EPA-600 / R-94-196
November 1994
GRAPHICAL REPRESENTATIONS OF 1991
STEAM-ELECTRIC POWER PLANT OPERATION
AND AIR EMISSIONS DATA
By:
Susan S. Rothschild
Janice Chen
E. H. Pechan & Associates, Inc.
5537-C Hempstead Way
Springfield, VA 22151
EPA Contract No. 68-D1-0146
Work Assignment No. 2/035
EPA Project Officer: Charles O. Mann
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington, DC 20460
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TECHNICAL REPORT DATA
(Please read fusirurtions on the reverse before conif
1. RI:PORT NO. 2.
EPA-600 /R- 94-196
4. TITLE AND SUB" ITLh
Graphical Representations of 1991 Steam-Electric
Power Plant Operation and Air Emissions Data
5. REPORT DATE
November 1994
6. PERFORMING ORGANIZATION CODL
7. AL I HCHIb!
Susan S. Rothschild and Janice Chen
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDHtSS
E. H. Pechan and Associates, Inc.
5537-C Hempstead Way
Springfield, Virginia 22151
10. PROGRAM tlXMENT NO.
1 1. CONTRACT/GRANT NO.
68-D1-0146, Task 2'035
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE Oh' REPORT AND PfcHlOC COVfcHfcU
Final; 7/93 - 9/94
14. SPONSORING AGENCY CODF
EPA/600/13
is. supplementary notes AEERL project officer is Charles 0. Mann, Mail Drop 62, 919/
541-4593.
)
is. ABoThAci report provides graphical representations of data derived from the
U.S. Department of Energy's (DOE's) Energy Information Administration's (EIA's)
Form EIA-767-(Steam Electric Plant Operation and Design Report). For more than
10 years, EIA has collected monthly boiler level data from EIA-767. The IJ.S. EPA
has contributed funding to DOE for this effort. The report summarizes information
from the EIA-767 database that is .otherwise not readily available to the community
of electric utility data users or other members of the general public. To facilitate
interpretation by non-technical readers, the report emphasizes graphical displays
of data, consisting of 98 charts and 3 tables. The graphics present national data,
national coal data, regional data, specified state data, and specified operating utility
company data. Data tables show sulfur dioxide (SC2) and nitrogen oxide (NOx) emis-
sions by state, and the highest emitting electric utility companies. Charts show S02
and NOx emissions by fuel type, fuel type and sulfur content, and fuel type and boiler
capacity. Charts also present data on boiler utilization, and heat input by fuel type
and sulfur content. Additional charts for coal display coal quantities by sulfur con-
tent, quantities of scrubbed and not scrubbed coal, and boiler capacity and utiliza-
tion.
17. key words and document analysis
2. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. cosati Field/Group
Pollution Coal
Steam Electric Pow~ Sulfur Dioxide
er Generation Nitrogen Oxides
Electric Utilities Fuels
Emission Boilers
Data
Pollution Control
Stationary Sources
13E 2 ID
07B
10 A
14G 13 A
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. Or PAGES
118
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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ABSTRACT
For over 10 years the U. S. Department of Energy (DOE) Energy Information
Administration (EIA) has collected monthly boiler level data from the EIA Form 767
(Steam Electric Plant Operation and Design Report). The U.S. EPA has contributed
funding to DOE for this effort. This report presents summary data from the 1991 Form
767 database for public information. The report summarizes information from the Form
767 database that is otherwise not readily available to the community of electric utility
data users or other members of the general public. To facilitate ease of interpretation by
non-technical readers, the report emphasizes graphical displays of data, including 98
charts and 3 tables. The graphics present national data, national coal data, regional data,
specified state data, and specified operating utility company data. Data tables show sulfur
dioxide (S02) and nitrogen oxide (NO,) emissions by state, and the highest emitting electric
utility companies. Charts show S02 and NO, emissions by fuel type, fuel type and sulfur
content, and fuel type and boiler capacity. Charts also present data on boiler utilization,
and heat input by fuel type and sulfur content. Additional charts for coal display coal
quantities by sulfur content, quantities of scrubbed and not scrubbed coal, and boiler
capacity and utilization.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
ii
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CONTENTS
Page
ABSTRACT ii
FIGURES iv
TABLES vi
ABBREVIATIONS AND ACRONYMS vii
SECTION I
INTRODUCTION 1
SECTION II
DATA SOURCE 2
DATA PROCESSING 3
VARIABLE DEVELOPMENT 3
SECTION III
GRAPHICS PREPARATION 6
SUMMARY 7
HIGHLIGHTS 8
REFERENCES 10
iii
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FIGURES
Number Page
1 National S02 Emissions by Fuel Type 11
2 National NO, Emissions by Fuel Type 12
3 Mean Boiler Utilization by Fuel Type 13
4 National Heat Input by Fuel Type and Sulfur Content 14
5 National S02 Emissions by Fuel Type and Sulfur Content 15
6 National Heat Input by Fuel Type and Boiler Capacity 16
7 National S02 Emissions by Fuel Type and Boiler Capacity 17
8 National NO, Emissions by Fuel TVPe and Boiler Capacity 18
9 National Heat Input by Sulfur Content 19
10 National S02 Emissions by Sulfur Content 20
11 National Heat Input by Boiler Capacity 21
12 National S02 Emissions by Boiler Capacity 22
13 National NO, Emissions by Boiler Capacity 23
14 National Heat Input by Fuel Type 24
15 National Coal Quantities by Sulfur Content 25
16 National Coal Quantities for Scrubbed and Not Scrubbed Coal 26
17 National Coal Quantities by Sulfur Content for Scrubbed and Not Scrubbed
Coal 27
18 National Coal Heat Input for Scrubbed and Not Scrubbed Coal 28
19 National Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 29
20 National Coal S02 Emissions by Sulfur Content for Scrubbed and Not
Scrubbed Coal 30
21 National Coal Boiler Capacity by Sulfur Content 31
22 National Coal Boiler Capacity for Scrubbed and Not Scrubbed Coal 32
23 National Coal Mean Boiler Utilization by Sulfur Content 33
24 National Coal Mean Boiler Utilization by Sulfur Content for Scrubbed and
Not Scrubbed Coal 34
25 National Boiler Capacity by Mean Boiler Utilization 35
26 National Mean Boiler Utilization by Boiler Capacity 36
27 Region 1 S02 Emissions by Fuel Type 37
28 Region 1 NO, Emissions by Fuel type 38
29 Region 1 S02 Emissions by Fuel Type and Sulfur Content 39
30 Region 1 S02 Emissions by Fuel Type and Boiler Capacity 40
31 Region 1 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 41
32 Region 2 S02 Emissions by Fuel Type 42
33 Region 2 NO, Emissions by Fuel Type 43
34 Region 2 S02 Emissions by Fuel Type and Sulfur Content 44
35 Region 2 S02 Emissions by Fuel Type and Boiler Capacity 45
36 Region 2 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 46
37 Region 3 S02 Emissions by Fuel Type 47
38 Region 3 NO, Emissions by Fuel Type 48
39 Region 3 S02 Emissions by Fuel Type and Sulfur Content 49
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40 Region 3 SOa Emissions by Fuel Type and Boiler Capacity 50
41 Region 3 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 51
42 Region 4 S02 Emissions by Fuel Type 52
43 Region 4 NO, Emissions by Fuel Type 53
44 Region 4 S02 Emissions by Fuel Type and Sulfur Content 54
45 Region 4 S02 Emissions by Fuel Type and Boiler Capacity 55
46 Region 4 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 56
47 Region 5 S02 Emissions by Fuel Type 57
48 Region 5 NO, Emissions by Fuel 1VPe 58
49 Region 5 S02 Emissions by Fuel Type and Sulfur Content 59
50 Region 5 S02 Emissions by Fuel Type and Boiler Capacity 60
51 Region 5 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 61
52 Region 6 S02 Emissions by Fuel Type 62
53 Region 6 NO, Emissions by Fuel Type 63
54 Region 6 S02 Emissions by Fuel Type and Sulfur Content 64
55 Region 6 S02 Emissions by Fuel Type and Boiler Capacity 65
56 Region 6 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 66
57 Region 7 SOs Emissions by Fuel Type 67
58 Region 7 NO, Emissions by Fuel Type 68
59 Region 7 S02 Emissions by Fuel Type and Sulfur Content 69
60 Region 7 S02 Emissions by Fuel Type and Boiler Capacity 70
61 Region 7 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 71
62 Region 8 S02 Emissions by Fuel Type 72
63 Region 8 NO, Emissions by Fuel Type 73
64 Region 8 S02 Emissions by Fuel Type and Sulfur Content 74
65 Region 8 S02 Emissions by Fuel Type and Boiler Capacity 75
66 Region 8 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 76
67 Region 9 S02 Emissions by Fuel Type 77
68 Region 9 NO, Emissions by Fuel Type 78
69 Region 9 S02 Emissions by Fuel Type and Sulfur Content 79
