result from all sectors of the U.S. economy.2 With emissions from electric power
        distributed to the end-users, the largest percentage of GHG emissions, according to the Inventory of U.S.
        Greenhouse Gas Emissions and Sinks: 1990-2005, result from the industrial sector, accounting for approximately
        29% of total U.S. GHG emissions. After the industrial sector, the transportation sector and—to a lesser
        degree—the commercial, residential, and agriculture sectors follow, in descending order by total GHG
        emissions. Approximately two-thirds of the industrial sector's emissions result from the combustion of fossil
        fuels and from the industrial processes of each sector. The remaining one-third of industrial sector GHG
        emissions results from the off-site generation of electricity purchased by the sector. If designated as a separate
        sector of the U.S. economy, the electric power sector becomes the most emissive sector (32% of total U.S.
        emissions), followed by transportation (27%), industrial (20%) and—to a lesser degree—the agriculture (9%),
        commercial (6%), and residential  (5%) sectors (Figure 1-3).J
                                 Figure 1-3: Total 2002 U.S. Greenhouse Gas Emissions by
                                 Sector (MMTC02E), Electric Power Presented as a Sector
                                                       Residential
                                                                    Agriculture
                                      Commercial            5%      r  go/0
                                                                            US Territories
                                                                                1%
                                   Transportation
                                       27%       ^^^n^!^^^^\  Bec Power
                                                                             32%
                                                     Industrial
                                 Source: EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                                 Note: MMTC02E stands for million metric tons of carbon dioxide equivalent.
                                 Emissions from the electric power sector are presented independent of other sectors.
1.1     Approach to Defining Sectors
        As partitioning of the electric power sector indicates, clear sector definitions are critical to preparing accurate
        emission estimates—particularly when developing a consistent set of emission estimates for multiple sectors.
        Because this report examines a set of sectors side-by-side in a single document, consistency across sectors was a
        priority for this analysis. The sectoral definitions used for the emission estimates provided in this report include
        consistency among:
        •    Identification of the facilities or activities within the sector
        2 U.S. Territories include American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. Pacific Islands. Emissions are from fossil fuel
        combustion. Fuels consumed by the U.S. Territories include coal, natural gas, distillate fuel oil, jet fuel, kerosene, LPG, lubricants, motor gasoline, residual fuel, and
        other types of petroleum (in small amounts). The consumption of these fuels in 2002 was approximately 0.7 QBtu.
        3 As reported in the/ni/enforyofU.S. Greenhouse Gas Emissions and Sinks: 1990-2005, Table 2-14.
U.S. Environmental Protection Agency                      WORKING DRAFT (May 2008)                                     1-2

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Introduction
        "   Delineation of the physical boundaries of the sector

        "   Choice of time period for the emission estimates

        "   Choice of GHG-emitting sources to include within each sector

        A description of the broad characteristics applied to define each sector in a consistent manner, according to
        each of the above elements, is provided below. Emission tables throughout the report do not contain qualifiers
        if an emission estimate is not estimated. Emissions  are not estimated if they do not occur, or if data or
        methodologies are not available to estimate the emissions. Assumptions associated with each sector's emission
        estimates are detailed in the  sector chapters.

1.1.1                 of the                          a

        In general, for the purposes of this analysis, the  definitions of the 14 industrial sectors addressed herein have
        been taken from the North American Industry Classification System (NAICS).4 Table 1-1 identifies the 14
        sectors studied and their corresponding NAICS codes, where applicable. A full description of activities
        contained within these NAICS codes is provided in individual chapters of the report.
                                        Table 1-1: Sectors Described in this Report, with
                                                Corresponding NAICS Codes
                    •••liefer
                     Alumina and Aluminum
                     Cement
                     Chemicals
                     Construction
                     Food and
                     Forest Products
                     Iron and
                     Lime
                          Casting
                     Mining
                     Oil and Gas

                     Plastic and Rubber Products
                     Semiconductors
                     Textiles

           3313
           NAa
           325
           23
           311,3121
           321,322
           331111
           327410
           3315
           212
           211111, 211112, 213111, 213112, 324110,
           48891,48821,22121
           328
           334413
           313,314,315
                    * Defined by the U.S. Geological Survey's Minerals Yearbook: Cement Annual Report 2005s
1.1.2               of the                     of the

        The emission estimates provided for each sector are not intended to represent the full life cycle emissions that
        could be attributed to the sector. With few exceptions, the emissions boundary begins and ends at the walls of
        the plant. Emissions associated with electricity generated offsite but used within the sector are also included,
        but presented separately  from emissions resulting from the use of fuels to generate energy on-site. The
        exception to this boundary condition occurs when the sector is defined more broadly; for example, the
        4 NAICS was developed jointly by the U.S., Canada, and Mexico. For more information, see http://www.census.gov/epcd/www/naics.html.
        5U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005, 2006, http://minerals.usas.gov/minerals/pubs/commoditv/cement/cemenmvb05.pdf.
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Introduction _

        definition of food manufacturing includes both the growing of foods and the processing and packaging, so
        some transportation occurs within the sector boundary that results in GHG emissions.6

1.1.3    Choice of Time Period
        A wide variety of external factors may impact the emissions from any sector, including changes in the U.S.
        economy, weather patterns, and commodity and fuel prices. In order to evaluate emissions using a common
        basis, emissions were estimated for all sectors for the year 2002. This year was chosen because the primary
        dataset from which fuel consumption can be obtained for all sectors contains data through 2002.

1.1.4    Choice of GHG-Emitting Sources within Each Sector
        Sources of GHG emissions for each sector were strictly defined as CO2 emissions from fuel consumption or
        electricity use, plus any process emissions that have been  identified by the Intergovernmental Panel on Climate
        Change and calculated for the Inventory of U.S.  Greenhouse Gas Emissions and Sinks: 1 990-200 5 7 No other GHG
        emitting sources were considered for the purposes of this report.

        In a similar vein, only emission sources were estimated. Many sectors are taking actions to reduce or offset
        their GHG emissions. To the extent that emissions are being reduced by the sector through  energy efficiency
        programs, for example, such actions are inherently accounted for in the emission estimates by the sector's
        reduced consumption of fuel. However, where sectors are taking actions to offset their emissions — e.g., by
        investing in projects offsite that yield GHG reductions — those actions are not accounted for in this report.
        Finally, carbon sinks, such as reforestation or geological carbon sequestration, are also not estimated  due to the
        inherent complexity of carbon accounting associated with these activities.

1.2     Methodology

1 .2.1    Calculation Methods for Direct and Indirect GHG Emissions
        Sources of emissions in industrial sectors include direct GHG emissions, i.e., emissions that occur as a result
        of activities at the industrial establishments, and indirect GHG emissions, i.e., emissions that are a
        consequence of the activities of the establishment but  that occur at sources owned by another operation. A
        variety of definitions exist for direct and indirect emissions; for the purposes of this report, direct and indirect
        emissions are defined as follows:
        •   Direct emissions consist of carbon dioxide (CCh) emissions from fuels combusted by the sector, plus any
            GHG emissions from non-combustion activities in the sector, such as industrial process emissions,
            emissions from the non-energy use of fossil fuels, or emissions associated with onsite wastewater
            treatment.

        •   Indirect emissions are limited to CC>2 emissions associated with the generation of electricity purchased by
            the sector.

        The majority of both direct and indirect emissions from these industrial sources are a result of fuel combustion.
        The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 -200 58 does not disaggregate fuel combustion
        emissions by sector but, rather, presents CC>2 emissions from national fuel consumption in aggregate (under the
        CC>2 from Fossil Fuel Combustion source category). Therefore, a methodology was developed for this report to
        estimate fossil fuel combustion emissions by sector. Due to this disjuncture, the emission estimates presented here
        6 For further information regarding the size and boundaries of sectors participating in EPA's Sector Strategies Program, please refer to Sector Strategies
        Performance Report, 2nd Edition.
        7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 April 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
        8 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 April 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
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Introduction
        are not directly comparable to the emissions presented in the Inventory of U.S. Greenhouse Gas Emissions and Sinks:
        1990-2005*

        Direct emissions
        Specific methodologies and data sources used in this report vary by sector, but, when possible and appropriate,
        consistency in calculation methods was the practice. Unless otherwise noted in a particular chapter, the
        following methodologies were universally applied to calculate direct GHG emission estimates for each of the
        14 industrial sectors:

        "   Direct emissions from fossil fuel combustion were calculated by multiplying estimates of fuel consumption
            by fuel-specific CO2 emission factors from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
            2005?  In most cases, fuel consumption estimates were taken from the U.S. Department of Energy's
            (DOE's) Energy Information Administration (EIA's) 2002 Manufacturing Energy Consumption Survey
            (MEGS) .9 Where fuel consumption data were not available, estimates  of expenditures on fuel (fuel
            purchases) and fuel cost data were used to estimate consumption. Exceptions to this methodology are
            described in relevant sector chapters.

            Although combustion activities also generate emissions of methane (CH4) and nitrous oxide (N2O), such
            emissions have not been estimated. Non-CO2 emissions typically account for only a small percentage
            (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.

        *   Direct emissions from non-combustion activities (e.g., industrial processes) were taken from Inventory of
            U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.8 In  some cases, additional analysis was required to parse
            out a sector's contribution to a source category. For example, this analysis disaggregates the total
            Wastewater Treatment source category CH4 emissions reported in the Inventory of U.S. Greenhouse Gas
            Emissions and Sinks:  1990-20058 into emissions from the treatment of pulp and paper wastewater, which was
            attributed to the forest products sector, and emissions  from the treatment of fruit, vegetable, meat and
            poultry processing wastewater, which was attributed to the  food and beverages sector.

        Indirect Emissions
        Indirect emissions associated with purchased electricity were estimated for each sector based on electricity
        purchases by sector, and information on the CO2 intensity  of generation from the electric power system. Where
        possible, the geographic distribution of the sector was taken into account  to reflect the differing fuel mixes (and
        hence different CO2 emissions intensities) for electricity generation in different regions of the country.
        Information on the geographic distribution of the sector was often not specifically available, i.e., the exact
        location of every facility within each sector was not known. The geographic distribution of electricity use within
        each sector was therefore based on the geographic distribution of the "value added" of each sector combined
        with a national or regional estimate of electricity purchases. This metric, "value added," was obtained from the
        U.S. Census Bureau's Economic Census10 and was considered the better proxy because it negates the effect of
        varying input prices that would be reflected in the alternate metrics.
        One of the following four methodologies was used to calculate  indirect GHG emission estimates for each of
        the  14 industrial sectors. The first method (Method 1) applies a national utility CC>2 emission factor to national
        electricity demand data for the sector, while the remaining methods (Methods 2, 3, and 4) allocate the sector's
        electricity demand to regions of the country using a proxy (distribution of industrial or commercial demand,
        distribution of sector's value-added, or distribution of sector's production capacity, respectively), then apply
        regional utility CC>2 emission factors. For the latter three methods, regions were defined by the North
        American Electricity Reliability Council (NERC).
        9 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        10 U.S. Census Bureau, 2005, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 6 Nov 2007, http://www.census.gov/mcd/asm-
        aslhtml.
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Introduction
        The methodology chosen for each sector was dependent upon sector characteristics (e.g., homogeneity of
        electricity use among sub-sectors) and data availability. In no cases were direct data on regional electricity
        purchases by a sector available. The method used for each sector is detailed in Table 1-2. Detailed information
        on all of the methodologies used is contained in Appendix A.3.

        In all cases:

        "    CO2 emission factors (in Ibs per kilowatt-hour (kWh) of generation) were taken from the Emissions &
             Generation Resource Integrated Database (eGRID), a comprehensive inventory of environmental attributes of
             the electric power system developed and maintained by EPA. eGRID is based on plant-specific data for
             U.S. electricity generating plants that provide power to the electric grid and report data to the U.S.
             government.  eGRID provides estimated CO2 emission factors (in Ibs per kWh of generation) at the
             national, NERC regional, NERC sub-regional, power control area, and state levels.

        "    Demand estimates were corrected for losses associated with the transmission and distribution of electricity.


                         Table 1-2: Method Used to Estimate Emissions from Purchased Electricity by Sector

                              1 -
                              2 - Regional-Level
                      Estimates/Customer Class

                              3 -                   with Sector
                              4 - Facility

             Food and
             Plastic and Rubber Products

             Construction
             Mining

             Oil and Gas (Production)
             Textiles

             Semiconductors
             Forest Products
             Chemicals
             Lime
             Alumina and Aluminum
             Oil and Gas (Refining)
             Cement
             Iron and
1,2.2
        Estimates in this report are based upon a variety of data sources, provided in detail within each chapter. Key
        data sources include:

        "   EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005;11

        "   DOE's 2002 Manufacturing Energy Consumption Survey',12

        "   U.S. Census Bureau's 2002 Economic Census: Industry Series Report^ and

        "   Source-specific activity data from organizations such as the U.S. Geological Survey (USGS) and industry
            associations.
        11 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15April 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
        12 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.aov/emeu/mecs/mecs2002.
        13 U.S. Census Bureau, 2002 Economic Census: Industry Series Reports, 22 Nov 2005, http://www.census.aov/econ/census02/guide/INDRPT23.HTM.
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Introduction	

1.3     Summary of Emission Estimates (2002)

        Total combined emissions from the sectors analyzed for this report are 1,713 million metric tons of carbon
        dioxide equivalent (MMTCG^E), representing approximately 84% of total U.S. industrial emissions. As Figure 1-2
        indicates emissions from the production and refining of oil and gas are the largest contributor, with emissions of
        501 MMTCO2E (24%). Emissions from the second largest contributor, chemicals, are 366 MMTCO2E (18%).
        Other sectors that account for more than 100 MMTCC^E include, in descending order, construction (6%), forest
        products (6%), iron and steel (6%), and food and beverages (5%). Figures 1-4,1-5, and 1-6 present three different
        aggregations of emission estimates for all 14 sectors: for total emissions (i.e., non-combustion emissions, on-site
        fossil-fuel combustion emissions, and purchased electricity emissions); for just non-combustion emissions; and
        finally for non-combustion emissions and on-site fossil-fuel combustion emissions; respectively. Table 1-3
        provides more detailed emissions information for all 14 sectors in alphabetical order.

        All GHG emissions in this report are estimated in units of MMTCC^E, a unit of measurement that takes into
        account the relative potency of the gas by applying global warming potentials (GWPs) of each gas. For
        example, the GWP of CO2 is 1, while the GWPs of CH4 and N2O are 21 and 310, respectively. For a listing of
        GWPs for other GHGs and a full explanation of GWPs, please see the Inventory of U.S. Greenhouse Gas Emissions
        and Sinks: 1990-200'5.14
        For each sector, emission estimates are provided for the year 2002, which is the most recent year for which a
        complete dataset is available to estimate emissions for fossil fuel combustion, non-combustion activities, and
        electricity purchases. Data are provided for 2002 in order to provide a single consistent baseline for all sectors.
        Where available, more recent data are also presented in individual sector chapters.

        Caution must always be applied when creating summed GHG emission estimates based on disparate sources,
        because the various sources may not always be able to be reconciled. For the current report, every attempt was
        made to ensure that a consistent definition of each sector was applied when more than one dataset was used in
        generating GHG emission estimates. For more information on key data sources, please see Appendix A.I.

        More detailed methodologies are provided in sector chapters.


        Figure 1-4:2002 Non-combustion, On-site Fossil Fuel Combustion, and Purchased Electricity Greenhouse Gas Emissions
        from Key Industrial Sectors (MMTC02E)
                    Oil and Gas

                     Chemicals

                    Construction

                  Forest Products

                   Iron and Steel

               Food and Beverages

                       Mining
              Alumina and Aluminum
                                                           	  Non-combustion
                       Cement
                                                               Fossil Fuel Combustion
           Plastic and Rubber Products ^^_
                                                               Purchased Bectricity
                      Textiles

                        Lime

                   Metal Casting

                  Semiconductors
                            0          100         200         300         400         500         600
                                                          (MMTCO2E)
            Estimates include emissions from fossil fuel combustion, non-combustion, and the generation of purchased electricity.

        "U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15April 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
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Introduction
          Figure 1-5: 2002 Non-combustion Greenhouse Gas Emissions from Key Industrial Sectors (MMTC02E)
                          Oil and Gas
                          Chemicals
                         Construction
                       Forest Products
                         Iron and Steel
                    Food and Beverages
                             Mining
                            Cement
                  Alumina and Aluminum
               Plastic and Rubber Products
                            Textiles
                              Lime
                         Metal Casting
                       Semiconductors
                    Non-combustion
                                               100
                                                            200
          FJstirrat.es include emissions fromfossilfuel combustion and non-combustion
                                                                         300
                                                                       (MMTC02E)
                                                                                      400
                                                                                                   500
                                                                                                                 600
          Figure 1-6: 2002 Non-combustion and On-site Fossil Fuel Combustion Greenhouse Gas Emissions from Key Industrial
         Sectors (MMTC02E)
                          Oil and Gas
                           Chemicals
                          Construction
                        Forest Products
                         Iron and Steel
                    Food and Beverages
                              Mining
                             Cement
                   Alumina and Aluminum
                Plastic and Rubber Products
                             Textiles
                               Lime
                         Metal Casting
                        Semiconductors
                    Non-combustion
                    Fossil Fuel Combustion
                                   0            100           200
          Estimates include emissions fromfossil fuel combustion and non-combustion
             300
           (MMTC02E)
                                                                                       400
                                                                                                    500
                                                                                                                 600
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Introduction
                                Table 1-3: 2002 GHG Emissions from Key Industrial Sectors (MMTC02E)
Emission Source
Alumina and Aluminum
Foss/7 Fuel Combustion
Non-Combustion
Electricity
C02
51
11
5
36
CH4 N20 MFCs SF6 RFC Total
5 57
11
5 10
36
Cement 83 83
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Chemicals
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Construction
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Food and Beverages
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Forest Products
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Iron and Steel
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Fossil Fuel Combustion
Non-Combustion
Electricity
32
43
8
322
203
18
101
131
100

31
100
51

49
120
62

58
114
22
55
37
•^^KE^H
••EsBI
9
12
1
32
43
8
1 23 20 366
203
1 23 20 62
101
131
100

31
HH^^B^HJHfl^HA^BHHHHHHHHHH^HnJIifl
51
43 7
49
•^^•••••••••••••••••••MBH
62
5 5
58
1 115
22
1 56
37
^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^fS^f
••••••••••••••••••••••••SB
9
12
1
Metal Casting 18 18
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Fossil Fuel Combustion
Non-Combustion
Electricity
Oil and Gas
Foss/7 Fuel Combustion
Non-Combustion
Electricity
7

11
15

27
349
276
30
43
7

11
15
58 58
27
152 501
276
152 181
43
Plastic and Rubber Products 44 44
Foss/7 Fuel Combustion
Non-Combustion
Electricity
8

36
8

36
Semiconductors 9 <1 3 1 13
Foss/7 Fuel Combustion
Non-Combustion
Electricity
1

8
1
<1 3 1 4
8
Text lies 32 32
Foss/7 Fuel Combustion
Non-Combustion
Electricity
Total
10

21

10

21
1,713
             Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions, and totals may not sum due to independent rounding.
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Introduction	

1.4     Company Reporting

        In addition to sector-level estimates, this report provides data from specific companies within these industrial
        sectors, which publicly report their GHG emissions.
        In order to report their emissions, these companies often use the following protocols:

        "   EPA's Climate Leaders Greenhouse Gas Inventory Protocol, which adds on to the WBCSD/WRI Greenhouse Gas
           Protoco/bj requiring Climate Leader Partners to look at emissions beyond the six GHGs defined by
           UNFCCC/IPCC. Boundaries are set using the same equity share and control techniques as the
           WBCSD/WRI protocol.

        "   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
           (WRI) Greenhouse Gas Protocol, which provides guidance for the design, tracking, and reporting of the
           emissions associated with the six GHGs identified by the Kyoto Protocol (CC>2, CH4, and N2O, as well as
           hydrofluorocarbon (HFC), perfluorocarbon (PFC), and sulfur hexafluoride (SF6)).  Under this protocol,
           companies account for emissions according to their share of equity in certain operations.

        "   DOE/EIA's 1605(b) Reporting Guidelines for the industrial sector, Technical Guidelines: Voluntary 'Reporting
           of Greenhouse Gases (1605(b)) Program, which provide support to an entity that would like to inventory and
           report its emissions of the six Kyoto gases and, optionally, chlorofluorocarbons (CFCs)  as well. The entity
           must report on direct and indirect emissions, not only for itself but also for all of its subsidiaries and any
           long-term lease sources. The protocol draws boundaries based on financial, equity  share, or operational
           control; the entity may select which boundary type to use.
        For more information on these reporting protocols, see Appendix A.7. Additional, sector-specific reporting
        protocols are presented in the respective, relevant chapters.

1.5     Organization of  Report

        This report is organized alphabetically by sector. Each  sector chapter contains the following elements:

        "   Definition of the sector;

        "   Description of GHG emission sources within the sector;

        "   2002 GHG emission estimates, along with a description of methodology and data sources, and key
           assumptions;

        "   1998-2005 GHG emission estimates (where possible);

        "   GHG emission estimates from other sources (e.g., industry associations);

        "   Sector emission-reduction commitments;  and

        "   Listing of sector-specific reporting protocols  and data from reporting companies.
        In addition, appendices provide more detailed information on key data sources as well as activity data and
        emission factors used in the emission calculations.
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        Alumina  and Aluminum
        Aluminum is a corrosion-resistant, light-weight, and malleable metal used in a variety of manufactured
        products. The transportation industry is a major
        buyer of aluminum, accounting for 37% of
        domestic shipments in 2005. Containers and
        packaging accounted  for an additional 22% of
                                                            Fossil Fuel Combustion
                                                            Non-Combustion
                                                    Source
aluminum shipments in that same year.2
   2002
 Emissions
(MMTC02E)
        Other uses for aluminum include: building and
        construction (16%), consumer durables (7%),
        electrical (7%), machinery and equipment (7%), and
        other (4%).
                                                    Purchased Electricity
                                                    Total
                                                    Percent of U.S. Industrial Emissions1
      11
      10
      36
      57
     3%
        The process of aluminum manufacturing (NAICS code 3313: Alumina and Aluminum) produces both primary
        metal, from bauxite ore, and secondary metal, from aluminum scrap. Primary aluminum manufacture is
        accomplished in two stages: (1) using the Bayer process of refining bauxite ore to obtain aluminum oxide
        (A12O3); and (2) employing the Hall-Heroult process of smelting the aluminum oxide to release pure aluminum.
        Secondary aluminum is produced by melting scrap and recycled aluminum, primarily using natural gas as the
        fuel.

2.1     Sources  of Greenhouse Gas Emissions
        GHG emissions in the alumina (or aluminum oxide) and aluminum sector result from non-combustion
        activities (i.e., industrial processes), on-site fossil fuel combustion, and generation of purchased electricity.
        Aluminum  smelting involves the reduction of aluminum oxide into aluminum through the Hall-Heroult
        reduction process. This reduction occurs through electrolysis in a carbon-lined bath of molten cryolite
        (NasAlFe). The carbon lining serves as the cathode, and the  anode is a carbon mass of paste or coke. During
        reduction, most of this carbon is oxidized and emitted into the  atmosphere as carbon dioxide (CO2).
        Perfluorocarbon (PFC) emissions occur during the production  of aluminum from "anode effects", which are
        rapid increases in voltage due to the alumina ore content of the electrolytic bath falling below critical levels for
        electrolysis. As a result, carbon from the anode and fluorine from the molten cryolite combine to produce
        fugitive emissions of perfluoromethane (CF4) and perfluoroethane (C2p6).

        The reduction of alumina requires a substantial amount of energy, which is primarily on-site fossil fuel
        combustion for secondary aluminum and purchased electricity for primary aluminum; this energy use yields
        CC>2 emissions beyond those generated from the aluminum manufacturing process.

2.2     Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the alumina and aluminum sector for the
        year 2002. The methodologies and data sources used to calculate these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

2.2.1    Estimates of Greenhouse Gas Emissions (2002)
        GHG emissions from the alumina and aluminum sector were estimated to be 57 MMTCG^E in 2002 (as seen
        in Table 2-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 U.S. Geological Survey, Minerals Yearbook: Aluminum Annual Report 2005, 2006, http://minerals.usas.aov/minerals/pubs/commoditv/aluminum/alumimvb05.pdf.
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                             Table 2-1: GHG Emissions from the Alumina and Aluminum Sector (MMTC02E)

Fossil Fuel Combustion3
Non-Cornbustionb
Purchased Electricity0
Total
C02
11
5
36
52
PFCs

5

5
Total
11
10
36
57
                    a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S. Greenhouse
                    Gas Emissions and Sinks: 1990-2005.
                    b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                    c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and Generation
                    Resource Integrated Database (eGRID).
                    Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis
                    did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail on
         the methodology used to estimate emissions from the alumina and aluminum sector can be found in Section 2.2.2.
         The analysis presented in this report addresses emissions related to the production processes and does not address
         lifecycle emissions from the use of aluminum products. Consequently, the analysis does not evaluate the
         environmental benefits of the produced materials. In particular, aluminum is a light-weight material that when
         used for automobiles may improve fuel economy and, consequently, result in reduced vehicle emissions. A more
         detailed lifecycle analysis would be needed to evaluate the benefits of products from this sector.
         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 2-1. For comparison, CCh emissions associated
         with fuel consumption are shown in Figure 2-2.
         Figure 2-1: 2002 Energy Consumption in the Alumina and
         Aluminum Sector, by Fuel Type (TBtu)
                    LPG and NGL
                       <0.5%
                    Other1
                     7%
          Distillate Fuel Oil /
             <0.5%
                 Natural Gas
                    37%
                                            Electricity
                                              56%
                                   Total:
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         a Composition of "other" fuel category varies among sectors.
         Note: TBtu stands for trillion British thermal units.
             Figure 2-2: 2002 C02 Emissions from Energy
             Consumption in the Alumina and Aluminum Sector, by
             Fuel Type (MMTC02E)
                              LPG and NGL
                                 0.5%
              Distillate Fuel Oil
                  <0.5%
                     Natural Gas
                        15%
      Electricity3
        76%
                                        Total:
47 MMTC02E
             Source: Estimate based on methodology in Section 2.2.2.
             a Fuel mix at utilities was taken into consideration in this calculation, per
             methodology described in Section 2.2.2.
             b Composition of "other" fuel category varies among sectors.
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                       and

         Foss/7 Fuel Combustion
         Fossil fuel combustion emissions from the alumina and aluminum sector were derived from the U.S.
         Department of Energy's (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption
         Survey (MEGS)3 estimates of fuel consumption for this sector. Those fuel consumption estimates were
         multiplied by the appropriate, fuel-specific emission factors to convert the consumption into CC>2 emitted. The
         emission factors for the fossil fuels used in the industry were taken from data contained in the Inventory of U.S.
         Greenhouse Gas Emissions and Sinks: 1990-200 5.4 CO2 emissions from the "other" fuel type were taken directly
         from EIA's report, Special Topic: Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing?

         Non-Combustion Activities
         Non-combustion emission estimates, including emissions of CO2 and PFCs, were those reported for the
         Aluminum Manufacturing source category within the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
         2005.6 These estimates include the aluminum manufacturing emissions identified by the Intergovernmental
         Panel on Climate Change's (IPCC)  2006IPCC Guidelines for National Greenhouse Gas Inventories.1

         Purchased Electricity
         Electricity emissions were estimated by multiplying national-level electricity purchases (in kilowatt-hours, or
         kWh) provided by MECS8 by a CC>2 emission factor (in Ibs/kWh) provided by eGRID9 at the North American
         Electricity Reliability Corporation (NERC)10 region level. In order to match electricity demand to the NERC
         regions, facility level electricity estimates were developed based on the intensity of electricity per unit of
         production, provided by DOE,11 and an estimate of production of primary aluminum.  Facility-level production
         estimates  were based on national production data (USGS)12 and the relative  capacities of the  facilities.
         Electricity purchases were adjusted by a loss factor to reflect losses incurred in the transmission and
         distribution of electricity. Methods  for estimating CO2 emissions from electricity are detailed in Appendix A.3.
         Non-combustion emission estimates were limited to sources identified by the 2006 IPCC Guidelines for National
         Greenhouse Gas Inventories and provided in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         Electricity and fossil fuel combustion emission estimates included only CO2. Emissions of other GHGs (e.g.,
         CH4and N2O) that may result from combustion were not estimated.13 Emission factors for purchased
         electricity provided by eGRID are for 2004, which may include different fuel mixes  for electricity generation
         than those of the 2002 inventory year.
         3 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
         http://www.eia.doe.gov/emeu/mecs/mecs2002.
         4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         5 U.S. Department of Energy, Special Topic: Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing, Nov 2006,
         http://www.eia.doe.gov/oiaf/1605/aarpt/pdf/industrv mecs.pdf.
         6 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         1 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006g I/index.htm.
         8 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey.
         9 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
         http://www.epa.aov/cleanenerav/egrid/index.htm.
         10 NERC is the designated reliability organization that has a role in overseeing the reliability of the electric power grid. NERC regions reflect the organization
         structure of the regional reliability entities within with the owners of generation operate.
         11 U.S. Department of Energy, Office of Industrial Technologies, Energy and Environmental Profile of the U.S. Aluminum Industry, July 1997,
         http://www1.eere.enerav.gov/industrv/aluminum/pdfs/aluminum.pdf.
         12 U.S. Geological Survey, Minerals Yearbook: Aluminum Annual Report 2005.
         13 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
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Alumina and Aluminum
2.3     Greenhouse Gas Emissions (1998,2002)

        GHG emissions from select years for the alumina and aluminum sector are provided in Figure 2-3.14
        Annual estimates of non-combustion GHG emissions from aluminum manufacturing were available from the
        annual Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, which show that such emissions have
        decreased by 51% between 1998 and 2005, from 14.8 to 7.2 MMTCO2E in 1998 and 2005, respectively.

        However, data for GHG emissions from fossil fuel combustion and purchased electricity are available only for
        two data points, 1998 and 2002, based on frequency of MEGS reports. During this period, emissions from
        fossil fuel combustion remained constant at 11.0 MMTCG^E, and purchased electricity emissions decreased by
        26%, from 48.1 to 35.9 MMTCO2E.

        In aggregate, emissions from the alumina and aluminum sector decreased 24% between 1998 and 2002. Over
        the same period, aluminum production15 decreased 27%.
        Figure 2-3: Greenhouse Gas Emissions from the Alumina and Aluminum Sector (MMTC02E)
                   1998         1999         2000

                      i   i Fossil Fuel Combustion
  2001         2002

 	1 Purchased Electricity
2003         2004         2005

   —•—Non-Combustion
2.4     Other Sources of Greenhouse Gas Emission Estimates for this Sector
        No reports containing complete GHG estimates for the alumina and aluminum sector were identified.

