TYPICAL SULFUR DIOXIDE EMISSIONS FROM
SUBPART D POWER PLANTS FIRING
COMPLIANCE COAL
PEDCo ENVIRONMENTAL
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TYPICAL SULFUR DIOXIDE EMISSIONS FROM
SUBPART D POWER PLANTS FIRING
COMPLIANCE COAL
by
David R. Dunbar
PEDCo Environmental~ Inc.
11499 Chester Road
Post Office Box 46100
Cincinnati, Ohio 45246-0100
Contract No. 68-02-3512
Work Assignment No. 65
PN 3525-65
Task Manager
Walter H. Stevenson
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF AIR QUALITY PLANNING AND STANDARDS
RESEARCH TRIANGLE PARK, NORTH CAROLINA 27711
May 1984
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Figures.
Tab 1 es. .
CONTENTS
. . . . . . . e, . . . . . . . . .
. . . .
..........
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........
. . . .
......
l.
2.
Summary and Conclusions
. . . .
........
. . . . . . '.
Introduction. . . . . .
........
.......
. . . .
Background. . . . . . . . . . . . . . . . . . . . . . .
Methodo logy.. . . . . . . . . . e. . . . . . . . . . . . .
3.
Survey of Coal-Fired Subpart D Units.
. . . .
........
4.
5.
Identification of potential Subpart D units. . ~ . . . .
Verification of Subpart D units. . . . . . . . . . . . .
Monthly Sulfur Dioxide Emissions. . . .
. . . .
.......
Estimated Sulfur Dioxide Emission.
. . . .
. . . .
. . . . .
Estimation of 3-h, 24-h, 7-day rolling, and 30-day rol-
ing average S02 emissions. . ~ . . . . . . . . . . . .
Evaluation of compliance with Subpart D limits on a 3-h,
24-h, 7-day, and 30-day basis. . . . . . . . . . . . .
References. . .
Appendices
. . . . . 8- .
................
.....
A.
B.
Listing of coal-fired power plants with all Subpart D (NSPS)
units (compliance coal and FGD) . . . . . . . . . . . . . .
Listing of coal-fired power plants with both SIP and
Subpart D (NSPS) units. . . . . . . . . . . . . . . . . . .
Monthly S02 emissions for Subpart D units. . . . . . . . . .
Map denoting boundary between Eastern and Western units. . .
C.
D.
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64
72
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Number
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FIGURES
Example of Table 7 from 1981 Annual report
Example of Appendix A listing.
........
.....
.........
Example of AppendixB listing. .
.......
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Example of information available from Cost and Quality of
Fuels for Electric Utility Plants - Monthly. . . . . . .
Example of individual monthly S02 emissions from January
1982 through June 1983 . . . . . . . . . . . . . . . . .
Typical S02 emission variability. . .. . . . . . . . . .
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Number
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3
4
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6
7
8
9
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TABLES
Summary of Coal~Fired Subpart 0 Utility Units. . . . . . .
Summary of Monthly S02 Emission Levels at Subpart 0 Com-
pliance-Coal-fired Utility Units. . . . . . . . . . . . .
Total Subpart 0 Coal-fired Unit Inventory.
. . . . . . . .
Monthly S02 Emissions at Subpart 0 (Compliance Coal) Units.
Monthly S02 Emissions for Eastern Compliance Coal-fired
Units Subject to Subpart D. . . . . . . . . . ~ . . . . .
Monthly S02 Emissions for Western Compliance Coal-fired
Units Subject to Subpart D. . . . . . . . . . . . . . . .
Long-Term Average S02 Emission Rate for Eastern and Western
Subpart 0 Utility Units (Compliance Coal) . . . . . . . .
Monthly Average and Projected 3-h Average S02 Emissions for
Eastern Electric Generating Units Subject to Subpart D. .
Monthly Average and Projected 3-h Average S02 Emissions.for
Western Electric Generating Units Subject to Subpart D. .
Monthly Average and Projected 24-h Average S02 Emissions
for Eastern Electric Generating Units Subject to Subpart
D........................... .
Monthly Average and Projected 24-h Average S02 Emissions
for We~tern Electric Generating Units Subject to Subpart
D........................... .
Monthly Average and Projected 7-day (Rolling) S02 Emissions
for Eastern Electric Generating Units Subject to Subpart
D........................... .
Monthly Average and Projected 7-day (Rolling) Average S02
Emissions for Western Electric Generating Units Subject
to Sub pa rt D. . . . . . . . . . . . . . . . . . . . . ...
v
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32
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37
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42
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Number
14
15
16
17
18
19
20
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22
TABLES (continued)
Monthly Average and Projected 30-Day (Rolling Average) S02
Emissions for Eastern Electric Generating Units Subject
to Subpa rt D. . . . . . . . . . . . . . . . . . . . . . .
Monthly Average and Projected 30-Day (Rolling Average) S02
Emissions for Western Electric Generating Units Subject
to Subpart D. . . . . . . . . . . . . . . . . . . . . . .
Projected Annual S02 Emission Levels Required to Meet 1.2
lb 502/106 Btu at Various Averaging Times. . . . . . . .
Projected Annual 502 Emission Levels Required to Meet 1.2
lb S02/106 Btu on a 3-h Basis. . . . . . . . . . . . . .