70 Region 9 S02 Emissions by Fuel Type and Boiler Capacity 80
71 Region 9 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 81
72 Region 10 S02 Emissions by Fuel Type 82
73 Region 10 NO, Emissions by Fuel Type 83
74 Region 10 S02 Emissions by Fuel Type and Sulfur Content 84
75 Region 10 S02 Emissions by Fuel Type and Boiler Capacity 85
76 Region 10 Coal S02 Emissions for Scrubbed and Not Scrubbed Coal 86
77 Top 5 Emitting States S02 Emissions by Fuel Type 88
78 Top 5 Emitting States S02 Emissions for Scrubbed and Not Scrubbed Coal 89
79 Top 5 Emitting States NO, Emissions by Fuel Type 90
80 Indiana (ranked 2nd) S02 Emissions by Fuel Type and Sulfur Content 91
81 Indiana (ranked 2nd) S02 Emissions by Fuel Type and Boiler Capacity 92
82 Kentucky (ranked 5th) S02 Emissions by Fuel Type and Sulfur Content 93
83 Kentucky (ranked 5th) S02 Emissions by Fuel Type and Boiler Capacity 94
84 Ohio (ranked 1st) S02 Emissions by Fuel Type and Sulfur Content 95
85 Ohio (ranked 1st) S02 Emissions by Fuel Type and Boiler Capacity 96
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86 Pennsylvania (ranked 3rd) S02 Emissions by Fuel Type and Sulfur Content 97
87 Pennsylvania (ranked 3rd) S02 Emissions by Fuel Type and Boiler Capacity 98
88 West Virginia (ranked 4th) S02 Emissions by Fuel Type and Sulfur Content 99
89 West Virginia (ranked 4th) S02 Emissions by Fuel Type and Boiler Capacity 100
90 Top 3 Emitting Operating Utilities S02 Emissions by Fuel Type 102
91 Top 3 Emitting Operating Utilities SOs Emissions for Scrubbed and Not
Scrubbed Coal 103
92 Top 3 Emitting Operating Utilities NO, Emissions by Fuel Type 104
93 Georgia Power Co. (ranked 3rd) S02 Emissions by Fuel Type and Sulfur
Content 105
94 Georgia Power Co. (ranked 3rd) S02 Emissions by Fuel Type and Boiler
Capacity 106
95 Ohio Power Co. (ranked 2nd) S02 Emissions by Fuel Type and Sulfur
Content 107
96 Ohio Power Co. (ranked 2nd) S02 Emissions by Fuel Type and Boiler
Capacity 108
97 Tennessee Valley Authority (ranked 1st) S02 Emissions by Fuel Type and
Sulfur Content 109
98 Tennessee Valley Authority (ranked 1st) S02 Emissions by Fuel Type and
Boiler Capacity 110
TABLES
Number Page
1 State S02 and NO, Emissions and Ranks 87
2 Top 10 S02-Emitting Operating Utilities 101
3 Top 10 NO,-Emitting Operating Utilities 101
vi
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ABBREVIATIONS AND ACRONYMS
bbl
Barrel (One barrel = 42 gallons = 158.97 liters)
Btu
British thermal unit (One Btu = 0.253 kilocalories)
Btu/lb
Btu per pound (One Btu/lb = 0.5556 kilocalories/kilogram)
CAAA
Clean Air Act Amendments of 1990
cf
Cubic feet (One cubic foot = 0.02832 cubic meters)
DOE
U.S. Department of Energy
EIA
Energy Information Administration
EPA
U.S. Environmental Protection Agency
FGD
Flue gas desulfurization
gal
Gallons (One gallon = 3.785 liters)
GT
Gas turbine
GW
Gigawatts (109 watts)
IC
Internal combustion
ID
Identification number
kton
Thousand tons (One ton = 2000 pounds = 907.2 kilograms)
lb
Pounds (One pound = 453.6 grams)
MMBtu
Million Btus
MMcf
Million cubic feet
MMton
Million tons
MW
Megawatts (106 watts)
NAPAP
National Acid Precipitation Assessment Program
NOx
Oxides of nitrogen
NURF
National Utility Reference File
OAQPS
Office of Air Quality Planning and Standards
PC
Personal (microcomputer
Pechan
E.H. Pechan & Associates, Inc.
ROM
Regional Oxidant Modeling
SAS
Statistical Analysis System
see
Source Classification Code
SO,
Sulfur dioxide
vii
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SECTION I
INTRODUCTION
In 1985, the electric utility industry in the United States accounted for 69 percent of
all U.S. emissions of sulfur dioxide (S02) and 32 percent of emissions of oxides of nitrogen
(NO,). As a result of the Acid Deposition Control Title IV of the Clean Air Act
Amendments of 1990 (CAAAs), electric utilities by the year 2010 will be expected to
account for 8.7 million tons (87 percent) of sulfur dioxide (S02) emission reductions and 2
million tons (100 percent) of oxides of nitrogen (NOz) emission reductions. Thus, there is a
heightened interest in electric utility data that are currently available for review and
analysis.
Each year, the U.S. Department of Energy (DOE) Energy Information Administration
(EIA) collects monthly boiler-level data from Form EIA-767 ("Steam-Electric Plant
Operation and Design Report"). Only data from steam boilers are included, not data for
gas turbines (GT) or internal combustion (IC) engines.
For over 10 years, the U.S. Environmental Protection Agency (EPA) has helped fund
EIA for the production of the annual boiler-level Form EIA-767 data, which are transferred
to data tapes that are not readily available to the public. EPA has used these data in the
past to aid in the development of the National Utility Reference File (NURF) for the
National Acid Precipitation Program (NAPAP), for preparation of National Air Pollution
Emission Estimates (Trends) reports, and as the basis for the fossil-fuel steam utility
component of the Interim Inventory that is used to support the Regional Oxidant Modeling
(ROM) program.
EPA has not previously used these data (which are usually presented as aggregated
monthly electric utility boiler-level data) to graphically display data elements that are of
interest. This report presents summary information to the public from a graphical
perspective, highlighting information that would be useful for those concerned about the
CAAAs.
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SECTION n
DATA SOURCE
The data used to produce the graphics included in this report were derived from a
master data base that is based on the 1991 Form EIA-767 data (EIA, 1991).
All electric utilities with plants that have at least one operating fossil-fuel steam boiler
of at least 10 megawatts (MW) are required to provide information to EIA on Form EIA-
767, although the amount of data required from plants with less than 100 MW of steam-
electric generating capacity is much less. For plants with a nameplate rating of at least 10
MW to less than 100 MW, only selected pages of the Form EIA-767 must be completed.
(Stack and flue information is not required for these smaller plants.)
The written form is designed so that information for each plant is reported on separate
pages that relate to different levels of data that are described below:
• Plant level: One page for delineating the plant configuration, which
establishes the number of boilers and the identification numbers (IDs) for
each boiler, as well as the associated generators), flue gas desulfurization
(FGD) unit(s), flue(s), and stack(s). Boilers and generators do not necessarily
have a one-to-one correspondence.
• Boiler level: One page per boiler for monthly fuel quantity and quality data
(for coal, oil, gas, and other), one page for regulatory data, and one page for
design parameters.
• Generator level: One page for data relating to up to five generators.
• Flue gas desulfurization (FGD) level: One page for up to five FGD units for
annual operating data and one page for each FGD unit for design parameter
data.
• Flue and stack level: One page per flue-stack for design parameter data.
The master data base was created on EPA's mainframe IBM computer using
customized software written in SAS, the Statistical Analysis System software package.
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DATA PROCESSING
Form EIA-767 is processed in a series of steps aimed at converting the computerized
data into data base form. The 1991 Form EIA-767 data graphically described in this
project were processed in the same manner as was employed under EPA's ROM project.
(For further information, see the associated technical document [Pechan, 1993].) Each
"page" format is reproduced on the computer file exactly as it appears on the written page
of the form. The data from each page must be extracted from the computer file, associated
with the correct boiler, and combined with all corresponding data from the other pages for
that boiler.
For example, fuel-related boiler data ~ monthly values for each fuel burned, along with
the fuel's associated sulfur, ash, and heat content - are reported on page six. These data
must be aggregated for each fuel in order to produce annual fuel quality and quantity
estimates for each boiler before they are combined with the other data (such as control
devices and efficiencies, plant location data, associated generator generation, and
associated stack parameters).
After Source Classification Codes (SCCs) are assigned to each reported fuel for each
boiler within a plant, the SCC-specific data are then separated so that each data base
observation is on the plant-boiler-SCC level.