2.5     Sector Emission Reduction Commitments
        The Aluminum Association (AA) and its members participating in the Voluntary Aluminum Industry
        Partnership (VAIP) have committed to a direct carbon intensity reduction of emissions of PFCs and of
        emissions of CG>2 from the consumption of the carbon anode from the primary aluminum reduction process.
        The target is a 53% total carbon equivalent reduction from these sources by 2010 from 1990 levels.16

2.6     Reporting Protocols
        When calculating emissions, one of the following protocols is typically used by companies in the alumina and
        aluminum sector:
        •   EPA's Climate Naders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below. Climate Leaders provides extra guidance, Draft Assessment oj'The Aluminum Sector
        14 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
        15 U.S. Geological Survey, Minerals Yearbook: Aluminum Annual Report 2005.
        16 See http://www.climatevision.gov/sectors/aluminum/index.html for more information on Climate VISION and the sector.
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Alumina  and Aluminum
            Greenhouse Gas Protocol: October 2006for Use in Climate Leaders Reporting,11 for the aluminum industry with
            regards to soderberg, prebaking, baking furnace and electrolysis reaction processes;

        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program, which include detailed
            guidance for recording PFC emissions from aluminum production;

        •   The World Business Council for Sustainable Development  (WBCSD) and the World Resource Institute's
            (WRJ) Greenhouse Gas Protocol', and

        •   The Aluminum Sector Greenhouse Gas Protocol, which is an addendum to the WBCSD/WRI protocol
            and was created through the VAIP. The Aluminum Sector Greenhouse Gas Protocol* provides additional
            information to guide companies in the industry in estimating their emissions.  The PFC Emissions
            Measurement Protocol for Primary Aluminum19 is a standard measurement protocol that the VAIP hopes to use
            to advance the industry's emission reduction efforts and to disseminate to forward the adoption of a
            common protocol. This measurement protocol expands beyond the WBCSD/WRI protocol by including a
            guide to data requirements, sampling design, measurement, calculation, and quality assurance.
        Table 2-2 presents a sample of companies in the sector that have publicly reported their GHG emissions.
                   Table 2-2: Sampling of Publicly-Reported GHG Emissions for Alumina and Aluminum Companies
        Company
        Alcoa
Protocol
WBCSD/WRI
Emissions    Year        Geographic
(MMTC02E)   Reported   Scope         Goal
   23.720
2006
U.S.
25% by 2010
(1990 baseline)20
        17 See http://www.epa.gov/stateplv/docs/CL Review of Aluminum Sector Protocol.pdf.
        18 See http://www.world-aluminium.org/environment/climate/aha protocol.pdf.
        19 See http://www.epa.aov/hiahawp/aluminum-pfc/pdf/measureprotocol.pdf.
        20 Alcoa Incorporated, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10Nov2007,
        http://www.cdproiect.net/responses/Alcoa Inc Corporate GHG Emissions Response CDP5 2007/public.htm.
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        Cement
                                                              Fossil Fuel Combustion
                                                                                                  Emissions
                                                                                                  (MMTC02E)
                                                   32
                                                              Non-Combustion
                                                   43
                                                              Purchased Electricity
                                                              Total
                                                   83
                                                              Percent of U.S. Industrial Emissions1
                                                   4%
        The cement industry includes establishments
        primarily engaged in manufacturing straight
        portland, natural, masonry, pozzolanic, and other
        hydraulic cements. Cement facilities included in this
        report are those that participate in the U.S.
        Geological Survey's (USGS) Minerals Yearbook:
        Cement Annual Report 2005, which accounts for 100%
        of U.S. cement and clinker production. Cement is
        manufactured in 37 states and Puerto Rico, and is a
        key ingredient in concrete. The United States ranks
        as the third largest cement producer in the world and produced approximately 111 million metric tons of
        portland and masonry cement in 2005.2

3.1     Sources of Greenhouse Gas Emissions

        Cement production results in CO2 emissions from on-site fossil fuel combustion, process-related non-
        combustion activities, and purchased electricity consumed in manufacturing operations.
        The manufacturing of cement requires energy to operate manufacturing equipment and generate and maintain
        high kiln temperatures. This energy use results in direct emissions of carbon dioxide (CC^) from fossil fuel
        combustion and indirect CC>2 emissions from purchased electricity.

        As described in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005? significant non-combustion
        CC>2 emissions also come from the cement production process—the high-temperature conversion of limestone
        (calcium carbonate, CaCOs) to lime (calcium oxide, CaO), with CC>2 as a byproduct. Lime is then combined
        with silica-containing materials to produce clinker, which is  an intermediate product combined with gypsum to
        produce portland cement.

3.2     Summary of Emissions (2002)

        This section presents a summary of emission estimates from the cement sector. It includes a discussion of
        methodologies  and data sources used to calculate emission estimates, as well as the assumptions and limitations
        surrounding the estimates.

3.2.1    Estimates of Greenhouse Gas Emissions (2002)
        Table 3-1 presents emission results for the cement sector, which totaled 83 MMTCOJi and primarily result
        from on-site fossil fuel combustion and non-combustion processes.
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005, 2006, http://minerals.usas.qov/minerals/pubs/commoditv/cement/cemenmvb05.pdf.
        3 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, Chapter 4-1.
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                                 Table 3-1: 2002 GHG Emissions from the Cement Sector (MMTC02E)
Source
Fossil Fuel Combustion3
Non-Cornbustionb
Purchased Electricity0
Total
C02
32
43
8
83
Total
32
43
8
83
                                a Emissions calculated based on USGS Minerals Yearbook: Cement Annual Report 2005 and
                                EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. Some fuels data do
                                not include Puerto Rico, please see USGS Minerals Yearbook.
                                b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. Includes Puerto Rico
                                c Emissions calculated based on USGS Minerals Yearbook: Cement Annual Report 2005 and
                                EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. Some fuels data do
                                not include Puerto Rico, please see USGS Minerals Yearbook.

        The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
        on the methodology used to estimate emissions from the cement sector can be found in Section 3.2.2. The
        analysis presented in this report addresses emissions related to the production processes and does not address
        lifecycle emissions from the use of cement. Consequently, the analysis does not evaluate the environmental
        benefits of the produced materials, such as the use of cement as a thermally efficient building material.
        Figure 3-1 shows the distribution of energy consumption in this sector by fuel type (including both on-site
        fossil fuel combustion and purchased electricity). For comparison, CC>2 emissions associated with fuel
        consumption are shown in  Figure 3-2.
        Figure 3-1: 2002 Energy Consumption in the Cement
        Sector, by Fuel Type (TBtu)
                                Figure 3-2: 2002 C02 Emissions from Energy
                                Consumption in the Cement Sector,
                                by Fuel Type (MMTC02E)
                      <0.5%
                              Petroleum Coke
                         Electricity
                           11%
    Natural gas
       5%
       Tires
      ~~ 3%
 ^_ Solid Waste
       1%
Liquid Waste
    9%
                             Total:

        Source: USGS Minerals Yearbook: Cement Annual Report 2005.
                                                         Coke
                                                        <0.5%
                                                                                                Petroleum Coke   oil
                                                                                                    15%    ^1%
Electricity Liquid Waste
  21 %       6%
                                                                                           40 MMTC02E
                                            Total:

                                Source: Estimate based on methodology in Section 3.2.2.
                                                                                                            Natural gas
                                                                                                                2%
                                                                                                          Solid Waste
                                                                                                              1%
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                       and

         Foss/7 Fuel Combustion
         Fossil fuel combustion emissions from the cement sector were estimated using USGS Minerals yearbook: Cement
         Annual Report 20054 estimates of fuel consumption for this sector. Those fuel consumption estimates were
         multiplied by the appropriate, fuel-specific emission factors to convert the consumption into CC>2 emitted. The
         emission factors for the fossil fuels used in the cement industry were taken from data contained in the Inventory
         of U.S. Greenhouse Gas Emissions and Sinks: 1990-20055 and the Intergovernmental Panel on Climate Change's
         (IPCC) 2006IPCC Guidelines for National Greenhouse Gas Inventories.6

         Non-Combustion Activities
         Non-combustion emission estimates for the cement industry were obtained directly from the Cement
         Manufacture source category of the  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005? The
         emission factor assumed is approximately 0.51 MTCC>2/metric ton clinker produced, plus an additional 2% of
         the CO2 estimated.8 The additional 2% is attributed to calcined raw materials contained in cement kiln dust,
         which is a general term for particulates that form during the clinker production process.  These particulates are
         often captured by dust control  technologies and recycled to the kiln.  Cement kiln dust that is not recycled to
         the kiln is assumed to be emitted.

         Purchased Electricity
         Electricity emissions were estimated by multiplying national-level electricity purchases (in kilowatt-hours, or
         kWh) provided by USGS,9 by CC>2 emission factors (in Ibs/kWh) provided by  eGRID10  at the North American
         Electricity Reliability Corporation (NERC) region level.11 Electricity purchases at the NERC region level were
         based on facility-level estimates of electricity consumption. Electricity consumed by each facility was estimated
         based on the electricity intensity per unit of production  (tons of clinker) and  an estimate of each facility's
         output. Total output was estimated based  on each facility's capacity (tons of clinker per year) and a state-
         appropriate utilization factor—a measure of how much  the facility's equipment is run. Different electricity
         intensities  were used for wet and dry clinker production processes and for grinding-only facilities. In all cases,
         the estimated total electricity consumption was scaled to reflect actual national electricity purchases provided by
         USGS, and a loss factor was applied to reflect losses incurred in the transmission and distribution of electricity.
         Methods for estimating CC>2 emissions from electricity are detailed in Appendix A.3

3,2.3    Key              and
         The boundaries of this sector correspond to facilities that reported to the USGS Minerals Yearbook: Cement Annual
         Report 2005, which accounts for 100% of U.S. cement and clinker production.12 Electricity and fossil fuel
         combustion  emission estimates  include only CC>2. Emissions factors for purchased electricity provided by eGRID
         4 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005.
         5 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         6 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006gI/index.htm. These guidelines detail the internationally agreed upon best available methods for national GHG emission inventories
         based on current technical and scientific knowledge.
         7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, Table 4-3, C02 Emissions from Cement Production.
         8 Factors used in the Inventory of U. S. Greenhouse Gas Emissions and Sinks: 1990-2005 are taken directly from the 2006 IPCC Guidelines for National
         Greenhouse Gas Inventories, pp. 2-13. These factors assume that all CaO stems from carbonate sources, which is likely not true since non-carbonates (e.g., fly
         ash, slag) are likely contained in the clinker. This factor and the addition of 2% for cement kiln dust may result in a slight overestimate of emissions.
         9 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005, Table 8.
         10 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
         http://www.epa.aov/cleanenerav/egrid/index.htm.
         11 The National Reliability Electricity Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric power
         grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
         12 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005.
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         are for 2004, which may include different fuel mixes for electricity generation than those of the 2002 inventory
         year. Emissions of other GHGs such as CFLjand N2O that may result from combustion were not estimated.13

3.3     Greenhouse Gas  Emissions  (1998,2002)
         GHG emissions for select years from fossil fuel combustion and non-combustion emissions are available for
         years 1998 to 2005 and are shown in Figure 3-1.14 GHG emissions from purchased electricity are available for
         1998 and 2002. Emission estimates were developed using the methodologies described above. From 1998 to
         2005, emissions from on-site fossil fuel combustion and non-combustion processes increased by 15%.
         Electricity emissions increased by 5% from 1998 to 2002. Emissions from the cement sector as a whole
         increased by 9% between 1998  and 2002. Cement production increased by 9% during the same period.15
         Figure 3-1: Greenhouse Gas Emissions for the Cement Sector
         o
         o
                   1998
                                1999
                                            2000
                                                        2001
                                                                     2002
                                                                                 2003
                                                                                              2004
                                                                                                          2005
                                  1 Fossil Fuel Combustion
                                                           I Purchased Electricity
                                                                                   Non-Combustion
3.4      Other Sources of Greenhouse Gas Emission Estimates for this Sector

         CO-2 Emissions Profile of the U.S. Cement Industry16 is a conference paper prepared to geographically disaggregate
         CO2 emissions from the cement industry. It provides an overview of national process emissions and energy use,
         as well as a detailed analysis of facility level capacity data. The report provides an emission estimate of 41.4
         MMTCG^E from process emissions in 2001. In addition, the analysis estimates 2001 fuels used for fossil fuel
         consumption for coal  (71%), petroleum coke (12%), liquid and solid waste fuels (9%), natural gas (4%), and the
         remainder from oil and coke.17 Emission totals from fossil fuel combustion were estimated at 35.5 MMTCG^E
         in 2001, for a total industry estimate of 76.9 MMTCO2E.18

3.5      Sector Emission Reduction Commitments

         In 2003, the Portland Cement Association committed to a 10% reduction in  CC>2 emissions per ton of
         cementitious product produced or sold from a 1990 baseline by 2020. PCA will be using metrics under DOE's
         13 These non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
         14 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
         level of significance; therefore, the reader may not be able to reproduce the calculation.
         15 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2005.
         16Hanle, L. andK. Jayaraman (2004). C02 Emissions Profile of the U.S. Cement Industry. Submitted to 13th International Emission Inventory Conference:
         "Working for Clean Air in Clearwater." Clearwater, FL, June 8-10, 2004. http://www.epa.gov/ttn/chief/conference/ei13/aha/hanle.pdf.
         17 Coke (i.e., metallurgical coke) may be misreported petroleum coke (van Oss 2008)
         18 Also see the Portland Cement Association's U.S. and Canadian Labor-Energy Input Survey 2006, a proprietary annual survey detailing the U.S. and Canadian
         cement industry's labor and energy usage. The report focuses on energy consumption by fuel type (including waste fuels) and contains aggregated historical labor
         and energy efficiency trends summarized by type of process, size of kiln, and age of plant. Individual plant detail is not presented. Available at
         http://www.cement.ora/bookstore/profile.asp?store=Spagenum=1Spos=OScatlD=Sid=15216.
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Cement	

         Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program and the World Business Council for
         Sustainable Development (WBCSD) and the World Resource Institute's (WRI) Greenhouse Gas'Protocol'to report
         its results.19

3.6      Reporting Protocols

         When calculating emissions, one of the following protocols is typically used by companies in the cement sector:

         •   EPA's Climate 'Leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
             protocol mentioned below. The cement industry's protocol, Draft Assessment oj"C02 Accounting and Exporting
             Standard for the Cement Industry: Version 2.0 for Use in Climate Leaders Reporting, for Climate Leaders exempts
             companies  from reporting purchased electricity, owned or leased off-site mobile combustion, and CHU and
             N2O emissions from kiln fuel combustion.20

         •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and

         •   WBCSD/WRI  Greenhouse Gas Protocol (note: WBCSD also coordinates a voluntary Cement Sustainability
             Initiative (CSI), a member-sponsored program to find new ways to meet the sustainability challenge of:
             reducing the industry's ecological footprint, increasing stakeholder engagement, and understanding the
             industry's social contributions).21

         Table 3-2 presents a sample of cement companies that have publicly reported their GHG emissions.

                           Table 3-2: Sampling of Publicly-Reported GHG Emissions for Cement Companies
         Company
         Holcim

         Lafarge24

         St. Lawrence
         Cement25
               Emissions
Protocol       (kg/t)
               65822

               670

               668
 Year          Geographic
 Reported     Scope          Goal
 2005          World           12% below 2000 levels per ton
                               cement by 200823
 2006          World           20% below 1990 levels per
                               metric ton cement by 2010
 2005          World           15% below 2000 levels per ton
	cement by 2010	
         I = Not Indicated
         19 See http://www.climatevision.gov/sectors/cement/index.html.
         20 See http://www.epa.gov/stateplv/docs/CLReview of Cement  Sector Protocol.pdf.
         21 See http://www.wbcsd.org/templates/TemplateWBCSD1/lavout.asp?tvpe=pSMenuld=MTI2SdoOpen=1SCIickMenu=LeflMenu.
         22 Holcim Ltd, "Corporate Sustainable Development Report 2005," Global Reporting Initiative, June 2006,
         http://www.corporatereaister.com/search/report.cgi?num=15774-Osb.ki8YtnY24.
         23 U.S. Environmental Protection Agency, "Partner Profile: Holcim (U.S.) Inc.," Climate Leaders, 12 Nov 2007,
         http://www.epa.aov/stateplv/partners/partners/holcimusinc.html.
         24 LaFarge, "Sustainability Report 2006," Global Reporting Initiative, May 2007, http://www.corporatereaister.com/search/report.cqi7nurrFl8921-2w8aZcpFvC2 20 - 21.
         25 St. Lawrence Cement Group, "Sustainable Development Report," February 2006,
         http://www.stlawrencecement.com/gc/CA/uploads/SLC%20SD%20Report%20Februarv%202006%20FINAL.pdf9.
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        Chemicals
        The chemical sector, as defined by NAICS code 325, produces products by transforming organic and inorganic
        raw materials by a chemical process.1 Over 96% of all manufactured goods are directly impacted by chemistry,
        either as a material, in processing, or in some other
        value-added means.2 The United States is the top
        chemical-producing country.2
                                                              Source
                                                 2002
                                               Emissions
                                              (MMTC02E)
                                                              Fossil Fuel Combustion
                                                              Non-Combustion
                                                              Purchased Electricity
                                                              Total
                                                              Percent of U.S. Industrial Emissions1
                                                   203
                                                    62
                                                   101
                                                   366
                                                  18%
        The chemical sector contains the following
        segments: basic chemicals, specialties, agricultural
        chemicals, pharmaceuticals, and consumer products.
        Basic, or commodity chemicals, such as industrial
        chemicals and fertilizers, are produced in large
        volumes to homogenous chemical composition
        specifications. Specialty chemicals are used for
        specific purposes such as a functional ingredient or
        as processing aids in the manufacture of a wide variety of products. Examples of specialty chemicals include
        adhesives, catalysts, coatings, and water management chemicals. Agricultural, pharmaceutical, and consumer
        product chemicals include crop protection chemicals, prescription and over-the-counter drugs, in-vitro and
        other diagnostic substances, vaccines, soaps, detergents, bleaches, and toothpaste.2

4.1     Sources of Greenhouse Gas Emissions

        The chemical sector depends on fuel inputs for energy and for raw materials (feedstocks) .2 As such, GHG
        emissions from chemicals result from both the  energy used by the industry as well as from the chemical
        processes themselves.

        Manufacturing in the chemical sector involves complex chemical reactions, often requiring large amounts of
        heat, pressure and/or electricity. Energy-related emissions result from on-site fossil fuel combustion and from
        purchased electricity. As described in the American Chemistry Council's (ACC) Guide to the business of Chemistry,
        fossil fuel combustion serves to supply heat and power for plant operations. The largest use of fuel for heat
        and power is in boilers used to produce steam to drive chemical reactions and perform product separation and
        finishing operations.3 Electricity is used to power equipment, drive electrochemical processes, and heat, light,
        and cool facilities.3
        Emissions resulting from feedstocks are referred to as process-related, or non-combustion, GHG emissions.
        Oil and natural gas are both feedstocks in the manufacturing of organic chemicals. As described in the Inventory
        of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,4 chemical manufacturing processes that result in
        significant non-combustion GHG emissions include (GHGs emitted by each process are provided in
        parentheses):

        •   Petrochemicals Production (CO2, CH/j): Petrochemicals are chemicals isolated or derived from petroleum
            or natural gas. Methane (CH4) emissions result from the production of carbon black, ethylene, ethylene
            dichloride, and methanol, while carbon dioxide (CO 2) emissions result solely from carbon black
            production. Carbon black is an intensely black powder generated by the incomplete combustion of an
            aromatic petroleum or coal-based feedstock.

        •   Phosphoric Acid Production (CC>2): Phosphoric acid production from natural phosphate rock emits CO2 due
            to the chemical reaction of the inorganic carbon (calcium carbonate) component of the phosphate rock.
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions andSinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 American Chemistry Council, Guide to the Business of Chemistry, 2006, pp. 1,16-40, 43,103.
        3 U.S. Department of Energy, 1998 Chemicals Industry Analysis Brief: Energy Consumption, Energy Information Administration, 7 Jan 2004,
        http://www.eia.doe.aov/emeu/mecs/iab98/chemicals/index.html.
        4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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Chemicals	

        "   Titanium Dioxide Production (CC>2): There are two processes used for making titanium dioxide: the
            chloride process and the sulfate process. Only the chloride process emits process-related CO2 as a result of
            using petroleum coke and chlorine as raw materials.

        "   Adipic Acid Production (N2O): Adipic acid is produced by oxidizing cyclohexane to form a
            cyclohexanone/cyclohexanol mixture, which is then oxidized with nitric acid to produce adipic acid. N2O
            is generated as a by-product of the nitric acid oxidation stage and is emitted in the waste gas stream.

        "   Nitric Acid Production (N2O): N2O is formed as a by-product of the catalytic oxidation of ammonia, the
            process by which virtually all of the nitric acid produced in the U.S. is manufactured.

        "   HCFC-22 Production  (HFC-23): HCFC-22 is produced by the reaction of chloroform and hydrogen
            fluoride in the presence of a catalyst, SbCls. The production process involves a continuous flow reactor,
            condensation of chemicals, and fluorination. The final vapors of these processes consist primarily of
            HCFC-22, HFC-23, HC1 and residual HF. Of the remaining vapors, the HC1 is recovered, the HF is
            removed, and once it is separated from HCFC-22, the HFC-23 is vented into the atmosphere.

        "   Soda Ash Manufacturing (CC>2): There are two types of soda ash produced internationally: natural and
            synthetic. The production of natural soda ash involves the treatment of trona ore which generates CO2 as a
            by-product.

        "   Ammonia Manufacturing (CC>2):  CO2 is emitted through the use of natural gas, naphtha, and in some cases
            petroleum coke, as a feedstock. The carbon from these feedstocks is removed to produce CO2, leaving
            hydrogen (H.2), which is used in the production of ammonia (NHs).

4.2     Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the chemical sector for the year 2002. The
        methodologies and data sources used to  calculate these emission estimates, as well as the assumptions and
        limitations surrounding the estimates, are also described.

4.2.1              of             Gas
        Total GHG emissions from the chemical sector were estimated to be 366 MMTCO2E in 2002 (as seen in  Table 4-1).

                               Table 4-1: 2002 GHG Emissions from the Chemical Sector (MMTC02E)
• flfifet;

Non-Combustion5
Petrochemicals Production
Phosphoric Acid Production
Titanium Dioxide Production
Adipic Acid Production
Nitric Acid Production
HCFC-22 Production
Ash Manufacture
Ammonia Manufacture

Total
COl
203
18
3
1
2



2
11
101
322
CH4

1
1








1
HO

23



6
17




23
HFC*

20





20



20
TaHi
203
62
4
1
2
6
17
20
2
11
101
366
        a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S. Greenhouse Gas Emissions and
        Sinks: 1990-2005.
        b Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and Generation Resource Integrated Database
        (eGRID).
        Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis did not address that
        emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
        5U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissbns and Sinks: 1990-2005.
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Chemicals
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions from the chemical sector can be found in Section 4.2.2.

         Figure 4-1 shows the distribution of energy consumption in this sector by fuel type (including both on-site
         fossil fuel combustion and purchased electricity). For comparison, CC>2 emissions associated with fuel
         consumption are shown in Figure 4-2.
        Figure 4-1: 2002 Energy Consumption in the Chemical
        Sector, by Fuel Type (TBtu)
              Natural Gas
                 45%
                             Distillate Fuel Oil
                                 <0.5%
Residual
Fuel Oil
              Electricity
                14%  -
             Coke and Breeze
                 <0.5%
                            Figure 4-2: 2002 C02 Emissions from Energy
                            Consumption in the Chemical Sector,
                            by Fuel Type (MMTC02E)
Distillate Fuel Oil
    <0.5%
                                                                          Natural Gas
                                                                            29%
Residual
Fuel Oil
                                                         Coal
                                                                                                           1%
                                                                                                          LPG and NGL
                                                                                                              1%
                              Total:
                                         Electricity3
                                            45%


                                            Total:
                         Coke and i
                             0.5%
                     304 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         'Composition of "other" fuel category varies among sectors. In the
         chemicals sector, "other" fuels include petroleum-derived byproduct gases
         and solids, woody materials, hydrogen, and waste materials.
         Note: TBtu stands for trillion British thermal units.
                            Source: Estimate based on methodology in Section 4.2.2.
                            aFuel mix at utilities was taken into consideration in this calculation,
                            per methodology described in Section 4.2.2.
4.2.2    Methodology and Data Sources

         Fossil Fuel Combustion

         Fossil fuel combustion emissions from the chemical sector were derived from the U.S. Department of Energy's
         (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption Survey (MEGS)6 estimates
         of fuel consumption for this sector. Those fuel consumption estimates were multiplied by the appropriate, fuel-
         specific emission factors to convert the consumption into CO2 emitted. The emission factors for the fossil
         fuels used in the chemical industry were taken from data contained in the Inventory of U.S.  Greenhouse Gas
         Emissions and Sinks:  1990-2005?

         Non-Combustion Activities

         Non-combustion emission estimates, including emissions of CG>2, CH4, N2O, and HFCs, from chemicals were
         obtained from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005? These estimates include the
         6 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
         http://www.eia.doe.gov/emeu/mecs/mecs2002.
         7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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Chemicals	

         chemical sector emission sources identified by the Intergovernmental Panel on Climate Change's (IPCC) 2006
         IPCC Guidelines for National Greenhouse Gas Inventories.* As described above, for the United States, the nine
         sources are petrochemical production, phosphoric acid production, titanium dioxide production, adipic acid
         production, nitric acid production, HCFC-22 production, soda ash manufacturing, and ammonia
         manufacturing. These are source categories 4.13, 4.9, 4.7, 4.16, 4.15, 4.18, 4.6, and 4.3, respectively, in the
         Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.

         Purchased Electricity
         Electricity emissions were estimated by mapping national electricity purchases (in kilowatt-hours, or kWh)
         provided by MECS to North American Electricity Reliability Corporation (NERC) regions,9 then applying
         NERC regional utility CC>2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
         adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.
         Since electricity purchase data were not available at the NERC regional level, distribution of the sector's value
         added was used to distribute the sector's national electricity purchases to the state-level, then state data were
         rolled up to the NERC  regions. Where a state lay in two or more NERC regions, electricity purchases were
         distributed to the appropriate NERC region using sales  data for the industrial customer class from EIA Report
         861. This approach assumes that the electricity-intensity of production activities are correlated with the value
         added. Methods  for estimating CC>2 emissions from electricity are described in more detail in Appendix A.3.

4.2,3    Key              and
         Non-combustion emission estimates were limited to sources identified by the 2006 IPCC Guidelines for National
         Greenhouse Gas Inventories. Electricity and fossil fuel combustion emission estimates include only CC>2. Emissions
         of other GHGs (e.g., CPTtand N2O) that may result from combustion were not estimated.10 Emission factors
         for purchased electricity provided by eGRID are for 2004, which may include different fuel mixes for electricity
         generation than those of the 2002 inventory year.

4.3     Greenhouse Gas Emissions (1998,2002)

         GHG emissions for select years from the  chemical sector are provided in Figure 4-3.u
         Data for non-combustion GHG emissions are available for the years 1998  to 2005 from the annual Inventory of
         U.S. Greenhouse Gas Emissions and Sinks:  1990-2005. These process-related emissions have decreased by
         approximately 38% over the time-series, from 90 to 56 MMTCG^E.

         Data for GHG emissions from fossil fuel combustion and purchased electricity are available only for two data
         points, 1998 and 2002, based on frequency of MECS reports.  Fossil fuel combustion emissions increased by
         approximately 10%, from 185 to 203 MMTCC>2E, and emissions from purchased electricity declined by
         approximately 13%, from 117 to 101 MMTCO2E.

         Total emissions from the chemical sector decreased by approximately 7% between 1998 and 2002. Over the
         same period, value added12 in the chemical sector increased 3%.
         8 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006gI/index.htm. These guidelines detail the internationally agreed upon best available methods for national GHG emission inventories
         based on current technical and scientific knowledge.
         9 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
         power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
         10 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
         11 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
         level of significance; therefore, the reader may not be able to reproduce the calculation.
         12 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
         production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
         and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
         http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
         inflation using a gross domestic product price deflator.
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Chemicals
        Figure 4-3: Greenhouse Gas Emissions for the Chemical Sector
                    1998          1999         2000


                     ^^B Fossil Fuel Combustion    M
                                                       2001
                                                I Purchased Bectricity
               2002         2003


                   Non-Combustion
                                                                                          2004
                                                                                                      2005
4.4     Other Sources of Greenhouse Gas Emission  Estimates for this Sector

        ACC's Guide to the business of Chemistry is an annual publication that describes the industry's performance and
        trends. The guide includes GHG emission estimates for CC>2, CH4, N2O, and "others," which may include HFCs,
        SFe, and other gases generated during the manufacturing process. Similar to estimates presented here, ACC's
        estimates include fossil fuel combustion, non-combustion activities, and purchased electricity. For the year 2002,
        ACC estimated total GHG emissions to be 278.6 MMTCC^E (Table 4-2), an estimate that is approximately 87
        MMTCG^E less than the estimate presented here. The difference results from the different energy consumption
        numbers used by MECS and ACC for the "other" fossil fuel category. For the year 2002, MECS data indicates
        1,158 TBtu for this category whereas ACC estimates 583 TBtus for this category. In addition, estimates for CC>2
        process-related emissions differ. Process CC>2 emissions are estimated to be 18 MMTCG^E, whereas ACC
        estimates these emissions to be 3.5 MMTCO2E. ACC's estimates account only for non-combustion emissions
        from soda ash manufacture and titanium dioxide production, whereas estimates presented here account for non-
        combustion emissions from these two sources in addition to ammonia manufacture, petrochemical production
        and phosphoric acid manufacture. ACC will evaluate the processes undertaken by its members and consider
        whether it is appropriate to include these in future estimates.13

                                        Table 4-2: GHG Emission Estimates from the
                          American Chemistry Council's Guide to the Business of Chemistry (MMTC02E)
                                                                        2003       2004      2005
                       Foss/7 Fuel Combustion and
                       Purchased Electricity CC>2
                      235
           226
           227
                      Non-Combustion CC>2
                      A/20
            23
 23
 22
 22
                       CH4
                       Others
            20
 12
 16
 16
                    Total
           279
276
269
270
                   Source: ACC, Guide to the Business of Chemistry.
        13 Personal communication, ACC and ICF International, 2 Nov 2007.
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Chemicals	


4.5     Sector Commitments

         ACC has committed to reduce overall GHG emission intensity by 18% by 2012 (from a 1990 baseline). ACC is
         using metrics under DOE's  Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program for its
         annual member-wide reports.14

4.6     Reporting Protocols

         When calculating emissions, one of the following protocols may be used by companies in the chemical sector:

         •    EPA's  Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
              protocol mentioned below;

         •    DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program, which include specific
              guidance on calculating N2O emissions from adipic and nitric acid production (Sector-Specific Issues 5/j;14and

         •    The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
              (WRI)  Greenhouse Gas Protocol.

         Table 4-3 presents  a sample  of companies in the sector that have publicly reported their  GHG  emissions.

                            Table 4-3: Sampling of Publicly-Reported GHG Emissions for Chemical Companies

Company
Air Products &
Chemicals15



Dow Chemical16

DuPont17
Johnson &
Johnson19
Rohm and Haas21

Protocol

WBCSD/WRI



WBCSD/WRI

WBCSD/WRI

WBCSD/WRI
WBCSD/WRI
Emissions
(MMTC02E)

2.0



20.2

10.3

0.6
3.2
Year
Reported

2006



2006

2005

2006
2006
Geographic
Scope

Annex Ba



U.S.

U.S.

U.S.
Global
Goal

Nl
2.5% per year reduction
per pound of produced
product till 201 5 (2005
baseline)
15% below 2004 levels by
201518
14% below 2001 levels by
201 020
Nl
         Nl = Not Indicated
         a Countries included in Annex B of the Kyoto Protocol
         14 See http://www.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/aa-v1-3-indust.pdf.
         15 Air Products & Chemicals, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 29 Feb
         2008, http://www.cdproiect.net/responses/Air Products   Chemicals Corporate GHG Emissions Response CDP5 2007/public.htm.
         16 The Dow Chemical Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 29 Feb
         2008, http://www.cdproiect.net/responses/Dow Chemical Company The Corporate GHG  Emissions Response CDP5 2007/public.htm.
         17 E.I. du Pont de Nemours & Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire,"
         29 Feb 2008, http://www.cdproiect.net/responses/EI du Pont de Nemours    Company Corporate GHG  Emissions Response CDP5 2007/public.htm.
         18 U.S. Environmental Protection Agency, "Partner Profile: DuPont Company," Climate Leaders, 29 Feb 2008,
         http://www.epa.aov/stateplv/partners/partners/iohnsoniohnson.html.
         19 Johnson & Johnson, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 29 Feb 2008,
         http://www.cdproiect.net/responses/Johnson    Johnson Corporate GHG Emissions Response CDP5  2007/public.htm.
         20 U.S. Environmental Protection Agency, "Partner Profile: Johnson & Johnson," Climate Leaders, 29 Feb 2008,
         http://www.epa.aov/stateplv/partners/partners/dupontcompanv.html.
         21 Rohm & Haas, "2006 EHS and Sustainability Report," September 2007, http://www.rohmhaas.com/assets/attachments/about us/ehs/pdfs/2006ehs.pdf.
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        Construction
                                                             Source
                                                             Fossil Fuel Combustion
                                                             Non-Combustion
                                                             Purchased Electricity
                                                             Total
                                                             Percent of U. S. Industrial Emissions1
                                                2002
                                             Emissions
                                             (MMTC02E)
                                                 100

                                                  31
                                                 131
                                                  6%
        The construction sector comprises establishments
        engaged in the construction of buildings and
        engineering projects.The work performed includes
        new work, additions, alterations, maintenance and
        repairs, and demolitions. With spending set at
        $873.1 billion in 2003, the U.S. construction sector
        is one of the world's largest, and it is the seventh-
        largest employer in the U.S.2 The activities
        included in the construction sector may be found
        under the following NAICS codes: Construction      ^^^^^^^^^^^^^^^^~^^^^^^^^^^^^^^^^~
        Buildings (NAICS code: 236), Heavy and Civil Engineering Construction (NAICS code 237), and Specialty
        Trade Contractors (NAICS code: 238).
        NAICS code 236, Construction Buildings, is defined as those establishments primarily responsible for the
        construction of buildings.3
        NAICS code 237, Heavy and  Civil Engineering Construction, is defined as those establishments whose primary
        activity is the construction of entire engineering projects (e.g., highways and dams), and specialty trade
        contractors, whose primary activity is the production of a specific component for such projects.3

        NAICS code 238, Specialty Trade Contractors, is defined as  establishments whose primary activity is
        performing specific  activities  (e.g., pouring concrete, site preparation, plumbing, painting, and electrical work)
        involved in building construction or other activities  that are similar for all types of construction but that are not
        responsible for the entire project.3

5.1     Sources of Greenhouse Gas Emissions

        GHG emissions from the construction sector result from fuel consumed by on- and off-road construction
        equipment and from electricity consumed to provide power  to construction tools and offices. Off-road diesel
        engines used by construction  companies include a wide variety of loaders, dozers, excavators, graders, and
        other specialized equipment.4 Emissions from this sector are associated with energy use from construction, and
        do not include the post-construction performance of buildings.

