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
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 1-4
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 1-5
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 1-7
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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
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 1-10
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Alumina and Aluminum
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Alumina and Aluminum
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 2-3
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 2-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Cement
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%
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Cement
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 3-3
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Cement
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 3-6
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 4-2
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 4-4
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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.
U.S. Environmental Protection Agency
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4-5
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 5-3
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 5-5
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 5-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
6-2
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 6-3
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 6-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 7-3
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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,
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 7-4
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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.
U.S. Environmental Protection Agency
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Forest Products
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/.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 7-6
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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.
U.S. Environmental Protection Agency
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Iron and Steel
• 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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 8-2
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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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 8-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 9-3
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 9-5
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 9-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Metal Casting
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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Metal Casting
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 10-3
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 10-4
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Metal Casting
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency
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Mining
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.
U.S. Environmental Protection Agency
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Mining
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 11-3
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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.
U.S. Environmental Protection Agency
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Mining
" 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.
U.S. Environmental Protection Agency
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 11-6
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 12-2
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Oil and Gas
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
-------
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.
U.S. Environmental Protection Agency
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 12-5
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 12-6
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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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
12-7
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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
WORKING DRAFT (May 2008)
12-8
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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
WORKING DRAFT (May 2008)
13-1
-------
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
13-2
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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
WORKING DRAFT (May 2008)
13-4
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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
WORKING DRAFT (May 2008)
14-1
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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)
14-2
-------
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
WORKING DRAFT (May 2008)
14-4
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 14-5
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U.S. Environmental Protection Agency WORKING DRAFT (May 2008) 14-6
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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)
15-1
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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
WORKING DRAFT (May 2008)
15-2
-------
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
-------
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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Initiative. http://www.corporateregister.com/search/report.cgi?num=18895-IxSMdtpMFO 2 June 2007.
—. —. CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse Gas
Emissions Questionnaire. http://www.cdproject.net/responses/Weyerhaeuser Corporate GHG
Emissions Response CDP5 2007/public.htm 13 Nov 2007.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) R-7
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References
Wolfe, Stuart to the Honorable Spencer Abraham (Secretary of Energy, U.S. Department of Energy). 11 June
2003. National Lime Association.
XTO Energy. 2007. CDP 5 Companies and Response Status: Carbon Disclosure Project (CDP5) Greenhouse
Gas Emissions Questionnaire. http://www.cdproiect.net/responses/XTO Energy Corporate GHG
Emissions Response CDP5 2007/public.htm 12 Nov 2007.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) R-8
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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
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-2
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-3
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-4
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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.
U.S. Environmental Protection Agency
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Appendices
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-6
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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.
U.S. Environmental Protection Agency
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Appendices
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-8
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-9
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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).
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-10
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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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-11
-------
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-12
-------
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-13
-------
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-14
-------
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
A-15
-------
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-16
-------
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
A-17
-------
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
A-18
-------
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.
U.S. Environmental Protection Agency
WORKING DRAFT (May 2008)
A-19
-------
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.
U.S. Environmental Protection Agency WORKING DRAFT (May 2008) A-20
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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
-------
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.
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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
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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
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