Although Form EIA-767 data are collected from plants with a total plant capacity of at
least 10 MW, there are fewer data elements required for those plants with a total capacity
less than 100 MW but at least 10 MW. These plants, therefore, will have certain data
elements that have missing values that will default to zero, with the exceptions that if
either boiler firing type or bottom type data are missing, default values of "wall-fired" and
"dry bottom," respectively, are assigned, based on a previous review of the data, since these
two data elements are needed in determining the SCC assignment.
Form EIA-767 data were subject to a review that resulted in some changes to boiler
firing configuration and bottom type. However, some more recent data changes resulting
from EPA's public reviews are not reflected in these data.
It should be noted that emissions data are not presently reported on the Form EIA-767
and must be calculated based on the reported data.
VARIABLE DEVELOPMENT
Data that were not obtained directly from the computerized data files (or converted to
other measurement units) were developed using existing algorithms. For example, in an
attempt to find a surrogate for capacity factor (which relies on generator generation), a
relatively new variable — boiler utilization, with a range between 0 and 1.0 - was
developed and selected to be graphically analyzed for this project. Boiler utilization is
defined as the total heat input (in MMBtu) divided by the product of a units conversion
3
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factor of 8,760 hours/year, the sum of the products of the fuel design firing rate at the
maximum steam flow (in tons, barrels, or 1,000 cubic feet per hour), and the fuel heat
content.
Other algorithms have been utilized since the 1980s. These algorithms relate to SCC
assignment and the calculation of S02 and NO, emissions, heat input, NOx control
efficiency. A description for each of these follows.
• The appropriate SCC is assigned to each fuel based on its characteristics. For
coal, the SCC is based on the American Society for Testing and Materials (ASTM)
criteria for moisture, mineral-free matter basis. If greater than 11,500 Btu/lb, coal
type is designated as bituminous. If between 8,300 and 11,500 Btu/lb, coal type is
designated as subbituminous. If less than 8,300 Btu/lb, coal type is designated as
lignite. The SCC is then based on the coal designation and the boiler type (firing
configuration and bottom type) as specified by EPA's AP-42 document (EPA,
1991). If both coal and oil were burned in the same boiler, it is assumed that the
oil is distillate; if not, it is assumed to be residual. Then, based on the oil
designation and boiler type, the SCC is assigned. For natural gas, the SCC is
based on firing type.
• Emissions calculations depend on AP-42 emission factors (EPA, 1991), which were
obtained from EPA's Office of Air Quality Planning and Standards (OAQPS). In
turn, the emission factor used depends on the SCC and pollutant. The following
equation is used to compute controlled NOx emissions:
NOx _ fuel * AP-42 * _ eff/100) * (J/2000) (1)
(tons) burned emf
The following equation is used to compute controlled S02 emissions:
S02 = fuel ^ AP-42 # %suyur „ (] _ eff/100) * (J/2000) (2)
(tons) burned emf
The following equation is used to compute heat input:
heat input fuel heat
= * (3)
(MMBtu) burned content
• The NOI control efficiency is estimated based on the assumption that the unit
would be controlled so that its emission rate would equal its regulatory emissions
limit, expressed on an annual equivalent basis. After calculating the heat input,
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controlled emissions assuming compliance with the applicable standard is back-
calculated. After calculating the uncontrolled NOx emissions, the presumed net
control efficiency is calculated.
• The AP-42 emission factor used to compute S02 emissions, 39S, (39 times the
weight percent fuel sulfur content) assumes an average of 2.5 % retention of sulfur
in the bottom ash, while the subbituminous coal emission factor, 35S, assumes an
average of 12.5 % retention of sulfur in the bottom ash.
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SECTION III
GRAPHICS PREPARATION
There are 98 charts and 3 tables presented in this report to describe the 1991 Form
EIA-767 reported and derived data. The following listing presents the variables in the
master data base.
E767 Variable Definitions for 1991
No. Variable Name
Type
Description
1
ORISPL
Num
Plant ID Code (unique)
2
BLRID
Char
Boiler ID Code (right justified)
3
UTNAME
Char
Operating Utility Name (unique)
4
STABB
Char
Postal Code for Plant Location State
5
FUELTYPE
Char
Fuel Type Code (coal, residual, distillate, natural gas)
6
SCRUBTYP
Num
SOj Scrubber Status (scrubbed, not scrubbed)
7
SULFCAT
Char
Sulfur Content Category: (0,0-.3,.3-.6,.6-l,l-2,2-3,>3)
8
SULF3
Char
Sulfur Content 3 Category: (0,0-1,1-3,>3)
9
MWCAT
Char
Boiler Nameplate Capacity Category: (0,0-25,25-100,100-200,
200-400,400-600,600-800,>800)
10
BLRUTCAT
Char
Boiler Utilization Category: (0,0-.2,.2-.4,.4-.6,.6-.8,.8-l,>l)
11
S02
Num
S02 Controlled Emissions (tons)
12
NOX
Num
NO, Controlled emissions (tons)
13
HTINPT
Num
Heat Input (MMBtu)
14
COALQUAN
Num
Annual Coal Operating Rate (SCC unit')
15
NETDC
Num
Boiler Maximum Nameplate Capacity (MW)
16
BLRUTIL
Num
Boiler Utilization (decimal 0-1)
17
EPARGN
Num
EPA Region Number for Plant Location
SCO units are tons (coal), thousand gallons (oil), and MMcf (gas).
Separate data files that include only the records and variables necessary for the charts
were created and downloaded from the mainframe to the PC. These files were input into
Microsoft Excel, a PC software package with spreadsheet and graphics capabilities.
Different chart types were used both to better describe the data and to vary the
presentation. The graphics were produced and grouped to represent national data,
national coal data, regional data, specified State data, or specified operating utility data.
The tables were prepared on the mainframe using SAS and then downloaded to the PC
and input into word processing software used to produce this report.
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SUMMARY
The charts and tables included in this report present data collected from the 1991
Form EIA-767. These are organized as follows:
• Figures 1 through 14 present national data for all types of fuels used by electric utilities.
• Figures 15 through 24 present national data for coal consumption by electric utilities.
• Figures 25 and 26 present national data for electric utility boiler capacity and
utilization.
• Figures 27 through 76 present data for each of the 10 EPA Federal regions. For the
purposes of this report, the states included in each Federal region are listed below.
Territorial possessions of the United States and Puerto Rico are not included in the
Form EIA-767 survey. The data shown for each Federal region in Figures 27 through
76 correspond to the national data shown in Figures 1, 2, 5, 6, and 19. Regional
differences are evident from an examination of these figures.
States Included in Each EPA Region
Region 1
Region 4
Region 7
Connecticut
Alabama
Iowa
Maine
Florida
Kansas
Massachusetts
Georgia
Missouri
New Hampshire
Kentucky
Nebraska
Rhode Island
Mississippi
Vermont
North Carolina
Region 8
South Carolina
Colorado
Reeion 2
Tennessee
Montana
New Jersey
North Dakota
New York
RepionS
South Dakota
Illinois
Utah
Region 3
Indiana
Wyoming
Delaware
Michigan
District of Columbia
Minnesota
Region 9
Maryland
Ohio
Arizona
Pennsylvania
Wisconsin
California
Virginia
Hawaii
West Virginia
Region 6
Nevada
Arkansas
Louisiana
Region 10
New Mexico
Alaska
Oklahoma
Idaho
Texas
Oregon
Washington
7
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• Table 1 shows the 1991 total SO2 and NOx emissions from electric utilities for
each state and for the United States as a whole. The table also shows the rank
for each state for SO2 and NOx emissions.
• Figures 77 through 89 present data for the states with the highest SO2 and NOx
emissions from electric utilities. Figures 77 through 79 show comparisons for
the top 5 emitting states for SO2 and NOx emissions by fuel type and SO2
emissions for scrubbed and not scrubbed coal. For each of the top 5 emitting
states, Figures 80 through 89 present data for SO2 emissions by fuel type and
sulfur content and SO2 emissions by fuel type and boiler capacity. These
correspond to the national data presented in Figures 5 and 7.
• Tables 2 and 3 show the 10 electric utility companies with the highest SO2 and
NOx emissions, respectively.
• Figures 90 through 98 present data for the top 3 electric utility companies with
the highest SO2 and NOx emissions.
HIGHLIGHTS
As shown in Figures 1 and 2, on a national basis coal combustion by electric utilities
contributes the most to SO2 and NOx emissions. Combustion of distillate oil, residual oil,
natural gas, and other fuels (not included in any of the figures due their relatively small
emissions) produce lesser amounts of SO2 and NOx emissions on a national basis. The
same was true in all Federal regions, except Region 1, where combustion of residual oil
produces more SO2 emissions than the combustion of coal (See Figure 27). Even though
there are no other regions where emissions from other fuels are greater than from coal
combustion, in selected regions the emissions from other fuels are much more significant
than for the nation as a whole. For example, in Region 1 (Figure 28), NOx emissions from
residual oil use are about two-thirds of the emissions from coal combustion. Other regions
where emissions from oil and gas use are significant are Region 2 (Figures 32 and 33),
Region 6 (Figure 53), and Region 9 (Figure 68).