Projected Annual S02 Emission Levels Required to Meet 1.2
lb S02/106 Btu on a 24-h Basis. . . . . . . . . . . . . .
Projected Annual S02 Emission Levels Required to Meet 1.2
lb S02 on a 7-day (Roll ing Average) Basis. . . . . . . .
Projected Annual S02 Emission Levels Required to Meet 1.2
lb S02/106 Btu on a 30-Day (Rolling Average) Basis. . . .
Projected Annual S02 Emission Levels Required to Meet 1.2 lb
S02/106 Btu on a 3-h Basis Assuming Normal Versus a
Lognormal Distribution. . . . . . . . . . . . . . . . .
Projected Annual S02 Emission Levels Required to Meet 1.2 lb
502/106 Btu on a 24-h Basis Assuming Normal Versus a
Lognormal Distribution. . . . . . . . . . . . . . . . . .
vi
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SECTION 1
SUMMARY AND CONCLUSIONS
On December 23, 1971, the U.S. Environmental Protection Agency (EPA)
adopted New Source Performance Standards (NSPS) for fossil-fuel-fired steam
generators that had a heat input greater than 250 x 106 Btu/h and which com-
menced construction after August 17, 1971. The standards limited emissions
. .
of sulfur dioxide (S02)' particulate matter, and nitrogen oxides. Coal-fired
steam-generating units at electric utilities are the most significant type
of fossil-fuel-fired steam generating units covered under Subpart D.
The' purpose of this study was to determine the typical S02 emission rates
from electric utility steam-generating units firing compliance coal. Before
the typical S02 emission rates could be determined, an inventory of coal-fired
Subpart D units had to be developed.. The initial inventory included power
plants firing compliance .coal.andpower plants operating flue gas desulfuriza-
tion (FGD) systems to comply with the Subpart D S02 emission standard.
This study identified 140 coal-fired electric utility steam generating
units subject to Subpart D that were operating at the end of 1983. The 140
units were divided into two groups. The first group included 78 units that -
were firing compliance coal, and the second group included 62 units that were
operating FGD systems (Table 1). Because continuous S02 emission monitoring
data were not readily available for many of the 78 compliance coal units,
Department of Energy (DOE) monthly coal sulfur content data from January 1982
. .
through June 1983 were used to determine the S02 emissions for a subset of
the 78 compliance coal units (i.e., this included 49 units where all units at
a plant site were subject to Subpart D).
For the compliance-coal-fired units analyzed, 18 months of fuel quality
data were reviewed for each power plant. The individual monthly S02 emission
6
levels ranged from 0.51 lb S02/10 Btu for one Western power plant to 1.32 lb
6
S02/10 Btu for one Eastern power plant. The 18-month (long-term) average
emission levels ranged from 0.60 lb S02/106 Btu to 1.04 lb S02/106 Btu. The
1
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TABLE 1.
SUMMARY OF COAL-FIRED SUBPART D UTILITY UNITSa
Technolo
Number of units
FGD
Compliance coal
Total
62
78b
140
aOperating as of June 1983.
bOOE data are only available on a plant total lias received" basis. The sub-
set analyzed include Subpart D units where all units at a plant were Subpart
D units (i.e., 49 out of the 78 compliance coal-fired units were included in
the subset analysis).
long-term average emission rate for the compliance-coal-fired units was 0.84
lb S02/106 Btu; the Western units averaged 0.81 and the Eastern units averaged
0.8a lb 502/106 Btu (Table 2).
TABLE 2. SUMMARY OF MONTHLY S02 EMISSION LEVELS AT SUBPART D COMPLIANCE-
COAL-FIRED UTILITY UNITS
502 emi ssions,. lb/106 Btub
Power plant Minimum Maxlmum 18-month
location month month averaqe
East 0.58 1. 32 0.88
West 0.51 1.19 0.81
National 0.51 .- 1.32 0.84
aAnalysis included 49 compliance-coal-fired units.
bAssumes 95 percent of the sulfur is converted to S02.
Based on the 18 month average S02 emis~ion rates, statistical projections
were made for the 3-h, 24-h, 7-day (rolling), and 30-day (rolling) average S02
emissions that would be expected at each of the Subpart D units analyzed.
The following statistical assumptions were used to project or estimate the
3-h, 24-h, 7-day, and 30-day average 502 emissions given the monthly S02 emis-
sion level: 1) the 1-h emission levels can be represented by an AR(l) process,
b) the emission levels are normally distributed, c) the relative standard
2
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deviation (RSD) of a rolling average can be estimated by the RSD of the I-h
time seriest d) the autocorrelation of the rolling average time series can be
estimated from the autocorrelation of the 1-h time seriest and e) the 18 month
average is equivalent to the long-term mean.
Based on these statistical assumptionst the maximum estimated 3-ht 24-ht
7-daYt and 30-day average 502 emission levels were projected for each of the
Subpart D units analyzed. The maximum projected 3-h average emissions ranged
f~om 0.79 to 2.03 lb 502/106 Btu; the maximum projected 24-h average emissions
ranged from 0.76 to 1.76 lb 502/106 Btu; the 7-day rolling average 502 emis-
sions ranged from 0.69 to 1.39 lb 502/106 Btu; and the 30-day rolling average
502 emissions ranged from 0.65 to 1.22 lb 502/106 Btu. These projections
assumed a 24-h autocorrelation of 0.7t a range of RSD's (lOt 1St and 20%) and
a range of compliance levels (1 exceedance in 10 yeart 1 exceedance per year
and 99% of the time). A review of these projections indicates that the pro-
jections are very sensitive to the statistical assumptions.