5.2     Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates from construction activities for the year 2002.
        The methodologies  and data sources used to calculate emission estimates, as well as the assumptions and
        limitations surrounding the estimates, are also described.

5.2.1    Estimates of Greenhouse Gas Emissions (2002)
        GHG emissions from the construction sector were estimated to be  131 MMTCG^E in 2002 (as seen in Table 5-1).
        Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis did not address that emission
        source, if applicable; see "Summary of Emissions (2002)" for additional information.
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 U.S. Department of Commerce, Construction Services Sector, International Trade Administration, 2007, http://trade.aov/investamerica/construction.asp.
        3 U.S. Census Bureau, 2002 NAICS Codes and Titles, 23 Mar 2004, http://www.census.gov/epcd/naics02/naicodQ2.htm.
        4ICF Consulting, Emission Reduction Incentives for Off-Road Diesel Equipment Used in the Port and Construction Sectors, 2005,
        http://www.epa.gov/sustainableindustrv/pdf/emission 20050519.pdf, p. 1.
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Construction
                                         Table 5-1: GHG Emissions from Construction (MMTC02E)
                        Source
                           Fossil Fuel Combustion3
                                    100
                                                       N20       MFCs      Total
                                     100
                           Non-Combustion
                           Purchased  Electricity13
                                      31
                                      31
                        Total5
                                    131
                                     131
                      a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey'and EPA's Inventory
                      of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                      b Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey'and EPA's Emissions and Generation
                       Resource Integrated Database (eGRID).
                      Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis
                      did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions from construction can be found in Section 5.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 5-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 5-2.
         Figure 5-1: 2002 Energy Consumption in the Construction
         Sector, by Fuel Type (TBtu)
                     Electricity
                       10%
Natural Gas
   14%
Figure 5-2: 2002 C02 Emissions from Energy
Consumption in the Construction Sector, by Fuel Type
(MMTC02E)

                            Electricity3
                              24%
              Gasoline
                18%
                                                                                    Gasoline
                                                                                      16%
                                              Distillate Fuel Oil
                                                                                   Distillate Fuel
                                                                                        51%
                                                                                Natural Gas
                                                                                    9%
                                      Total:
                                                                     Total:
                                     131 MMTC02E
         Source: U.S. Census Bureau, 2002 Economic Census Industry Series Reports
         Construction.
         Note: TBtu stands for trillion British thermal units.
                                          Source: Estimate based on methodology in Section 5.2.2.
                                          a Fuel mix at utilities was taken into consideration in this calculation, per
                                          methodology described in Section 5.2.2.
         5 A report developed by EPA's Sector Strategies Division, Measuring Construction Industry Environmental Performance (September 2007) tracks various
         environmental performance indicators of U.S. construction activities, including energy use and GHG emissions. Carbon dioxide emissions from construction
         activities were estimated to be approximately 85 MMTC02E from fossil fuel combustion and 29 MMTC02E from electricity in this report. Due to new data and
         information, the numbers presented here -100 MMTC02E from fossil fuel combustion and 31  MMTC02E from electricity - differ. The emission estimate presented
         in the previous report assumes 100 percent of fuel consumed by on-highway vehicles is gasoline.  This report assumes a 50/50 split between diesel and gasoline
         fuel types for on-highway vehicles.
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Construction
5.2.2    Methodology and Data Sources

         Foss/7 Fuel Combustion
         Fossil fuel consumption was estimated based on reported dollars spent on distillate fuel, natural gas, and
         gasoline for construction activities, provided by the U.S. Census Bureau's Industry Series Report for Construction.6
         Those fuel consumption estimates were divided by the cost of fuel, provided by EIA's State Energy Data Report,
         as shown in Table 5-2. Because the U.S. Census data provides dollars spent on on- and off-highway fuel use as
         an aggregated sum of diesel and gasoline, the
         emission estimates were based on the                           Table 5-2: Cost of Fuel Provided  by
         assumption that all off-highway use was                       EIA's State Energy Data Report ($/TBtu)


         fossil fuel combustion emission estimate              Distillate Fuel                          $ 6,324,590
         utilized an emission factor of 0.073                    Natural Gas                            $4,365,110
         MMTCO2E/TBtu for distillate fuel, 0.071             Motor Gasoline	$10,658,510
         MMTCC^E/TBtu for motor gasoline, and        Source: DOE, Sfafe Energy Data Report, Fuel Prices.
         0.053 MMTCO2E/TBtu for natural gas, as
         provided by EIA's Annual Electric Power Industry Report.

         Non-Combustion Activities
         Non-combustion emissions would  include GHG emissions that occur from activities within construction that
         are not related to energy use. Non-combustion emissions  from this sector are not identified by the
         Intergovernmental Panel on Climate Change's (IPCC) 2006IPCC Guidelines for National Greenhouse Gas
         Inventories* and, hence, are not included in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 or
         this report.

         Purchased Electricity
         Electricity consumption was determined by dividing dollars spent on purchased electricity provided by the U.S.
         Census Bureau's Industry Series Report for Construction, by the cost of electricity ($0.049/kWh), provided by EIA's
         State Energy Data Report? Electricity emissions were estimated by multiplying electricity consumption (in
         kilowatt-hours, or kWh) by CC>2 emission factor (in Ibs/kWh) provided by eGRID10 at the North American
         Electricity Reliability  Corporation (NERC) region level.11  Sector electricity purchases were adjusted by a loss
         factor to reflect losses incurred in the transmission and distribution of electricity.  The geographic distribution
         of electricity purchases was assumed to be the same as that of the commercial class. This customer  class
         distribution was based on data collected by EIA on sales,  by customer class, on all electricity providers  (from
         EIA Form 861).12 Methods for estimating CC>2 emissions from electricity are detailed in Appendix  A.3.
         6 U.S. Census Bureau, 2002 Economic Census Industry Series Reports Construction, 22 Nov 2005.
         7 Personal communication from Peter Truitt of EPA's Sector Strategies Division to ICF International, 8 Nov 2007.
         8 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006gI/index.htm. These guidelines detail the internationally agreed upon best available methods for national GHG emission inventories
         based on current technical and scientific knowledge.
         9 U.S. Department of Energy, Sfafe Energy Data Report, Fuel Prices, Energy Information Administration, 1 Jun 2007,
         http://www.eia.doe.gov/emeu/states/ seds.html.
         10 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, May 2007,
         http://www.epa.aov/cleanenerav/egrid/index.htm.
         11 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
         power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
         12 U.S. Department of Energy, Annual Electric Power Industry Report: Form EIA-861, Energy Information Administration,
         http://www.eia.doe.aov/cneaf/electricitv/page/eia861.html.
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Construction
5.2.3    Key Assumptions and Completeness
        Electricity and fossil fuel combustion emission estimates included only CO2. Emissions of other greenhouse
        gases (e.g., CHUand N2O) that may result from combustion were not estimated.13 Emission factors for
        purchased electricity provided by eGRID are for 2004, which may include different fuel mixes for electricity
        generation than those of the 2002 inventory year.

        Information from the U.S. Census Bureau's 2002 NAICS Codes and Titles WAS obtained for fuel use according to
        the NAICS codes that define the construction sector. Further research is needed to determine whether data
        provided by the U.S. Census Bureau on total dollars spent on gasoline and diesel fuel can be disaggregated into
        dollars spent on gasoline and dollars spent on diesel fuel. Additional research is also needed regarding the
        assumption that all off-highway fuel use is diesel and that 50% of on-highway use is motor gasoline and the
        other 50% diesel.

5.3     Greenhouse Gas Emissions (1997,2002)

        GHG emissions for select years from construction activities are provided in Figure 5-3.u

        Data for GHG emissions from purchased electricity and fossil fuel combustion are available only for two data
        points, 1997 and 2002, based on the frequency of the U.S. Census Bureau's Industry Series Report for Construction.1^
        During this period, emissions from fossil fuel combustion increased by approximately 26%, from 79.4 to 100.1
        MMTCC>2E, and emissions from purchased electricity increased by approximately 31%, from 23.8 to 31.1
        MMTCO2E.

        Total emissions increased by approximately 27% over this time period, from 103 to 131 MMTCO2E. Over the
        same period, the value of construction put in place increased 23%.16
         Figure 5-3: Greenhouse Gas Emissions for the Construction Sector (MMTC02E)
            120 n
         UJ
         o
                   1997
                              1998
                                        1999
                                                   2000
                                                             2001
                                                                        2002
                                                                                  2003
                                                                                             2004
                                                                                                        2005
                                     I Fossil Fuel Combustion
                                                                     • Purchased Bectrlclty
5.4     Other Sources of Greenhouse Gas Emission Estimates for this Sector
        No reports containing complete GHG emissions estimates for the construction sector were identified.
        13 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        14 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
        15 Because only one data point was available between the years 1998 and 2002, data from 1997 was included in this chapter.
        16 U.S. Census Bureau, Construction Spending: October 2007 Construction at a Glance, 30 Nov 2007, http://www.census.gov/const/C30index.html.
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Construction
5.5    Sector Emission Reduction Commitments

       No sector commitments to reducing GHG emissions were identified.

5.6    Reporting Protocols

       When calculating emissions, one of the following protocols may be used by companies in the construction
       sector:

       •   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
           protocol mentioned below; and

       •   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
           (WRI) Greenhouse Gas Protocol.
       No public reports of GHG emissions from companies in the construction sector were identified.
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6.      Food and Beverages
                                                             Source
                                                             Fossil Fuel Combustion
                                                             Non-Combustion
                                                             Purchased Electricity
                                                             Total
                                                             Percent of U.S. Industrial Emissions1
                                                2002
                                             Emissions
                                             (MMTC02E)
                                                  51
                                                   6
                                                  49
                                                 106
                                                  5%
        The food and beverage sector represents a wide
        range of processes by which food products are
        manufactured and both alcoholic and non-alcoholic
        beverages are made.
        For the purposes of this report, the food and
        beverage sector includes facilities that manufacture
        food products by transforming livestock or
        agricultural products into products for intermediate
        (or final) consumption by humans  (NAICS code       ^^^^^^^^^^^^^^~^^^^^^^^^^^^^^~
        311: Food Manufacturing); and facilities that produce non-alcoholic beverages (including water and ice),
        alcoholic beverages via fermentation, or distilled alcoholic beverages (NAICS code 3121: Beverage
        Manufacturing) .2

6.1     Sources  of Greenhouse Gas Emissions

        GHG emissions from the food and beverage sector result from energy use and non-combustion activities.
        Food and beverage manufacturing involves energy use for heating, cooking, drying, cooling, freezing, and other
        common processes. Most of these  energy inputs come from fossil fuel combustion and purchased electricity.
        The processes that consume the most energy in the sector are grain milling, fruit and vegetable processing,
        meat processing, and beverage production.

        Non-combustion emissions from the sector include hydrofluorocarbon (HFC) emissions from refrigeration
        and air conditioning equipment and emissions from on-site wastewater treatment. Note that emissions from
        off-site (municipal) wastewater treatment were not included in this analysis.

6.2     Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the food and beverage sector for the year
        2002. The methodologies and data sources used to calculate these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

6.2.1    Estimates of Greenhouse Gas Emissions (2002)
        GHG emissions from the food and beverage sector were estimated to be 106 MMTCC>2E in 2002 (as shown in
        Table 6-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 The GHG emissions due to farming, food wholesaling, and retailing were considered outside of the scope of this sector.
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Food and Beverages
Table 6-1 : 2002 GHG Emissions from the Food
^^^^^^^^H Source
Fossil Fuel Combustion3
Non-Cornbustionb
On-Site Wastewater Treatment
Refrigeration
Purchased Electricity0
Total

51



49
100
and Beverages Sector (MMTC02E)


3
3


3
N20 MFCs

3

3

3
Total 1
51
6
3
3
49
106
                     a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S. Greenhouse
                     Gas Emissions and Sinks: 1990-2005.
                     b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                     c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and Generation
                     Resource Integrated Database (eGRID).
                     Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis
                     did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information. Totals may not
                     sum due to independent rounding.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail on
         the methodology used to estimate emissions from the food and beverages sector can be found in Section 6.2.2.

         The distribution of energy consumption in this sector by fuel type (including both on-site fossil fuel
         combustion and purchased electricity) is illustrated in Figure 6-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 6-2.
         Figure 6-1: 2002 Energy Consumption in the Food and
         Beverages Sector, by Fuel Type (TBtu)
                 Coke and Breeze
          LPG and NGL
             0.5%
                     <0.5%
Electricity
  21%
               Residual Fuel Oil //
                    1%
                       Distillate Fuel Oil
                                                 Natural Gas
                                                    52%
                                        Total:
                                           Figure 6-2: 2002 C02 Emissions from Energy
                                           Consumption in the Food and Beverages Sector, by Fuel
                                           Type (MMTC02E)
Coke and Breeze
    <0.5%
                                                                                    Electricity11
                                                                                      49%
                                           Residual Fuel Oil
                                                 1%
                                                Distillate Fuel Oil
                                                     1%
                                                                    Natural Gas
                                                                       33%
                                                                   Total:
                 100 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         a Composition of "other" fuel category varies among sectors.
         Note: TBtu stands for trillion British thermal units.
                                           Source: Estimate based on methodology in Section 6.2.2.
                                           a Composition of "other" fuel category varies among sectors.
                                           b Fuel mix at utilities was taken into consideration in this calculation, per
                                           methodology described in Section 6.2.2.
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Food and  Beverages
6.2.2                 and Data

        Foss/7 Fuel Combustion
        The methodology developed for this report to estimate fossil fuel combustion emissions from the food and
        beverages sector utilizes the U.S. Department of Energy's (DOE) Energy Information Administration's (EIA)
        Manufacturing Energy Consumption Survey (MEGS)3 estimates of fuel consumption for the sector. Fuel
        consumption estimates were multiplied by appropriate fuel-specific emission factors to convert the
        consumption into CC>2 emitted. The emission factors for the fossil fuels used in the food and beverages
        industry were taken from data contained in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-200 5.4
        CC>2 emissions from the "other" fuel type were taken directly from EIA's report, Special Topic: Energy-Related
        Carbon Dioxide Emissions in U.S. Manufacturing.

        Non-Combustion Activities
        The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 provides information on total emissions  from
        ozone depleting substances substitutes (Section 4.17 of the Inventory, Substitution  of Ozone Depleting
        Substances). The United States provides  more detailed information in its companion dataset, the Common
        Reporting Format (CRF) tables, which contain information on total emissions from refrigeration and air-
        conditioning end-use applications. Of these applications, emissions from cold storage and industrial process
        refrigeration (IPR) were relevant to the food processing sector. Information on the percent of total
        refrigeration and air-conditioning emissions that were the result of these two end-use applications was found in
        the report, Global Mitigation ofNon CO 2 Greenhouse Gases,5 which indicated that 1 and 5 percent of total
        refrigeration and air-conditioning HFC emissions result from cold storage and IPR, respectively. No
        information was  available on the amount of emissions from each of these end-use applications that was from
        use in the food production sector. Therefore, for this analysis it was estimated that most of the emissions
        (95%) from cold storage would be from  food production uses, and that IPR would be more diverse, such that
        half (50%) could be assumed to be associated with food and beverage production in applications such as
        bakeries, dairy products, meat processing, and ice manufacturing.6

        Non-combustion CHU emissions from onsite wastewater treatment were  estimated based on production data
        and methodology detailed in the Wastewater Treatment source category of the Inventory of U.S. Greenhouse Gas
        Emissions and Sinks:  1990-2005.1 Specifically, the industrial wastewater emission estimate in the Inventory includes
        emissions from pulp and paper production and meat, poultry, fruit, and vegetable processing facilities. The
        activity data to calculate emissions from meat, poultry, fruit, and vegetable processing were not available in the
        Inventory, however, the activity data for pulp and paper production were. Therefore, the CHU emissions for pulp
        and paper production were calculated using the activity data, constants, and equations provided; this number
        was then subtracted from the total industrial wastewater CH4 emissions number, to yield the CH4 emissions
        associated with wastewater treatment from meat, poultry, fruit, and vegetable processing facilities.

        Purchased Electricity
        Electricity emissions were estimated by multiplying national-level electricity purchases (in kilowatt-hours, or
        kWh) provided by MECS,8 by a national-level CO2 emission factor (in Ibs/kWh) provided by eGRID.9 Sector
        electricity purchases were multiplied by a loss factor to reflect losses incurred in the transmission and
        distribution of electricity.
        3 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        5 U.S. Environmental Protection Agency, Global Mitigation of A/on C02 Greenhouse Gases, 2006, http://www.epa.gov/nonco2/econ-inv/international.html.
        6 The other 50% of IPR use includes the chemical, pharmaceutical, petrochemical, manufacturing, and construction industries.
        7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        8 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey.
        9 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
        http://www.epa.gov/cleanenergy/egrid/index.htm.
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Food and Beverages
6.2.3    Key Assumptions and Completeness
        Emissions associated with N2O used in pressure-packaged foods and CO2 used in carbonated beverages were
        assumed to occur at the point of consumption and were consequently outside of the boundary of this sector.
        Those emissions were, therefore, not counted in the emission estimates presented here. CO2 emissions
        associated with fermentation were assumed to be biogenic in origin and, therefore, not applicable (as indicated
        in the 2006IPCC Guidelines for National Greenhouse Gas Inventories]. Electricity and fossil fuel combustion
        emission estimates included only CO2. Emissions of other GHGs (e.g., CHLtand N2O) that may result from
        combustion were not estimated.10 Emission factors for purchased electricity provided by eGRID are for 2004,
        which may include different fuel mixes for electricity generation than those of the 2002 inventory year.

6.3    Greenhouse Gas Emissions (1998,2002)

        GHG emissions for select years from the food and beverage sector are provided in Figure 6-3.n
        Data for HFC emissions from refrigeration were available for the years 1998 to 2005 from the CRF tables of
        the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. Data for CH4 emissions from
        wastewater treatment were available for years 2000 to 2005; the datum for 2000 was then used as a proxy from
        1998 to  1999 (since the wastewater emissions number remains essentially constant over the time series, no time
        projection was deemed necessary). These non-combustion process-related emissions have increased by
        approximately 38% between 1998 and 2005, from 5.3 to 7.3 MMTCO2E.

        Data for GHG emissions from fossil fuel combustion and purchased electricity were available only for two
        data points, 1998 and 2002, based on the frequency of MEGS reports. Fossil fuel combustion emissions
        increased by 9% over this time period, while electricity emissions increased by 4 percent.

        Overall, emissions from the food and beverage  sector increased 8% between 1998 and 2002. Over the same
        period, value added12 in the food and beverage sector increased 26%.
        Figure 6-3: Greenhouse Gas Emissions from the Food and Beverages Sector (MMTC02E)
                     1998
                                 1999
                                              2000
                                                          2001
                                                                      2002
                                                                                  2003
                                                                                              2004
                                                                                                           2005
                                1 Fossil Fuel Combustion
                                                         1 Purchased Bectrlclty
                                                                                 Non-Combustion
        10 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        11 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
        12 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
        http://www.census.gov/mcd/asm-as1.htmll. The  data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
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Food and  Beverages
6.4     Other Sources of Greenhouse Gas  Emission Estimates for this Sector

         No reports containing complete GHG emissions estimates for the food and beverages sector were identified.

6.5     Sector Emission  Reduction Commitments

         No sector commitments to reducing GHG emissions were identified.

6.6     Reporting Protocols

         When calculating emissions, one of the following protocols is typically used by companies in the food and
         beverages  sector:

         •   EPA's Climate Naders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WKJ
             protocol mentioned below;

         •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and

         •   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
             (WRI) Greenhouse  Gas Protocol.

         Table 6-2 presents  a sample of companies which have publicly reported their GHG emissions.

                      Table 6-2: Sampling of Publicly-Reported  GHG Emissions for Food and Beverages Companies

Company
Molson Coors
Brewing13
Anheuser-Busch14

General Mills15
Heinz16

Green Mountain
Coffee Roasters17
Kellogg Company18
Kraft Foods19

Protocol
WBCSD/WRI

WBCSD/WRI

WBCSD/WRI
EPA fuel emission
factors
Nl

WBCSD/WRI
WBCSD/WRI
Emissions
(MMTC02Ea)
0.96

3.03

1.02
0.81

9,823 short
tons
1.1
2.67
Year
Reported
2006

2006

2006
2006

2005

2006
2006
Geographic
Scope
U.S.

Annex Bb

Annex Bb
Annex Bb

Global

Global
Global

Goal
Nl

5% by 2010
(2005 baseline)
Nl
Nl

Zero net emissions
from 2005-2009
Nl
Nl
         Nl = Not Indicated
         a Unless otherwise noted
         b Countries included in Annex B of the Kyoto Protocol
         13 Molson Coors Brewing Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 12
         Nov 2007, http://www.cdproiect.net/responses/Molson Coors Brewing Company Corporate GHG Emissions Response CDP5 2007/public.htm.
         14 Anheuser-Busch Companies Incorporated, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions
         Questionnaire," 10 Nov 2007, http://www.cdproiect.net/responses/AnheuserBusch Companies  Inc Corporate GHG Emissions Response CDP5 2007/
         public.htm.
         15 General Mills Incorporated, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10 Nov
         2007, http://www.cdproiect.net/responses/General Mills Inc Corporate GHG Emissions Response CDP5 2007/public.htm.
         16 HJ Heinz Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 25 Oct 2007,
         http://www.cdproiect.net/responses/HJ Heinz Company Corporate GHG Emissions  Response  CDP5 2007/public.htm.
         17 Green Mountain Coffee Roasters, "Corporate Social Responsibility Report," July 2006,
         http://www.areenmountaincoffee.com/GMCRContent/HTMLFiles/gmcr csr full.pdf97.
         18 Kellogg Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10 Nov 2007,
         http://www.cdproiect.net/responses/Kelloaa Company Corporate GHG Emissions  Response CDP5 2007/public.htm.
         19 Kraft Foods, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10 Nov 2007,
         http://www.cdproiect.net/responses/Krafl Foods Corporate GHG Emissions Response  CDP5 2007/public.htm.
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        Forest  Products
                                                              Source
                                                              Fossil Fuel Combustion
                                                              Non-Combustion
                                                              Purchased Electricity
                                                              Total
                                                              Percent of U.S. Industrial Emissions1
                                                 2002
                                              Emissions
                                              (MMTC02E)
                                                   62
                                                    5
                                                   58
                                                  125
                                                   6%
        The forest products sector is defined as companies
        that process wood and wood fiber; manufacture
        pulp, paper and paperboard products from both
        virgin and recycled fiber; and produce engineered
        and traditional wood products.
        For the purposes of this analysis, the forest products
        sector includes facilities that make wood products
        by sawing and shaping logs, and establishments that
        purchase sawed lumber to make wood products
        (NAICS code 321: Wood Product Manufacturing); and facilities that process and create pulp, paper, and
        converted paper products (NAICS code 322: Paper Manufacturing).

        The wood products manufacturing subsector includes the manufacture of lumber, plywood, veneers, wood
        containers, wood flooring, wood trusses, mobile homes, and prefabricated wood buildings. Common processes
        include sawing, planning, shaping, laminating, and assembly. The paper manufacturing subsector includes
        manufacture of pulp, paper, and converted paper products (e.g., making paper bags from paper). The main
        process in pulping is separating usable cellulose fibers from other materials in wood or recycled paper.
        Papermaking involves matting fibers into a sheet. Converted paper products are made by cutting, shaping,
        coating, and laminating paper products. Photosensitive papers are excluded.

7.1     Sources of Greenhouse Gas Emissions

        The forest product sector encompasses a variety of processes, including sawing, wood product fabrication,
        pulping, and papermaking. Fossil fuel combustion provides power and heat for these operations, both through
        direct burning of fossil fuels and through the consumption of purchased electricity. Fossil fuels are burned
        directly for heated processes in lumber processing and pulp and papermaking. Electricity is used to operate
        equipment. To a greater extent than other sectors, much of the electricity and process heat used by this sector
        comes from onsite, largely biomass-based, efficient co-generation plants.2 To the extent that these burn
        biomass, the GHG emissions were not counted in our estimates, in accordance with the Intergovernmental
        Panel on Climate Change's (IPCC) 2006IPCC Guidelines for National Greenhouse Gas Inventories? Approximately
        52% of the energy used in the forest product sector was derived from biomass.4 To the extent that any fossil
        fuels are burned, they were included in totals cited in this chapter. GHG emissions also result from the
        treatment of wastewater onsite at facilities in this sector.

7.2     Summary of Emissions (2002)

        This section presents a summary of the emission estimates from the forest products  sector for the year 2002.
        The methodologies and data sources used to calculate these emission estimates,  as well as the assumptions and
        limitations surrounding the estimates, are also described.

7.2.1    Estimates of Greenhouse Gas Emissions (2002)
        Total emissions from the forest product sector were estimated to be 125 MMTCC^E in 2002 (as shown in
        Table 7-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions andSinks:1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 17 Oct 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 National Council for Air and Stream Improvement (NCASI), Monitoring Progress Toward the AF&PA Climate VISION Commitment, 2007, p. 2.
        3 According to IPCC Guidelines, C02 released from the burning of biogenic materials, such as wood, is not counted toward anthropogenic emissions of GHGs
        because that C02 was only recently sequestered from the atmosphere into the wood.
        4 U.S. Department of Energy, Energy Use, Loss and Opportunities Analysis: U.S. Manufacturing and Mining, Energy Efficiency and Renewable Energy Industrial
        Technologies Program, Dec 2004.
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Forest Products
                                Table 7-1: 2002 GHG Emissions from the Forest Product Sector (MMTC02E)
Source
Fossil Fuel Combustion3
Paper
Wood Products
Non-Combustion15
Purchased Electricity0
Paper
Wood Products
Total

62
58
4

58
44
14
120
•JlI^H ^I^Q^I
62
58
4
5 5
58
44
14
5 125
                         a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory
                         of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                         b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                         c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and
                         Generation Resource Integrated Database (eGRID).
                         Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the
                         analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions  from the forest products sector can be found in Section 7.2.2.

         The distribution of energy consumption in this sector by fuel type (including both on-site fossil fuel
         combustion and purchased electricity) is illustrated in Figure 7-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 7-2.
         Figure 7-1: 2002 Energy Consumption in the Forest
         Products Sector, by Fuel Type (TBtu)
Coke and Breeze
0.5%
LPG and NGL
<0.5%


Electricity
11%
                                            Natural Gas
                                               21%

                                              Distillate Fuel Oil
                                                    1%
                                         \ Residual Fuel Oil
                                    Coal  L
                                                4%
                                     9%
                                Figure 7-2: 2002 C02 Emissions from Energy
                                Consumption in the Forest Products Sector, by Fuel Type
                                (MMTC02E)
                                                                                      Coke and Breeze
                                                                                          0.5%
                                                                                                               Electricity11
                                                                                                                 64%
                                      Distillate Fuel Oil
                                           1%
                                  Total:
2,736 TBtu
Natural Gas
   25%
 Total:
120 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         'Composition of "other" fuel category varies among sectors. In the forest
         products sector, "other" fuels include primarily black liquor and other biomass.
         Note: TBtu stands for trillion British thermal units.
                                Source: Estimate based on methodology in Section 7.2.2.
                                a Note that biomass-related emissions are not included in the estimates for
                                "other" fuel types.
                                b Fuel mix at utilities was taken into consideration in this  calculation, per
                                methodology described in Section 7.2.2.
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Forest Products
        Note that the emission estimates presented in this report do not account for emissions or benefits (e.g., carbon
        sequestration) associated with the raw materials used by this industry or products produced by this industry.
        The analysis presented in this report addresses emissions related to the production processes and does not
        address lifecycle emissions or sequestration from the use or disposal of forest products. Consequently, the
        analysis does not evaluate the environmental benefits of the produced materials. For further discussion of
        sequestration, see Section 7.2.3.

7.2.2                 and

        Foss/7 Fuel Combustion
        The methodology developed for this report to estimate fossil fuel combustion emissions from the forest
        products sector utilizes the U.S. Department of Energy's (DOE) Energy Information Administration's (EIA)
        Manufacturing Energy Consumption Survey (MECS) 5 estimates of fuel consumption for the sector. Fuel
        consumption estimates were multiplied by appropriate fuel-specific emission factors to convert the
        consumption into CC>2 emitted. The emission factors for the fossil fuels used in the forest products industry
        were derived from data contained in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-200 5.6 CC>2
        emissions from the "other" fuel type were taken directly from EIA's report, Special Topic: Energy-Related Carbon
        Dioxide Emissions in U.S. Manufacturing.

        Non-Combustion Activities
        Non-combustion CH.4 emissions from onsite wastewater treatment were estimated based on production data
        for this sector and methodology detailed in the Wastewater Treatment source category of the Inventory of U.S.
        Greenhouse Gas Emissions and Sinks: 1990-2005.6 Specifically, the CHU emissions for pulp and paper production
        were calculated using the emission calculation equation, pulp and paper production data, wastewater generation
        rate, chemical oxygen demand, CH4 production potential, correction factor, and wastewater treatment rate, all
        of which are provided in the Inventory of U.S. Greenhouse Gas Emissions and Sinks:  1990-2005.

        Purchased Electricity
        Electricity emissions were estimated by mapping national electricity purchases (in kilowatt-hours, or kWh)
        provided by MECS to North American Electricity Reliability Corporation  (NERC) regions,7 then applying
        NERC regional utility CC>2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
        adjusted by a loss factor to reflect losses incurred in  the transmission and distribution of electricity.

        Since electricity purchase data were not available  at the NERC regional level, distribution of the sector's value
        added was used to distribute the sector's national electricity purchases to the state-level, then state data were
        rolled up to the NERC regions. Where a state lay in  two or more NERC regions, electricity purchases were
        distributed to the appropriate NERC region using sales data for the industrial customer class from EIA Report
        861. This approach assumes that the electricity-intensity of production activities are correlated with the value
        added. Methods for estimating CC>2 emissions from  electricity are described in more detail in Appendix A.3.

7.2.3    Key              and
        Electricity and fossil fuel combustion emission estimates include only CC>2. Emissions of other GHGs such as
        CHU and N2O that may result from combustion were not estimated due to data  and methodological
        constraints.8 Emission factors for purchased electricity provided by eGRID are  for 2004, which may include
        different fuel mixes for electricity generation than those of the 2002 inventory year. In addition, CC>2 emissions
        5 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        6 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        1 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        8 These non-C02 emissions account for less than 2% of GHG emissions from fossil fuel combustion.
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Forest Products
        from make-up carbonates during pulp and paper manufacturing and CO2 emissions from wood byproduct
        (biomass) combustion were not included. These sources were excluded because the associated emissions were
        biogenic in origin; in accordance with 2006IPCC Guidelines for National Greenhouse Gas Inventories, emissions of
        CO2 from biogenic sources were not counted as contributing to emissions.
        Emission estimates presented here do not include emissions from logging or transportation of logs, nor do
        they include carbon sequestration by forests, as these processes were considered outside the boundary of the
        sector as it is defined in this report.