Figure 3 shows mean boiler utilization by fuel type. The mean values shown in the
figure represent arithmetic averages of boiler utilization for each fuel type. These were
calculated by first computing a boiler utilization fraction for each individual boiler and
then computing the overall average of the individual values. Figure 3 shows that the mean
boiler utilization was about 50 percent for boilers burning coal and distillate oil, but was
much lower for boilers burning residual oil and natural gas.
Figures 4 and 5 present data according to fuel type and sulfur content ranges. Sulfur
content ranges are expressed as average weight percents of sulfur in the fuel on an as
8
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burned basis. The missing category represents those utility boilers for which no data were
reported on the Form EIA-767. Comparing Figures 4 and 5 shows that about half of the
national heat input from coal combustion was from coal with a sulfur content of 1 percent
or more, but that SC>2 emissions from combustion of coal with a sulfur content of 1 percent
or more represents over three-fourths of the total.
Figures 6, 7, and 8 display national heat input, SC^ and NOx emissions according to
generator nameplate capacity ratings in megawatts. These figures show similar
distributions of heat input, SO2 emissions, and NOx emissions by capacity category for all
cases except for SO2 emissions from natural gas combustion. Since the sulfur content of
natural gas is negligible, SO2 emissions from natural gas combustion are small for all
capacity category ranges.
Figure 14 shows that for 1991, coal accounted for over 80 percent of the total heat
input to electric utility boilers. Natural gas was a distant second, accounting for about 13
percent of total heat input, and residual oil accounted for less than 6 percent. Heat input
from distillate oil was very small, less than 0.2 percent of the national total.
Figures 15 through 24 present data for coal only. Figure 16 shows that about 26
percent of the coal burned was scrubbed, i.e. controlled by a flue gas desulfurization system
for SO2 emissions. Figure 22 shows that the capacity of coal-fired units with scrubbers
was about 21 percent of the total. The capacity utilization of units with scrubbers was
higher than for non-scrubbed units. This was true for all sulfur content ranges, as shown
in Figure 24. Figure 17 shows a breakdown of the scrubbed and not scrubbed coal
according to sulfur content ranges. This shows that a much higher portion (about 38
percent) of the coal with a sulfur content greater than 3 percent was scrubbed than for coal
with lower sulfur contents. About 19 percent of the coal with sulfur content between 1 and
3 percent was scrubbed, while about 28 percent of the coal with a sulfur content of less
than 1 percent was scrubbed. Figure 20 shows that about 95 percent of the SO2 emissions
from coal combustion came from units that were not scrubbed. Coal with a sulfur content
between 1 and 3 percent accounts for over half of this total, while coal with a sulfur content
of less than 1 percent and coal with a sulfur content in excess of 3 percent account for
approximately the same level of SO2 emissions.
Figures 25 and 26 present national data on electric utility boiler capacity and
utilization. As was the case for Figure 3, mean boiler utilization in these figures
represents an arithmetic average of the calculated boiler utilization rates for individual
boilers. Figure 25 shows the overall distribution of national utility boiler capacity
according to fractional utilization ranges. Figure 26 shows the mean boiler utilization level
for different boiler capacity size ranges. Figure 26 clearly shows that mean boiler
utilization increases as boiler capacity increases.
9
-------
REFERENCES
EIA, 1991: Energy Information Administration, "Steam-Electric Plant Operation and
Design Report," Form EIA-767,1991.
EPA, 1991: U.S. Environmental Protection Agency, "Supplement D to Compilation of Air
Pollutant Emission Factors," Volume I: Stationary Point and Area Sources, AP-42
(GPO 055-000-00391-2), September 1991.
Pechan, 1993: E.H. Pechan & Associates, Inc., "Regional Interim Emission Inventories
(1987-1991)," Vols. I (Development Methodologies) and II (Emission Summaries), EPA-
454/R-93-021a and -021b (NTIS PB93-236107 and -236115, May 1993.
10
-------
Figure 1
National S02 Emissions by Fuel Type
(15.65 MMtons total)
Residual Oil
Distillate Oil
-------
Figure 2
National NOx Emissions by Fuel Type
(7,204 ktons total)
7,000 T
6,445
6,000 --
5,000 -
4,000
;4
* c t "W
* - /Hf
S&kkiM
Coal
560
+
vV:if j
Distil lots Oil Residual Oil
Fuel Type
Natural Gas
12
-------
Figure 3
Mean Boiler Utilization by Fuel Type
jr-Vf* 1
1p$»
d£§§|
"ffcsQ
»n' r^..^ f.s- ^
m
SilPP
7&4PSX&,.
ara$s&ro&
SWB^.8KS^.
fSllill
Coal
Distillate OH Residual Oil
Fuel Type
Natural Gas
13
-------
Figure 4
National Heat Input by Fuel Type and Sulfur Content
(19,812 MMBtu total)
Fuel Type Sulfur
Content%
Coal
Missing T 2.50
1-2
Distillate Oil Missing
~ 1,418
Si 3,707
4,312
inaw
18
.3-.6;
14
2
1-2;
"1
"4
>3;
>
Missing ~
"0.0070
¦ 94
.3-.6 ~
135
416
358
107
:*5t- ^ttaaMdtiwwtai 2,836
3,566
Natural Gas Missing J
.3-.6
1-2
>3
2,635
-+-
500 1,000 1,500 2,000 2,500
Heat Input (MMBtu)
3,000
3,500
4,000
4,500
-------
Fuel Type
Coal
Distillate Oil
Residual Oil
Natural Gas
Sulfur
Content%
Missing
Figure 5
National S02 Emissions by Fuel Type and Sulfur Content
(15,757 ktons total)
1,409
1,903
¦ .v jjUagW*** W.ja
3,862
5,161
>3
Missing
0
1.65
.3-.6 "
2.54
0.81
1-2 ^
0.86
4
>3 "
~o
Missing
"o
14
m
2,720
.3-.6 J 33
203
1-2
mm 2
B 123
>3
0
Missing
0.77
0
.3-.6
0
0
1-2
0
0
>3
0
1
1,000
2,000
1
3,000
4,000
5,000
6,000
S02 (ktons)
-------
Fuel Type Capacity
(MW)
Figure 6
National Heat Input by Fuel Type and Boiler Capacity
(19,812 MMBtu total)
Coal
Missing ¦ 151
25-100
200-400
648
200-400
5) >600
Residual Oil Missing
25-100
0.32
0.03
4
6
7
14
9
200-400
>600 EB 164
Natual Gas
Missing J| 55
^2.60
25-100 268
200-400
>600
545
725
586
2,347
453
3,105
>600 :• 4,349
Distillate Oil Missing
25-100
5,422
1,000
2,000
1
3,000
4,000
1
5,000
6,000
Heat Input (MMBtu)
-------
Figure 7
National S02 Emissions by Fuel Type and Boiler Capacity
(15,754 ktons total)
Fuel Type
Capacity
(MW)
Missing
25-100
Distillate Oil Missing
0.0031
25-100
200-400
Residual Oil Missing
25-100
768
wm
3,107
2,703
a>.».'ill .IIM
3,647
4,694
Natural Gas Missing "0.0163
0.0008
25-100
200-400
>600
0.08
0.16
0.21
0.17
0.13
500
1,000
1,500
2,000
—I
2,500
3,000
3,500
4,000
1
4,500
—I
5,000
S02 (ktons)
-------
Figure 8
National NOx Emissions by Fuel Type and Boiler Capacity
(7,205 ktons total)
Fuel Type
Coal
Capacity
(MW)
Missing
25-100
73
291
1,061
200-400 .uj^xu. vummmm 1 ™
>600
re..1
osw* %
Distillate Oil Missing
0.0024
25-100
200-400
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
1,659
2,117
500
1,000
—I
1,500
2,000
2,500
NOx (ktons)
-------
4,500
4,000
Missing
Figure 9
National Heat Input by Sulfur Content
(19,811 MMBtu total)
4,460
3,925
4,125
3,500
2,946
3,000
2,638
E 2,500
a 2,000
01
1,500
1,000
0-.3
,3-.6 .6-1.0 1-2
Sulfur Content %
1,418
>3
19
-------
Figure 10
National S02 Emissions by Sulfur Content
(15,754 ktons total)
6,000 T
5,287
t
^ v'
Missing
Sulfur Content %
20
-------
Figure 11
National Heat Input by Boiler Capacity
(19,812 MMBtu total)
7,000
6,325
6,000 --
5,000
3 4,000
CQ
s
s
Ol
c
S 3,000
¦Am
2,000 --
1,000 --
224
Missing
10
3,096
Pit?
mm*
*
<=25
25-100 100-200 200-400
Boiler Capacity (MW)
400-600
>600
21
-------
5,000 T
4,500 --
4,000
3,500
3,000 -
to
E 2,500
8
CO
2,000
1,500 --
1,000 --
500
Figure 12
National S02 Emissions by Boiler Capacity
(15,753 ktons total)
189
Missing
<=25
4,918
3,213
-
a'-p*
**1f
25-100 100-200 200-400
Boiler Capacity (MW)
400-600
>600
22
-------
Figure 13
National NOx Emissions by Boiler Capacity
(7,205 ktons total)
2,500
2,289
2,000
1,500
<0
x
O
1,000 --
500
Missing
<=25
.o
1,456
V
400-600
25-100 100-200 200-400
Boiler Capacity (MW)
23
-------
Figure 14
National Heat input (MMBtu) by Fuel Type
(19,812 MMBtu total)
Natural
Gas
IResidual101
2,635
13.3%
'¦iCi 'ys-'-r-f '•;**?>•.V'-k-W-
•^*•^5.6%:.