Based on the preceding statistical assumptionst several calculations were
performed to estimate the long-term 502 emissions in lb/106 Btu that would be
required to meet the Subpart D emission limit of 1.2 lb 502/106 Btu on a 3-ht
24-ht 7-daYt and 30-day basis. The results of these calculations indicated
that with an RSD of 20 percent and a 24-h autocorrelation 0.7t annual 502
emissions would have to be equal to or less than 0.62 lb/106 Btu for the unit
not to exceed the 1.2 lb/106 Btu on a 3-h average more than once in 10 years.
The annual 502 emissions could be as high as 0.77 lb/106 Btu if the unit were
permitted to exceed the 3-h limit 29 times per year (99% compliance level).
The annual 502 emi ssions necessary to meet the 1. 2 1 b/106 Btu standard on a
3-h basis varied from 0.56 to 0.95 lb/106 Btut depending on the assumed RSD
(lOt 1St or 20%)t 24-h autocorrelation (0.5t 0.7t or 0.8)t and whether the
unit would be permitted to exceed the limit 29 times per yeart once per year
or only once in 10 years. The annual 502 emissions necessary to meet the 1.2
lb/106 Btu standard on a: 24-h basis varied from 0.71 to 0.97 lb/106 Btu;
7-day rolling average varied from 0.87 to 1.09 lb/106 Btu; and 30-day rolling
average varied from 1.00 to 1.14 lb/l06 Btu depending on the RSD and 24-h
autocorrelation that were assumed and whether the unit would be permitted to
exceed the limit 4 times per yeart once per yeart.or only once in lQ years.
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The above variation in the annual emission limits clearly points out
that the ability of a given unit to meet. a limit of the 1.2 lb/106 Btu on a
3-h basis depends a great deal on the variability of the coal sulfur content
at the particular plant, the distribution of the emission values, and whether
the enforcement policy permits 29 exceedances per year (99% compliance), one
exceedance per year or one exceedance in 10 years. A sensitivity analysis
was conducted to quantify the extent of this variation and it pointed out that
the annual S02 emission levels required.to meet the 1.2 lb/106 Btu standard
on a 3-h basis could vary from 0.52 lb/106 Btu (assuming lognormal distribu-
. .
tion of data, a 24-h RSD of 20%, 24-h autocorrelation of 0.5, and one permitted
exceedance in 10 years) to 0.95 lb/106 &tu (assuming normal distribution of
dat~, 24-h RSD of 10%, 24-h autocorrelation of 0.8, and 29 exceedances are
permitted per year).
The sensitivity analysis also pointed out that the annual S02 emission
levels required to meet the 1.2 lb/106 Btu standard on a 24-h basis could
vary from 0.67 lb/106 Btu (assuming that the data are lognormally distributed,
24-h RSD equal 20%, 24-h autocorrelation equals 0.5, and one permitted
exceedance in 10 years) to 0.97 lb/106 Btu (assuming that the data are
normally distributed, 24-h RSD equals 10%, 24-h autocorrelation equals 0.8
and 29 exceedances are permitted per year).
4
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SECTION 2
INTRODUCTION
2.1 BACKGROUND
On December 23,1971, EPA promulgated NSPS for large fossi1-fue1-fired
steam-generating units (36 FR 24876; 40 CFR Part 60, Subpart D). The standards
limit emissions of S02' particulate matter, and nitrogen oxides. The 502
emission standard for coal is 520 ng/J (1.2 1b per million Btu) heat input;
for fuel oil it is 340 ng/J (0.8 1b S02' per million Btu) heat input. The
S02 standard can be met by the use of low sulfur fuels, FGD, or a combination
of the two. Subpart D also required the installation and operation of con-
tinuous S02 emission monitors for FGD equipped units. Continuous S02 monitors
were not required for facilities using compliance fuel provided fuel sampling
and analysis were conducted. The fuel sampling and analysis provisions,
however, were reserved in the October 6; 1975 promulgation and were not pro- .
posed until October 21, 1983.
When EPA proposed emission standards for large fossi1-fue1-fired steam
generating units in 1971, EPA indicated that plants could comply with the 520
ng/J (1.2 1b S02 per million Btu) emission limit for coal-fired units by using
either an FGD system or low-sulfur coal. During the development of the stan-
dard, EPA reviewed u.S. coal reserve data to determine the potential impacts
of the standard on compliance-coal reserves. As indicated in the background
document for the 1971 standard, a high-grade coal with a sulfur content of
0.7 percent or less was judged capable of complying with the standard.
Many facilities subject to Subpart D have elected to use compliance fuel.
A survey conducted by EPA in 1978 indicated that approximately 200 coal-fired
electric utility boilers subject to Subpart D would begin operation by 1983.
Approximately one-half of these planned to use compliance coal; the other
half planned to use FGD systems.