        Annual change (net flux)  in carbon stocks within forests, in harvested wood products, and in landfilled wood
        and paper have been calculated in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 and
        Monitoring Progress Toward  the AF&PA Climate VISION Commitment (published by the National Council for Air
        and Stream Improvement [NCASI]9), but there remain significant obstacles to allocating net flux estimates to
        the forest product sector. In short, three issues remain unclear:

        1.   The origin of the carbon. Whether carbon from forests grown on land not owned by the  forest product
            sector should be attributed to the forest product sector was unclear.
        2.   The fate of the carbon. Similarly, it was not clear whether the accumulation of carbon in the harvested
            wood products pool  (in the form of ever-increasing amounts of furniture or structural lumber) or the
            accumulation of un-degraded carbon in landfills (from disposal of wood and paper) should be attributed to
            the forest product sector. From a life cycle perspective, the farther from the industrial activity (harvest/
            milling), the more tenuous the case for attributing carbon accumulation  to the  forest product sector.

        3.   The location of the carbon. There were enormous cross-boundary flows of inputs, products, and
            recyclables. Estimates developed by the U.S. Department of Agriculture, Forest Service (USDA-FS)
            account for carbon in exported wood and paper as  if it remained in the United States, and carbon in
            imported wood was not counted.

        For these reasons, carbon sequestration from the forest products sector was not included in emission totals.
        However, sequestration in harvested wood products was estimated by NCASI at 28.2 MMTCO2E in 2002.10
        For comparison purposes, the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 reported an
        estimate of 34.1 MMTCC^E sequestered in harvested wood products in use in 2002.

7.3     Greenhouse Gas Emissions (1998,2002)

        GHG emissions for select years from the forest product sector are provided in Figure 7-3.

        Data for CH4 emissions from wastewater treatment were available for years 2000 to 2005; the datum for 2000
        was then used as  a proxy  from 1998 to 1999  (since the wastewater emission estimate remains essentially
        constant over the time  series, no time projection was deemed necessary).  These non-combustion process-
        related emissions have fluctuated over the time series, but overall have decreased by approximately 8% between
        in 2000 and 2005.

        Data for GHG emissions from fossil fuel combustion and purchased electricity were available only for two
        data points, 1998 and 2002, based on the frequency of MECS reports. Fossil fuel combustion emissions
        decreased 15% over this time period, while electricity emissions decreased by 6%.
        Overall, emissions from the forest products sector decreased 11 % between  1998 and 2002. Over the same
        period, value added11 in the forest products sector decreased 3%.
        9 NCASI, Monitoring Progress Toward the AF&PA Climate VISION Commitment, p. 5.
        10 NCASI, Monitoring Progress Toward the AF&PA Climate VISION Commitment, p. 5.
        11 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
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Forest Products
        Figure 7-3: Greenhouse Gas Emissions from the Forest Products Sector (MMTC02E)
                   1998
                              1999         2000         2001          2002

                               ^^B Fossil Fuel Combustion ^^B Purchased Bectrlclty
                         2003          2004

                       Non-Combustion
                                                                                                     2005
7.4     Other Sources of Greenhouse Gas Emission Estimates for this Sector

        An alternate source of emission estimates for fossil fuel combustion and purchased electricity was the report
        Monitoring Progress Toward the AF&PA Climate VISION Commitment}*2- produced by NCASI based on a survey of
        American Forest and Paper Association (AF&PA) members. AF&PA members account for over 75% of the
        paper, wood, and forest products produced in the United States.

        •   Fossil fuel combustion estimates from this report were based on fuel use data collected by the AF&PA
            from their members. NCASI used emission factors from the World Resources Institute/World Business
            Council for Sustainable Development (WRI/WBCSD) Greenhouse Gas Pmtoco/when calculating estimates
            for this report.

        •   Emission estimates from purchased electricity consumption were based on energy use data collected by the
            AF&PA from their member companies. NCASI used a national electricity emission factor to calculate
            emissions based on purchased electricity consumption data collected in the biannual AF&PA  fuel and
            energy survey. The purchased electricity data collected in the survey were adjusted upward by  NCASI to
            account for the fact that not all AF&PA members reported purchased electricity consumption. The
            emission factor represents a three-year weighted average of U.S. utilities and was taken from DOE's
            Updated State-Level Greenhouse Gas Emission Coefficients for Electricity Generation 1998-2000 report.13
        The two methods (MECS and NCASI) result in similar fossil fuel emissions, as shown in Table 7-1 and Table
        7-2, respectively; however, electricity emissions estimated by NCASI  are lower than those estimated with the
        MECS data. One explanation may be that AF&PA accounts for only about 75% of the industry, and that
        survey data were incomplete and had to be extrapolated based on completed surveys.
        http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
        12 NCASI, Monitoring Progress Toward the AF&PA Climate VISION Commitment, p. 2.
        13 U.S. Department of Energy, Updated State-Level Greenhouse Gas Emission Coefficients for Electricity Generation 1998-2000, Energy Information
        Administration, 2002, http://tonto.eia.doe.gov/FTPROOT/environment/e-supdoc-u.pdf.
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                          Table 7-2: Emissions from the National Council for Air & Stream Improvement's
                         Monitoring Progress Toward the AF&PA Climate VISION Commitment (MMTC02E)
Source
Fossil Fuel Combustion3
Pulp and Paper
Wood Products
Purchased Electricity3
Pulp and Paper
Wood Products
Total
C02
54
53
1
28
22
5
81
Total
54
53
1
28
22
5
81
                     a Fossil fuel and purchased electricity emissions taken directly from NCASI, p. 5.
                     Note: totals may not sum due to independent rounding.


7.5     Sector Emission Reduction  Commitments

        AF&PA has an initiative to reduce GHG intensity by 12% by 2012 relative to a 2000 baseline.14 The industry is
        using a combination of WBCSD/WRI and NCASI protocols. To calculate emissions, industries use two tools,
        one for pulp and paper mills, and the other for wood product facilities. There is also a sequestration tool
        provided by NCASI for companies  requesting to inventory their stored carbon quantities.

7.6     Reporting  Protocols

        When calculating emissions, one of the following protocols is typically used by companies in the forest
        products sector:

        •   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below, has a special protocol for pulp and paper mills known as the Draft Assessment of
            Calculation Tools for Estimating Greenhouse Gas Emissions from Pulp and Paper Mills: v 1.1 for Use in Climate Leaders
            Reporting.15 The mills are to use international factors for stationary combustion and purchased electricity.
            Mills are to use emissions factors for Kraft Mill Lime Kilns and Calciners, detailed CH4 and N2O factors
            for biomass combustion and methodologies to calculate emissions from anaerobic treatment of sludge and
            use of carbonate-based make-up chemicals;

        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program',

        •   The previously-mentioned WBCSD and WRI  Greenhouse  Gas Protocoled NCASI protocol; and

        •   The California Climate Action Registry, which has added a protocol for the forest products industry in
            order to account for forest carbon stocks as well as biological emissions.16
        Table 7-3 presents a sample of companies that have publicly reported their GHG emissions.
        14 See http://www.climatevision.gov/sectors/forest/index.html.
        15See http://www.epa.gov/stateplv/docs/CLReview of PulpnPaper Sector Protocol.pdf.
        16 See http://www.climatereaistrv.org/PROTOCOLS/FP/.
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Forest Products
                           Table 7-3: Sampling of Publicly-Reported GHG Emissions for Forest Products Companies

Company
Kimberly Clark17
International Paper18

Mead Westvaco19

Protocol
WBCSD/WRI
WBCSD/WRI

WBCSD/WRI
Emissions
(MMTC02E)
3.8
11.7

3.4
Year
Reported
2006
2006

2006
Geographic
Scope
U.S.
U.S.

Annex Ba

Goal
Nl
15% by 2010
(2000 baseline)
6% by 2010
                                                                                                                        (average of 1998-
                                                                                                                        2000 baseline)
Boise Cascade

StoraEnso21
Weyerhaeuser22

Nl 3.1

Nl 12.0
WBCSD/WRI 10.7

2006

2006
2006

U.S. and
Canada
Global
Global

10% by 201 4
(2004 baseline)
Nl
40% by 2020
(2000 baseline)
          Nl = Not Indicated
          a Countries included in Annex B of the Kyoto Protocol
          17 Kimberly-Clark Corporation, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 23 Oct
          2007, http://www.cdproiect.net/responses/KimberlvClark Corporation Corporate GHG Emissions Response CDP5 2007/public.htm.
          18 International Paper Company, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 23 Oct
          2007, http://www.cdproiect.net/responses/lnternational Paper  Company Corporate GHG  Emissions Response CDP5 2007/public.htm.
          19 MeadWestVaco, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 23 Oct 2007,
          http://www.cdproiect.net/responses/MeadWestVaco Corporate GHG Emissions Response CDP5 2007/public.htm.
          20 U.S. Environmental Protection Agency, "Partner Profile: Boise Cascade," Climate Leaders, 12 Nov 2007,
          http://www.epa.gov/stateplv/partners/partners/boisecascade.html.
          21 Stora Enso, "Annual Report 2006 -Sustainability Booklet," March 2007, http://www.storaenso.eom/CDAvgn/main/0,, 1 EN-1861-1059-.OO.html 23.
          22 Weyerhaeuser Company, "2006 Sustainability Performance Report," Global Reporting Initiative, June 2007,
          http:M/vww.corporatereaister.com/search/report.cgi?num=18895-lxSMdtpMF02 12.
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        Iron and  Steel
        Iron and steel are durable, strong metals used for many purposes including as building and bridge skeletons and
        supports, vehicle bodies, and as parts of appliances, tools, and heavy equipment. The iron and steel sector
        consists of establishments that produce pig iron from iron ore, produce metallurgical coke from coking coal,
        and produce steel through the use of one of two primary technologies— from iron in basic oxygen furnaces
        (BOFs) and from recycled steel in electric arc furnaces (EAFs). In 2002, 51% of raw steel production stemmed
        from EAFs with the remainder produced by  BOFs at integrated steel mills.2
                                                                 Source
                                                                 Fossil Fuel Combustion
                                                                 Non-Combustion
                                                                 Purchased Electricity
                                                                 Total
                                                                 Percent of U.S. Industrial Emissions1
                                                   2002
                                                 Emissions
                                                (MMTC02E)
                                                      22
                                                      56
                                                      37
                                                     115
                                                     6%
         In an integrated steel mill, a blast furnace produces
         molten iron from iron ore, coal, coke, and fluxing
         agents (e.g., limestone, dolomite). A EOF is then
         used to convert the molten iron, along with scrap
         steel and alloying metals, into steel and steel alloys.
         EAFs use scrap steel and other iron-bearing
         materials to produce carbon, alloy, and specialty
         steels. While both processes are energy intensive,
         their emission profiles differ due to differences in
         energy consumption. Integrated steel mills have
         more on-site fossil fuel consumption and use more raw materials than EAF mills, which primarily consume
         electricity. For the purposes of this report, emissions from the production and use of metallurgical coke at
         integrated steel mills  are classified as non-combustion (process) emissions, rather than as emissions from
         energy use.

         Though the energy intensity of steel production in the U.S. has been steadily declining, the production of iron
         and steel remains an energy intensive process.

8.1      Sources of Greenhouse  Gas Emissions

         GHG emissions in the iron and steel sector result from on-site fossil fuel combustion, generation of purchased
         electricity, and non-combustion activities (i.e., industrial processes).  On-site use of fossil fuels for energy
         purposes largely occurs at integrated steel mills  to supply energy to the blast furnace, process heaters, and
         generate electricity through cogeneration,3 while purchased electricity consumption largely occurs at EAFs to
         melt the scrap steel and other iron-bearing materials.4
         Emissions associated with the industrial process of producing iron and steel stem from a variety of sources,
         which can be broadly categorized into the production of metallurgical coke from coking coal,5 pig iron
         production, and steel making (GHGs emitted by each process are provided in parentheses):

         •    Metallurgical Coke Production (CC>2, CH4): To produce metallurgical coke, coking coal is heated in a low-
             oxygen, high temperature environment within a coke oven. This process can occur on-site at integrated
             steel mills or off-site at merchant coke plants.6 At an integrated  steel mill, the metallurgical coke produced
             is used in the blast furnace  charge during iron production. Some carbon contained in the coking coal is
             released during this process as CO2 and CH4 emissions. Coke-oven gas, which is produced as a by-product
             of metallurgical coke production, is often used for energy purposes within the integrated steel mill.
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions andSinks:1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 American Iron and Steel Institute (AISI), 2005 Annual Statistical Report, 2006, Washington, D.C., pp. 9.
        3 AISI, "How a Blast Furnace Works."
        4 AISI, "Electric Arc Furnace Steelmaking."
        5 The non-combustion emission estimate is based on the industrial process emission estimate provided by the Inventory of U.S. Greenhouse Gas Emissions and
        Sinks: 1990-2005, which accounts for both the carbon emissions from the use of metallurgical coke as a reducing in the blast furnace and the carbon stored in raw
        steel produced. For the purposes of this report, emissions from the production and use of metallurgical coke are classified as non-combustion emissions.
        6 According to the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005—upon which non-combustion GHG emissions for this report are based—
        GHG emissions from all coking coal used to produce metallurgical coke are attributed to the iron and steel sector. However, it should be noted that this includes
        emissions from coke ovens that are not located on iron and steel facilities, the coke from which is predominantly used by steel mills.
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        •   Sintering (CC>2): At integrated steel mills, CC>2 emissions also result from sintering, a process used to
            convert iron-bearing materials into a higher-grade ore (or sinter) for use as a raw material in the blast
            furnace.

        •   Pig Iron Production  (CO2, CHU): At integrated steel mills, metallurgical coke is used as a reducing agent in
            the blast furnace to chemically reduce iron ore to pig iron, which is used as a raw material in the
            production of steel. The carbon contained in the metallurgical coke also provides heat to the blast furnace,
            and produces CC>2 through both the heating and reduction process.  For the purposes of this report,
            emissions from the production and use of metallurgical coke are classified as non-combustion (process)
            emissions, rather than as emissions from energy use.

        •   Steelmaking (CO2): At an integrated steel mill, molten iron produced by a blast furnace enters a BOF
            where the iron is combined with high-purity oxygen to oxidize the carbon and reduce the carbon content
            of the metal—producing steel. Carbon contained in both the scrap steel and molten iron is released as
            CC>2. In EAFs,  CC>2 emissions occur from the use of carbon anodes that produce the electric arc used in
            the melting of scrap steel.7 EAFs also use injected carbon in the form of coal and other raw materials. Both
            integrated mills and EAFs use natural gas for reheat furnaces and other processes. CCh emissions also
            result from the  use of limestone and other carbonate raw materials as fluxing agents.

8.2     Summary of Emissions  (2002)

        This section presents a summary of emission estimates from the iron and steel sector. It includes a discussion
        of methodologies and data sources used to estimate emissions, as well as the assumptions and limitations
        surrounding the estimates.

8.2.1    Estimates of Greenhouse Gas Emissions (2002)
        As shown in Table 8-1, total 2002 GHG emissions from the iron and steel sector were 115 MMTCG^E. More
        than half of the sector's GHG emissions were from non-combustion (process) emissions, rather than from
        energy use.

                             Table 8-1: 2002 GHG Emissions from the Iron and Steel Sector (MMTC02E)
Source
Fossil Fuel Combustion3
Non-Combustion b
Purchased Electricity0
Total
C02
22
55
37
114
^^Ql^^J

1

1
^^^I^Q^I
22
56
37
115
                      a Emissions calculated based on AISI's 2005 Annual Statistical Report and EPA's Inventory of U.S. Greenhouse Gas
                      Emissions and Sinks: 1990-2005.
                      b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, pp. 4-6.
                      c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and
                      Generation Resource Integrated Database (eGRID).
                      Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the
                      analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.


        The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
        on the methodology used to estimate emissions from the iron and steel sector can be found in Section 8.2.2.

        The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
        combustion and purchased electricity), is illustrated in Figure 8-1. For comparison, CC>2 emissions associated
        with fuel consumption are shown in Figure 8-2.
        7U.S .Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks, pp. 4-6.
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Iron and  Steel
         Figure 8-1: 2002 Energy Consumption in the Iron and Steel
         Sector, by Fuel Type (TBtu)a

                                    Electricity
         Distillate Fuel Oil
                                                Natural Gas
                                                  53%
                                      Total:
             Figure 8-2: 2002 C02 Emissions from Energy
             Consumption in the Iron and Steel Sector, by Fuel Type
             (MMTC02E)a
                                                                                      Coal
                                                                        Distillate Fuel Oil
                                                     Electricityb
                                                       63%
                                          Total:
59 MMTC02E
         Source: Fossil Fuel Combustion, AISI, 2005 Annual Statistical Report',
         Electricity, DOE, 2002 Manufacturing Energy Consumption Survey.
         'Excludes metallurgical coke, blast furnace, and coke oven gas used for
         energy purposes. See Section 8.2.3 for further details.
         Note: TBtu stands for trillion British thermal units.
             Source: Estimate based on methodology in Section 8.2.2.
             a Excludes metallurgical coke, blast furnace, and coke oven gas used for
             energy purposes. See Section 8.2.3 for further details.
             b Fuel mix at utilities was taken into consideration in this calculation, per
             methodology described in Section 8.2.2.
8.2.2    Methodology and Data Sources

         Fossil Fuel Combustion
         CC>2 emissions due to fossil fuel consumption for iron and steel manufacturing were based on on-site fuel
         consumption data from the American Iron and Steel Institute's (AISI) 2005Annual Statistical'Report* These fuel
         consumption estimates were multiplied by the appropriate, fuel-specific emission factors to convert the
         consumption into CC>2 emitted. The emission factors were taken from the Inventory of U.S. Greenhouse Gas
         Emissions and Sinks: 1990-2005?

         Non-Combustion Activities
         Non-combustion CO2 and CHLj emission estimates for iron and steel manufacturing were obtained directly
         from the iron and steel production source category of the Inventory of U.S. Greenhouse Gas Emissions and Sinks:
         1990-2005. CO2 emission estimates from the consumption effluxes (e.g., limestone, dolomite), which are not
         included in the iron and steel chapter of the Inventory of U.S. Greenhouse Gas Emissions Inventory and Sinks: 1990-
         2005, were estimated based on consumption data from AISI's 2005 Annual Statistical Report and emission
         factors presented by the Intergovernmental  Panel on Climate Change's (IPCC)  2006IPCC Guidelines for National
         Greenhouse  Gas Inventories.^
         8 AISI, 2005 Annual Statistical Report, Table 37.
         9 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         10 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006gI/index.htm. Table 4.3.
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Iron and Steel
        Purchased Electricity
        Electricity emissions were estimated by multiplying national-level electricity purchases (in kilowatt-hours, or kWh)
        provided by MEGS11 by CC>2 emission factors (in Ibs/kWh) provided by eGRID12 at the North American
        Electricity Reliability Corporation (NERQ region level.13 NERC regional electricity purchases were developed
        based on estimates of facility-level electricity consumption. Facility level electricity purchases were estimated for
        each facility based on the facility's furnace type (EAF or EOF) and the furnace's electricity intensity per ton of
        raw steel produced. Purchase estimates were scaled to match national level purchase estimates. Electricity
        purchases were adjusted by a loss factor to reflect losses incurred in the transmission and distribution of
        electricity. Methods for estimating CC>2 emissions from electricity are detailed in Appendix A.3.

        Key              and
        The non-combustion emission estimate, taken directly from the industrial process  emission estimate presented
        by the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, includes emissions associated with
        producing metallurgical coke from coking coal and consuming metallurgical coke during the production of pig
        iron. Because metallurgical coke is used both as a reducing agent and to produce heat, the resultant emissions
        are both process and energy based. Both emission types (process and energy) are included in the non-
        combustion emission estimate because, in accordance with the 2006IPCC Guidelines for National Greenhouse Gas
        Inventories,14 the Inventory of U.S. Greenhouse Gas Emissions and Sinks does not make this distinction. This estimate
        also includes emissions associated with metallurgical coke production in coke ovens that are not located in iron
        and steel mills. Some consumption of the metallurgical coke occurs during metal casting processes; however,
        data are unavailable to disaggregate emissions associated with this consumption from those presented for iron
        and steel.

        Blast furnace gas and coke  oven gas consumption are not included in the on-site fossil fuel combustion
        emission estimate, because the carbon contained in  these gases stems from carbon contained in coking coal and
        metallurgical coke that, based on the methodologies described in the Inventory of U.S. Greenhouse Gas Emissions
        and Sinks: 1990-2005, has already been accounted for in the non-combustion emission estimates.
        Electricity and fossil fuel combustion emission estimates include only CC>2. Energy consumption data are taken
        from AISI's Annual Statistical Report vftih the exception of purchased electricity data, which is taken from
        MEGS. Purchased electricity data are taken from MEGS, because AISI  data likely underestimates electricity
        consumed by EAFs during the 2002 inventory year due to limitations in data collection. Emission factors for
        purchased electricity provided by eGRID are for 2004, which may include different fuel mixes for electricity
        generation than those of the 2002 inventory year. Emissions  of other GHGs that may result from combustion,
        such as CH4and N2O, were not estimated.15

8.3     Greenhouse Gas Emissions (1998,2002)

        GHG  emissions for select years from the iron and steel sector are provided in Figure  8-3.16
        Data for GHG emissions from non-combustion and on-site  fossil fuel  combustion in the iron and steel sector
        are available from 1998 through 2005, while purchased electricity estimates are available only for 1998 and 2002
        using the data sources and  methodologies described above. From 1998 to 2005, emissions from fossil fuel
        11 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        12 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
        http://www.epa.aov/cleanenerav/egrid/index.htm.
        13 The National Reliability Electricity Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric power
        grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        14 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories.
        15 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        16 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
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Iron and Steel
        combustion decreased 20%, and non-combustion emissions decreased by 32%. From 1998 to 2002, emissions
        from purchased electricity increased by 1%.

        Overall, from 1998 to 2002, emissions decreased by approximately 12%, from 131 to 115 MMTCO2E. Raw
        steel production, from both integrated steel mills and EAFs, increased by 4% over the same time period.17
        Figure 8-3: Greenhouse Gas Emissions for the Iron and Steel Sector
                   1998
                              1999         2000

                              • Fossil Fuel Combustion
  2001         2002

 ZZI Purchased Electricity
 2003         2004

- Non-Combustion
                                                                                                   2005
8.4     Other Sources of Greenhouse Gas Emission Estimates for this Sector

        No reports containing complete GHG emissions estimates for the iron and steel sector were identified.

8.5     Sector Emission Reduction Commitments

        AISI has committed to a goal of achieving by 2012 a 10% increase in sector-wide average energy efficiency
        using a 1998 baseline of 18.1 million Btu (MMBtu) per ton of steel produced.18

8.6     Reporting Protocols

        When calculating emissions, one of the following protocols is typically used by companies in the iron and steel
        sector:

        •  EPA's Climate Naders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
           protocol mentioned below, provides sector specific guidance, Direct Emissions from Iron & Steel Production, for
           the iron and steel industry through support for calculating coke, coke oven gas, blast furnace gas, EAF, and
           carbon-bearing product emissions;19

        •  DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program;

        *  The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
            (WRI) Greenhouse Gas Protocol; and
        17 AISI, 2005 Annual Statistical Report, Table 23.
        18 See http://www.climatevision.gov/sectors/steel/index.html.
        19 See http://www.epa.gov/stateplv/docs/ironsteel.pdf.
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Iron and Steel
        The International Iron and Steel Institute (IISI), which has established an emissions calculation protocol and is
        establishing a common system of CO2 emission accounting and reporting to collect data on a site-wide, rather
        than company-wide, basis. The system will include both direct and indirect emissions and will have a standard
        set of boundaries that will be common among all sites.20
        Table 8-2 presents a sample of companies that have publicly reported their GHG emissions.

                       Table 8-2: Sampling of Publicly-Reported GHG Emissions for Iron and Steel Companies
        20 International Iron and Steel Institute, Fact Sheets on Climate Change, 2007.
        21 Gerdau Ameristeel, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10 Nov 2007.
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        Lime is a manufactured product with major applications in steel production, flue gas desulphurization systems
        at coal-fired power plants, construction, and water purification.
                                                              Source
                                                              Fossil Fuel Combustion
                                                              Non-Combustion
                                                              Purchased Electricity
                                                              Total
                                                              Percent of U.S. Industrial Emissions1
                                                 2002
                                               Emissions
                                              (MMTC02E)
                                                     9
                                                    12
                                                     1
                                                    23
                                                    1%
        In 2006, lime was used for the following purposes:
        metallurgical uses (36%), environmental uses (29%),
        chemical and industrial uses (21%), construction
        uses (13%), and to make dolomite refractories (1%).2
        In terms of manufacturing distribution throughout
        the U.S., 35 states (and Puerto Rico) produce lime.2

        In U.S. operations, the term "lime" in lime
        manufacturing (NAICS code 327410: Lime
        Manufacturing), refers to several chemical
        compounds. These compounds include high-calcium
        quicklime (calcium oxide, CaO), hydrated lime (calcium hydroxide, Ca(OH)2), dolomitic quicklime (CaO'MgO),
        and dolomitic hydrate ([CA(OH)2-MgO] or [Ca(OH)2-Mg(OH)2]).

9.1     Sources of Greenhouse Gas Emissions

        GHG emissions in the lime sector result from non-combustion activities (i.e., industrial processes), on-site
        fossil fuel combustion, and generation of purchased electricity.
        As  described in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005} lime manufacture results in
        non-combustion CO2 emissions. There are three main processes in lime production: stone preparation,
        calcination, and hydration. CO2 is emitted during the calcination stage, in which limestone — mostly calcium
        carbonate (CaCOs) — is roasted in a kiln at high temperatures to produce CaO and CO2.
        The manufacturing of lime requires energy to operate manufacturing equipment and maintain high kiln
        temperatures. This energy use results in direct emissions of CO2 from fossil fuel combustion and indirect CO2
        emissions from purchased electricity.

9.2     Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the lime sector as estimated for the year
        2002. The methodologies and data sources used to calculate these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

9.2.1    Estimates of Greenhouse Gas Emissions (2002)
        The total GHG emissions from the lime sector are estimated to be 23 MMTCO2E in 2002 (as seen in Table 9-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 U.S. Geological Survey, Minerals Yearbook: Lime Annual Report 2005, 2006, http://minerals.usas.gov/minerals/pubs/commoditv/lime/lime mvb05.pdf.
        3 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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Lime
                                    Table 9-1: 2002 GHG Emissions from the Lime Sector (MMTC02E)

Fossil Fuel Combustion3
Non-Cornbustionb
Purchased Electricity0
Total
9
12
1
23
9
12
1
23
                               a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's
                               Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                               b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                               c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's
                               Emissions and Generation Resource Integrated Database (eGRID).


         The overall methodology for estimating the GHG emissions  for this report was described in Section 1.2; more detail
         on the methodology used to estimate emissions from the lime sector can be found in Section 9.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated  in Figure 9-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 9-2.
         Figure 9-1: 2002 Energy Consumption in the Lime Sector,
         by Fuel Type (TBtu)
                          Distillate Fuel Oil
                Natural Gas
              Electricity
                4%
                                     Residual Fuel Oil
             Figure 9-2: 2002 C02 Emissions from Energy
             Consumption in the Lime Sector, by Fuel Type (MMTC02E)

                               Distillate Fuel Oil
                     Natural Gas       1%     Residual Fuel Oil
                        Ar\f
                                                1%
                    Electricity11
                                   Total:
                                     Total:
10 MMTC02E
         Source: DOE', 2002 Manufacturing Energy Consumption Survey.
         a Composition of "other" fuel category varies among sectors and is not defined
         in source.
         Note: TBtu stands for trillion British thermal units.
             Source: Estimate based on methodology in Section 9.2.2.
             a Fuel mix at utilities was taken into consideration in this calculation, per
             methodology described in Section 9.2.2.
             b Composition of "other" fuel category varies among sectors.
9.2.2    Methodology and Data Sources

         Fossil Fuel Combustion

         Fossil fuel combustion emissions from the lime sector were derived from the U.S. Department of Energy's
         (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption Survey (MEGS)4 estimates
         4 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
         http://www.eia.doe.gov/emeu/mecs/mecs2002.
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Lime	

         of fuel consumption for this sector. Those fuel consumption estimates were then multiplied by the appropriate,
         fuel-specific emission factors to convert the consumption into CO2 emitted. The emission factors for the fossil
         fuels used in the lime manufacturing industry were taken from data contained in the Inventory of U.S. Greenhouse
         Gas Emissions and Sinks: 1990-2005.

         Non-Combustion Activities
         Non-combustion emissions of CO2 from lime manufacturing were those reported for the Lime Manufacturing
         source category within the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005? These estimates
         include the  lime manufacturing emission sources identified by the Intergovernmental Panel on Climate
         Change's (IPCC) 2006IPCC Guidelines for National Greenhouse Gas Inventories.6

         Purchased Electricity
         Electricity emissions were estimated by mapping national electricity purchases  (in kilowatt-hours, or kWh)
         provided by MECS to North American Electricity Reliability Corporation (NERC) regions,7 then applying
         NERC regional utility CC>2 emission factor (in Ibs/kWh) provided by eGRID.  Sector electricity purchases were
         adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.

         Since electricity purchase data were not available at the NERC regional level, distribution of the sector's value
         added was used to distribute the sector's national electricity purchases to the state-level, then state data were
         rolled up to the NERC regions. Where  a state lay in two or more NERC regions, electricity purchases were
         distributed  to the appropriate NERC region using sales data for the industrial customer class from EIA Report
         861. This approach assumes that the electricity-intensity of production activities are correlated with the value
         added. Methods for estimating CC>2 emissions from electricity are described in more detail in Appendix A.3.

9.2,3    Key               and
         Non-combustion emission estimates were limited to sources identified by the 2006 IPCC Guidelines for National
         Greenhouse Gas Inventories and provided in the Inventory of U.S.  Greenhouse Gas Emissions and Sinks: 1990-2005.
         Electricity and fossil fuel combustion emission estimates include only CC^.  Emissions of other GHGs (e.g.,
         CH4and N2O) that may result from combustion were not estimated.8 Emission factors for purchased electricity
         provided by eGRID are for 2004, which may include different fuel mixes for electricity generation than those
         of the 2002 inventory year.

9.3     Greenhouse Gas Emissions (2002)

         GHG emissions for select years from the lime sector are shown in Figure 9-3.9

         Annual estimates of non-combustion GHG emissions from the sector were available from the Inventory of U.S.
         Greenhouse Gas Emissions and Sinks:  1990-2005, which show that such emissions  have decreased by 2% between
         1998 and 2005, from 14.0 to 13.7 MMTCC>2E. Over the same period, lime production remained relatively
         unchanged  (decreasing 0.5%)10, while value added11 in lime manufacturing decreased 4%.
         5 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         6 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
         naaip.iaes.or.ip/public/2006g I/index.htm.
         7 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
         power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
         8 Non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
         9 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
         level of significance; therefore, the reader may not be able to reproduce the calculation.
         10 U.S. Geological Survey, Minerals Yearbook: Lime Annual Report 2005.
         11 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
         production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
         and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
         http://www.census.aov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
         inflation using a gross domestic product price deflator.
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Lime
        However, data for GHG emissions from fossil fuel combustion and purchased electricity in 1998 were not
        available, since the 1998 MEGS report does not separately report energy used for lime manufacturing.
Figure 9-3: Greenhouse Gas Emissions from the Lime Sector (MMTC02E)
16 -i
14-
O 10 .
m 8 •
^ 6 .
4 .
2 .
0 .