Coal
16,027
80.9%
-------
Figure 15
National Coal Quantities by Sulfur Content
(775 MMtons total)
236
0.16
Missing
-&r-
M
tew*
-1*
msz?*
0-.3
.3-.6 .6-1.0
Sulfur Content %
1-2
2-3
>3
25
-------
Figure 16
National Coal Quantities (MMtons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
202
26%
Not Scrubbed
574
74%
26
-------
Figure 17
National Coal Quantities (MMtons) by Sulfur Content for
Scrubbed and Not Scrubbed Coal
Scrubbed
Scrubbed >3 ^
1-3 %S
7%
Scrubbed
0-1 %S
Not Scrubbed
0-1 %S
16%
307
39%
Not Scrubbed
>3 %S
5%'
230
30%
Not Scrubbed
1-3 %S
Note: Records with missing sulfur content are not included.
27
-------
Figure 18
National Coal Heat Input (MMBtu) for
Scrubbed and Not Scrubbed Coal
Scrubbed
3,675
23%,
28
-------
Figure 19
National Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
804
5%
Not Scrubbed
14,297
95%
29
-------
Figure 20
National Coal S02 Emissions (ktons) by Sulfur Content for
Scrubbed and Not Scrubbed Coal
Scrubbed
0-1 %S
1-3 %S >3 %S
Hot Scrubbed
0-1 %S
Not Scrubbed
>3 %S
3,050
20%
g&i? •• --fr.
ar;
r>:v«r-3 ••...• . ,
a-: v ¦>.»..*
8,699
58%
Not Scrubbed
1-3 %S
Note: Records with missing sulfur content are not included.
30
-------
Figure 21
National Coal Boiler Capacity by Sulfur Content
(273 GW total capacity)
0-.3 .3-.6 .6-1.0 1-2 2-3
Sulfur Content %
Note: Records with missing suttur content are not Included.
31
-------
Figure 22
National Coal Boiler Capacity (GW) for
Scrubbed and Not Scrubbed Coal
Scrubbed
56
21%
Not Scrubbed
217
79%
32
-------
Figure 23
National Coal Mean Boiler Utilization by Sulfur Content
0.60 T
0-.3
A
m?
.V »''i^jA T
. >:4\:-yXj&
- xr:&£&M
¦
.3-.6
.6-1.0 1-2
Sulfur Content %
Note: Records with missing sulfur content are not Included.
33
-------
Figure 24
National Coal Mean Boiler Utilization by Sulfur Content
for Scrubbed and Not Scrubbed Coal
Scrubbed Sulfur
Type Content %
Not 0-.3
Scrubbed
.3-.6
.6-1.0
0-.3
Scrubbed
.3-.6
.6-1.0
1-2
2-3
>3
0.00
0.47
] 0.52
1 0.52
1 0.46
0.00 0.10 0.20
Note: Records with missing sulfur content are not included.
0.30 0.40
Mean Boiler Utilization
0.50
1 0.6
1 0.66
0.60
-------
Figure 25
National Boiler Capacity by Mean Boiler Utilization
(397 GW total boiler capacity)
Missing 0-.2 .2-.4 .4-.6 .6-.8
Mean Boiler Utilization
35
-------
Figure 26
National Mean Boiler Utilization by Boiler Capacity
0.60
0.55
0.50
0.40
c
o
3
o
m
c
0.30
0.20 --
0.10 -
0.00
0.0001
1—¦
Missing <=25
0.53
25-100 100-200 200-400
Boiler Capacity (MW)
400-600
>600
36
-------
200
180
160
140
120
100
80
60
40
20
0
Figure 27
Region 1 S02 Emissions by Fuel Type
(345 ktons total)
194
y*,-i-'*.•.
WMkmtm
Coal Distillate Oil Residual Oil Natural Gas
Fuel Type
37
-------
70 x
69
Figure 28
Region 1 NOx Emissions by Fuel Type
(123 ktons total)
46
0.20
Coal
Distillate Oil Residual ON
Fuel Type
Natural Gas
38
-------
Figure 29
Region 1 S02 Emissions by Fuel Type and Sulfur Content
(345 ktons total)
_ _ Sulfur
Fuel Type Cont>nt%
Missing 0
Distillate Oil Missing
0.0024
Residual Oil Missing
0.0004
so
Natural Gas Missing
137
82
20
40
-H 1—
60 80
S02 (ktons)
100
120
140
-------
Fuel Type
Capacity
(MW)
Figure 30
Region 1 S02 Emissions by Fuel Type and Boiler Capacity
(345 ktons total)
Coal
Missing
25-100
0.74
0
17
35
Distillate Oil Missing
25-100
27
Residual Oil Missing
25-100
200-400
Natural Gas Missing
0.0010
0
0.0012
0.0004
0.0041
0.0048
0
25-100
200-400
128
20
40
60
80
100
120
140
S02 (ktons)
-------
Figure 31
Region 1 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
0.7
0.5%
Not Scrubbed
149
99.5%
41
-------
Figure 32
Region 2 S02 Emissions by Fuel Type
(454 ktons total)
314
m
vv \jv«*' 1r4.-r.xt «*
H
* i
*r-'W
' IsilS
t;
&£¦
•j&i
Coal
0.21
Distillate Oil Residual Oil
Fuel Type
0.08
Natural Gas
42
-------
Figure 33
Region 2 NOx Emissions by Fuel Type
(221 ktons total)
140 T
122
£¦"». f
-v.«
Coal Distillate Oil Residual Oil Natural Gas
Fuel Type
43
-------
Fuel Type Su,fur
Content%
Figure 34
Region 2 S02 Emissions by Fuel Type and Sulfur Content
(454 ktons total)
Missing
Distillate Oil Missing
Residual Oil Missing
3-.6 Eg 4.77
Missing
31
Natural Gas
124
20
40
60
80
100
120
140
160
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 35
Region 2 S02 Emissions by Fuel Type and Boiler Capacity
(454 ktons total)
Coal
Missing
25-100
23
84
200-400 WST^TTm
169
>600
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
Natural Gas
*K2sW*. - .
0.0042
0.0011
0.20
0.0015
0
0.0005
0
0.32
0.0028
8
23
18
200-400 ji-J* 39
,mu i..tjm 46
>600 29
Missing
25-100
200-400
>600
0
0
0.01
0.02
0.02
0.01
0.01
20
40
60
80
100
120
140
160
180
S02 (ktons)
-------
Figure 36
Region 2 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
4%
Not Scrubbed
301
96%
46
-------
3,000
2,500 --
2,000 --
to
c
o
g, 1,500 --
CM
o
to
Figure 37
Region 3 S02 Emissions by Fuel Type
(2,784 ktons total)
2,714
m
1,000
500
Coal
65.53
4.52
0.0066
Distillate Oil Residual Oil
Fuel Type
Natural Gas
47
-------
Figure 38
Region 3 NOx Emissions by Fuel Type
(835 ktons total)
umn i
700 --
94**<*KA.
f&lb&ti'PZ
500 --
!.'iK®Sm-
• - -•-¦
400 -¦
r
300 --
:-.r.iVzr
200 --
4 »
100 --
Coal
19
0.93
5.74
4-
Dlstillate Oil Residual Oil
Fuel Type
Natural Gas
48
-------
Fuel Type
Sulfur
Content%
Figure 39
Region 3 S02 Emissions by Fuel Type and Sulfur Content
(2784 ktons total)
Coal
Missing
257
>3 _ p-apisi*^ >*-*¦*¦** gga 374
1,348
Distillate Oil Missing
.3-.S
1-2
>3
0
0.37
0.60
0.14
0
3.41
0
«S
Residual Oil Missing Jo
0.0047
.3-.6 T 2
32
28
3.55
0
0
0.0066
0
0
0
0
0
0
>3
Natural Gas Missing
•3-.6
1-2
>3
200
400
600
800
1,000
1
1,200
1,400
S02 (ktons)
-------
Capacity
Fuel Type (MW)
Figure 40
Region 3 S02 Emissions by Fuel Type and Boiler Capacity
(2,784 ktons total)
Coal
Missing
21.54
25-100
200-400
534
236
"fcsfr * a- wtww
>600 ^4AUaMMfcdJViUgW«
706
1,130
Distillate Oil Missing
0.01
"0.00
25-100;
"0.15
"0.31
200-400 ^
0.07
3.63
>600 [
>.35
Residual Oil Missing ~
"0.08
0.79
25-100 [
( 7
i 9
200-400 "
¦ 13
i 15
>600;
¦ 21
Natural Gas Missing
"0.0002
"0.0001
25-100 ^
0.0011
"0.0012
200-400 ;
0.0016
"0.0023
>600 "
0.0002
4-
200
400
600
S02 (ktons)
800
1,000
1,200
-------
Figure 41
Region 3 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
41
2%
Not Scrubbed
2,673
98%
-------
4,500
Figure 42
Region 4 S02 Emissions by Fuel Type
(4,283 ktons total)
M
S
s
-------
1,600
1,400
1,200
1,000
«r
c
o
2 800
x
O
Z
600
400
200
Figure 43
Region 4 NOx Emissions by Fuel Type
(1,560 ktons total)
1,442
MpiM:
" Tikt'
'MS$.