In their proposal on October 21, 1983, to complete the S02 emission monitor-
ing and fuel sampling and analysis provisions, EPA addressed the appropriate
5
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averaging time for enforcing the S02 emission standard. The issue of averaging
time for the S02 standard relates to both the variability of sulfur content of
the coal and FGO performance. With regard to compliance coals, the variability
of sulfur has been addressed in various EPA studies since 1975. From these
studies, it is clear that coal is not homogeneous and that the sulfur content
of coal used in a steam generator can vary even when the coal is supplied from
the same mine. In addition to geological properties, other factors that affect
coal sulfur content variability include mining practices, coal preparation
. .
procedures, onsite coal handling procedures (including the onsite mixing of
coal from various suppliers), and the chemical characteristics of the coal.
These factors can interact and result in complex sulfur variability patterns
that are difficult for boiler operators to predict or manage on a short-term
basis.
The purpose of this study was to identify units subject to Subpart 0 that
use compliance coal and to determine the typical S02 emission levels from the
compliance coal-fired electric utility steam generating units subject to
Subpart O. The first step in this study was to develop a list of coal-fired
electric utility steam generating units sUbject to Subpart O. The initial
list included all coal-fired utility units subject to Subpart 0 (compliance
coal and FGO). This list was then refined to identify those units using
compliance coal prior to estimating the typical S02 emission levels from the
compliance coal units.
2.2 METHODOLOGY
An initial review of available Subpart 0 data indicated that 502 emission
data from continuous emission monitoring (GEM) devices were not readily availa-
ble for a majority of units (i.e., GEM's were not installed on many compliance
coal-fired units). The initial review also indicated that no general list of
Subpart 0 units existed. Because GEM data and a list of Subpart 0 units were
generally unavailable, other available emission data bases were investigated
that would permit a timely identification of Subpart 0 units and an estima-
tion of the typical 502 emission levels. A review of the available data bases
indicated that DOE maintains an up-to-date inventory of power plants in the
United States and publishes a summary of the monthly fuel data for all plants.
Thus, the DOE data base was selected for use in this study.
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Based on the DOE power plant inventory data, a list of coal-fired power
plants with a startup date after 1975 was developed. This assumes a 4-year
period between initial commencement of construction (1971) and startup. The
list of compliance-coal-fired (Subpart D) units was further refined by remov-
ing those that were identified as being equipped with FGD systems. The re~
vised list of Subpart D units was verified by comparing it against data sub-
mitted by the EPA Regional Offices and EPA's Flue Gas Desulfurization Informa-
tion System (FGDIS).
After the list of Subpart D un.its was verified, the S02 emission levels
from each unit were determined. Because DOE only maintains lias received"
monthly fuel data on a total plant basis, a subset of Subpart D units was
developed in which all units at a plant site were subject to Subpart D; thus,
the plant average lias received" data would be representative of Subpart D
emissions. This further refinement was necessary because at power plant sites
where some units are subject to Subpart D and others are subject to SIP regu-
lations, the plant average lias received" fuel data would overestimate the
Subpart D emissions. The following example illustrates this point. If a
power plant has two units (one a Subpart D unit and one an SIP unit) and the
plant average sulfur content is 1 percent, use of the 1 percent sulfur content
. to calculate the emissions from the Subpart D unit would indicate that the
S02 emissions would be in excess of the allowable Subpart D 502 standard.
Actually, however, the Subpart D unit could have an average sulfur content
of 0.5 percent and the SIP unit an average sulfur content of 1.5 percent.
Thus, the emission levels of both units would be consistent with those allowed
under Subpart D and the SIP, even though the average plant emissions would be
in excess of 1.2 lb S02/106 Btu.
After the subset list of Subpart D was prepared, 18 months of monthly
lias received" fuel data were tabulated for each of the power plants. These
data were used to calculate both the monthly and long-term (18-month) S02
emission levels for each of the power plants in the subset of Subpart D units.
The 3-hour, 24-hour, 7-day rolling, and 30-day rolling average 502 emis-
sion levels were projected by use of the statistical approach outlined in the
October 21, 1983 proposal and the following statistical assumptions: 1) the
unknown 1-h emission levels at each plant (unit) can be represented .by an AR(l)
7
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process with an arithmetic mean ~, relative deviation RSDl' and an autocor-
relation p; 2) the arithmetic means of the associated 3-h, 24-h, 7-day (168-h),
and 3D-day (72D-h) average values are also equal to ~; 3) the distribution
of the 3-h, 24-h, 7-day rolling, and 3D-day rolling average values are normal;
4) the RSD of the 3D-day rolling average values 1.s equal to that of the monthly
average values for the same period; 5) the RSD of a rolling average of length
n can be estimated from the RSD of the I-h time series; and 6) the autocor-
relation of the rolling average time series can be estimated from the autocor-
relation of the l-~ time series. The use of a full range of statistical as-
sumptions resulted in a range of projected 3-h, 24-h, 7-day rolling, and
3D-day rolling average SD2 emission levels. The actual 3-h, 24-h, 7-day, and
3D-day rolling average SD2 emission levels occurring at a particular Subpart
. D unit will depend on the actual SD2 emission variability at the unit in
question.