1998 1999 2000 2001 2002 2003 2004 2005
^^m Fossil Fuel Combustion ^^B Purchased Bectrlclty — • — Non-Combustion

9.4     Other Sources of Greenhouse Gas Emission Estimates for this Sector

        The National Lime Association (NLA), under the Department of Energy's Climate VISION program, prepares
        GHG emission estimates using a protocol developed by the NLA and approved by the Department of Energy,
        and survey data provided by NLA members.12 The NLA's GHG emission estimate includes CG>2 emissions
        that result from fossil fuel combustion, non-combustion activities, and purchased electricity. For the year 2002,
        NLA estimated total GHG emissions to be 26 MMTCO2E (Table 9-2), an estimate that is approximately 3
        MMTCChE higher than the estimate presented in Table 9-1. The emission estimate provided by NLA is higher
        for both fossil fuel combustion and non-combustion emissions.  The NLA suggests that the higher fossil fuel
        combustion estimate occurs because survey respondents use more coal than natural gas relative to the estimate
        presented here, and that the higher non-combustion estimate occurs because the NLA protocol includes
        emissions from carbonaceous byproducts.13

                     Table 9-2: 2002 GHG Emission Estimates from the National Lime Association (MMTC02E)
Source C02 Total
Fossil Fuel Combustion
Non-Combustion
Purchased Electricity
Total
11
14
1
26
11
14
1
26
Source: National Lime Association 2007.
9.5     Sector Emission Reduction Commitments
        The National Lime Association (NLA) has committed that NLA members will, on an aggregate basis, reduce
        GHG emissions from fuel combustion per ton of production by 8% between 2002 and 2012.14
        12 National Lime Association 2005.
        13 National Lime Association 2007.
        14 See http://www.climatevision.gov/sectors/lime/index.html.
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Lime	

9.6     Reporting Protocols

        When calculating emissions, one of the following protocols may be used by companies in the lime sector:

        "   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below;
        "   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program',
        "   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
            (WRI) Greenhouse Gas Protocol, and
        "   The specific protocol developed by the NLA for the lime industry, which includes guidance for estimating
            CC>2 emissions associated with quicklime, calcined byproducts/wastes, and kiln, quarry, mine and other
            miscellaneous fuels.

        No public reports of GHG emissions from companies in the lime sector were identified.
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10.    Metal Casting
        Metal casting is prevalent in the U.S. economy, as over 90% of goods manufactured in the United States
        contain cast metal components.2 The automotive and transportation sectors are the largest users of castings,
        consuming 50-60% of all castings produced.3
                                                                Source
                                                                Fossil Fuel Combustion
                                                                Non-Combustion
                                                                Purchased Electricity
                                                                Total
                                                                Percent of U.S. Industrial Emissions1
                                                   2002
                                                Emissions
                                               (MMTC02E)
                                                     11
                                                     18
                                                     1%
        The industry includes over 2,300 facilities, among
        which the metals used, the capacity of the plants, the
        casting processes, and other characteristics vary
        greatly. These 2,300 facilities are primarily small,
        independent foundries, though some facilities are
        vertically integrated within larger manufacturing
        operations. Although the industry is geographically
        widespread, 80% of the industry's shipments
        originate in ten states—Alabama, California, Illinois,
        Indiana, Michigan, Ohio, Pennsylvania, Tennessee, Texas, and Wisconsin.4
        The metal casting sector (NAICS code 3315: Foundries) consists of operations that pour or inject molten metal
        into molds or dies to form castings. Establishments that use metal castings as a primary input—such as
        machining or assembling—are classified according to the nature of the finished product. Thus, more involved
        processes that  transform castings into secondary products are classified elsewhere in the manufacturing sector,
        according to the product being made. For example, an automobile manufacturing plant may cast engines, but it
        would not be classified under this NAICS code.

10.1    Sources of  Greenhouse Gas Emissions

        Metal casting requires a significant amount of heat and electricity to achieve high furnace temperatures. Indirect
        GHG emissions from metal casting result from electricity consumption by electric arc furnaces and electric
        induction furnaces. Direct emissions result from onsite fossil fuel combustion. Almost half of these direct
        sources of combustion-related emissions are from the combustion of natural gas and coke for the firing of
        holding and cupola melting furnaces, with the remainder coming primarily from combustion of coal, liquefied
        petroleum gas  (LPG), and distillate  fuel.

10.2    Summary of Emissions  (2002)

        This section presents  a summary of the GHG emission estimates  for the metal casting sector as estimated for
        the year  2002. The methodologies and data sources used to calculate these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

10.2.1   Estimates of Greenhouse  Gas Emissions (2002)
        The total GHG emissions from the metal casting sector are estimated to be 18 MMTCC^E (as seen in Table
        10-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, 15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16. Note that for the purpose of this report, a blank cell does not necessarily indicate
        zero emissions; rather, it indicates that the analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional
        information.
        2 U.S. Environmental Protection Agency, Energy Trends in Selected Manufacturing Sectors: Opportunities and Challenges for Environmentally Preferable Energy
        Outcome, 2007, http://www.epa.gov/sectors/pdf/energv/report.pdf.
        3 U.S. Environmental Protection Agency, Profile of the Metal Casting Industry, 1998,
        http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/metcstsnapt1.pdf.
        4 U.S. Environmental Protection Agency, Energy Trends in Selected Manufacturing Sectors.
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                                Table 10-1: 2002 GHG Emissions from the Metal Casting Sector (MMTC02E)

Fossil Fuel Combustion3
C02
7
Total
7
Non-Cornbustionb
Purchased Electricity0
Total d
11
18
11
18
                                 a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and
                                 EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                                 b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                                 c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and
                                 EPA's Emissions and Generation Resource Integrated Database (eGRID).
                                 d Emission estimates do not include captive foundries.
                                 Note that for the  purpose of this report, a blank cell does not necessarily indicate zero emissions;
                                 rather it indicates that the analysis did not address that emission source, if applicable; see
                                 "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating the GHG emissions for this report is described in Section 1.2; more
         detail on the methodology used to estimate emissions from the metal casting sector can be found in Section
         10.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 10-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 10-2.
         Figure 10-1: 2002 Energy Consumption in the Metal
         Casting Sector, by Fuel Type (TBtu)
               Coke and Breeze
                     15%
                                      Electricity
                                        34%
                Distillate Fuel Oil
                     1%
                                          Natural Gas
                                  Total:
             Figure 10-2: 2002 C02 Emissions from Energy
             Consumption in the Metal Casting Sector, by Fuel Type
             (MMTC02E)
                     Coke and Breeze
                  Distillate Fuel Oil
                      <0.5%    Natural Gas
                                 23%
                                                  Electricity3
                                                     62%
                                       Total:
18 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         Note: TBtu stands for trillion British thermal units.
             Source: Estimate based on methodology in Section 10.2.2.
             a Fuel mix at utilities was taken into consideration in this calculation, per
             methodology described in Section 10.2.2.
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10,2.2                 and

        Foss/7 Fuel Combustion
        Fossil fuel combustion emissions from the metal casting sector were derived from U.S. Department of
        Energy's (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption Survey (MEGS)5
        estimates of fuel consumption for this sector. Those fuel consumption estimates were then multiplied by the
        appropriate, fuel-specific emission factors to convert the consumption into CC>2 emitted.

        The emission factors for the fossil fuels used in the metal casting industry were taken from data contained in
        the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.

        Non-Combustion Activities
        Emissions from non-combustion sources were not estimated for this sector due  to methodological and data
        constraints, though some emissions may result from the use of SF6 as a cover gas for magnesium casting.
        (Cover gases are used during the metal casting process to prevent burning at the  molten metal surface.)
        However, the use of magnesium is uncommon in the metal casting sector, as it is forecasted to account for only
        1% of the sector's casting capacity in 2007.6

        Purchased Electricity
        Electricity emissions were estimated by mapping national electricity purchases (in kilowatt-hours, or kWh)
        provided by MEGS to North American Electricity Reliability Corporation (NERC) regions,7 then applying
        NERC regional utility CC>2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
        adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.

        Since electricity purchase data were not available at the NERC regional level, distribution of the sector's value
        added was used to distribute the sector's national electricity purchases to the state-level, then state data were
        rolled up to the NERC regions.  Where a state lay in two or more NERC regions, electricity purchases were
        distributed  to the appropriate NERC region using sales data for the industrial customer class from EIA Report
        861. This approach assumes that the electricity-intensity of production activities are correlated with the value
        added. Methods for estimating CC>2 emissions from electricity are described in more detail in Appendix A.3.

10.2.3   Key              and
        Non-combustion emissions of SFe as a result of the manufacturing process were not included in this report.
        Emission estimates  do not include captive foundries because these  foundries are not included in the MECS
        data used to define the sector boundary. Electricity and fossil fuel combustion emission estimates include only
        CC>2. Emissions of other GHGs (e.g.,  CHjand N2O) that may result from combustion were not estimated.8
        Emission factors for purchased  electricity provided by eGRID are for 2004, which may include different fuel
        mixes for electricity generation than those of the 2002 inventory year.

10.3   Greenhouse Gas Emissions (1998,2002)

        GHG emissions for select years from the metal casting sector are shown in Figure 10-3.9
        Data for GHG emissions from fossil fuel combustion and purchased electricity were available only for two
        data points, 1998 and 2002, based on frequency of MECS reports. During this period, fossil fuel combustion
        5 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        6 Kirgin, Ken, "U.S. Casting Sales to Maintain Course with 3.7% Rise," Nov 2007, http://www.afsinc.org/imaaes/stories/aboutmetalcastina/27ian07.pdf.
        7 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        8 These non-C02 emissions typically account for only a small percentage (approximately) 2% of a sector's GHG emissions from fossil fuel combustion.
        9 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
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Metal Casting
        emissions declined by 36%, from 10.9 to 6.9 MMTCC^E, and emissions from purchased electricity declined by
        22%, from 14.2 to 11.1 MMTCC^E. Over the same period, shipments of ferrous and nonferrous metals10
        decreased 11%.
        Figure 10-3: Greenhouse Gas Emissions from the Metal Casting Sector (MMTC02E)
                   1998          1999          2000          2001          2002          2003          2004          2005
                                 • Fossil Fuel Combustion                   • Purchased Electricity



10.4   Other Sources of Greenhouse Gas Emission Estimates for this Sector
        A report prepared for DOE, Theoretical/Best Management Energy Use in Metal Casting Operations,11 describes a study
        conducted to determine the theoretical and practical potential for minimizing energy requirements (and
        associated CO2 emissions) to produce one ton of molten metal in metal casting operations.
        This report includes cast iron, steel, aluminum, copper, zinc, magnesium, and other non-ferrous metals in its
        CO2 emission estimates. As shown in Table 10-2, for the year 2003, the report estimates total CO2 emissions to
        be 27.5 MMTCO2E. This estimate is approximately 10 MMTCO2E more than the estimate presented here. The
        difference in emission estimates is likely due to the fact that the DOE report accounts for captive foundries,
        which are not included in this report's emission estimates.12
        10 American Foundry Society, "Metal Casting Forecast & Trends: Demand & Supply Forecast," Stratecasts, Inc.
        11 Schifo, J.F. and J.T. Radia, KERAMIDA Environmental, Inc. Theoretical/Best Practice Energy Use in Metalcasting Operations. Prepared for the U.S. Department
        of Energy Industrial Technologies Program, May 2004.
        12 "Data Reconciliation for the Metal Casting Sector," BCS 2008.
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                            Table 10-2: C02 Emission Estimates from the U.S. Department of Energy's
                              Theoretical/Best Management Energy Use in Metal Casting Operations
                    Grey Iron
                    Ductile (Other than pipe)
                    Ductile Iron Pipe
                    Steel
                    Al High         Die Casting
                    Al Permanent
                    Al Lost Foam
                    Mg Die Casting
                    Zinc Die Casting
                    Copper-Base;
                    Titanium;           Induction; Hot                 (HIP)
                    Other Non-Ferrous
                  Total
                                  10.1
                                   3.2
                                   1.1
                                   2,7
                                   5,6
                                   1.2
                                   1.5
                                   0,4
                                   0,5
                                   07
                                   0,2
                                   0,3
                                  27.5
                'Emission estimates were converted from thousand short tons C02, as reported by DOE, intoMMTC02E. 1,000 short ton = 0.0009072 MMT.
10.5    Sector Emission Reduction Commitments

        No sector commitments to reducing GHG emissions were identified.

10.6    Reporting Protocols

        When calculating emissions, one of the following protocols may be used by companies in the metal casting
        sector:

        "  EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
           protocol mentioned below;

        "  DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and

        "  The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
           (WRI) Greenhouse Gas Protocol.

        No public reports of GHG emissions from companies in the metal casting sector were identified.
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11.    Mining
        Mining operations provide the mineral commodities that are essential to numerous indispensable goods and
        services. Mined materials are necessary to construct
        roads and buildings, to make computers and
        satellites, to generate electricity, and to build other
        common commodities.
          Source
                                                                                                      2002
                                                                                                   Emissions
                                                                                                   (MMTC02E)
                                                              Fossil Fuel Combustion
                                                              Non-Combustion
                                                              Purchased Electricity
                                                              Total
                                                              Percent of U.S. Industrial Emissions1
                                                   15
                                                   58
                                                   27
                                                   99
                                                  5%
        The mining sector (NAICS code 212: Mining),
        contains facilities that primarily engage in mining,
        mine site development, and preparing metallic
        minerals and nonmetallic minerals. Mining activities
        broadly include ore extraction, quarrying, and
        beneficiating (e.g., reducing extracted materials to
        particles for separation into mineral for processing or use and waste). Mining establishments include those that
        have complete responsibility for operating mines and quarries, as well as those establishments that operate
        mines and quarries on a contract or fee basis. This sector includes mining of all materials (e.g., coal, metal, and
        nonmetallic minerals) except oil and gas (NAICS code 211: Oil and Gas Extraction), which is included in the
        Oil and Gas chapter of this report.

11.1    Sources of Greenhouse Gas Emissions

        As described in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,2 significant direct, non-
        combustion emissions result from coal mining operations. In particular, CHLt  is liberated during normal coal
        mining operations, as CH4 that resides in coal ("in situ")  is released during underground mining, surface mining,
        and post-mining (i.e., coal handling) activities. The in-situ CH4 content of coal depends upon the amount of
        CH4 created during the coal formation process, as well as the geological characteristics of the coal seam. Coal
        mines without ongoing mining operations continue to emit CHLt, albeit at a much slower rate than active mines.
        Mining operations require energy to operate quarrying and beneficiating machinery. This energy use results in
        direct emissions of CO2 from fossil fuel combustion and indirect CO2 emissions from purchased electricity.

11.2    Summary of Emissions  (2002)

        This section presents a summary of the GHG emission  estimates for the mining sector as estimated for the
        year 2002. The methodologies and data sources used to  calculate these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

11.2.1   Estimates of Greenhouse Gas Emissions (2002)
        The total GHG emissions from the mining sector are estimated to be 99 MMTCO2E (as seen in Table 11-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 Apr 2007, http://www.epa.gov/climatechanae/emissions/
        usinventorvreport.html. Table 2-16. Note that for the purpose of this report, totals may not sum due to independent rounding.
        2 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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                                   Table 11-1: 2002 GHG Emissions from the Mining Sector (MMTC02E)

Fossil Fuel Combustion3
Non-Cornbustionb
Coal Mining
Abandoned Coal Mines
Purchased Electricity0
Total
15



27
41

58
52
6

58
15
58
52
6
27
99
                        'Emissions calculated based on U.S. Census Bureau's 2002 Mining Statistics Sampler and EPA's Inventory of U.S
                        . Greenhouse Gas Emissions and Sinks: 1990-2005.
                        b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                        c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and
                        Generation Resource Integrated Database (eGRID).
                        Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the
                        analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating GHG emissions for this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions from the mining sector can be found in Section 11.2.2.
         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 11-1. For comparison, CO2  emissions associated
         with fuel consumption are shown in Figure 11-2.
        Figure 11-1: 2002 Energy Consumption in the Mining
        Sector, by Fuel Type (TBtu)
                                       Distillate Fuel Oil
                        Figure 11-2: 2002 C02 Emissions from Energy Consumption
                        in the Mining Sector, by Fuel Type (MMTC02E)

                                                  Distillate Fuel Oil
                                                       33%
           Natural Gas and
          Other Gases (e.g.,
              Mixed)
               48%
Residual Fuel Oil
 Natural Gas and
Other Gases (e.g.
     Mixed)
                                      Gasoline
                                        3%

                                      Total:
    Coal
   <0.5%
                                                                                                            Residual Fuel Oil
                Gasoline
                  2%
Coal
29%
                                                         Total:
                                       15 MMTC02E
         Source: U.S. Census Bureau, 2002 Mining Statistics Sampler.
         Note: TBtu stands for trillion British thermal units.
                         Source: Estimate based on methodology in Section 11.2.2.
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11,2.2                and

         Foss/7 Fuel Combustion
         Fossil fuel combustion emissions from the mining sector were derived from the U.S. Census Bureau's 2002
         Economic Census Industry Series Reports: Mining1 estimates of fuel consumption for this sector, as the U.S.
         Department of Energy's (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption
         Survey (MEGS) does not contain fuel use estimates for this sector. These estimates include fuel consumed for
         both on-road and off-road mining equipment. Those fuel consumption estimates were then multiplied by the
         appropriate, fuel-specific emission factors to convert the consumption into CC>2 emitted. The emission factors
         for the fossil fuels used in  the mining sector were derived from data contained in the Inventory of U.S. Greenhouse
         Gas Emissions and Sinks: 1990-2005.

         Non-Combustion Activities
         Non-combustion emissions of CHU from coal mining operations were those reported for the coal mining and
         abandoned underground coal mines source categories within the Inventory of U.S. Greenhouse Gas Emissions and
         Sinks: 1990-2005."> These estimates also include the mining emission sources identified by the Intergovernmental
         Panel on Climate Change's (IPCC) 2006IPCC Guidelines for National Greenhouse Gas Inventories?

         Purchased Electricity
         Electricity emissions were  estimated by mapping national electricity purchases (in kilowatt-hours, or kWh)
         provided by MECS to North American Electricity Reliability Corporation (NERC) regions,6 then applying
         NERC regional  utility CC>2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
         adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.
         Since electricity  purchase data were not available at the NERC regional level, distribution of the sector's value
         added was used  to distribute the sector's national electricity purchases to the state-level, then state data were
         rolled up to the  NERC regions. Where a state lay in two or more NERC regions, electricity purchases were
         distributed to the appropriate NERC region using sales  data for the industrial customer class from EIA Report
         861. This  approach assumes that the electricity-intensity of production activities are correlated with  the value
         added. Methods for estimating CC>2 emissions from electricity are described in more detail in Appendix A.3.

11.2.3   Key               and
         Non-combustion emission estimates were limited to sources identified by the 2006 IPCC Guidelines for National
         Greenhouse Gas Inventories and provided in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         Electricity and fossil fuel combustion emission estimates include only CCh- Emissions of other GHGs (e.g.,
         CH4and N2O) that may result from combustion were not estimated.7 Emission factors  for purchased electricity
         provided by eGRID are for 2004, which may include different fuel mixes for electricity generation than those
         of the 2002 inventory year.

11.3    Greenhouse Gas Emissions  (1997,2002)
         GHG emissions for select years from the  mining sector are shown in Figure 11-3.8
        3 U.S. Census Bureau, 2002 Economic Census of Mining Industry Series Data, Economics and Statistics Administration, 2005,
        http://www.census.gov/econ/census02/auide/INDRPT21.HTM.
        4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        5 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
        naaip.iaes.or.ip/public/2006g I/index.htm.
        6 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        7 These non-C02 emissions typically account for a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        8 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
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Mining
        Annual estimates of non-combustion GHG emissions from mining were available from the annual Inventory of
        U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, which show that such emissions have decreased by 18%
        between 19979 and 2005, from 70.3 to 57.9 MMTCO2E.

        However, the data for GHG emissions from fossil fuel combustion were available only for two data points,
        1997 and 2002, based on frequency of U.S. Census reports. Data for GHG emissions from purchased
        electricity were available for 1998 and 2002. The 1998 value was assumed for 1997. During the period,
        1997-2002, these energy-related emissions declined by 22%, from 52.9 to 41.4 MMTCO2E.

        In aggregate, emissions  from the mining sector decreased 19% between 1997 and 2002. Over the same period,
        mining production10 increased 4%.
         Figure 11-3: Greenhouse Gas Emissions from the Mining Sector (MMTC02E)
            70 -     I
         8  50-
            40 -
                             n
                  1997
                             1998        1999       2000

                             i   ' Fossil Fuel Combustion
       2001        2002

      1 Purchased Electricity
2003        2004        2005

—•— Non-Combustion
11.4   Other Sources of Greenhouse Gas Emission Estimates for this Sector

        No reports containing complete GHG emissions estimates for the mining sector were identified.

11.5   Sector Emission Reduction Commitments

        In 2003, the National Mining Association (NMA) and its members that are in the coal and metals and minerals
        industry, committed to increasing the energy efficiency of production (and where applicable) processing
        operations, with the goal of obtaining a 10 percent increase in efficiency in systems that can be optimized with
        the processes and techniques developed by the Department of Energy (DOE) and made available to the
        industry through a series of jointly sponsored government industry workshops. NMA members also committed
        to maintain and improve progress made in reduction of QrU  emissions from coalmines, wherever economically
        and technically possible.

11.6   Reporting Protocols

        When calculating emissions, one of the following protocols is typically used by companies in the mining sector:

        •   EPA's Climate 'Leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the  WBCSD/WRI
            protocol mentioned below;
        9 Trends in GHG emissions from the mining sector start in 1997 since only one data point for emissions from energy consumption was available for this sector.
        10 U.S. Department of Energy, "Coal Production in the United States," 5 Oct 2006,
        http://www.eia.doe.gov/cneaf/coal/paae/fia1 us historical production bar chart.xls: U.S. Geological Survey, Minerals Yearbook: Mining and Quarrying Report
        2000, 2001, http://minerals.usas.gov/minerals/pubs/commoditv/mSa/, Table 1; U.S. Geological Survey, Minerals Yearbook: Mining and Quarrying Report2005,
        2006, http://minerals.usas.aov/minerals/pubs/commoditv/mSg/, Table 1.
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         "    DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and
         "    The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
             (WRJ) Greenhouse Gas Protocol.
         Table 11-2 presents a sample of mining companies that have publicly reported their GHG emissions.
                           Table 11-2: Sampling of Publicly-Reported GHG Emissions for Mining Companies
        11 Newmont Mining Corporation, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire," 10 Nov
        2007 http://www.cdproiect.net/responses/Newmont Mining Corporation Corporate GHG Emissions Response CDP5 2007/public.htm.
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12.    Oil and  Gas
                                                               Source
                                                               Fossil Fuel Combustion
                                                               Non-Combustion
                                                               Purchased Electricity
                                                               Total
                                                               Percent of U. S. Industrial Emissions1
                                                 2002
                                               Emissions
                                              (MMTC02E)1
                                                   276
                                                   181
                                                    43
                                                   501
                                                  24%
The oil and gas sector, as defined in this report, includes the exploration and production of petroleum and
natural gas, processing of natural gas, the refining of petroleum and the non-combustion emissions from the
transportation and distribution of oil and gas. The processes included in these sub-sectors may be found under
the following NAICS codes: Crude Petroleum and Natural Gas Extraction (211111), Natural Gas Liquid
Extraction (211112), Drilling Oil and Gas Wells (213111), Support Activities for Oil and Gas Operations
(213112), Petroleum Refineries (324110), Pipeline Transportation of Refined Petroleum Products (48691),
Pipeline Transportation of Natural Gas (48621) and Natural Gas Distribution (22121).

The sector can be divided into two parts in two
ways: the first is to split oil and gas production (i.e.,
the exploration and production of oil and gas from
the ground or off-shore sources) from petroleum
refining (i.e., processing of crude oil that has been
extracted or imported) and processing of natural
gas (i.e., the removal of impurities and natural gas
liquids from wellhead natural gas); the  second is to
split petroleum systems  from natural gas systems —
with systems defined in  each case to include the
exploration, production, transportation, and refining of petroleum and the exploration, production, processing,
transmission and storage, and distribution of natural gas.
The oil and gas exploration and production sub-sector includes the upstream operations engaged in locating
and extracting oil and natural gas resources that may undertake activities such as seismic and geological data
acquisition and interpretation, leasing and permitting, exploration drilling, development drilling, work-overs
and re-completions, and production operations. Geographically, this industry extracts oil and natural gas from
more than 30 states, including offshore sources. In 2005, the U.S. produced almost two billion barrels  of crude
oil with the largest sources being the Gulf of Mexico, Texas (onshore), Alaska and California. In total,  these
wells accounted for 77% of all U.S. oil production.2 In natural gas production, the U.S. produced nearly 24
trillion cubic feet of raw gas from onshore and offshore sources in 2005, with the largest producers being
Texas, the Gulf of Mexico, Wyoming, New Mexico, Oklahoma, Colorado, and Louisiana. Together, these
sources accounted for 83% of all U.S. gross  gas withdrawals that year.3 After processing, this production
yielded about 18 trillion cubic feet of marketable  dry natural gas.3
The petroleum refining  sub-sector includes establishments engaged in refining crude petroleum into refined
petroleum products through multiple distinct processes that may include distillation, hydrotreating, alkylation,
and reforming. In addition to fuel production, this sub-sector produces raw materials  for the petrochemical
industry. Currently there are 149 petroleum refineries in the U.S. located in 33 states, with approximately 75%
of the total refining capacity held in just 7 states (Texas, Louisiana, California, New Jersey, Pennsylvania, Ohio
and Oklahoma). In 2006, U.S. refineries had processed more than 5.5 billion barrels of crude oil.4
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16. Note: totals may not sum due to independent rounding.
        2 U.S. Department of Energy, EIA Distribution and Production of Oil and Gas Wells, 1990-2004, Energy Information Administration, 2006. Data for 2005 were
        developed by using ElA's state oil production growth from 2004 to 2005.
        3 U.S. Department of Energy, EIA Natural Gas Gross Withdrawals and Production, February 2008, http://tonto.eia.doe.aov/dnav/na/ng prod sum dcu NUS a.htm.
        4 U.S. Department of Energy, EIA Refinery Capacity and Utilization, 2007, Energy Information Administration, June 2007,
        http://tonto.eia.doe.gov/dnav/pet/pet pnp unc dcu nus a.htm.
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Oil  and Gas	

12.1    Sources of Greenhouse Gas Emissions

12.1.1   Oil and Gas                        and
        There are two direct sources of GHG emissions (in the form of CO2) in the oil and gas production and
        delivery sub-sector: processes (considered non-combustion emissions) and fossil fuel combustion. Natural gas
        and distillates (i.e., diesel and fuel oils) are the primary fuels used in oil and gas exploration and production, and
        they are used to operate internal combustion engines, process heaters, and to produce steam. Additionally,
        diesel fuel is used for off-road transportation. The majority of the natural gas consumed by this sub-sector is
        produced and used locally in the production areas or in gas processing plants (called natural gas lease and plant
        fuel), although some gas may also be purchased. Where gas is not available, diesel fuel is the preferred internal
        combustion engine fuel due to its transportability.
        In natural gas processing plants, the direct sources of GHG emissions are primarily the acid-gas removal units
        that rid raw natural gas of CO2- Other direct  sources of non-combustion CO2 emissions are the flaring of gas in
        field production5, leaks from transmission and storage, and fugitive emissions in the distribution systems.

        The indirect sources of GHG emissions (in the form of CH4) are leaks, venting and fugitive emissions. In field
        production, a substantial portion of the total  CH4 emissions come from pneumatic devices, while in natural gas
        processing plants, the primary source of CH4 emissions is fugitive emissions from compressors. In transmission
        and storage facilities, CH4 emissions may come from the compressors at metering and  regulating stations or
        storage facilities, or CH4 may be emitted from the dehydrators at storage facilities. Fugitive CH4 emissions are
        also emitted from distribution systems  for natural gas.

12.1.2
        The direct source of GHG emissions in the petroleum refining sub-sector is fossil-fuel combustion. The two
        largest fossil-fuel consuming processes in the petroleum refining industry are fluid heating and steam
        production. Fluid heaters are used in a variety of important refining steps such as distillation and pre-heating
        feedstock to induce reactions. Steam production is also considered to be a major refinery activity since
        substantial amounts of steam are used throughout a refinery.

        Refinery fuel gas (also called still gas), catalyst coke and natural gas are the primary fossil fuels consumed by
        this sub-sector. Refinery fuel gases are the by-products of various petroleum refinery processes (such as crude
        oil distillation, cracking, reforming and treating). These gases are collected and then processed (to recover the
        propane, or other light hydrocarbons), and then the sulfur and nitrogen compounds are removed. This cleaner
        gas is basically a mixture of methane, ethane, and lesser amounts of hydrogen and light hydrocarbons with trace
        amounts of ammonia and hydrogen sulfide. Refinery gas is the primary fuel used in fluid heaters, with natural
        gas being the preferred purchased fuel.

        For steam production, petroleum coke (a by-product of the coking process) is the fuel of choice since it
        provides a free source of fuel. Coke, primarily from the fluid catalytic cracking unit (FCCU) is burned
        continuously to regenerate the FCCU catalyst, with the heat of combustion captured in a steam boiler. The
        main  supplemental fuel for steam generation is natural gas. The petroleum  refining industry is considered to be
        a major co-generator of steam and electricity. As a result of co-generation, purchased electricity (primarily used
        for machine drives) in petroleum refineries is not as significant a source of indirect emissions as it is in other
        major energy-intensive industries that do not produce their own electricity.
        5 Flaring is a combustion activity; however, the IPCC reporting requirements are designed such that natural gas flaring is reported within the process emissions
        from Natural Gas Systems rather than from C02 emissions from fossil fuel combustion within the U.S. Inventory (See U.S. Environmental Protection Agency,
        Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 Apr 2007). Thus, flaring is reported here as a "non-combustion" activity.
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12.2   Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the oil and gas sector for the year 2002.
        The methodologies and data sources used to calculate these emission estimates, as well as the assumptions and
        limitations surrounding the estimates, are also described.

12.2.1             of             Gas
        As shown in Table  12-1, 2002 GHG emissions from the oil and gas sector totaled 501 MMTCO2E and resulted
        primarily from the combustion of fossil fuels (276 MMTCG^E) and non-combustion emissions (181
        MMTCG^E) were also a significant contributor.
        Figure 12-1 and Figure 12-2 illustrate the distribution of energy consumption (including both on-site fossil fuel
        combustion and purchased electricity) and CO2 emissions by fuel type, respectively. Figure 12-1 shows that
        natural gas (including natural gas used at the wellhead and in the gas processing plants) and other fuels
        (primarily comprised of by-product fuels, like refinery gas and petroleum coke) are the main  energy types used
        in the oil and gas  sector. These two fuels account for 93% of total energy consumption by the sector.

                              Table 12-1: 2002 GHG Emissions from the Oil and Gas Sector (MMTC02E)
i j*dui*i f Ctt CR| 1 l|t|l ;;j
Fuel
Petroleum Refining
Oil and Gas Exploration and Production
Non-Combustion13
Petroleum
Exploration and Production
Transportation
Refining
Natural Gas
Exploration and Production
Processing
Transmission and Storage
Distribution

Petroleum Refining
Oil and Gas Production
Total
276
199
77
30




30
7
23
<1
<1
43
22
21
349



152
27
26

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Oil and  Gas
        Figure 12-1: 2002 Energy Consumption in the Oil and Gas
        Sector, by Fuel Type (TBtu)
                    Figure 12-2: 2002 C02 Emissions from Energy Consumption
                    in the Oil and Gas Sector, by Fuel Type (MMTC02E)
                    Electricity
                      5%
                                  Electricity
          LPG and NGL
             <0.5%
                    Other
                                         Natural Gas
                      LPG and NGL
                         <0.5%
   Distillate Fuel Oil
       1%
Residual Fuel Oil
     1%
                                      Tota|.
Natural Gas
   37%
    Distillate Fuel Oil
         1%
      Residual Fuel Oil
           1%
                                                      319 MMTC02E
        Source: DOE, 2002 Manufacturing Energy Consumption Survey and U.S.
        Census, 2002 Economic Census of Mining.
        a Composition of "other" fuel category varies among sectors. In the oil and
        gas sector, "other" fuels include crude oil, petroleum coke, and refinery gas.
        Note: TBtu stands for trillion British thermal units.
                    Source: Estimate based on methodology in Section 12.2.2.
                    a Composition of "other" fuel category varies among sectors. In the oil and
                    gas sector, "other" fuels include crude oil, petroleum coke, and refinery gas.
12.2.2  Methodology and Data Sources

        Foss/7 Fuel Combustion
        The estimated GHG emissions due to on-site fossil fuel combustion by the exploration and production sub-
        sector and petroleum refining sub-sector of the oil and gas sector were developed using two distinct
        methodologies.