% *•
^2«P«$V
3\* £ 7
«v» i ""w-r
Coal
0.71
-+-
Distillate Oil Residual Oil
Fuel Type
3S3l&&s*i&
Natural Gas
53
-------
_ . _ Sulfur
Fuel Type Conttnt%
Figure 44
Region 4 S02 Emissions by Fuel Type and Sulfur Content
(4,283 ktons total)
Coal
Missing To
•3-.6 WBM 81
1,401
S
>3 214
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
114
1,775
0
0.46
0.60
0.01
0
0
0
0.0126
.3-.6 "
0.0034
|H 54
1-2 "
H 36
>3
0
Natural Gas Missing
0.08
"o
.3-.6 ~
"o
"o
1-2 ^
"o
"o
>3 "
"o
200
400
600
800
—I
1,000
1,200
1,400
1,600
1,800
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 45
Region 4 S02 Emissions by Fuel Type and Boiler Capacity
(4,283 ktons total)
Missing
25-100
Distillate Oil Missing
0.0001
25-100
200-400
Residual Oil Missing
25-100
Natural Gas Missing
25-100
200-400
719
769
1,213
1,288
0.0010
0
0.02
0.01
0.02
0.01
0.02
200
400
600
800
1,000
1,200
1,400
S02 (ktons)
-------
Figure 46
Region 4 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
171
4%
Not Scrubbed
3,905
96%
56
-------
Figure 47
Region 5 S02 Emissions by Fuel Type
(5,339 ktons total)
5,329
1.37
9
0.01
Coal
Distillate Oil Residual Oil
Fuel Type
Natural Gas
57
-------
2,000
1,800
1,600
1,400
1,200
c
E i,ooo
800
600
400
200
Figure 48
Region 5 NOx Emissions by Fuel Type
(1,947 ktons total)
1,933
M
¥*"v?' *T5 ^
SstSS
0.73
3.80
j
Coal Distillate Oil Residual Oil
Fuel Type
Natural Gas
58
-------
Sulfur
Fuel Type Content%
Figure 49
Region 5 S02 Emissions by Fuel Type and Sulfur Content
(5,339 ktons total)
Coal
Missing 0
5
.3-.6
300
544
1-2 573
>3
1,861
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
2,047
0
0.60
0.69
0.08
0
0
0
0
0.0219
0.0009
18
0.63
0
0
0.01
0
0
0
0
0
0
500
—I
1,000
—I—
1,500
2,000
2,500
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 50
Region 5 S02 Emissions by Fuel Type and Boiler Capacity
(5,339 ktons total)
Coal Missing
25-100
200-400
>600
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
1,434
744
1,937
734
0.03
0.0012
0.15
0.28
0.21
0.46
0.23
0.01
0
1.67
0.06
0
7
0.27
0.0031
0.0001
0.0041
0.0014
0.0029
0.0004
0.001
200
400
600
800
1,000
1,200
—I
1,400
1,600
1,800
2,000
S02 (ktons)
-------
Figure 51
Region 5 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
153
3%
Not Scrubbed
5,177
97%
-------
Figure 52
Region 6 S02 Emissions by Fuel Type
(803 ktons total)
802
200 -
IllNlllpI
"tit" "
mm
....,
mmmm
w$
sag^Hm
IV* ,
}*:y<.1
ssir
£*^;&«SSt5
gsSF
m
Pw.
£«•»
SH
jy.,.
fc&ri
'\>iK
is#
&2feiS
sEm®
Coal
0.35
0.50
0.42
Distillate Oil Residual Oil
Fuel Type
Natural Gas
62
-------
800 T
Figure 53
Region 6 NOx Emissions by Fuel Type
(1,053 ktons total)
745
700 --
600 --
500 -
M
E 400
x
O
z
300
200
100 --
m
«ts
- -
S
spff
M..
***&
?jje*
P
J*#®
te
|§^
m
jar-
p&M-
bSSyKfr
Coal
0.17
0.25
¦+-
Distillate Oil Residual Oil
Fuel Type
308
a. /«! ~
M«i« -v p* . •
Natural Gas
63
-------
Fuel Type
Coal
Sulfur
Content%
Missing To
Figure 54
Region 6 S02 Emissions by Fuel Type and Sulfur Content
(803 ktons total)
.3-.6
1-2
>3
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
18
473
143
JJTMWZZm-&mSSLW1SS53B*.:
0
0
0
0.06
0.29
0.0023
0
0
0
0
0.01
0.06
0.36
0.06
0
0
0.42
0
0
0
0
0
0
168
50
100
150
200
250
300
350
400
450
500
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 55
Region 6 S02 Emissions by Fuel Type and Boiler Capacity
(803 ktons total)
Coal
Missing
25-100
200-400
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
0
0
0
0
0.02
0.18
0.15
0.0041
0
0.01
0.08
0.19
0.15
0.06
0.01
0
0.02
0.08
0.12
0.13
0.07
468
220
50
100
150
200
250
300
350
400
450
500
S02 (ktons)
-------
"e9fon 6 Coal S02 Emi56
Scrubbed
Wots,
cwbbe
-------
Figure 57
Region 7 S02 Emissions by Fuel Type
(1,049 ktons total)
1,200 T
1,047
Coal Distillate Oil Residual Oil Natural Gas
Fuel Type
67
-------
Figure 58
Region 7 NOx Emissions by Fuel Type
(562 ktons total)
550
Coal
0.13
0.25
Distillate Oil Residual Oil
Fuel Type
11.59
Natural Gas
68
-------
Fuel Type
Sulfur
Content%
Figure 59
Region 7 S02 Emissions by Fuel Type and Sulfur Content
(1,049 ktons total)
Missing
» f.i¦'**> ¦
^ nit *1*^^*1 4 .
>3 wtmwmmgm 85
Distillate Oil Missing
Residual Oil Missing
0.0002
0.0003
Natural Gas Missing
0.0144
651
100
200
300
400
500
600
700
S02 (ktons)
-------
Capacity
Fuel Type (MW)
Figure 60
Region 7 S02 Emissions by Fuel Type and Boiler Capacity
(1,049 ktons total)
Coal Missing 32
0.31
25*100
200-400
>600
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
137
619
0.0015
0.0005
0.01
0.01
0.02
0.22
0.06
0.0004
1
0.01
0.01
0
0
0
0.0019
0.0006
0.0041
0.0056
0.0018
0.0004
0.00004
100
200
300
400
500
600
700
S02 (ktons)
-------
Figure 61
Region 7 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
62
6%
Not Scrubbed
984
94%
-------
450
400
350
300
250
to
c
o
&
s
w 200
150
100
50
Figure 62
Region 8 S02 Emissions by Fuel Type
(417 ktons total)
417
.r. .'•"'A
MA
tup
lite:
fS®
• ,§&&
'"*i JV itVft
Coal
0.12
0.10
0.0028
-+-
+-
Distillate Oil Residual Oil Natural Gas
Fuel Typa
72
-------
Figure 63
Region 8 NOx Emissions by Fuel Type
(549 ktons total)
547
ml
fawtfkS
ISB1
ifei
'S»S:
r~K
-.t, ^
as33fr*&jr
paSaatfs&ai&Ssgs
P£PF
OR
|§il§2#si£.
-ft.