8
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SECTION 3
SURVEY OF COAL-FIRED SUBPART D UNITS
As noted in Section 2, the first task in this study was to identify
coal-fired electricity utility steam generators subject to Subpart D. This
included units with and without FGD systems (i.e., those burning compliance
coa 1) .
3.1 IDENTIFICATION OF POTENTIAL SUBPART D UNITS
The basic references used to identify those steam generators that are
subject to Subpart D were a DOE Inventory of Power Plants in the United
States - 1981 Annual1 and the first condensed version of the Inventory of
Power Plants in the United States - 1982 Annual.2 /
The 1981 and 1982 Annual Inventories of Power Plants in the United States
are prepared by the Electric Power Division; Office of Coal, Nuclear, Electric
and Alternate Fuel s; Energy Information Admini strati on; DOE. These reports
represent a compilation of data obtained from the following forms:
o
Form EIA-759, Monthly Power Plant Report
FPC Form 12, Ann~al Power Systems Statement
o
o
EP Form 411, Regional Reliability Council Coordinated Bulk
Power Supply Program
Form EIA-119A, Annual Projection of System Changes
o
o
Form EIA-767, Steam Electric Plant Air and Water Quality Control
Data.
The data from these forms were used to prepare a summary of the electric
generating units by State, company, plant, and county, which was reviewed to
identify potential Subpart D units. Figure 1 is an example of the informa-
tion contained in the Annual inventories.
Although the Inventory of Power Plants in the United States contains a
great deal of information, it does not contain any information that would
9
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Electric Generating Units (continued)
Table 7. ElectrIc GeneratIng UnIts by State, Company. Plant. and County
(ContInued'
St8t8
~y Pftmary Alternate In
um. Nameplate Unit !nervy !nervy Seovlce Jointly
County NumIIer Aattnv MW Type Source Source 08te 0wnacI
AU8AMA ~nt.
SO CO:ALABAMA POWER CO -COm.
JORDAN
ELMORE...................._................................... 1 2S.0 HY WATER NONE 1928 NO
2 25.0 HY WATER NONE 1928 NO
3 2S.0 HY WATER NONE 1928 NO
4 25.0 HY WATER NONE 1928 NO
LAYOAM .
CHILTON [[[ 1 30.0 HY WATER NONE 1968 NO
2 30.0 HY WATER NONE. 1968 NO
3 30.0 HY WATER NONE 1967 NO
4 30.0 HY WATER NONE 1967 NO
5 30.0 . HY WATER NONE 1967 NO
8 30.0 HY WATER NONE 1967 NO
LEWIS SMITH OAM
WALKEFI[[[ 1 79.0 HY WATER NONE 1961 NO
2 79.0 HY WATER NONE 1962 NO
LOGAN MARTIN OAM
T ALLAOEGA [[[ 1 43.0 HY WATER NONE 1984 NO
2 43.0 HY WATER NONE 1984 NO
3 43.0 HY WATER NONE 1984 NO
MARTIN OAM
ELMORE[[[ 1 33.0 HY WATER NONE 192!1 NO
. 2 33.0 HY WATER NONE 1928. NO
3 33.0 HY WATER NONE 1928 NO
4 55.0 HY WATER NONE 1952 NO
MILLER
JEFFERSON [[[ 705.5 ST BIT NONE 1978 NO
MITCHELL DAM
COOSA [[[ 1 18.0 HY WATER NONE 1923 NO
2 18.0 HY WATER NONE 1923 NO
3 18.0 HY WATER NONE 1923 NO
4 20.0 HY WATER NONE 1949 NO
THURLOW OAM .
ELMORE[[[ 1 2S.0 HY WATER NONE 1930 NO
2 25.0 HY WATER NONE 1930 NO
WEISS OAM
CHEROKEE............................................_..... 1 29.0 HY WATER NONE .1962 NO
2 29.0 HY WATER NONE 1961 NO
3 29.0 HY WATER NONE 1961 NO
YATES DAM
ELMORE[[[_.. 1 18.0 HY WATER NONE 1928 NO
2 18.0 HY WATER NONE 1928 NO
SOUTHEASTERN POWER ADM
JONES BLUFF
AUT AUGA [[[ 1 17.0 HY WATER NONE 1975 NO
2. 17.0 HY WATER NONE 1975 NO
3 17.0 HY WATER NONE 1975 NO
4 17.0 HY WATER NONE 1975 NO
TENNESSEE VALLEY AUTHORITY
BROWNS FERRY
UMESTONE........................................-........ 1 1152.0 NB URAN NONE 1974 NO
2 1152.0 NB URAN NONE 1975 NO
3 1152.0 NB URAN NONE 1977 NO
COLBERT
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directly indicate whether a particular unit at a given plant would be subject
to the Subpart D ~NSPS) requirements. For this reason, an indirect method
was used to identify those units that could be subject to Subpart D. The
Subpart D requirements published in 1971 indicated that a unit greater .than
250 x 106 Btu/h heat input capacity [:::23 megawatt electric output capacity
(MWe)] would be subject to the requirements unless it had commenced construc-
tion prior to the publication of the Subpart D requirements. Therefore, all
units larger than 250 x 106 Btu/h that commenced construction after 1971 would
be subject to the Subpart D requirements. Because it can take 4 years or more
for a unit to be constructed and placed in service, it was assumed that all
units greater than 23 MW with an in-service data of 1975 or later would be
e .
subject to Subpart D. It should be noted,however, that it may now take from
5 to8 years for some units to be constructed and placed in service.