        •   Exploration and "Production Sub-Sector: The methodology developed to estimate fossil fuel combustion
            emissions from crude oil and natural gas extraction, drilling oil and gas wells, and support activities for oil
            and gas operations utilizes the U.S Census Bureau's 2002 Economic Census of Mining (2005) estimates of fuel
            consumption. However, the fuel consumption estimates for two fuel types in the Census  pertaining to
            byproduct natural gas—"natural gas produced and used in the same plant as  fuel" (commonly called lease
            fuel),  and "residue gas produced and used in the same plant as fuel" (commonly called plant fuel)—were
            replaced by EIA natural gas  lease and plant estimates. This was done for consistency with other studies and
            estimates done by industry groups and other organizations. EIA has the most consistent source of lease
            and plant data since they survey plants annually.

            Fuel consumption estimates were multiplied by appropriate, fuel-specific emission factors to convert the
            consumption into CC>2 emitted. The emission factors for the fossil fuels were derived from data contained
            in the Inventory of U.S. Greenhouse Gas Emissions and Sinks'. 1990-2005.7

        •   Petroleum Refining Sub-Sector: The methodology developed to estimate fossil fuel combustion emissions
            from  petroleum refining utilizes the U.S. Department of Energy's Energy Information Administration's
        6 U.S. Department of Commerce, 2002 Economic Census: Crude Petroleum and Natural Gas Extraction: 2002, December 2004,
        http://www.census.gov/prod/ec02/ecQ2211211111 .pdf.
        7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
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Oil and Gas
                                         >tion Survey (MEGS)8 estimates of fuel consumption, found in Tables 3.1 and
            3.2 of MEGS. Estimates of fuel consumption by fuel type were obtained for NAICS code 324110
            (petroleum refineries). Fuel consumption estimates were multiplied by appropriate, fuel-specific emission
            factors to convert the consumption into CC>2 emitted. The emission factors for the fossil fuels used in
            petroleum refining were derived from data contained in the Inventory of U.S. Greenhouse Gas Emissions and
            Sinks: 1990-2005.

        Non-Combustion Activities
        Estimates for non-combustion emissions from the petroleum systems and natural gas systems sub-sectors of
        this sector were both derived from the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        Non-combustion emissions for petroleum systems (source category lB2a, which includes petroleum
        production, transportation, and refining) were obtained directly from Table 3-38 of the Inventory of U.S.
        Greenhouse Gas Emissions and Sinks: 1990-2005, which only includes CH4 emissions. These emissions were
        calculated from activity data on the production, transportation, and refining for petroleum systems in
        accordance with the Intergovernmental Panel on Climate Change's  (IPCC) 2006IPCC Guidelines for National
        Greenhouse Gas Inventories, the internationally agreed upon best available methods for national GHG emission
        inventories based on current technical and scientific knowledge.
        Non-combustion emissions for natural gas systems (source category lB2b, which includes natural gas production,
        processing, transmission and storage, and distribution) were obtained directly from Table 3-33 of the Inventory of
        U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, which includes CC>2 and CHLt emissions. These emissions were
        calculated from activity data on the production, processing, transmission and storage, and distribution for natural
        gas systems in accordance with the 2006 IPCC Guidelines for National Greenhouse Gas Inventories.

        Purchased Electricity
        Estimated emissions from purchased electricity from the  exploration and production and petroleum refining
        sub-sectors of the  oil and gas sector were developed using two separate methodologies.  Methods for estimating
        CC>2 emissions from electricity are detailed in Appendix A.3.

        "   Oil and Gas Production Sub-Sector: Electricity emissions  were estimated by mapping national electricity
            purchases (in kilowatt-hours, or kWh) provided by the U.S. Census Bureau's 2002 Economic Census of Mining
            to North American Electricity Reliability Corporation (NERC)  regions,9 then applying NERC regional
            utility CC>2 emission factor  (in Ibs/kWh) provided by eGRID. Sector electricity purchases were adjusted by
            a loss factor to reflect losses incurred in the transmission and distribution of electricity.

            Since electricity purchase data were not available at the NERC regional level, distribution of the sector's
            value added was used to distribute the  sector's national electricity purchases to the state-level, then state
            data were rolled up to the NERC regions.10 Where a  state lay in two or more  NERC regions, electricity
            purchases were distributed to the appropriate NERC region using sales data for the industrial customer
            class  from EIA Report 861. This approach assumes that the electricity-intensity of production activities are
            correlated with the value added.

        *   Petroleum Refining Sub-Sector:  Electricity emissions were estimated by multiplying electricity purchases by
            refineries provided by EIA's Petroleum Supply Annual, by CC>2 emission factors (in Ibs/kWh) provided by
            eGRID at the NERC region level.  The electricity purchases by  refinery were based on total electricity
        8 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        9 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        10 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
        http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
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Oil and  Gas	

            purchased by each Petroleum Administration for Defense District (PADD), and adjusted to the refinery-
            level using the "equivalent distillation capacity" (EDC) of each refinery. This value was calculated because
            it more accurately reflects the electricity purchasing needs of a refinery than the pure atmospheric
            distillation capacity alone. The EDC of each refinery was multiplied by its utilization for the given year, as
            provided by EIA's Petroleum Supply Annual, in order to determine electricity purchases.11-12

12,2.3  Key              and
        Non-combustion emission estimates were limited to sources identified by the 2006IPCC Guidelines for National
        Greenhouse Gas Inventories. Electricity and fossil fuel combustion emission estimates include only CC>2. Emissions
        of other GHGs (e.g., N2O) were not estimated due to data and methodological constraints.13

12.3   Greenhouse Gas Emissions (1998,2002)

        GHG emissions for select years from the oil and gas sector are provided in Figure 12-3:.
        Data for non-combustion GHG emissions  were available for the years 1998 to 2005 from the Inventory of U.S.
        Greenhouse Gas Emissions and Sinks: 1990-2005.

        Fuel combustion and purchased electricity emission estimates were provided only for two years, 1998 and 2002.
        As mentioned above, emissions from oil and gas production and petroleum refining were estimated separately;
        the data sources used were both available for the year 2002. However, the dataset used for the exploration and
        production sub-sector (Economic Census of Mining) provided fuel consumption for the years 1997 and 2002, while
        the dataset used for the petroleum refining  sub-sector (MEGS) was available for the years 1998 and 2002. To
        estimate emissions from fossil fuel combustion in oil and gas production, emission estimates were created for
        1997 and then the rate of growth in  industrial production from 1997 to 1998 published by the Federal Reserve
        Board was applied to these estimates.
        Figure 12-3 shows GHG emission estimates for the oil and gas sector. Overall emissions from the oil and gas
        sector decreased 4% between 1998 and 2002. Emissions from fossil fuel combustion have fallen by 5% from
        1998 to 2002, while emissions from  purchased electricity have remained constant. Non-combustion emissions
        decreased by 2%, and oil & gas production14 decreased 3% over the same timeframe. From 1998 to 2005, non-
        combustion emissions decreased by 9%, while oil & gas production decreased by 6% over that same timeframe.
        11 U.S. Department of Energy, Petroleum Supply Annual 1998, Volume 1. Table 16. Energy Information Administration, June 1999,
        http://www.eia.doe.gov/pub/oil gas/petroleum/data publications/petroleum  supply annual/psa volume1/historical/1998/pdf/table 16.pdf.
        12 U.S. Department of Energy, Petroleum Supply Annual 2002, Volume 1. Table 16. Energy Information Administration, June 2003,
        http://www.eia.doe.gov/pub/oil gas/petroleum/data publications/petroleum  supply annual/psa volume1/historical/2002/pdf/table 16.pdf.
        13 These non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        14 U.S. Department of Energy, Production in Btu derived from Crude Oil Field Production (Barrels) and Natural Gas Gross Withdrawals and Production (MMcf)]
        Energy Information Administration, http://tonto.eia.doe.gov/dnav/pet/pet  crd crpdn adc mbbl m.htm and
        http://tonto.eia.doe.gov/dnav/na/na prod sum  dcu NUS m.htm.
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Oil and Gas
        Figure 12-3: Greenhouse Gas Emissions from the Oil and Gas Sector (MMTC02E)
                    1998
                                1999         2000

                               ZZ1 Fossil Fuel Combustion
   2001         2002

  ZZI Purchased Electricity
 2003         2004

Non-Combustion
                                                                                                     2005
12.4    Other Sources of Greenhouse Gas Emission Estimates for this Sector

        No reports containing complete GHG emissions estimates for the oil and gas sector were identified.

12.5    Sector Emission Reduction Commitments

        The American Petroleum Institute (API) has instituted three programs for the industry.15 The API Climate
        Action Challenge focuses on reducing, sequestering, offsetting or avoiding GHG emissions. API-member
        refining companies have committed to improve energy efficiency by 10% by 2012. The API Climate R&D
        Challenge focuses on research and development into improved technologies to reduce or sequester GHG
        emissions. The API Climate Greenhouse Gas Estimation & Reporting Challenge focuses on improving calculation and
        reporting techniques, and adopting a world-wide compendium for consistent estimation throughout the world.

12.6    Reporting Protocols

        When calculating emissions, one of the following protocols is typically used by companies in  the oil and gas
        sector:

        •   EPA's  Climate 'Leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below;

        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program, which has a protocol on
            estimating methane emissions from natural gas operations in Sector-Specific Issues and Reporting Methodologies:
            Supporting the General Guidelines for the  Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy
            Polity Act of1'992.,16 The protocol provides guidance specifically on methane emissions due to normal
            operations, routine maintenance and system upsets;

        •   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
            (WRI)  Greenhouse Gas Protocol; and

        •   The Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions protocol developed by API  and the
            International Association of Oil and Gas Producers, which provides sector specific guidance for oil and gas
            companies in reporting their emissions.
        15 See http://www.climatevision.gov/sectors/oil gas/index.html.
        16 See http://www.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/aa-v1-3-indust.pdf.
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Oil and Gas
       Table 12-2 presents a sample of oil and gas companies that have publicly reported their emissions.




                      Table 12-2: Sampling of Publicly-Reported GHG Emissions for Oil and Gas Companies
U.S. Environmental Protection Agency
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13.    Plastic and  Rubber Products
        In the U.S., the plastic and rubber products sector is comprised of more than 16,000 companies producing
        goods that range from plastic bottles to rubber hoses
                                                               Source
                                                               Fossil Fuel Combustion
                                                               Non-Combustion
                                                               Purchased Electricity
                                                               Total
                                                               Percent of U.S. Industrial Emissions1
                                                  2002
                                               Emissions
                                               (MMTC02E)
                                                    36
                                                    44
                                                    2%
        For the purposes of this analysis, the plastic and
        rubber products sector (NAICS code 326: Plastic
        and Rubber Product Manufacturing) is defined as
        creating goods by processing plastic and raw rubber2
        into industrial or consumer goods that are generally
        made of just one material (i.e., rubber or plastic) with
        the major exception of tires (which is included in this
        sector). Where a product uses more than one
        material for their manufacture (e.g., footwear or
        furniture), those activities are not included, as the core technologies are diverse and involve multiple materials.
        Given this definition, there are  two main sub-sectors studied in this analysis.

        The first is the plastic manufacturing sub-sector (NAICS code 3261: Plastic Product Manufacturing), which is
        primarily engaged in processing new or spent (i.e., recycled) plastic resins into intermediate or final products by
        means of compression, extrusion, injection, or blow molding, or else by casting. The second sub-sector
        analyzed was the rubber manufacturing sub-sector (NAICS code 3262: Rubber Product Manufacturing), which
        is comprised of companies that mainly process  natural and synthetic (or reclaimed) rubber materials into
        intermediate or final products using processes like vulcanizing, cementing, molding, extruding, and lathe-
        cutting. (This is the sub-sector under which tire manufacturing and other related composite products fall.)

13.1    Sources of Greenhouse  Gas Emissions

        Direct GHG emissions from the plastic and rubber product manufacturing sector result from on-site fossil fuel
        combustion. Natural gas  is the primary fuel used for creating plastic and rubber products. Electricity (either
        generated on-site or purchased) may be used to power equipment that operates injection or compression
        molding machines or other processes.
        Manufacturing products from either rubber (whether natural or synthetic) or plastic (whether new or recycled)
        requires electricity for both the manufacturing and handling equipment, as well as for various processes like
        heating, drying, cooling, molding, sheeting, forming, and other common processing techniques. One process
        that is changing  the energy use  in these factories is reaction injection molding, which requires little heating and,
        therefore, uses considerably less energy. Still, the on-site energy use by this sector represents a direct  source of
        GHG emissions.
        Indirect sources  of GHG emissions in this sector result from the purchased electricity needed to supplement
        any on-site combustion of fossil fuels.

13.2    Summary of  Emissions (2002)

        This section presents  a summary of emissions estimates from the plastic and rubber products sector for the
        year 2002. The methodologies and data sources used to calculate these emissions estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S. Environmental
        Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15Apr2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html. Table 2-16. Note that for the purpose of this report, a blank cell does not necessarily indicate zero
        emissions; rather, it indicates that the analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
        2 Plastic and rubber are combined in the same NAICS code, because plastic is increasingly being used as a substitute for rubber.
U.S. Environmental Protection Agency
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Plastic and  Rubber Products
13.2.1   Estimates of Greenhouse Gas Emissions (2002)

         GHG emissions from the plastic and rubber products sector were estimated to be 44 MMTCG^E in 2002 (as
         seen in Table 13-1).

                           Table 13-1: GHG Emissions from the Plastic and Rubber Product Sector (MMTC02E)
                      	
                           Fossil Fuel Combustion3
                           Non-Combustion
                           Purchased Electricity13
                                                       36
                                    36
                        Total
                                                      44
                                    44
                       a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S.
                       Greenhouse Gas Emissbns and Sinks: 1990-2005.
                       b Emissions calculated based on data from DOE's 2002 Manufacturing Energy Consumption Survey and EPA's
                       Emissions and Generation Resource Integrated Database (eGRID).
                       Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the
                       analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions from the plastic and rubber products sector can be found in
         Section 13.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 13-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 13-2.
         Figure 13-1: 2002 Energy Consumption in the Plastic and
         Rubber Products Manufacturing Sector by Fuel Type (TBtu)a
                LPG and NGL

           Other    1%
            2%  ~\
Residual Fuel Oil
     2%
              Distillate Fuel Oil
                   1%
                    Natural Gas  /
                       39%
                                                Electricity
                                                  55%
  Figure 13-2: 2002 C02 Emissions from Energy
  Consumption in the Plastic and Rubber Products Sector,
  by Fuel Type (MMTC02E)a

              Other  LPG and NGL
                        <0.5%
                ...  j
  Residual Fuel Oil
        1%
Distillate Fuel Oil
    0.5%
                                                                             Natural Gas
                                                                                15%
                                       Total:
                                                                                      Total:
                                                                                                   Electricity
                                                                                                     83%
                                   44 MMTC02E
         Source: U.S. DOE, 2002 Manufacturing Energy Consumption Survey.
         a Excludes coal because data are withheld by MEGS.
         Note that composition of "other" fuel category varies among sectors.
                                                            Source: Estimate based on methodology in Section 13.2.2.
                                                            a Excludes coal because data are withheld by MEGS.
                                                            b Fuel mix at utilities was taken into consideration in this calculation, per
                                                            methodology described in Section 13.2.2.
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Plastic and Rubber Products
13,2.2                and

         Foss/7 Fuel Combustion
         The methodology developed for this report to estimate fossil fuel combustion emissions from the plastic and
         rubber products sector utilized the U.S. Department of Energy's Energy Information Administration's (EIA)
         Manufacturing Energy Consumption Survey 3 (MEGS) estimates of fuel consumption for the sector. Fuel
         consumption estimates were multiplied by appropriate, fuel-specific emission factors to  convert the
         consumption into CC>2 emitted. The emission factors for the fossil fuels used in the plastic and rubber product
         sector were taken from data contained in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.4
         The "other" fuel type includes all other types of fuel that MEGS respondents indicated could have been
         consumed and were not otherwise listed.

         Non-Combustion Activities
         Non-combustion emissions would include GHG emissions that occur from activities within the sector that
         were not related to on-site fossil fuel consumption or purchased energy. Non-combustion emissions were not
         specifically identified for this sector by the Intergovernmental Panel on Climate Change's (IPCC) 2006IPCC
         Guidelines for National Greenhouse Gas Inventories^ and, hence, were not included in the Inventory of U.S. Greenhouse
         Gas Emissions and Sinks: 1990-2005 or this report.

         Purchased Electricity
         Electricity emissions were estimated by multiplying national- or regional-level electricity purchases (in  kilowatt-
         hours, or kWh) provided by MECS6 by CC>2 emission factor (in Ibs/kWh) provided by eGRID7 at the North
         American Electricity Reliability Corporation (NERC) region level.8 Sector electricity purchases were adjusted by
         a loss factor to reflect losses incurred in the transmission and distribution of electricity. The geographic
         distribution of electricity purchases were assumed to be the same as those of the industrial class. This customer
         class distribution was based on data collected by EIA on sales, by customer class, on all  electricity providers
         (from EIA Form 861).9

13.2.3   Key               and
         Electricity and fossil fuel combustion emission estimates include only CC^. Emissions of other greenhouse
         gases  such as CFLjand N2O that may result  from combustion were not estimated.10 Emission factors for
         purchased electricity provided by eGRID are for 2004, which may include different fuel mixes for electricity
         generation than those of the 2002 inventory year.

13.3    Greenhouse Gas Emissions (1998,2002)
         GHG emissions for select years from purchased electricity and fossil fuel combustion consist of two data
         points based on data availability from MECS for the years 1998 and 2002.11 Overall process-related emissions
         3 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
         http://www.eia.doe.gov/emeu/mecs/mecs2002.
         4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
         5 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007,
         http://www.ipcc-naaip.iaes.or.ip/public/2006gl/index.htm.
         6 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey.
         1 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, May 2007,
         http://www.epa.aov/cleanenerav/egrid/index.htm.
         8 The National Reliability Electricity Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric power
         grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
         9 U.S. Department of Energy, Annual Electric Power Industry Report: Form EIA-861, Energy Information Administration,
         http://www.eia.doe.aov/cneaf/electricitv/page/eia861.html.
         10 These non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
         11 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
         level of significance; therefore, the reader may not be able to reproduce the calculation.
U.S. Environmental Protection Agency                       WORKING DRAFT (May 2008)                                 13-3

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Plastic and Rubber Products
        have decreased by approximately 6% over the time-series, from 47.2 to 44.5 MMTCC^E. Over the same
        period, value added12 in plastic and rubber products remained relatively unchanged — increasing 0.2%.
        Figure 13-3: Greenhouse Gas Emissions for the Plastic and Rubber Products Sector
         o
                   1998
                               1999         2000         2001

                                    • Fossil Fuel Combustion
             2002         2003

                • Purchased Electricity
                                                                                           2004
                                                                                                       2005
13.4   Other Sources of Greenhouse Gas Emission Estimates for this Sector

        No reports containing complete GHG emissions estimates for the plastic and rubber products sector were
        identified.

13.5   Sector Emission Reduction Commitments

        No sector  commitments to reducing GHG emissions were identified.

13.6   Reporting Protocols
        When calculating emissions, one of the following protocols may be used by companies in the plastic and
        rubber products sector:

        •   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below;

        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and

        •   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
            (WRI) Greenhouse Gas Protocol.

        No public  reports of GHG emissions from companies in the plastic and rubber products sector were
        identified.
        12 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
        http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
U.S. Environmental Protection Agency
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14.    Semiconductors
        Semiconductors form the heart of many modern technologies. A semiconductor is a solid that has electrical
        conductivity between that of a conductor and that of an insulator. Semiconductors operate many electronic
        devices ranging from cell phones to computers.
        Other examples of semiconductor products include
        microprocessors, memory chips, integrated circuits,
                                                             Source
                                                 2002
                                              Emissions
                                             (MMTC02E)
                                                             Fossil Fuel Combustion
                                                             Non-Combustion
                                                             Purchased Electricity
                                                             Total
                                                             Percent of U.S. Industrial Emissions1
                                                    1
                                                    4
                                                    8
                                                   13
                                                   1%
        diodes, transistors, and solar cells.
        The process of semiconductor manufacturing
        (NAICS code 334413: Semiconductor and Related
        Device Manufacturing) produces semiconductors
        and related solid state devices.

14.1    Sources of Greenhouse Gas Emissions

        The direct sources of GHG emissions due to semiconductor manufacturing result from industrial processes
        (i.e., non-combustion activities) and on-site fossil fuel combustion. The indirect sources of GHG emissions due
        to semiconductor manufacturing result from the purchased electricity consumed in manufacturing operations.
        As described in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,2 direct non-combustion
        emissions from semiconductor manufacturing result from the use of a variety of high global warming potential
        (GWP) gases to etch patterns onto dielectric films to provide pathways for conducting material to connect
        circuitry, as well as to rapidly clean chemical vapor deposition (CVD) tool chambers. The perfluorocarbons
        (PFCs) used in these processes (CF4, C2p6, and CsF8, as well as HFC-23, SF6, and NF3) are vital for the
        development of significantly more complex semiconductor products.3 The materials removed during the
        production process and cleaning of CVD chambers, as well as the undissociated gases, are emitted into the
        atmosphere unless abatement systems are employed. Under normal operating conditions, anywhere  from 10%
        to 80% of these gases are emitted.3
        The manufacture of semiconductors requires energy for both the manufacturing and the semiconductor
        handling equipment, as well as for the heating, ventilation, and air conditioning equipment required  to maintain
        sanitary production conditions. This energy use results in direct emissions of CC>2 from fossil fuel combustion
        and indirect CCh emissions from purchased electricity.

14.2    Summary of Emissions (2002)

        This section presents a summary of the GHG emission estimates for the semiconductor  sector as estimated for
        the year 2002. The methodologies and data sources used to calculate  these emission estimates, as well as the
        assumptions and limitations surrounding the estimates, are also described.

14.2.1   Estimates of Greenhouse Gas Emissions (2002)
        The total GHG emissions from the semiconductor sector are estimated to be 13 MMTCC>2E in 2002  (as seen in
        Table 14-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions andSinks: 1990-2005. See U.S.
        Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15 Apr 2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16.
        2 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        3 U.S. Environmental Protection Agency, "PFC Reduction/Climate Partnership for the Semiconductor Industry," 15 Mar 2007, http://www.epa.gov/semiconductor-
        pfc/index.html.
U.S. Environmental Protection Agency
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Semiconductors
                              Table 14-1: 2002 GHG Emissions from the Semiconductor Sector (MMTC02E)

Fossil Fuel Combustion3
Non-Cornbustionb
Semiconductor Manufacturing
Purchased Electricity0
Total
C02 MFCs
1
<1
<1
8
9 <1
PFCs

3
3

3


1
1

1

1
4
4
8
13
                      a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S.
                      Greenhouse Gas Emissbns and Sinks: 1990-2005.
                      b EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
                      c Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and Generation
                      Resource Integrated Database (eGRID).
                      Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the
                      analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information.
         The overall methodology for estimating the GHG emissions for this report was described in Section 1.2; more detail
         on the methodology used to estimate emissions from the semiconductor sector can be found in Section 14.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site  fossil fuel
         combustion and purchased electricity), is illustrated in Figure 14-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 14-2.
         Figure 14-1: 2002 Energy Consumption in the
         Semiconductor Sector, by Fuel Type (TBtu)
                                            Electricity
          Natural Gas
             32%
             Figure 14-2: 2002 C02 Emissions from Energy
             Consumption in the Semiconductor Sector, by Fuel Type
             (MMTC02E)
                                                                          Natural Gas
                                                                             13%
                                  Total:
                                      Total:
                                                  Electricity3
9 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         Note: TBtu stands for trillion British thermal units.
             Source: Estimate based on methodology in Section 14.2.2.
             a Fuel mix at utilities was taken into consideration in this calculation, per
             methodology described in Section 14.2.2.
14.2.2   Methodology and Data Sources

         Fossil Fuel Combustion

         Fossil fuel combustion emissions from the semiconductor sector were derived from the U.S. Department of
         Energy's (DOE) Energy Information Administration's (EIA) Manufacturing "Energy Consumption Survey (MEGS)4
         4 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
         http://www.eia.doe.aov/emeu/mecs/mecs2002.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Semiconductors
        estimates of fuel consumption for this sector. Those fuel consumption estimates were then multiplied by the
        appropriate, fuel-specific emission factors to convert the consumption into CC>2 emitted.
        The emission factors for the fossil fuels used in the semiconductor manufacturing industry were taken from the
        Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.

        Non-Combustion Activities
        Non-combustion emissions of PFCs from semiconductor manufacturing were those reported for the
        Semiconductor Manufacturing source category within the Inventory of U.S. Greenhouse Gas Emissions and Sinks:
        1990-2005? These estimates include the semiconductor manufacturing emissions identified by the
        Intergovernmental Panel on Climate Change's (IPCC) 2006IPCC Guidelines for National Greenhouse Gas
        Inventories.6

        Purchased Electricity
        Electricity emissions were estimated by mapping national electricity purchases (in kilowatt-hours, or kWh)
        provided by MECS to North American Electricity Reliability Corporation (NERC) regions,7 then applying
        NERC regional utility CC>2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
        adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.
        Since electricity purchase data were not available  at the NERC regional level, distribution of the sector's value
        added was used to distribute the sector's national electricity purchases  to the state-level, then state  data were
        rolled up to the NERC regions. Where a state lay in two or more NERC regions, electricity purchases were
        distributed to the appropriate NERC region using sales data for the industrial customer class from EIA Report
        861. This approach assumes that the electricity-intensity of production activities are correlated with the value
        added. Methods  for estimating CC>2 emissions from electricity are described in more detail in Appendix A.3.

14,2.3   Key              and
        Non-combustion emission estimates were limited to sources identified by the 2006 IPCC Guidelines for National
        Greenhouse Gas Inventories and provided in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        Electricity and fossil fuel combustion emission estimates include only CO2- Emissions of other GHGs (e.g.,
        CHUand N2O) that may result from combustion were not estimated.8 Emission factors for purchased electricity
        provided by eGRID are for 2004, which may include different fuel mixes for electricity generation than those
        of the 2002 inventory year.

14.3   Greenhouse Gas Emissions (1998,2002)

        GHG emissions for select years  from the semiconductor sector are shown in Figure 14-3.9
        Annual estimates of non-combustion GHG emissions from semiconductor manufacturing were available from
        the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, which show that such emissions have
        decreased by 39% between 1998 and 2005, from 7.1 to 4.3 MMTCO2E.

        However, the data for GHG emissions from fossil  fuel combustion and purchased electricity were available
        only for two data points, 1998 and 2002, based on frequency of MECS reports. During this period, emissions
        from fossil fuel combustion increased by 5%, and emissions from purchased electricity declined by 6%, from
        8.0 to 7.5 MMTCO2E.
        5 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        6 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007, http://www.ipcc-
        naaip.iaes.or.ip/public/2006g I/index.htm.
        7 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        8 These non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        9 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
U.S. Environmental Protection Agency                       WORKING DRAFT (May 2008)                                14-3

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Semiconductors
        In aggregate, emissions from the semiconductor sector decreased 20% between 1998 and 2002. Over the same
        period, value added10 in semiconductor manufacturing decreased 31%.
        Figure 14-3: Greenhouse Gas Emissions for the Semiconductor Sector
         o
         o
                  1998
                               1999          2000

                              • Fossil Fuel Combustion
 2001          2002

ZZI Purchased Electricity
 2003          2004

Non-Combustion
                                                                                                       2005
14.4   Other Sources of Greenhouse Gas Emission  Estimates for this Sector

        No reports containing complete GHG emissions estimates for the semiconductor sector were identified.

14.5   Sector Emission Reduction Commitments

        The members of the PFC Reduction/Climate Partnership for the Semiconductor Industry have committed to
        reduce their absolute PFC emissions to 10% below 1995 levels by 2010.n

14.6   Reporting Protocols
        When calculating emissions, one of the following protocols is typically used by companies in the
        semiconductor sector:

        •   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below;

        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program',

        *   The World Business  Council for Sustainable Development (WBCSD)  and the World Resource Institute's
            (WRI) Greenhouse Gas Protocol; and

        •   Intergovernmental Panel on Climate Change Good Practice Inventory Tier 2 Methods for the Semiconductor Industry for
            PFC reduction reporting.
        10 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
        http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
        11 See http://www.climatevision.gov/sectors/semiconductors/index.html.
U.S. Environmental Protection Agency
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Semiconductors
        Table 14-2 presents a sample of companies that have publicly reported their GHG emissions.

                       Table 14-2: Sampling of Publicly-Reported GHG Emissions for Semiconductor Companies
        12 National Semiconductor Corporation, "CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas Emissions Questionnaire,"
        12 Nov 2007, http://www.cdproiect.net/responses/National Semiconductor Corporation  Corporate GHG Emissions Response CDP5  2007/public.htm.
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15.    Textiles
        Textiles are materials consisting of synthetic or natural fibers that are sewn together to produce apparel (e.g.,
        shirts, pants) and non-apparel items—such as sheets or blankets. For the purposes of this report, the textile
        sector is defined by NAICS codes 313, 314, and
        315, which consist of textile mills, textile product
        mills, and apparel manufacturers, respectively.
        These sub-sectors form products by transforming
        basic natural or synthetic fibers into  a manufactured
        good, but do generate the synthetic fibers.
         Source
         Fossil Fuel Combustion
         Non-Combustion
         Purchased Electricity
         Total
         Percent of U. S. Industrial Emissions1
                                                                                                       2002
                                                                                                    Emissions
                                                                                                   (MMTC02E)
                                                                                                         10
                                                                                                         21
                                                                                                         32
                                                                                                        2%
        Textile mills transform a basic fiber (natural or
        synthetic) into a product, such as yarn or fabric that
        is further manufactured into usable items, such as
        apparel, sheets, towels, and textile bags for
        individual or industrial consumption. Further manufacturing may occur in the same establishment or it may be
        performed at a separate establishment such as a textile product mill. The main processes in this subsector
        include preparation and spinning of fiber, knitting or weaving of fabric, and the finishing of the textile.

        Textile product mills make textile products other than apparels, which are made at an apparel manufacturer.
        Generally, textile product mills cut and sew textiles to produce non-apparel items such as towels.

        Apparel manufacturers make ready-to-wear custom apparel from the textile usually through a cut and sew
        process or by first knitting the fabric and then cutting and sewing the fabric into a garment. Only when knitting
        is combined with garment production is the process classified as apparel manufacturing; knitting fabric for later
        manufacturing into apparel is classified under textile mills.

15.1    Sources of Greenhouse  Gas Emissions

        GHG emissions from the textile sector result from on-site fossil fuel combustion and, indirectly, through the
        purchase of electricity. The primary fossil fuel consumed is natural gas, which is largely used to heat boilers that
        provide steam and or dry fabric. Manufacturing textiles (both at the  mill level or the factory level) requires
        electricity for both the manufacturing and handling equipment, as well as for various processes like heating,
        drying, cooling, finishing, dying, and other common processing techniques. Processes that consume the most
        energy in this sector are drying and application of various finishes.

15.2    Summary  of Emissions (2002)

        This section presents  a summary of the GHG emission estimates for the textile sector for the year 2002. The
        methodologies and data sources used to calculate these emission estimates, as well as the assumptions and
        limitations surrounding the estimates, are also described.

15.2.1   Estimates of Greenhouse Gas Emissions (2002)
        The total GHG emissions from the textiles sector are estimated to be 32 MMTCG^E in 2002 (as seen in Table
        15-1).
        1 Total 2002 industrial emissions are 2,047 MMTC02E as reported in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005. See U.S. Environmental
        Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005,15Apr2007,
        http://www.epa.aov/climatechanae/emissions/usinventorvreport.html. Table 2-16. Note that for the purpose of this report, a blank cell does not necessarily indicate zero
        emissions; rather, it indicates that the analysis did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information. Totals
        may not sum due to independent rounding.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Textiles
                                   Table 15-1: 2002 GHG Emissions from the Textile Sector (MMTC02E)

Fossil Fuel Combustion3

10
CH4 N20 MFCs Total
10
Non-Combustion
Purchased Electricity15
Total
21
32
21
32
                     a Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Inventory of U.S. Greenhouse
                     Gas Emissions and Sinks: 1990-2005.
                     b Emissions calculated based on DOE's 2002 Manufacturing Energy Consumption Survey and EPA's Emissions and Generation
                     Resource Integrated Database (eGRID).
                     Note that for the purpose of this report, a blank cell does not necessarily indicate zero emissions; rather, it indicates that the analysis
                     did not address that emission source, if applicable; see "Summary of Emissions (2002)" for additional information. Totals may not sum
                     due to independent rounding.
         The overall methodology for estimating GHG emissions in this report is described in Section 1.2; more detail
         on the methodology used to estimate emissions  from the textile sector can be found in Section 15.2.2.