Coal
0.12
0.07
-t-
Distillate Oil Residual Oil
Fuel Type
Natural Gas
73
-------
Fuel Type
Sulfur
Content%
Figure 64
Region 8 S02 Emissions by Fuel Type and Sulfur Content
(417 ktons total)
Coal
Missing 0
0.63
.3-.6
Distillate Oil Missing 0
0.05
.3-.6 T 0.05
0
0.02
0
0
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing " 0.0028
0
.3-.6 ""
.3-.6
>3
0
0
0.0018
0.09
0.01
0
0
20
40
60
80
100
120
140
160
180
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 65
Region 8 S02 Emissions by Fuel Type and Boiler Capacity
(417 ktons total)
Coal
Missing
25-100
Jt*
78
167
>600 lES 7
129
Distillate Oil Missing
0.0033
"0
25-100 "
"0.0038
0.02
200-400 [
0.04
0.06
>600 ~
0.0039
Residual Oil pissing
0.01
0.0018
25-100 ]
0.09
0
200-400 j
"o
"o
>600 ~
^0
Natural Gas Missing ~
0.0008
0.00002
25-100 "
0.0002
0.0016
200-400 ~
0.0001
" 0.00002
>600 '
"o
20
40
60
80
100
120
140
160
180
S02 (ktons)
-------
Figure 66
Region 8 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
129
31%
76
-------
Figure 67
Region 9 S02 Emissions by Fuel Type
(208 ktons total)
Coal Distillate Oil Residual Oil Natural Gas
Fuel Type
77
-------
Figure 68
Region 9 NOx Emissions by Fuel Type
(303 ktons total)
160
140
120
x
O
2 80
60
40
20
176
Site*)
miIS§§
mm
pSSSi
fM
iSSfeSK
. j.. .&sj£&6»£
ffihwr5---
Coal
0.07
Distillate Oil Residual Oil
Fu«l Type
113
Natural Gas
78
-------
Fuel Type
Sulfur
Content%
Figure 69
Region 9 S02 Emissions by Fuel Type and Sulfur Content
(208 ktons total)
Missing
Distillate Oil Missing
Residual Oil Missing
Natural Gas Missing
16.58
170
20
40
60
80
100
120
140
160
180
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 70
Region 9 S02 Emissions by Fuel Type and Boiler Capacity
(208 ktons total)
Coal
Missing
25-100
Distillate Oil Missing
25-100
0.0005
Residual Oil Missing
25-100
11.81
0.47
0.01
>600 I 0.47
Natural Gas Missing
25-100
200-400
>600
0.0007
0
0.01
0.04
0.04
0.02
0.03
45
126
20
40
60
80
100
120
140
S02 (ktons)
-------
Figure 71
Region 9 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Scrubbed
16
9%
Not Scrubbed
164
91%
81
-------
Figure 72
Region 10 S02 Emissions by Fuel Type
(71 ktons total)
80 T
Vv -«¦ Vp
sk
mk
SlIPP
2 40 --
i - v
iVSSgfEC
Coal
0.04
Distillate Oil Residual Oil
Fuel Type
Natural Gas
82
-------
Figure 73
Region 10 NOx Emissions by Fuel Type
(52 ktons total)
52
Safe
Coal Distillate Oil Residual Oil Natural Gas
Fual Type
83
-------
Sulfur
Fuel Type content*
Coal
Missing To
Missing
Distillate Oil
.3-.6
1-2
>3
Missing
Residual Oil
.3-.6
1-2
>3
Natural Gas
Missing 0
.3-.6
1-2
>3
0
0.01
0.03
0
0
0
0
0
0
0
0
0
0
0
Figure 74
Region 10 S02 Emissions by Fuel Type and Sulfur Content
(71 ktons total)
59
-4-
10
20
30
S02 (ktons)
40
50
—I
60
-------
Capacity
Fuel Type (MW)
Figure 75
Region 10 S02 Emissions by Fuel Type and Boiler Capacity
(71 ktons total)
Coal
Missing | 0.79
Distillate Oil
Residual Oil
Natural Gas
0
25-100 "
"o
*0
200-400 ~
"
0
>600 ~
Missing
r 0.0018
"0
25-100 "
>
0
200-400 "
0
0.03
>600 ~
0.01
Missing
"
"o
"0
25-100 "
"o
"o
200-400 *
"o
"o
>600 "
>
Missing
"o
"o
25-100 ~
"o
"o
200-400 ~
"o
"o
>600 "
"o
11
59
-+-
10
20
30
S02 (ktons)
40
50
60
-------
Figure 76
Region 10 Coal S02 Emissions (ktons) for
Scrubbed and Not Scrubbed Coal
Not Scrubbed
100%
-------
Table 1
State SO, and NO, Emissions and Ranks
so,
SO,
NO.
NO,
State
(tons)
Rank
(tons)
Rank
AK
563
48
2,611
46
AL
533,182
11
211,499
11
AR
66,422
31
77,910
30
AZ
125,358
23
120,983
20
CA
1,488
46
104,520
26
CO
83,013
27
118,191
22
CT
48,906
37
21,007
43
DC
1,372
47
390
49
DE
48,800
38
24,307
40
FL
725,666
10
340,529
5
GA
793,728
7
200,350
12
HI
24,627
42
12,620
44
IA
181,578
19
118,937
21
ID
0
51
0
51
IL
873,930
6
336,103
6
IN
1,468,234
2
491,076
3
KS
75,850
30
113,525
25
KY
874,894
5
335,328
7
LA
106,468
24
116,744
23
MA
236,508
18
75,040
32
MD
262,686
17
88,943
27
ME
11,403
44
2,309
47
MI
384,428
14
284,926
8
MN
79,696
29
146,670
17
MO
738,043
9
265,166
10
MS
105,470
25
45,658
38
MT
19,555
43
62,739
36
NC
330,555
15
164,064
15
ND
172,674
21
114,756
24
NE
53,177
36
64,359
35
NH
48,206
39
23,738
41
NJ
64,479
32
50,805
37
NM
53,983
35
76,688
31
NV
56,361
34
65,364
34
NY
390,309
13
170,873
14
OH
2,241,387
1
527,182
2
OK
103,159
26
129,106
19
OR
10,755
45
10,722
45
PA
1,225,024
3
363,429
4
RI
374
49
607
48
SC
163,410
22
81,785
29
SD
32,629
40
22,467
42
TN
755,348
8
180,336
13
TX
473,572
12
652,659
1
UT
28,826
41
85,763
28
VA
179,800
20
74,949
33
VT
1
50
298
50
WA
59,447
33
39,068
39
WI
291,966
16
160,314
16
WV
1,066,396
4
281,900
9
WY
80,113
28
145,411
18
US
15,753321
7,204,725
87
-------
Figure 77
Top 5 Emitting States S02 Emissions by Fuel Type
2,500
2,000 --
1,500 - «-
1
s
CO
1,000
500
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
88
-------
Figure 78
Top 5 Emitting States S02 Emissions (ktons) for Scrubbed and Not Scrubbed Coal
Scrubbed
27
1%
Not Scrubbed
2,214
99%
Ohio
Scrubbed
68
5%
Not Scrubbed
1,400
95%
Indiana
Scrubbed
41
3%
Not Scrubbed
1,171
97%
Pennsylvania
Scrubbed
0
0%
Not Scrubbed
1,066
100%
West Virginia
Scrubbed
75
8.5%
Not Scrubbed
800
91.5%
Kentucky
-------
Figure 79
Top 5 Emitting States NOx Emissions by Fuel Type
Pennsylvania
Florida
90
-------
Figure 80
Indiana (ranked 2nd) S02 Emissions by Fuel Type and Sulfur Content
(1,468 ktons total)
Fuel Type Sulfur
Content%
Coal
Missing
.3-.6
1-2 pmmm 64
>3 350
956
Missing 0
Distillate Oil
•3-.6
to 1-2
>3
Missing
Residual Oil
.3-.S
1-2
>3
Missing
Natural Gas
.3-.6
1-2
>3
0.12
0.16
0
0
0
0
0
0.01
0
0
0
0
0
0.0027
0
0
0
0
0
0
100
200
300
400
500
600
700
800
900
1,000
S02 (ktons)
-------
Fuel Type
(MW)
Figure 81
Indiana (ranked 2nd) S02 Emissions by Fuel Type and Boiler Capacity
Capacity (1,468 ktons total)
Coal
49
Missing M 21
25-100
200-400 319
usmwwwiiw
>600 56
Distillate Oil Missing
453
570
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
0.0002
0
0.04
0.06
0.03
0.05
0.11
0.0023
0
0.01
0
0
0
0
0.00004
0
0.0011
0.0008
0.0003
0.0003
0
100
200
300
400
500
600
S02 (ktons)
-------
Fuel Type Q0ntenty0
Figure 82
Kentucky (ranked 5th) S02 Emissions by Fuel Type and Sulfur Content
Sulfur (875 ktons total)
Coal
Missing
440
203
Missing
0
"0.05
.3-.6 |
0.12
"o
1-2;
"o
l0
>3 "
0
Residual Oil Mislsng