. Next, the list was compared with available EPA enforcement survey infor..,
mation to ensure consistency. Differences were resolved through contacts with
the EPA Regional Offices. This procedure identified units with an in-service
date as late as 1979 that were not subject to the Subpart D requirements;
however, this was the exception, not the rule.
3.2 VERIFICATION OF SUBPART D UNITS
Appendices A and B present listings of coal-fired power plants, based on
the 1981 and 1982 Inventory of Power Pl ants, where units have an in-servi-ce
date later than 1975 and a~ electrical output greater than 23 MWe (i.e.,
those that are potentially subject to the Subpart D requirements). Appendix
A lists coal-fired power plants where all units at the power plant site are
Subpart D units. Appendix B lists coal-fired power plants where both Subpart
D and SIP units are located at the power plant site. These listings of
potential coal-fired Subpart D utility units were compared with information.
contained in EPA's Compliance Data System (CDS), which is designed to include
information on the major stationary sources in the United States, to confirm
whether a given unit was subject to Subpart D. The data in CDS are. provided
by the 10 EPA Regional Offices and the State and local air pollution control
agencies. The EPA Regional Offices were contacted via telephone to confirm
any units not contained in CDS. The units verified to be subject to Subpart
11
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D based on information contained in CDS are noted with the footnote "d;"
those units verified to be subject to Subpart D based on information available
from the EPA Regional Offices are noted with the footnotes "f" (Appendix A)
and "e" (Appendix B). Appendices A and B contain information on the 140
coal-fired Subpart D utility units that were identified. The 140 units' were
located at 99 power plants. Figure 2 is an example of the Appendix A listing.
Figure 3 is an example of the Appendix B listing.
12
-------
APPENDIX A
LISTING Of COAL-fIRED POWER PLANTS WITH ALL SU8PART 0 (NSPS) UNITS (COMPLIANCE COAL AND fGD)a,b
......
W
In Plant c
Unit Capact ty, servl~e location fGD used
Company name Plant County State number HWe date E W Yes No
Alabama Power Hiller Jefferson AL 1 70S.5d 1~78 )( )(
Arizona Electric Apache Sta- CocM se AZ 2 194.7d 1979 )( )(
Power Coop., Inc. tion 3 204.0d 1979
)( )(
Salt River ProJ. Agri. Coronado Apache AZ 1 410.9d 1979 )( )(
Imp. Power Dlst. 2 410.9d 1980 )( )(
Arkansas Power and White 81uff Jefferson AR 1 800.0d 1980 )( )(
light Co. 2 800.0d 1981 )( )(
Southwestern Elec. f 11 nt Creek Benton AR 1 512.3d 1978 )( )(
Power Co.
~olorado Springs, Ray D. El Paso CO 1 207.0d 1980 )( x
City of Nixon
Colorado - UTE Elec. Craig Hoffat CO 1 447.0d 1980 x x
Assn.. Inc. 2 447.0d 1979 x )(
Public Service S07.0d
Co. of Colorado Pawnee Horgan CO 1 1981 x x
Lakeland, City of Hclntosh,
Dept. of Electric C.D. 364.0d
and Water Polk fl 3 1982 e
x x
Georgia Power Co. Scherer Heard GA 1 891. Od 1982 x x
Wansley Heard GA 1 952.0 1976 x )(
2 952.0 1978 x x
aLlstlng only Includes Subpart 0 units located at power plants with all Subpart 0 units with In-service date of
1975-1982 and a capacity ~ 23 HWe. Plant sites with both Subpart 0 and SIP units are not Included.
b
Reference: InventorY of power plants In the United States 1981 and 1982 Annual - DOE and Cost and Quality of
Fuels for Electric Utility Plants - DOE.
cEastern locations Includes units located In all States east of the Hlsslsslppl River and one State west of the
Hlsslsslppl River. E = Eastern and W = Western.
dSubject to Subpart 0 as listed In EPA's:Compllance Data System (CDS).
eper flue Gas Desulfurlzatfon Information System (FGDIS).
fSubject to Subpart 0 per telephone conversation with EPA Regional Office.
Figure 2.
Example of Appendix A listing.
-------
.....
~
In Phnt
Unit Capac i ty, service locationc FGD used
Company name Plant County State number MWe date E W Yes No
Alabama Electric Corp., Inc. Tombigbee Washington AL 1 75 1969 x x
2 235d 1978 x x
3 235d 1980 x x
Arizona Public Service Cho 11 a Navajo AZ 1 113.6 1962 x x
Company 2 288.9d 1978 x x
3 288.9d 1980 x x
4 414.0 1981 x x
Salt River PROJ AGRI IMP PMR Navajo Coconino AZ 1 803.0 1974 x x
DIST 2 803.0 1975 x x
3 803.0 1976 x x
Colorado-UTE Electric Assn., Hayden Routt CO 1 190.0d 1965 x x
Inc. 2 275.4 1976 x x
Public Service Company of Comanche Pueblo CO 1 382.5d 1973 '! x
Colorado 2 396.0 1976 x x
Delmarva Power and Light Indian Sussex DE 1 81.6 1957 x x
Company of Delaware River 2 81.6 1959 x x
3 . 176.8d 1970 x x
, 4 403.0 1980 x x
Florida Power Corp. Crysta 1 Citrus FL 1 440.5 1966 x x
River 2 523.8d 1969 x x
4 793.3 1982 x x
Gainsville-Alachua Company Deerhaven Alachua FL 1 83.0d 1972 x x
2 243.0 1981 x x
APPENDIX B
LISTING OF COAL-FIRED POWER PLANTS WITH BOTH SIP AND SUBPART 0 (NSPS) UNITSa,b
aListing includes plants with both Subpart 0 (units with in-service date of 1975 to 1982 and a capacity >23 MWe) and
SIP units. Units marked with footnote "d" or "e" are sUbject to Subpart 0 and units that are unmarked are subject to
SIP requirements. .