         The distribution of energy consumption in this sector, by fuel type (including both on-site fossil fuel
         combustion and purchased electricity), is illustrated in Figure 15-1. For comparison, CO2 emissions associated
         with fuel consumption are shown in Figure 15-2.
         Figure 15-1: 2002 Energy Consumption in the Textiles
         Sector by Fuel Type (TBtu)
                       Figure 15-2: 2002 C02 Emissions from Energy
                       Consumption in the Textiles Sector, by Fuel Type
                       (MMTC02E)
                   Other
         Residual Fuel Oil
              2%
                         LPG and NGL
                              1%
Electricity
  41%
                  Distillate Fuel Oil
                                            \  Natural Gas
                                                  42%
                                        Total:
LPG and NGL
    1%
                  Residual Fuel Oil
                        2%
                                                                                                                       Electricity3
                            Distillate Fuel Oil
                                         Natural
                                            19%
                                                       Total:
                         32 MMTC02E
         Source: DOE, 2002 Manufacturing Energy Consumption Survey.
         Note that composition of "other" fuel category varies among sectors.
         Note: TBtu stands for trillion British thermal units.
                      Source: Estimate based on methodology in Section 15.2.2.
                      a Fuel mix at utilities was taken into consideration in this calculation, per
                      methodology described in Section 15.2.2.
U.S. Environmental Protection Agency
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Textiles	


15.2,2                and

         Foss/7 Fuel Combustion
         The fossil fuel combustion estimate for textile manufacturing is derived using the U.S. Department of Energy's
         (DOE) Energy Information Administration's (EIA) Manufacturing Energy Consumption Survey 2 (MEGS) estimates
         of fuel consumption for textile manufacturing. Fuel consumption estimates were multiplied by appropriate,
         fuel-specific emission factors to convert the consumption into CC>2 emitted. The emission factors for the fossil
         fuels used in the textile sector were taken from data contained in the Inventory of U.S. Greenhouse Gas Emissions
         and Sinks: 1990-2005? "Other" CO2 emissions were calculated by applying an emission factor for
         "miscellaneous products" based on carbon contents from the Inventory of U.S. Greenhouse Gas Emissions and Sinks:
         1990-2005.

         Non-Combustion Activities
         Non-combustion emissions would include GHG emissions that occur from activities within the sector that are
         not related to on-site fossil fuel consumption or purchased energy. Non-combustion emissions were not
         specifically identified for this sector by the Intergovernmental Panel on Climate Change's (IPCC) 2006IPCC
         Guidelines for National Greenhouse Gas Inventories^ and, hence, were not included in the Inventory of U.S. Greenhouse
         Gas Emissions and Sinks: 1990-2005 or this report.

         Purchased Electricity
         Electricity emissions were  estimated by mapping national electricity purchases  (in kilowatt-hours, or kWh)
         provided by MECS to North American Electricity Reliability Corporation (NERC) regions,5 then applying
         NERC regional utility CO2 emission factor (in Ibs/kWh) provided by eGRID. Sector electricity purchases were
         adjusted by a loss factor to reflect losses incurred in the transmission and distribution of electricity.

         Since electricity purchase data were not available at the NERC regional level, distribution of the sector's value
         added was used to distribute the sector's national electricity purchases to the state-level, then state data were
         rolled up to the NERC regions. Where a state lay in two or more NERC regions, electricity purchases were
         distributed to the appropriate NERC region using sales data for the industrial customer class from EIA Report
         861. This approach assumes that the electricity-intensity of production activities are correlated with the value
         added. Methods for estimating CO2 emissions from electricity are described in more detail in Appendix A.3.

15.2.3   Key              and
         Electricity and  fossil fuel combustion emission estimates include only CO2. Emissions of other greenhouse
         gases such as CFLjand N2O that may result from combustion were not estimated.6 Emission factors for
         purchased electricity provided by eGRID are for 2004, which may include different fuel mixes for electricity
         generation than those of the 2002 inventory year.

15.3    Greenhouse Gas  Emissions (1998,2002)

         GHG emissions for select years from the textiles sector are shown in Figure 15-3.7
        2 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration, 24 Jan 2005,
        http://www.eia.doe.gov/emeu/mecs/mecs2002.
        3 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005.
        4 Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007,
        http://www.ipcc-nqaip.iaes.or.ip/public/2006gl/index.htm.
        5 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
        6 These non-C02 emissions typically account for only a small percentage (approximately 2%) of a sector's GHG emissions from fossil fuel combustion.
        7 Note: in the following discussion, the percentages shown are calculated from the raw data. However, rounded data values are given in the text at an appropriate
        level of significance; therefore, the reader may not be able to reproduce the calculation.
U.S. Environmental Protection Agency                       WORKING DRAFT (May 2008)                                15-3

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Textiles
        GHG emissions from purchased electricity and fossil fuel combustion consist of two data points based on data
        availability from MEGS for the years 1998 and 2002. These process-related emissions have decreased by 19%
        over the time-series, from 39.1 to 31.5 MMTCG^E in 1998 and 2002, respectively. Over the same period, value
        added8 in textiles manufacturing decreased 29%.
         Figure 15-3: Greenhouse Gas Emissions for the Textile Sector
                    1998          1999          2000          2001          2002          2003          2004          2005
                                     • Fossil Fuel Combustion               • Purchased Bectrlclty
15.4   Other Sources of Greenhouse Gas Emission  Estimates for this Sector
        No reports containing complete GHG emissions estimates for the textiles sector were identified.
15.5   Sector Emission Reduction Commitments
        No sector commitments to reducing GHG emissions were identified.
15.6   Reporting Protocols
        When calculating emissions, one of the following three protocols may be used by companies in the textile
        sector:
        •   EPA's Climate leaders Greenhouse Gas Inventory Protocol, which is an enhanced version of the WBCSD/WRI
            protocol mentioned below;
        •   DOE's Technical Guidelines: Voluntary Reporting of Greenhouse Gases (1605(b)) Program', and
        •   The World Business Council for Sustainable Development (WBCSD) and the World Resource Institute's
            (WRI) Greenhouse Gas Protocol.
        No public reports of GHG emissions from companies in the textile sector were identified.
        8 Value added is a measure of the enhancement a company gives its product or service before offering the product to customers. It is used here as a surrogate for
        production. Value added is considered to be the best value measure available for comparing the relative economic importance of manufacturing among industries
        and geographic areas (source: U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005,
        http://www.census.gov/mcd/asm-as1.htmll. The data were normalized to account for fluctuation in industry size or production over time; dollars were adjusted for
        inflation using a gross domestic product price deflator.
U.S. Environmental Protection Agency                       WORKING DRAFT (May 2008)                               15-4

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       Appendices
       The following appendices contain additional information on data sources and factors used to calculate emission
       estimates presented in the main body of this report.
       A.I Key Data Sources
       A.2 Emission Factors for On-site Fossil Fuel Combustion
       A.3 Emissions Estimation Methods for Electricity Purchases
       A.4 General Conversion Factors & Global Warming Potentials
       A.5 Energy Consumption Data
       A.6 CC>2 Emissions for "Other" Fuels
       A.7 Reporting Protocols
       A. 8 Economic Data
       A.9 List of Acronyms
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Appendices
        A.1  Key Data Sources
        Data used to estimate GHG emissions from the 14 sectors included in this report were taken from a variety of
        sources. The following section describes in more detail some of the key data sources used, placed into
        categories by type of data provided (energy consumption, emission estimates, economic data).
        U.S. Department of Energy, Energy Information Administration, 2005. 2002 Manufacturing Energy Consumption
        Survey
        The Manufacturing "Energy Consumption Survey (MEGS) is produced every four years by DOE/EIA. The
        manufacturing sector is defined by EIA as consisting of all manufacturing establishments in all 50 U.S. states
        and the District of Columbia. Data from the survey are based on a nationally representative sample of
        manufacturing establishments, which supply the information through mailed questionnaires. The 2002 MEGS
        sample size was approximately  15,500 establishments drawn from a sample frame representing 97-98% of the
        manufacturing payroll, which is approximately 60% of the establishments of the manufacturing sector.1 MEGS
        data provide energy consumption by fuel type, including electricity, natural gas, residual fuel oil, distillate fuel
        oil, liquid petroleum gas, coal, coke, and other. The composition of the "other" category varies from sector to
        sector. More detail is provided in individual sector chapters.
        Available online at: http://www.eia.doe.gov/emeu/mecs/contents.html



        U.S. Environmental Protection Agency, 2007.  Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005
        The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 is the official GHG emissions inventory
        submission of the United States produced by EPA in order to comply with commitments under the United
        Nations Framework Convention on Climate Change (UNFCCC). It is prepared according to the official
        reporting guidelines established by UNFCCC. The inventory contains estimates of national anthropogenic
        GHG emissions and sinks for source categories including Energy; Industrial Processes; Agriculture; Land Use,
        Land-Use Change, and Forestry; and Waste. The inventory describes the processes from these source
        categories that result in GHG emissions. Data for this report taken from the inventory were largely related to
        non-combustion estimates and information on these processes.
        Available online at: http://www.epa.gov/climatechange/emissions/usinventoryreport.html

        U.S. Department of Energy, Energy Information Administration, 2006. Energy-Related Carbon Dioxide Emissions in
        U.S. Manufacturing
        EIA's Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing estimates energy-related CC>2 emissions from
        manufacturing in 2002 based upon energy consumption statistics from MEGS. The report focuses on 23 of the
        473 six-digit North American Industry Classification System (NAICS) industries. The report provides some
        additional description regarding petroleum refineries, natural gas and electricity in the chemical manufacturing
        sector, iron and steel mills, nonmetallic mineral products, and trends in carbon dioxide intensity for some but
        not all sectors from 1991 to 2002.

        Available online at: http://www.eia.doe.gov/oiaf/1605/ggrpt/pdf/industry_mecs.pdf

        U. S Environmental Protection Agency, Emissions and Generation Resource Integrated Database
        The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive inventory of environmental
        attributes of the electric power system developed and maintained by EPA. It is based on the available plant-
        1 U.S. Department of Energy, "2002 Manufacturing Energy Consumption Survey," Energy Information Administration, 24 Jan 2005
        http://www.eia.doe.aov/emeu/mecs/mecs2002.
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Appendices
        specific data for all U.S. electricity generating plants that provide power to the electric grid and report data to
        the U.S. government. eGRID contains generation data and air emissions data for nitrogen oxides, sulfur
        dioxide, CO2, and mercury. eGRID provides estimates of CO2 emissions factors (in Ibs per kWh of
        generation). These factors are provided at the national, NERC2 regional, NERC sub-regional, power control
        area, and state level.

        Available online at: http://www.epa.gov/cleanenergy/egrid

        The Global Reporting Initiative
        The Global Reporting Initiative (GRI) is host to company-specific GHG emission information. Many
        companies  report their GHG emissions to the GRI through a Corporate Sustainability Report. The reports
        require that the companies state what protocol they use when estimating their emissions. Each company's
        report is used to gauge organizational performance, demonstrate commitment, and compare performance over
        time. The goal of GRI is to stimulate the demand for sustainability information, which they hope will benefit
        the reporting organizations and the consumers who use this information.
        Available online at: http://www.globalreporting.org/AboutGRI/WhatWeDo/

        The Carbon Disclosure Project
        The Carbon Disclosure Project (CDP) seeks information on risks and opportunities presented by climate
        change for  the world's largest companies. These companies use the project's methodology and process for
        disclosing GHG emissions. The CDP has the world's largest repository of corporate GHG emissions data and
        hopes that by making this information publicly available it will stimulate policymakers, stakeholders,
        consultants, accountants and marketers to take action.
        Available online at: http://www.cdproject.net
        U.S. Census Bureau, 2004. 2002 Economic Census: Industry Series Schedule
        The U.S. Census Bureau's Economic Census profiles businesses every five years. The Industry Series reports
        contain fuel consumption data for some sectors (e.g., Mining) and dollars spent on fuel and electricity for other
        sectors (e.g., Construction). Census forms are mailed to more than five million companies. The Economic
        Census is mandated by law under Title 13 of the United States Code. Industries are classified based on the
        NAICS 2002 manual.
        Available online at: http://www.census.gov/econ/census02/guide/INDSUMM.HTM

        U.S. Geologic Survey, 1998 and 2002. USGS Minerals Yearbook
        The Minerals Yearbook is an annual publication that contains data on materials and minerals, including
        information on economic and technical trends and developments. It includes information on approximately 90
        commodities and over 175 countries. Production data from the yearbook was used to estimate emissions for
        some sectors, such as cement.
        Available online at: http://minerals.usgs.gov/minerals/pubs/myb.html
        2 The North American Electricity Reliability Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within with the owners of generation operate.
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Appendices
        A.2 Emission  Factors for On-site Fossil Fuel Combustion

        Table A-l presents the fuel-specific emission factors used in calculating GHG emission estimates from fossil
        fuel combustion in this report. For some sectors that derive their emission estimate using MEGS data, energy
        consumption listed in the "other" category was distributed by fuel type. This distribution was estimated
        according to the different types of byproduct fuels, which may include waste gases, petroleum coke, purchased
        steam, and waste oils, among others.3

                                         Table A-1: GHG Emission Factors by Fuel Type4

                                              Fuel                           0,079
                                              Fuel                           0,073
                                            Gas                             0,053
                                     Liquefied Petroleum                      0,062
                                     Coal                                    0,094
                                     Coal Coke                              0,114
                                     Motor                                   0,071
                                     Misc. Products                          0,074
                                     Coke Oven Gas                         0,047
                                     Blast Furnace Gas                       0,274
                                  Other
                                     Still Gas                                0,064
                                     Petroleum Coke                         0,102
                                                                             0,068
                                            Gas                              0,064
                                            Oils                              0,074
                                     Other Fuels (mostly petroleum)            0,074
                                            Gas                             0,053
                                     Tires                                   0,093
        3 Steam purchases were determined using MEGS Table 7.7, which provides the amount of steam purchased from a non-utility. Steam purchased from a utility was
        excluded due to double counting. The remaining "other fuel" was calculated by subtracting purchased steam and byproduct fuels from total "other fuel."
        4 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2005,15 Apr 2007,
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
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Appendices
        A.3 Emission  Estimation Methods for Electricity Purchases

        This appendix describes four different methods that were used to estimate CC>2 emissions associated with the
        generation of electricity purchased by the industrial sectors in this report.
        The primary differences across the sectors relate to (1) the disaggregation to regions of the electricity purchase
        estimates to capture the unique geographic distribution of each of the 14 sectors, and (2) the level of
        disaggregation in the estimate of carbon intensity per kWh of electricity generated to meet the sector's demand.
        Disaggregating to the extent data allow is important in order to capture the relative differences in the
        characteristics of electricity generation in the various regions. Specifically, Method 1 applies a national utility
        emissions factor for electricity generation to national electricity demand data for a sector, while Methods 2, 3,
        and 4 allocate the sector's electricity demand to NERC regions using a proxy (distribution of industrial
        demand, distribution of sector's value-add, or distribution of sector's production capacity) and then apply
        NERC regional utility emission factors to estimate total emissions. These methods are summarized in Table A-
        2 and are described in more detail. The latter three methods account for differences in emissions due to varying
        fuel mixes used by utilities in different regions of the country. For example, iron and steel manufacturers tend
        to be concentrated in the Midwest, while cement manufacturers are more dispersed throughout the country.
        This will influence the overall carbon emissions  associated with the two sectors' electricity consumption.
                                     Table A-2: Summary of Electricity Emissions Methodology
        Method
        Method 1: National-Level
        Estimates

        Method 2: Regional-
        Level Estimates/
        Customer Class
        Disaggregation
        Method 3: Regional
        Estimates with Sector
        Level Disaggregation
        Method 4: Facility Level
        Estimates
Description
Applied to:
National-level electricity purchases, adjusted for transmission and   Food and Beverages
distribution (T&D) and national emissions factor for electricity
generation
National and regional (census-based) electricity purchase
estimates (adjusted for T&D losses) distributed geographically
based on historic distribution and regional electricity factors
Plastic and Rubber Products, Construction
National and regional (census-based) electricity purchase
estimates (adjusted for T&D losses) are disaggregated further to
states based on value added data.
Information on facility level capacity, and regional utilization
estimates and/or electricity intensity estimates are used to
estimate production level at the plant level. National level
electricity demand is than allocated to plants based on these
factors and appropriate emissions factors are applied to derive
total emissions.
Mining, Oil and Gas (Production), Textiles,
Metal Casting, Semiconductors, Forest
Products, Chemicals, Lime
Alumina and Aluminum, Oil and Gas
(Refining), Cement, Iron and Steel
        Data Sources
        Purchased Electricity. Purchased electricity data is taken from the best available source data. Generally,
        electricity estimates were based on U.S. Department of Energy (DOE), Energy Information Administration
        (EIA) ManufacturingElectricity Consumption Survey (MEGS) data for 2002 and 1998. Specifically, data on purchased
        electricity (as opposed to consumed electricity) were used (see MEGS Table 3.1). For oil and gas, mining, and
        construction, alternative sources are used.  For mining and oil and gas production,  data from U.S. Census
        Bureau's  2002 and 1997 Economic Census Industry Series Reports: Mining are used. For  construction, data from the
        U.S. Census Bureau's 2002 and 1997 Economic Census Industry Series Reports: Construction are used.
        For all sectors, these data reflect electricity purchases from the grid and excludes consumption of electricity
        generated onsite, as these emissions are accounted for in the direct fossil fuel combustion emission estimates.
        These data reflect purchases at the end-use site and so must be adjusted for losses incurred in the transmission
        and distribution  of the electricity from the generating station. For all methods and all sectors,  electricity
        demand data was adjusted upward to account  for losses associated with transmission and distribution (T&D) of
        electricity. Loss factors were developed based  on generation and sales data collected by EIA.
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        Customer Sector Geographic Distribution. The carbon associated with electricity purchases depends in part
        on the location of the sector's facilities. Different regions of the country may have different mixes of generating
        technologies and fuel sources. A region more heavily dependent on coal-fired resources will have higher-
        intensity electricity production, while regions with larger shares of nuclear, renewables, and hydro resources will
        have lower intensities.

        Because the grid is highly interconnected and each facility buys from a coordinated grid, it is only necessary to
        determine the broad geographic region within which a sector's facilities are located. However, determining
        where electricity demand occurs within a sector is not readily done without plant-specific data. Therefore,
        where no facility data were available, simpler methods using proxies for electricity demand were used (as
        described below).

        Value added for each of the sectors is used as a proxy for distribution of electricity demand under Method 3.
        States with higher estimates of value added for a sector (based on Economic Census data) are presumed to have  a
        proportionally higher share of demand for electricity. Using this as a proxy assumes that the electricity intensity
        of production activities are correlated with value added. This may not be the case for industries with diverse
        products and/or processes; however, absent a better indicator, this method using value added was applied.

        For some sectors, value added data were not reported for certain states due to U.S. Census disclosure
        restrictions. Therefore, where the missing data were deemed to be significant, missing values were estimated for
        those states without reported data. Value added estimates were developed based on the assumption that all
        non-reporting establishments had a value added equal to the average of all non-reporting establishments. The
        Census reports total national-level value added for a sector and the number of non-reporting establishments,
        allowing one to  estimate the average value added for missing establishments.

        The relative share of a sector's total added value is used to apportion electricity demand to the states as
        described in Method 3.

        Electricity Emission Factors are provided by eGRID.5 The eGRID database combines plant-specific
        generation data  and CC>2 emission estimates for U.S. electricity generating plants that provide power to the
        electric grid and report data to the U.S. government in order to estimate CC>2 emissions factors (in Ibs  per kWh
        of generation) at the national, NERC6 regional, NERC sub-regional, power control area, and state levels.

        Two vintages of eGRID were used: 1998 for the 1998 estimates and 2004 for the 2002 estimates. The  eGRID
        database does not provide 2002 data, so 2004 data was used to create  estimates. For each year, two types of
        emission factors are used. The first is a national-level emission factor  (in Ibs/kWh)  that represents the  average
        carbon intensity of the entire U.S. electricity system. The second emission factors are regional estimates
        representing the carbon intensity of generation of each NERC region. In  2004, estimates for nine NERC
        regions are defined in the eGRID data, while in 1998 twelve NERC regions are defined.

        Table A-3 shows the eGRID data used in the analyses. NERC regional definitions have changed over  time —
        both in terms of their name, but more importantly in their geographic definitions -  as new reliability
        organizations have formed and power generators  have decided to move from one organization to another.
        Figure A-l illustrates the NERC regional structures applicable to the 2004 eGRID data set.7
        5 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
        http://www.epa.aov/cleanenerav/egrid/index.htm.
        6 The North American Reliability Electricity Corporation (NERC) is the designated reliability organization that has a role in overseeing the reliability of the electric
        power grid. NERC regions reflect the organization structure of the regional reliability entities within which the owners of generation operate.
        7 NERC maps for eGRID 1998 were unavailable from government sources. The images available at the following website were assumed to be similar to the 1998
        eGRID regions. The one notable exception was that Kentucky was changed to be part of SERC (rather than ECAR) to be consistent with the 2004 eGRID
        methodology. See http://www.areen-e.org/docsA/erificationReport03.pdf.
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Appendices
                                       Table A-3: eGRID COa Emissions Factors, 2002 and 1998
         (eGRID 2004 region)
         NPCC
2002 C02 Emission
Rate (Ibs/kWh)
(Based on 2004 eGRID)
      0.91
(eGRID 1998 region)
NPCC
 I998 C02 Emission
Rate (ibs/kWh)
(Based on 2002 eGRID
data release)
        1.02
Fraction of 1998
region that is part
of 2004 region
         all
         RFC
      1.43
ECAR
        2.01
         Source data:
         eGRID2002 Version 2.01 Location (Operator)-Based NERC Region File (Year 1998 Data)
         eGRID2006 Version 2.1 NERC Region Location (Operator)-based File (Year 2004 Data)
         all


MRO

ERGOT
FRCC
SERC

SPP
WECC
ASCC
HICC
National


1.82

1.42
1.33
1.39

1.83
1.11
1.11
1.65
1.36
MAAC
MAIN
MAPP
MAIN
ERGOT
FRCC
SERC
MAIN
SPP
WSCC
ASCC
HICC
National
1.20
1.55
1.95
1.55
1.42
1.48
1.30
1.55
1.85
1.00
1.38
1.60
1.42
all
part
all
part
all
all
all
part
all
all
all
all

         Figure A-1: 2004 eGRID NERC Regional Structure for 2002 Data8
         8 U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database (eGRID) v2.1, 21 May 2007,
         http://www.epa.aov/cleanenerav/egrid/index.htm.
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        The differences in regional definitions of NERC regions in 1998 and 2004 are the result of the evolution of
        membership of the reliability system organizations, and of most recent eGRID's particular methodology. As
        opposed to the year of the reported data, 2004, eGRID defines the NERC geography to be consistent with that
        in place at the time of the eGRID release, 2006. For example, the state of Kentucky in 1998 was largely in the
        ECAR region, as defined by NERC and eGRID. In the 2004 eGRID data, Kentucky is located in the SERC
        region.9 The result of this shift in the NERC regional definitions is that the CC>2 emission factor applicable to
        some regions changes from 1998 to 2006 as a result not only of the changes in the makeup of the generating
        system over time, but also due to the shift in membership of the reliability organizations and in generation
        included in each region relative to 1998. On a national level the shift  in eGRID data locations changes the
        relative carbon intensities of the regions. For each year's analysis, the facility and regional data were assigned to
        the appropriate eGRID region.

                   of
        Four methods for estimating emissions  from purchased electricity were used in this report. A summary of
        which method was applied to which sector can be found in Table A-2.

        Method 1: National-Level Estimates
        Estimates of emissions associated with electricity consumption in each sector were estimated based on
        purchased electricity by the sector and information on the CC>2 intensity of generation from the power system.
        National-level electricity purchase estimates were based on MECS, EIA, U.S. Geological Survey (USGS), or
        other sources as defined in the main body of this report. Electricity data reflect purchased electricity and
        exclude consumption of electricity generated on site. These estimates were adjusted upwards to account for
        losses associated with the transmission and distribution of electricity.10

        Estimates of the CC>2 emissions from grid-connected electricity generators were based on eGRID. eGRID is
        based on available plant-specific data for all U.S. electricity generating plants that provide power to the electric
        grid and report data to the U.S. government. eGRID contains air emissions data for nitrogen oxides, sulfur
        dioxide, carbon dioxide, and mercury. Combined with generation data from the same plants from eGRID,
        eGRID provides estimates of CC>2 emissions factors (in MMTCC>2E) per kWh of generation. These factors are
        provided at the national, regional, and state level. Two versions of eGRID were used: 1998 for the 1998
        emissions estimates and 2004 for the 2002 emissions estimates.

        National-level sector electricity purchases estimates (adjusted for T&D losses) were multiplied by the year-
        appropriate CC>2 emissions factor (in Ibs/kWh) to  derive CO2 emissions  attributable to the sector in that year.

        Method 2: Regional Emissions Factors and Customer Class Data
        Method 2 begins with the same national-level demand estimates as used  in Method 1 (either based on MECS,
        EIA, USGS, or other sources depending on sector). In this method, however, the demand is allocated first to
        census region and then to eGRID NERC regions in order to more closely align the demand with the
        generation meeting that demand, and therefore refine the estimate of carbon emission reductions.

        In cases where MECS data is used, typically census region data is also available. In some cases, disclosure rules
        prevent the reporting of one or more census regions, in which case missing data is estimated, typically based
        regional distributions for years when data are reported.

        This census region-based data must in turn be "mapped" to the NERC regions. In Method 2, this mapping is
        achieved by assuming that the distribution of a sector's electricity demand to the NERC regions mirrors the
        distribution of electricity demand of the customer class of which the  sector is a member. For example, it is
        assumed that the geographic distribution of electricity demand in the chemical  manufacturing sector is the
        9 The eGRID regional definitions in the 2004 data release are defined according to the 2006 NERC geographic definitions.
        10 Loss estimates were based on EIA data. See U.S. Department of Energy, Monthly Energy Review, Energy Information Administration, October 2007,
        http://www.eia.doe.gov/emeu/mer/elect.html.
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Appendices
        same as the industrial customer class overall. Information on the geographic distribution of industrial sales is
        based on the EIA 861 report11 which reports customer class sales at the utility level. Summing these sales by
        customer class over the geographic area of interest, or NERC region, allows one to develop an estimate of the
        share of electricity demand by each NERC region. EIA 861 data for 2002 were used.
        As in Method 1, the sector-level NERC region electricity demand, adjusted for T&D losses, is multiplied by the
        appropriate NERC CC>2 emissions factor to estimate the sector's total CC>2 emissions.

        Method 3: Geographic Distribution of Electricity Purchases based on Value Added
        This method is  similar in concept to Method 2, except that instead of distributing electricity demand using
        customer class distributions, value added  data are used to distribute sectoral electricity demand to states. Then,
        state-level demand is mapped to the NERC regions. As mentioned earlier, using value added as a proxy
        assumes that the electricity-intensity of production activities are correlated with the value added. For industries
        with diverse products and/or processes that are geographically concentrated, or where there are large regional
        differences in input costs or value of final shipments, this assumption may not hold. However, absent
        additional information on the distribution of electricity sales, this method was used.

        The relative state share of a sector's  national-level value added is used to share electricity demand to the states.
        States are then aggregated up to NERC regions. For states that lie  in 2 or more NERC regions, it is necessary
        to distribute this demand further to the appropriate NERC region. The  EIA 861 data for the appropriate
        customer class is used to make this disaggregation.

        The disaggregated electricity demand is multiplied by the appropriate  NERC CC>2 emissions factor to estimate
        CC>2 emissions  for the sector.

        Method 4: Plant  by Plant Assessments
        Method 4 was applied when sufficient data existed to allocate national electricity purchases to the plant level.
        This was the case in the cement, petroleum refining, primary aluminum, and iron and steel sectors. In general,
        the  approach was to estimate electricity purchases at each facility (based on some proxy  such as capacity or
        production). Because each plant's location is known, it then can be assigned to a specific NERC region, and
        thus, emissions  can be estimated with a region-specific eGRID emissions factor. This emission factor
        multiplied by the estimated electricity purchase (adjusted for losses) results in the estimated emissions for that
        facility. Summing over all facilities results in national-level emissions for the sector. Specific methods for each
        sector are outlined below:


        Facility-level data location, capacity, and process data for the  cement sector were gathered from the following
        2002 and 1998 Portland Cement Plant Information Summaries:

        "   U.S. and Canadian Portland Cement Industry Plant Information Summary. Portland Cement Association,
            December  31, 2002.

        "   U.S. and Canadian Portland Cement Industry Plant Information Summary. Portland Cement Association,
            December  31, 1998.

        For each year, the facility-level data were grouped into two sets. The grinding-only facilities were identified and
        their grinding capacities (metric tons/year) were noted. The remaining plants are full production cement
        facilities and are identified along with their process type (wet, dry,  etc.) and clinker capacity (metric tons/year).

        Next, using the known locations of all facilities, the facilities are assigned to NERC regions based on 2004
        eGRID NERC  regions.  Facilities from the 1998 list were assigned based on 1998 eGRID  NERC regions.
        11 U.S. Department of Energy, Annual Electric Power Industry Report: Form EIA-861, Energy Information Administration,
        http://www.eia.doe.aov/cneaf/electricitv/page/eia861.html.
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Appendices
        USGS Minerals Yearbooks (2002 and 1998 respectively) provided data needed to compute electricity consumed
        (kWh) by each facility.12
        For each cement-plant (non-grinding only) facilities, a state-appropriate utilization factor12 was applied to
        facility capacity to compute tons of clinker produced per year. The utilization factor is an estimate of how
        much the facility's equipment is run. It can be measured in terms of clinker or cement production capacity.
        USGS compiles utilization data by plant, and compiles and reports them by region  (and by year). In this
        analysis we used clinker capacity and utilization. Based on each facility's clinker capacity and the applicable
        utilization factor, facility-level production was estimated.

        Next, the total energy used (kWh) by each facility for finished cement production was computed. Based on
        which process the plant used (wet or dry), a different calculated electricity "intensity" for clinker production
        (kWh purchased per ton of finished clinker production) was used. These intensities were  calculated based on
        USGS-reported total U.S. electricity purchases divided by clinker production. These were calculated for cement
        producing plants, distinguished by wet and dry processes, and for grinding-only plants. Electricity purchases
        were then estimated for each plant based on its clinker production multiplied by the appropriate intensity
        factor. Finally, because the analyses in this report are tied to the USGS energy use estimates, the calculated
        electricity purchase estimates were scaled again to the total USGS estimates of electricity purchased by cement
        facilities (not including grinding-only facilities).
        For each grinding-only facility, an appropriate utilization factor12 for cement production (that is, the grinding
        plant's cement production as a percentage of capacity) was applied to compute tons of cement produced per
        year. Because these estimates were tied to USGS data, the cement production numbers for these grinding-only
        facilities were scaled up to the total U.S. reported cement production (metric tons)12 for grinding-only plants in
        that year.

        Next the total energy used (kWh) by each grinding-only facility for finished cement production was computed
        using a calculated cement production intensity for grinding-only plants in kWh/metric ton cement.12 Again, the
        electricity purchased numbers were scaled up to total U.S. electricity purchased by grinding-only facilities.
        To compute emissions for both types of facilities, a NERC-appropriate emissions factor (Ibs/kWh) was applied
        to the estimated electricity purchased for each facility in both 1998 and 2002. That  is, for 2002, each facility had
        an eGRID 2004 emissions factor associated with its specific location  (i.e., NERC region)  which was multiplied
        by the estimated electricity (kWh) purchased by that facility to result in Ibs. emission (Ibs/kWh x kWh = Ibs).
        Similarly,  for 1998, each facility had an eGRID 1998 emissions factor that was multiplied by its estimated
        electricity purchases to estimate its total CO2 emissions. Finally, for each year, emissions from the facilities were
        tallied up  into a national CO2 emissions estimate.