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
0
0
0.0024
0
0
0
0
0.00002
0
0
0
0
0
0
50
100
150
200
250
300
350
400
450
S02 (ktons)
-------
Figure 83
Capacity Kentucky (ranked 5th) S02 Emissions by Fuel Type and Boiler Capacity
Fuel Type (MW) (875 ktons total)
Coal Missing I 1.25
"0
25-100 —WW 16
200-400
>600
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
263
0
0
0.0050
0.03
0.06
0.06
0.02
0
0.0024
0
0
0
0
0
0
0
0
0
0.00002
0
0
50
100
150
200
250
300
S02 (ktons)
-------
Figure 84
Fuel Type Sulfur Ohio (ranked 1st) S02 Emissions by Fuel Type and Sulfur Content
Content% (2,241 ktons total)
Coal
Missing
.3-.6
1-2
>3
96
222
jL."'«v^.T£ ¦ ... .>•
464
Distillate Oil Missing
r0
0.09
.3-.6 ~
0.36
0
1-2 ~
0
0
>3 ^
0
Residual Oil Missing
"o
"o
.3-.6 "
"o
"o
1-2 ^
0.63
0
>3 "
0
Natural Gas Missing ~
~ 0.0009
.3-.6
1-2
>3
200
1,456
-+-
4-
400
600
800
S02 (ktons)
1,000
1,200
1,400
1,600
-------
Fuel Type
Capacity
(MW)
Figure 85
Ohio (ranked 1st) S02 Emissions by Fuel Type and Boiler Capacity
(2,241 ktons total)
Coal
Missing
25-100
200-400
>600
Distillate Oil Missing
25-100
200-400
>600
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
•WMMM 82
mmm
0.01
o
0.02
0.12
0.02
0.22
0.06
0
0
0.63
0
0
0
0
0.00001
0.00001
0.0009
0.00001
0
0
0
769
100
200
300
400
500
600
700
800
S02 (ktons)
-------
Fuel Type
Sulfur
Content%
Figure 86
Pennsylvania (ranked 3rd) S02 Emissions by Fuel Type and Sulfur Content
(1,225 ktons total)
Coal
Missing 0
Distillate Oil Missing
Residual Oil Missing
0.0047
.3-.6 | 2
Natural Gas Missing
0.0004
69
JRirn ^
449
100
200
300
400
500
600
700
S02 (ktons)
-------
Fuel Type
Coal
Figure 87
Capacity Pennsylvania (ranked 3rd) S02 Emissions by Fuel Type and Boiler Capacity
(1,225 ktons total)
Missing
25-100
322
>600
Distillate Oil Missing "
"0.01
0.0004
25-100 ~
0.04
" 0.14
200-400 ~
0.03
0.07
>600 j
10.11
Residual Oil Missing
0.08
"o
25-100 '
0
I 2
200-400 ^
I 1
"o
>600 ]
¦ 10
Natural Gas Missing
0.0001
"o
25-100 "
0
"o
200-400 ~
0.0003
0.0001
>600 ~
0
533
100
200
300
400
500
600
S02 (ktons)
-------
Fuel Type
Sulfur
Content%
Figure 88
West Virginia (ranked 4th) S02 Emissions by Fuel Type and Sulfur Content
(1,066 ktons total)
Coal Missing
.3-.6
1-2
>3
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
.. .-^
0
0.06
0.31
0
0
0
0
0
0
0
0
0
0
0
0.00004
0
0
0
0
0
0
359
267
341
50
100
150
200
250
300
350
400
S02 (ktons)
-------
Figure 89
Fuel Type West Virginia (ranked 4th) S02 Emissions by Fuel Type and Boiler Capacity
( ^ (1,066 ktons total)
Coal
Missing
25-100
204
200-400
236
>600
597
Missing
Distillate Oil
25-100
0.0054
0.04
0.02
0.07
0.24 .
200-400
>600
Missing
Residual Oil
25-100
200-400
>600
Missing
Natural Gas
25-100
200-400
>600
0.00004
400
500
600
0
100
200
300
S02 (ktons)
-------
Table 2
Top 10 SOj-Emltting Operating Utilities
SO,
so,
Utility Name
(tons)
Rank '
TENNESSEE VALLEY AUTHORITY
1,064,194
1
OHIO POWER CO
891,188
2
GEORGIA POWER CO
788,480
3
MONONGAHELA POWER COMPANY
563,703
4
PENNSYLVANIA ELECTRIC CO
506,402
5
PS1 ENERGY, INC.
505,710
6
ALABAMA POWER CO
421,721
7
UNION ELECTRIC CO
368,465
8
PENNSYLVANIA POWER & LIGHT CO
326,268
9
ILLINOIS POWER CO
302,309
10
Table 3
Top 10 NOx-Emitting Operating Utilities
NO,
NO,
Utility Name
(tons)
Rank
TENNESSEE VALLEY AUTHORITY
365,732
1
TEXAS UTILITIES ELECTRIC CO
265,825
2
GEORGIA POWER CO
198,068
3
PACIFICORP
192,148
4
DETROIT EDISON CO
188,320
5
OHIO POWER CO
167,543
6
ALABAMA POWER CO
148,534
7
PENNSYLVANIA ELECTRIC CO
132,616
8
COMMONWEALTH EDISON CO
132,451
9
HOUSTON LIGHTING & POWER CO
130,431
10
101
-------
Figure 90
Top 3 Emitting Operating Utilities S02 Emissions by Fuel Type
1,200 T
1,064
1,000
Ohio Power
Georgia Power
102
-------
Figure 91
Top 3 Emitting Operating Utilities S02 Emissions
Scrubbed and Not Scrubbed Coal
(ktons) for
Scrubbed
Not Scrubbed
1,028
97%
Not Scrubbed
891
100%
TVA
Ohio Power
-------
Figure 92
Top 3 Emitting Operating Utilities NOx Emissions by Fuel Type
400
350
300
250
E 200
x
O
150
100
50
366
Texas Utilities Electric
Georgia Power
104
-------
Fuel Type
Sulfur
Content%
Figure 93
Georgia Power Co. (ranked 3rd) S02 Emissions by Fuel Type and Sulfur Content
(788 ktons total)
Coal Missing
.3-.6
1-2
>3
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
0
0
0.18
0
0
0
0
0
0
0.0010
0
0.08
0
0
0.00002
0
0
0
0
0
0
456
50
100
150
200
250
300
350
400
450
500
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 94
Georgia Power Co. (ranked 3rd) S02 Emissions by Fuel Type and Boiler Capacity
(788 ktons total)
Coal
Missing
25-100
200-400 E
*e. ***#:¦:
>600
Missing
"0
"0
25-100 ]
0.01
0.02
200-400 ~
0.02
0.02
>600
"0.11
532
Residual Oil Missing
25-100
200-400
>600
Natural Gas Missing
25-100
200-400
>600
0
0
0.08
0
0
0
0
0
0
0.00002
0
0
0
0
100
200
300
S02 (ktons)
400
500
600
-------
Fuel Type
Sulfur
Content%
Figure 95
Ohio Power Co. (ranked 2nd) S02 Emissions by Fuel Type and Sulfur Content
(891 ktons total)
Missing
Distillate Oil Missing
Residual Oil Missing
Natural Gas Missing
830
100
200
300
400
500
600
700
800
900
S02 (ktons)
-------
Fuel Type
Capacity
(MW)
Figure 96
Ohio Power Co. (ranked 2nd) S02 Emissions by Fuel Type and Boiler Capacity
(891 ktons total)
Coal
Missing
25-100
a
0.88
0
0
200-400 0
>600
Missing
0.01
"o
25-100 [
"o
"0.02
200-400 "
"o
0.02
>600 ~
10.09
Missing
0
"o
25-100 "
"o
"o
200-400 ~
"o
"o
>600 "
0
Missing
"o
"o
25-100 "
"o
"o
200-400 ~
"o
"o
>600 "
"o
291
126
473
50
100
150
200
250
300
350
400
450
500
S02 (ktons)
-------
Fuel Type
Sulfur
Content%
Figure 97
Tennessee Valley Authority (ranked 1st) S02 Emissions by Fuel Type and Sulfur Content
(1,064 ktons total)
Coai Missing
•3-.6
1-2
>3
Distillate Oil Missing
.3-.6
1-2
>3
Residual Oil Missing
.3-.6
1-2
>3
Natural Gas Missing
.3-.6
1-2
>3
¦ 12
0
0.14
0.09
0.01
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
66
342
643
-t-
100
200
300 400
S02 (ktons)
500
600
700
-------
Capacity Fi9ure 98
Fuel Type (MYf) Tennessee Valley Authority (ranked 1st) S02 Emissions by Fuel Type and
Boiler Capacity
(1,064 ktons total)
Coal
Missing
25-100
200-400
Distillate Oil Missing
25-100
Residual Oil Missing
25-100
200-400
Missing
25-100
190
S'JWW 50
Natural Gas
100
200
297
527
300
400
500
600
S02 (ktons)
------- |