bReferences: "Inventory of Power Plants 1n the United States 1981 and 1982 Annual" and "Cast and 'Qualit'y of fuels for
Electric Utility Plants."
. cEastern locations include units located in all states east of and one state west of the ~iss1ssippi River.
dSubject to Subpart D as listed in EPA's comp11ance data system (CDS).
eSubject to Subpart 0 per telephone conversation with EPA Regional Office.
Fi gure 3.
Example of Appendix B listing.
-------
SECTION 4
MONTHLY SULFUR DIOXIDE EMISSIONS
As noted in Section 2, the second task was to determine monthly average
S02 emissions. Calculation of S02 emissions from a coal-fired Subpart 0 unit
require information on the quantity and quality of the coal being burned in
each unit. The Office of Coal, Nuclear, Electric, and Alternate Fuels (DOE)
is responsible for collecting, reviewing, and summarizing the information on
the cost and quality of fuels for electric utility plants. . This information
is presented in the Federal Power Commission (FPC) Form 423, which is a monthly
record of each fuel purchase delivered to electric power generation plants with
a combined fossil-fuel capacity of 25 megawatts or larger. The FPC Form 423
is submitted by approximately 281 electric utilities. Data from FPC Form 423
are reviewed, verified, and summarized in the Cost and Quality of Electric
Utility Plants Fuels -Monthly3 (published through the end of 1982) and the
Electric Power Quarterly4, which succeeded the no-longer-published Cost and
Quality of the Electric Utility Plants Fuels - Monthly.. Data in both of
these publications are presented on a plant-by-plant basis. The data of
interest for the purpose of calculating S02 emissions are:
o
Plant type
Fuel type
o
o.
Quantity (heat content):
average Btu content
o
Quantity (sulfur content):
sulfur content (percentage by weight)
o
Quantity (cost):
cents per million Btu.
Figure 4 is an example of Table 33 from the Cost and Quality of Fuels
for Electric Utility Plants- Monthly, which summarizes information used to
calculate the S02 emissions from the Subpart 0 units.
Because this table only contains monthly information on a plantwide basis
(DOE does not report unit-by-unit data), the information should not "be used for
15
-------
TABLE 33. OuantIty, Coat, and Quality 01 FouU Fuel ReceipU by Company and Plant. April 1982
011 I
CollI
aa
I '" of TOt8I BIll
.'
ComPMIJ ' I '" . -I '-I A~ '.-I'-Ieu 011 I aa
I a-.uty /' - o-.tIIy 0uMtny
-I-I I:::: '- A~ 1000 1000
Ton SuI- - 10' Bill II1II SuI- lief 10' BIll McI
fur fur I
-Elec ~Inc - 57.3 118.1 46.22 U. 0.5 ...u 4.58 100
TomcigI>ee (AU '''-'-''''-''-- 58.9 198.0 ~ 1.~ .. 100
Mc-I~. .3 2DU - 1.88 .5 405.2 4.58 94 8
- """- Co (SC) - tn.1 198.9 47.34 1.1. U -.. 38.79 11.27 1CM.1 303.8 3A8 .. 1
BarTy (~ '''-''''-''--- .2 858.1 37.91 Z3 102.2 302.2 3.45 99
~(AU.. 8.7 211.1 52.97 1.02 .2 863.1 38.33 .25 1.9 398.8 4.12 98 1
Gorva 2 and 3 (~...--..- 488.1 189.8 48.33 .92 4.0 671.8 39.01 .28 - 100
Gt- (ALI.-.....--..-....... 38.5 238.1 58.22 1..57 1.5 883.3 38.58 .24 99
GuIon (All .....---..---- 378.1 1118.1 44.50 1.S2 .8 670.5 38.87 .34 100
..... Miller (AL) ...-.---..- 84.8 242.3 60.10 .60 1.7 1!68. 7 38.52 Z3 100
.---. CIty of 388.8 3110.8 4.08 - 100
--- (LA).._..........._. 3118.6 390.6 4.08 .. 100
.-..-. CIty of ILO 188.5 32.01 ..58 2.1 85L5 37.80 .1M 3N.O 3.J4 98 4
- (1A1..-..--..-.-.... 18.0 188.5 32.01 .58 2.1 /lS5.5 37.80 .04 394.0 3.94 98 4
~_(AEP)- _7 2CM.7 4..,0 .73 - 100
CIJncI1 RiYw (VA) '-''''''''''''--'' 104.3 184.6 44.16 .72 .. 100
Glen Lyn (VAl --.......-.-.... 33.1 185.9 44.57 .86 .. 100
Amos (WVJ .-.......--.-...-.... 50!1.9 221.5 52.95 .79 .. 100
K--. - (WVJ ...---.-. 82.6 186.7 38.89 .75 - 100
~ (WVJ "-'-"-- 243.8 193.0 47.32 .80 - 100