        Iron and
        Iron and steel facility-level data were compiled using a list of facilities13 that contained two categories of plants:
        integrated mills (integrated/EOF) and carbon steel  minimills (EAF). The file contained the locations and
        capacities (tons of raw steel per year) for all facilities. Using zip code and county information about the location
        of each of the facilities, NERC regions were assigned to  the facilities in two different ways. The first was based
        on 2004 eGRID NERC regions and the second was based on 1998 eGRID NERC regions.
        The following reference  sources were used to determine production by each facility and each  facility's
        estimated electricity purchases:
        12 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2002, 2003, http://minerals.usas.aov/minerals/pubs/commoditv/cement/cemenmvb02.pdf,
        and U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 1998,1999, http://minerals.usas.gov/minerals/pubs/commoditv/cement/170498.pdf.
        13 Facilities list prepared by EPA's Sector Strategies Program (7 Nov 2007).
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Appendices
        "   American Iron and Steel Institute (AISI) 2002 Annual Statistical Report, Table 23 contained data on raw
            steel production by type of furnace within the iron and steel industry during 2002 and 1998.14

        "   MEGS 2002 and 1998 provided information about purchases of electricity and the breakdown of those
            purchases between BOF and EAF plants.
        For each of the two years, 1998 and 2002, the facility-level production of iron/steel was determined by using
        the share of the total U.S. capacity that each individual facility represented (i.e., total U.S. production x % of
        total U.S. capacity that a facility represented)  to distribute the known national production across all the
        facilities.15

        Electricity consumed by integrated/EOF mills and EAF mills in both  1998 and 2002 was computed separately
        using the 1998 electric intensity data for various iron and steel industry operations reported in the DOE/OIT
        (2000) report and the AISI (2003) production data for the respective years.16 For the EAF mills, the calculated
        electricity consumption was considered as purchased electricity. For integrated/EOF mills, the calculated total
        amount of purchased electricity included both purchased and onsite generated electricity, therefore, the
        purchased electricity for the integrated/EOF mills was calculated by subtracting the amount of electricity
        generated onsite in the iron and steel mills  [which was calculated based on the data on cogeneration share from
        the total electricity consumption] ,17
        Then, the EAF mills' purchased electricity consumption estimates were developed by applying the share of
        EAF mills' purchased electricity consumption to the MEGS purchased electricity consumption estimates (for
        the iron and steel industry) for the respective years. For the integrated/EOF mills, purchased electricity
        consumption estimates were developed by subtracting the EAF mills' purchased electricity consumption
        estimates from the total purchased electricity consumption estimate. The MEGS net electricity consumption
        estimates were adjusted for transmission losses (i.e., the amount of additional electricity that is lost during
        transmission to the end-users was added to the total using the loss factors, calculated using EIA data).18
        Based on the purchased electricity consumption and the production estimates for the integrated/EOF and
        EAF mills for 1998 and 2002, the electricity consumption intensities were computed for integrated/EOF and
        EAF plants, using AISI (2003)  raw steel production data for 1998 and 2002 for the respective plant, or furnace,
        categories (i.e., kWh net electricity purchased/tons production = kWh/ton).19
        Next, the facility-specific estimate of electricity purchased (kWh)  for each of the two years was calculated by
        multiplying the furnace-specific (integrated/EOF mills and EAF plants)  electricity intensities by the production
        data.
        Facility-level CC^ emissions for 1998 and 2002 were computed by multiplying the NERC region-specific CC>2
        emissions factors (Ibs/kWh) for 1998 and 2002, and the respective facility-specific estimates of purchased
        electricity consumed. Because the eGRID data were not available for 2002, 2004 data were used as  substitutes,
        without any adjustment. Underlying this method was the assumption that the regional emission intensities
        remained unchanged between 2002 and 2004. Finally, for each year, emissions from all the facilities were
        summed up to a national CC^ emissions estimate.
        14 American Iron and Steel Institute, 2002 Annual Statistical Report, 2003, Table 23.
        is AISI, 2003, Table 23.
        16 U.S. Department of Energy, "Energy and Environmental Profile of the U.S. Iron and Steel Industry," Office of Industrial Technologies, 2000,
        http://www1.eere.enerav.gov/industrv/steel/pdfs/steel profile.pdf.
        17 AISI, 2003, Table 35.
        18 U.S. Department of Energy, "Monthly Energy Review," 23 Nov 2007, http://www.eia.doe.gov/emeu/mer/elect.html.
        19 AISI, 2003, Table 23.
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Appendices
        Primary Aluminum
        Facility-level production capacity data were compiled using USGS Minerals yearbooks for Aluminum 1998 and
        2002.20 The locations and capacities (tons per year) of all facilities were noted. Using zip  code and county
        information about the location of each of the facilities, the facilities from the 2002 list were assigned to NERC
        regions based on 2004 eGRID NERC regions, while facilities from the 1998 list were assigned based on  1998
        eGRID NERC regions.
        DOE's Energy and Environmental Profile of the U.S. Aluminum Industry, contained information about 1995 electricity
        consumption of primary aluminum production processes.21 DOE/Office  of Industrial Technologies (OIT)
        (2000; Table 1-6) provided estimates for specific energy consumption of the primary aluminum production
        processes in Btu/ton.22 These estimates were converted to kWh/ton using the process-specific conversion
        factors used in the report. The sum of these specific energy intensities (in  kWh/ton) is the overall energy
        intensity of primary aluminum production. This estimate was used in the calculations for both 1998 and 2002
        due to lack of availability of more recent data.
        The 2002 USGS Minerals Yearbook provided primary aluminum production estimates for 1998 and 2002 in
        million metric tons. Purchased electricity estimates for primary aluminum  production were obtained from
        MEGS 1998 and 2002. The net electricity consumption estimate for 1998 was readily available from MEGS
        1998. However for 2002, it was calculated by subtracting the other fuels (noted in MEGS), data for some of
        which were withheld, from the total fuel consumed,  yielding a conservative (or higher) estimate of purchased
        electricity consumption for 2002.

        For each of the two years, facility-level production of primary aluminum was determined by multiplying the
        share of the total U.S. capacity that each individual plant represented by the national aluminum production for
        the respective years (i.e., total USGS national primary aluminum production x % of total U.S capacity that a
        facility represents).

        Due to rounding, the total U.S. production capacity  given for each year by the USGS slightly differed from the
        facility-level production capacity total. To adjust for  this discrepancy, the individual facility-level production
        estimates were scaled to the national production estimates  for that year. The  industry-specific electric energy
        intensity (calculated based on the DOE/OIT, 2000 report) was applied to each facility's  production estimate to
        get an estimate of electricity purchased by each facility.

        The facility-specific CG>2 emissions were computed by multiplying the NERC region-specific CO2 emissions
        factors (Ibs/kWh)  and the plant-specific purchased electricity estimates for the same years. The  NERC region-
        specific CC>2 emission factors were obtained from eGRID  for 1998 and 2004, which was used as a surrogate
        estimate for 2002 on the assumption that the electric intensity remained unchanged for this industry between
        2002 and 2004. Finally, for each year, emissions from each of the facilities were summed to produce a national
        CC>2 emissions estimate.

        Refineries
        Refinery emissions are based on raw data collected from EIA refinery capacity databases for year 1998 and
        2002.23>24 The data for atmospheric distillation capacity as well as secondary unit capacities was organized such
        that it could be used to determine the "equivalent distillation capacity"  (EDC) of each refinery in the United
        20 Table 2: Primary Annual Aluminum Production Capacity in the United States, U.S. Geological Survey, Minerals Yearbook: Aluminum Annual Report 2002, 2003
        http://minerals.usas.aov/minerals/pubs/commoditv/aluminum/alumimvb02r.pdf. U.S. Geological Survey, Minerals Yearbook: Aluminum Annual Report 1998, 1999
        http://minerals.usas.gov/minerals/pubs/commoditv/aluminum/050498.pdf.
        21 U.S. Department of Energy, Energy and Environmental Profile of the U.S. Aluminum Industry, Office of Industrial Technologies. 1997,
        http://www1.eere.enerav.gov/industrv/aluminum/pdfs/aluminum.pdf.
        22 U.S. Department of Energy, Energy and Environmental Profile of the Aluminum Industry, Table 1-6.
        23 U.S. Department of Energy, Petroleum Supply Annual, 1998: Vol. 1 Refinery Capacity Report, Energy Information Administration, 1999,
        http://www.eia.doe.gov/oil gas/petroleum/data publications/refinery capacity data/refcap historical.html Volume 1.
        24 U.S. Department of Energy, Petroleum Supply Annual, 2002, Energy Information Administration, 12 Jun2003,
        http://www.eia.doe.gov/pub/oil gas/petroleum/data publications/petroleum supply annual/psa volume1/historical/2002/psa volumel 2002.html Volume 1.
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Appendices
         States for the given year. EDC scales up capacity based on the complexity of the secondary units of the
         refinery. This value was calculated because it is believed that it will more accurately reflect the electricity
         purchasing needs of a refinery than the pure atmospheric distillation capacity alone. The EDC of each refinery
         was multiplied by its utilization for the given year, as provided by EIA's Petroleum Supply Annual, Table 16.25-26
         The electricity purchases by refineries for each PADD in 1998 and 2002 were collected from EIA's Petroleum
         Supply Annual, Table 47 for each of these respective years.27-28 These will give a more accurate purchased power
         estimate for the refineries  of each PADD. The amount of this purchased power was apportioned to each
         refinery in each PADD based on its EDC using the formula below:
                            Power purchased by refinery = (EDC of refinery/Total EDC of PADD)
                                            x Power purchased by refineries in PADD
         Each refinery was mapped onto its corresponding NERC/eGRID region using a map for 1998 and 2002,
         specifically. From this the total power purchased by refineries in each NERC/eGRID region was summed. An
         appropriate emissions factor was applied to derive total regional emissions of CC>2. Regional estimates were
         summed to a national total.
         25 U.S. Department of Energy, Petroleum Supply Annual, 1998: Vol. 1 Refinery Capacity Report, Energy Information Administration, 1999,
         http://www.eia.doe.gov/oil gas/petroleum/data publications/refinery capacity data/refcap historical.htmlTable#16.
         26 U.S. Department of Energy, Petroleum Supply Annual, 2002, Energy Information Administration, 12 Jun2003,
         http://www.eia.doe.gov/pub/oil  gas/petroleum/data publications/petroleum supply annual/psa volume1/historical/2002/psa volumel 2002.html Table #16.
         27 U.S. Department of Energy, Petroleum Supply Annual, 1998: Vol. 1 Refinery Capacity Report, Energy Information Administration, 1999,
         http://www.eia.doe.gov/oil gas/petroleum/data publications/refinery capacity data/refcap historical.html Table # 47.
         28 U.S. Department of Energy, Petroleum Supply Annual, 2002, Energy Information Administration, 12 Jun2003,
         http://www.eia.doe.gov/pub/oil  gas/petroleum/data publications/petroleum supply annual/psa volume1/historical/2002/psa volumel 2002.html Table #47.
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Appendices
        A.4 General Conversion Factors & Global Warming  Potentials
        Table A-4 and Table A-5 show general conversion factors and global warming potentials that are used in
        calculating emission estimates throughout this report.

                                                 Table A-4: Conversion Factors29
                                                       3,412   Btu/kWh
                                                       1,055   TJ/TBtu
                                               1,000,000,000   kg/Tg
                                                      0.9072   Metric ton/ton
                                                   1,000,000   Metric ton/kg
                                   Table A-5: Global Warming Potentials (100 Year Time Horizon)30
                                    Carbon Dioxide (C02)                           1
                                    Methane (CH4)                                21
                                    Nitrous Oxide (N20)                          310
                                    HFC-23                                  11,700
                                    HFC-134a                                 1,300
                                    CF4                                       6,500
                                    C2F6                                      9,200
                                    C4Fio                                      7,000
                                    C6Fi4                                      7,400
                                    SF6	23,900
        29 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2005, 15 Apr 2007
        http://www.epa.gov/climatechanae/emissions/usinventorvreport.html.
        30IPCC Second Assessment Report (1996)—used for this report in accordance with the Inventory of U.S. Greenhouse Gas Emissions and Sinks.
        Intergovernmental Panel on Climate Change, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 2007 http://www.ipcc-
        naaip.iaes.or.ip/public/2006g I/index.htm.
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Appendices
         A.5 Energy Consumption Data

         MEGS data provide energy consumption by fuel type for 1998 and 2002 by NAICS code for some of the
         sectors covered in this report.31 For some sectors, identified in Appendix A.6, CO2 estimates for the "other"
         fuels category were obtained directly from EIA's  Special Report Energy-Related Carbon Dioxide Emissions in U.S.
         Manufacturing.

                                            Table A-6:1998 MECS Fuel Consumption Data32
1 ji i !i§ ipWl jyiltati Di^iijirti

Industry
Alumina and Aluminum
Chemical Manufacturing
Food
Beverages

Paper
Casting
Petroleum Refineries
Plastics and Rubber
Products
Semiconductors and
Devices
Textiles
	 1 	

3313
325
311
3121
321
322
3315
324110
326

334413

313, 314, &315
	 ftfi
(TBtu)
441
3,704
1,044
88
504
2,744

3,477
327

66

351
	 licfl^
(TBtu)
246
577
213
20
72
240

118
183

46

138
	 	 I
(TBtu)
*
50
14
*
1
151

70
5

*

17


1
9
16
*
12
9
1
4
1

*

5
Natural
	 ||| 	
(TBtu)
184
1984
568
41
73
586
137
948
126

20

149
iWftf
	 Ill 	
(TBtu)
1
51
5
*
4
5
2
33
4

*

3

	 fit.
(TBtu)
Q
284
129
&
2
277

&
3

0

24
Coke and
	 inliW 	
(TBtu)
2
2
2
&


30
0
0

0

0
P

(TBtu)
6
748
97
4
341
1,476
1
2,304
5

*

17
* Estimate less than 0.5. OWithheld because Relative Standard Error is greater than 50 percent.
Table A-7:
2002 MECS
Fuel Consumption
I \l illicit IQMW

Industry
Alumina and Aluminum
Chemical Manufacturing
Food
Beverages

Paper
Lime
Casting
Petroleum Refineries
Plastics and Rubber
Products

Code
3313
325
311
3121
321
322
327410
3315
324110
326

Semiconductors and Related 334413
Devices
Textiles

313,314,&315
	 leii
(TBtu)
351
3,769
1,116
85
375
2,361
106

3,086
348

66

295
	 liiM^
(TBtu)
193
522
230
22
72
223
5

121
181

44

115
	 	 B
(TBtu)
*
43
13
1
1
100
1
*
21
7

*

6


1
14
19
2
10
13
1
1
5
2

*

3
Data33
Natural 1
	 ill 	
(TBtu)
130
1,678
575
42
57
504
8
77
821
128

21

119

rfMaW
	 Mi 	
(TBtu)
1
37
5
1
5
6
*
1
20
3

*

3


	 ;6||jl 	
(TBtu)
0
314
184
8
1
234
66
1
1
Q

0

22

Coke and
	 SiifliL
(TBtu)
*
1
1
.

4
*
23
0
0

0

0

|
	 jyyj
(TBtu)
26
1,158
90
10
228
1,276
26

2,097
5

Q

15
         * Estimate less than 0.5. OWithheld because Relative Standard Error is greater than 50 percent.
         31 Fuel consumption was multiplied by the appropriate emission factor depending on fuel type to estimate emissions.
         32 U.S. Department of Energy, 1998 Manufacturing Energy Consumption Survey, Energy Information Administration, 14 Aug 2001,
         http://www.eia.doe.gov/emeu/mecs/mecs98/datatables/contents.htmltffuel.
         33 U.S. Department of Energy, 2002 Manufacturing Energy Consumption Survey, Energy Information Administration 24 Jan 2005,
         http://www.eia.doe.aov/emeu/mecs/mecs2002/data02/shelltables.html.
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Appendices
        Note the following definitions from EIA's on-line glossary of terms:34

        •   Coke (coal): A solid carbonaceous residue derived from low-ash, low-sulfur bituminous coal from which
            the volatile constituents are driven off by baking in an oven at temperatures as high as 2,000 degrees
            Fahrenheit so that the fixed carbon and residual ash are fused together. Coke is used as a fuel and as a
            reducing agent in smelting iron ore in a blast furnace. Coke from coal is grey, hard, and porous and has a
            heating value of 24.8 million Btu per ton.

        •   Coke (petroleum): A residue high in carbon content and low in hydrogen that is the final product of
            thermal decomposition in the condensation process in cracking. This product is reported as marketable
            coke or catalyst coke. The conversion is 5 barrels (of 42 U.S. gallons each) per short ton. Coke from
            petroleum has a heating value of 6.024 million Btu per barrel.

        •   Coke breeze: The term refers to the fine  sizes of coke, usually less  than one-half inch, that are recovered
            from coke plants. It is commonly used for sintering iron ore.

        •   Distillate fuel oil: A general classification for one of the petroleum fractions produced in conventional
            distillation operations. It includes diesel  fuels and fuel oils. Products known as No. 1, No. 2, and No. 4
            diesel fuel are used in on-highway diesel engines, such as those in trucks and automobiles, as well as off-
            highway engines,  such as those in railroad locomotives and agricultural machinery. Products known as No.
            1, No. 2, and No. 4 fuel oils are used primarily for space heating and electric power  generation.

        •   Residual fuel oil: A general classification for the heavier oils, known as No. 5 and No.  6 fuel oils, that
            remain after the distillate fuel oils and lighter hydrocarbons are distilled away in refinery operations. It
            conforms to ASTM Specifications D 396 and D 975 and Federal Specification W-F-815C. No. 5, a
            residual fuel oil of medium viscosity, is also known as Navy Special  and is defined in Military Specification
            MIL-F-859E, including Amendment 2 (NATO Symbol F-770). It is used in steam-powered vessels in
            government service and inshore powerplants. No. 6 fuel oil includes Bunker C fuel oil and is used  for the
            production of electric power, space heating, vessel bunkering, and various industrial purposes.
        Those sectors for which MECS data were not available or for which more sector-specific data were available
        (i.e. cement), data from a variety of sources were used, including the USGS Minerals Yearbook and the U.S.
        Census. Tables A-8 through A-12 below contain data from sources that were used to estimate GHG emissions
        for this report.

                                          Table A-8: Clinker Production for Cement
                                                            Clinker Production
                                                            (1,000 metric tons)
                                         199835                    75,842
                                         200236	82,959
        34 See http://www.eia.doe.gov/alossarv/index.html.
        35 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 2003, 2004, http://minerals.usas.gov/minerals/pubs/commoditv/cement/cemenmvb03.pdf.
        36 U.S. Geological Survey, Minerals Yearbook: Cement Annual Report 1999, http://minerals.usgs.gov/minerals/pubs/commoditv/cement/170499.pdf.
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Appendices
                                             Table A-9: Dollars Spent on Fuel for Construction
         37 U.S. Census Bureau, 2002 Economic Census Industry Series Reports Construction, 22 Nov 2005, http://www.census.gov/econ/census02/auide/INDRPT23.HTM.
         38 U.S. Census Bureau, 1997 Economic Census Industry Series Reports Construction, Jan 2000, http://www.census.gov/prod/ec97/97c23-is.pdf.
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Appendices
                                                                        Table A-10: Fuel Consumption Data for Mining
^^ ^ Mi,^i* ^^Ui V'i *Vj%W S' >:''' >••"'••- ^ '::.'::-. p% >i >i J'vi >::' :i / 5; >::< >:'''.«". J ;^ '*
d 1 i W? DlWiiKftiWIRWdiialPi
	 lidiMS 	 M| 	 K 	 flSttiii 	 LiiiittJiS 	
and 211111
Gas
Fuel Consumption 2,017.8
Delivered Cost
ff 000 Dollars]

Extraction
Fuel Consumption 47.7
Delivered Cost
ff 000 Dollars]
Oil and Gas Wells
Fuel 3, 355,3 f , 954, f
Delivered Cost $51,921
ff 000 Dollars]
for Oil 213112*107'442
and Gas
Fuel Consumption 1, 424. 8 1,032. 1
Cost
^mo
JR^IdiutlitA^aiaj*
S; J4ci
	
2,199
2,363
|i%li% dfpffjlfiii, | f || 0 jj
iiilflal jr4Nuft|i|!>la,c%)|fn|s|| 0:'
{Re«|du» jEtecWclf |
	 %i|| 	 MaW||isffl 	 KsfcifiSI 	


29,577,576 3,325,432




427










          39 U.S. Census Bureau, 1997 Economic Census of Mining Industry Series Data, Economics and Statistics Administration, 2000, http://www.census.gov/prod/www/abs/97ecmini.html.
          40 U.S. Census Bureau, 2002 Economic Census Industry Statistics Sampler: Mining, 15 Feb 2006, http://www.census.gov/econ/census02/data/industrv/E21.HTM.
          41 U.S. Census Bureau, 2002 Economic Census of Mining Industry Series Data, Economics and Statistics Administration, 2005, http://www.census.gov/econ/census02/guide/INDRPT21.HTM.
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Appendices
Table A-12: Fuel Consumption Data for Oil and Gas
^^m
^^^H 1 nd ustry
and
Gas
Fuel Consumption
Delivered Cost
\ m m IMU
NAICS J
	 (Sill 	 f^^ijkA
211111

3,716,4
$109,965
(Us „ j J ISas^JlliJil, IJJJ
ipliJulll! 1 (|iihjfciWd,liMl
1 Ptolpjiisi)£j|


102,4

! I Jl $
$aiS|W . jp
	 	 Jn



$15,575
Extraction, 200242
NWLJI yiiy
MWWtt fAdUSdaiyttd |^IaU6
liiiil 	 i«ii 	 CM 	


731


.Ml 9 lle^ttfel^s
ttWIlf
	 jpu|||ttl| 	 |rM.!lt 	




           (1000 Dollars)

         Extraction
           Fuel Consumption
           Delivered Cost


           Fuel Consumption
                    Cost                        $37,355


         and Gas
           Fuel Consumption
           Delivered Cost
           (1000 Dollars)	
 121.6
                    ,552
             5,575
$7,278
$311
                             $62,932
                                                     382
         42 U.S. Census Bureau, 2002 Economic Census of Mining Industry Series Data, Economics and Statistics Administration, 2005, http://www.census.gov/econ/census02/auide/INDRPT21.HTM.
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Appendices
        A.6 COi              for
        The EIA special topic report, Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing, reports CO2
        emissions for combustion of "other" fuels as described by MEGS. This category includes a variety of other
        fuels (e.g., waste materials, woody materials, black liquor, petroleum coke, etc.) for which EIA has underlying
        data not provided in MEGS that are used to produce the CC>2 emission estimates.  Table A-13 provides
        estimates of CC>2 emissions from the combustion of other fuels for relevant sectors.

                                   Table A-13: C02 Emissions for Combustion of Other Fuels43


        43 U.S. Department of Energy, Special Topic: Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing, Nov 2006,
        http://www.eia.doe.aov/oiaf/1605/aarpt/pdf/industrv mecs.pdf.
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Appendices
        A.7 Reporting Protocols

        Certain companies in the aforementioned industrial sectors may voluntarily report their GHG emissions.
        Several programs have created protocols for designing and implementing a plan to estimate and track an
        entity's GHG emissions. The following protocols may be used by companies to guide them in estimating and
        reporting their GHG emissions.

        EPA Climate Leaders
        EPA's Climate Naders Greenhouse Gas Inventory Protocol \s an enhanced version of the WBCSD/WRI protocol for
        GHG emission reporting. EPA's program has enhanced the WBCSD/WRI protocol to better fit the
        requirements of the Climate Leaders program. The Climate Leaders GHG Protocol consists of three
        components: Design Principles, Core Modules and Optional Modules. The Design Principles aid Climate
        Leader partners to define boundaries, identify emission sources, assign a base year, report requirements, and set
        goals. The Core Modules guidance gives specific information on calculating direct and indirect emission
        sources. The Optional Modules guidance helps partners account for emissions that are associated with their
        company, but over which they have no control (e.g., employee commuting programs). Companies that are
        committed to Climate Leaders develop corporate-wide  GHG  reduction goals and inventory their emissions.

        Available online at: http://www.epa.gov/stateply/docs/climateleadersdesignprinciples.pdf, http://www.epa.
        gov/stateply/resources/cross_sector.html and http://www.epa.gov/stateply/resources/optional.html

        World Business Council for Sustainable Development (WBCSD) and World Resources Institute (WRI)
        The WBCSD created two modules with WRI for accounting and reporting GHGs. The Greenhouse Gas Protocol:
        A Corporate Accounting and Reporting Standard provides guidance for design and reporting principles as well as
        standards for setting organizational and operational boundaries, tracking emissions over time, and reporting
        GHG emissions. The objectives of the protocol's guidance include helping companies prepare the inventory,
        simplifying and reducing costs of compiling the inventory, providing information that can build an effective
        strategy to manage and reduce GHG emissions, and increasing consistency and transparency in GHG
        accounting and reporting. The GHG Protocol for Project Accounting is similar, but helps companies report
        emissions for specific GHG emission reducing projects.
        Available online at: http://www.wbcsd.org/DocRoot/IX9QDY3RmB83EDgaeKUW/ghg-protocol-
        revised.pdf

        U.S. Department of Energy, Energy Information Administration's 1605(b) Reporting Guidelines
        U.S. Department of Energy, Energy Information Administration's 1605(b) General Guidelines for Voluntary
        Reporting of Greenhouse Gases (April 2006) and Technical Guidelines for Voluntary Reporting of Greenhouse Gases (1605(b))
        Program (April2007) provide guidelines for reporting greenhouse gas emissions, emission reductions, and
        carbon sequestration for all sectors of the economy, including the industrial sector. The Technical Guidelines
        provide specific protocols for calculating industrial emissions  from a wide array of industrial processes, as well
        emission reduction calculation methods. This protocol provides support for reporting a number of activities
        that have reduced GHG emissions including reductions in greenhouse gas intensity, absolute emissions,
        changes in carbon storage,  reduced emissions from purchased electricity, landfill  methane recovery, coal mine
        methane recovery, geologic sequestration, anaerobic digestion at wastewater treatment plants and farms,
        recycling of fly ash, and combined heat and power.
        Available online at: http://www.eia.doe.gov/oiaf/1605/aboutcurrent.html and
        http://www.eia.doe.gov/oiaf/1605/frntvrgg.html.

        California Climate Action Registry
        The California Climate Action General Reporting Protocol provides the approach, methodology and procedures
        required to report under the Registry. The protocol includes guidelines on determining geographic scope,
        organizational boundaries,  operational boundaries and emission baselines. It also includes guidance for
        calculating indirect emissions from electricity, co-generation, imported steam and district heating and cooling,
U.S. Environmental Protection Agency                     WORKING DRAFT (May 2008)                              A-21

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Appendices
       and direct emissions from mobile combustion, stationary combustion, process emissions and fugitive
       emissions. The Registry's online emission calculation and reporting tool (CARROT) helps participants to be
       effective and minimizes the burden of reporting.

       Available online at: http://www.climateregistry.org/docs/PROTOCOLS/GRP%20V2-March2007_web.pdf
U.S. Environmental Protection Agency                     WORKING DRAFT (May 2008)                             A-22

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Appendices
          A.8 Economic Data
                                                               Table A-14: Economic Data
Aluminum

Cement

Chemicals

Construction

Agribusiness

Forest Products

Iron &

Lime

Casting

Mining

Oil & Gas

Plastic and Rubber

Semiconductors

Textiles

1998
2002
1998
2002
1998
2002
1997
2002
1998
2002
1998
2002
1998
2002
1997
2005
1998
2002
1997
2002
1998
2005
1998
2002
1998
2002
1998
2002
11,071
8,711
4,441
4,206
230,219
237,255
653,429
802,971
173,416
218,874
101,349
98,200
24,728
17,446
755
723
17,334
14,242
35,597
33,593


85,542
85,697
59,977
41,499
68,071
48,466
31,904 3./13 thousand metric tons
26,107 2, 707 thousand metric tons
74,523 million metric tons
81,517 million metric tons








98,600 thousand metric tons
91,600 thousand metric tons
20,100 thousand metric tons
20,000 thousand metric tons
14,725 thousand tons
13,081 thousand tons
5,333 million short tons
5,535 million short tons
38, 090, 616 billion Btu
35,719,530 billion Btu






          44 U.S. Census Bureau, Annual Survey of Manufactures (ASM): Statistics for Industry Groups and Industries, 2005, http://www.census.gov/mcd/asm-as1.html. For
          mining and oil and gas, see U.S. Census Bureau, 2002 Economic Census of Mining Industry Series Data, Economics and Statistics Administration, 2005,
          http://www.census.aov/econ/census02/guide/INDRPT21.HTM.
          45 U.S. Census Bureau, Construction Spending: October 2007 Construction at a Glance, 30 Nov 2007, http://www.census.gov/const/www/c30index.html.
          46 For aluminum, cement, iron and steel, lime, and mining-crude ore, see U.S.  Geological Survey,  Commodity Statistics and Information, Minerals Yearbook: Annual
          Reports for Aluminum, Cement, Iron and Steel, Lime, Mining (crude ore), 10 Nov 2007, http://minerals.usgs.gov/minerals/pubs/commoditv/.
          47 For mining-coal, see U.S. Department of Energy, Coal Production in the United States, 5 Oct 2006,
          http://www.eia.doe.gov/cneaf/coal/page/fig1 us historical  production bar chart.xls.
          48 For oil and gas, see U.S. Department of Energy, Crude Oil Production, 26 Nov 2007, http://tonto.eia.doe.gov/dnav/pet/pet  crd crpdn adc mbbl m.htm, and
          U.S. Department of Energy, Natural Gas Gross Withdrawals and Production, 31 Oct 2007, http://tonto.eia.doe.gov/dnav/ng/ng prod sum  dcu  NUS  m.htm.
          49 For metal casting, see American Foundry Society, "Metal Casting Forecast & Trends: Demand & Supply Forecast," Stratecasts, Inc.
U.S. Environmental Protection Agency
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Appendices
       A.9 List of Acronyms

       AA            Aluminum Association
       ACC          American Chemistry Council
       ACEEE       American Council for an Energy Efficient Economy
       AF&PA       American Forest and Paper Association
       AISI          American Iron and Steel Institute
       A^Os          Aluminum oxide
       API           American Petroleum Institute
       BOF          Basic oxygen furnace
       C2p6          Perfluoroethane, hexafluoroethane
       CsF8          Perfluoropropane
       CF4           Perfluoromethane
       CFC          Chlorofluorocarbon
       CH4           Methane
       CKD          Cement kiln dust
       CC>2           Carbon dioxide
       CRF          Common Reporting Format
       CVD          Chemical vapor  deposition
       eGRID        Emissions and Generation Resource Integrated Database
       DOE          U.S. Department of Energy
       EAF          Electric arc  furnace
       EIA           Energy Information Administration (DOE)
       EPA          U.S. Environmental Protection Agency
       FS            Forest Service (USDA)
       GHG          Greenhouse gas
       GRI           Global Reporting Initiative
       GWP          Global warming potential
       HCFC         Hydrochlorofluorocarbon
       HF            Hydrofluoric acid
       HFC          Hydrofluorocarbon
       HFC-23       Trifluoromethane
       HIP           Hot isostatic pressing
       IPCC          Intergovernmental Panel on Climate Change
       IPR           Industrial process refrigeration
       kWh          kilowatt-hour
       Ibs            pounds
       LPG          Liquified  petroleum gas(es)
       MBtu          Million British thermal units
       MECS         Manufacturing Energy Consumption Survey
       MMTCO2E    Million metric tons of carbon dioxide equivalent
       N2O          Nitrous oxide
       NAICS        North American Industry Classification System
       NCASI        National  Council for Air and Stream Improvement
       NERC         North American Electricity Reliability Corporation
       NFs           Nitrogen  trifluoride
       NGL          Natural gas  liquids
       NIR          National  Inventory Report
       NLA          National  Lime Association
       NMA          National Mining Association
       PCA          Portland  Cement Association
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
A-24

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Appendices
       PFC           Perfluorocarbon
       SFe            Sulfur hexafluoride
       TBtu          Trillion British thermal units
       UNFCCC      United Nations Framework Convention on Climate Change
       U.S.           United States
       USDA         United States Department of Agriculture
       USGS         United States Geological Survey
       VAIP          Voluntary Aluminum Industrial Partnership (EPA)
       WBCSD       World Business Council on Sustainable Development
       WRI           World Resource Institute
U.S. Environmental Protection Agency                     WORKING DRAFT (May 2008)                             A-25

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U.S. Environmental Protection Agency                      WORKING DRAFT (May 2008)                              A-26

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