-Elec_~lnc- 88.4 280.8 - .... 231.3 384.. 172 88 12
AII8Ch8 (Al) --..........-.--... 118.4 280.6 _ .~ 231.3 350... 3.72 86 12
- - S8nr 744.7 88.5 18.40 .88 24.4 527.. - ..51 579JI 378.5 4.03 II '1
ChoiIa (Al) """"-"'---- 309.0 120.7 24.08 .47 2.3 305.0 2.62 100
0c0tiII0 (Al) ..-.....--..--... 384.1 377.0 4.05 - '00
F'hoconix (AZ) '----"-"'- 24.4 527.9 33.04 .51 5.9 382.0 4.04 98 4
Saguato (AZ) .......-.....-...--.....-.. 93.8 382.0 4.00 - 100
Yucca (Al) ""'"'-'''-''''''''''''-''''''' 9.2 379.0 4.00 .. 100
Four c...." (NM) ....-.........-.... 435.7 82.5 10.97 .83 113.7 . 372.0 4.02 98 2
- EIec COOl' 77.7 318.2 3.30 .. 100
Fitznugn (AR) ........--.--....-. .1 318.2 3.22 .. 100
Bliley (AR) ""'"'-'''''''''''''''''''-''''''' .3 318.2 3.22 - 100
- (AR) -..,...........--....--. 77.3 318.2 3.30 .. 100
---U(MSU)- 358.8 188.7 32.11 .44 La 888.0 3L43 .34 1,1184.8 283.4 2.92 77 22
Lyncn (AR) .........---.-..--.. 638.0 38.11 .30 114.7 322.0 3.27 100
- (AR) ....-.-.-----...... 674.0 38.04 .30 186.2 319.0 3.24 100
Couch (AR) .-...--.--- 426.3 178.2 1.90 - 100
LaKe ea1ll8rine (AR) .-...-..- 122.9 319.0 3.24 - 100
M- (GT) (AR) .--.......- .1 322.0 3.25 .. 100
RitcI1ie (AR) '..-.......-......'''-'''''-'' 812.5 322.0 3.29 - 100
WhileIIIufI (AR) ............-.....---.. 358.8 1118.7 32.11 .44 8.8 658.0 38.43 .34 99
_Elec~_- 3112..5 188.2 23.29 133 - 100
Madrid (MO) ....................-....-...... 308.6 183.2 34.95 3.17 .. - 100
Hill (MO) ................-...-.--......... 75.9 127.0 28.58 3.99 .. 100
AII8ntIC CIty EIec 87.3 .178.7 45.13 2.79 151.3 QO.8 2U1 1.83 85 35
England (NJ) ....................-.........-. 87.3 176.7 45.13 2.79 147.9 423.0 28.47 1.67 65 35
CaroU Comr (GT) (NJ) ....-.............. 1.4 805.3 45.98 .01 - 100
Cedar 518 (GT) (NJ) ""'-""""-""-' 1.8 809.4 ~.19 .01 - 100
MiUQm Avenue (NJ) .....----....-. .2 808.3 46.13 .01 .. 100
- EIec ~ CIty 01- 1233.4 _.8 4.10 .. 100
Dect
-------
calculating the S02 emissions unless one is assured that all units are subject
only to Subpart O. If there are both SIP and Subpart 0 units at a plant, the
plantwide average information would reflect the sulfur content needed to meet
the SIP limits as well as the Subpart 0 limits for the applicable units. In
most cases, depending on the State, the' pl antwi de average sul fur content for
plants with a mixture of Subpart 0 and SIP units would not be representative
of the plantwide sulfur content required for plants with all Subpart 0 units.
The plantwide average sulfur content where all units at a plant are subject
to Subpart 0 but some units are using compliance (low-sulfur) coal and others
are using an FGO ~o meet the S02 emission limits set forth in Subpart 0 would
also not be representative of the plantwide sulfur.content for plants with all
Subpart 0 units. Because the plantwide average information available from DOE
cannot be further refined to provide information on a unit-by-unit basis,
the calculation of S02 emissions was limited to those plants where all units
were subject to Subpart 0 and none of the units were equipped with an FGO.
Limiting the analysis to only these plants made it possible to obtain a
reasonable representation of the monthly (30-day) S02 emissions from Subpart 0
units.
Based on the information available from the previously noted DOE publi-
cations, the following equation was used to calculate the monthly (30-day)
average S02 emissions for an 18-month period from January 1982 until July
1983:
E = (1O~B)(38S)
(Eq. 4-1)
where
E = potential S02 emissions (lb S02/106 Btu)
A = fuel cost per heat content (t/l06 Btu)
B = .fuel cost by weight ($/ton coal)
S = fuel sulfur content (weight percent)
Basis for equation:
A 1 - A
(100) (S) - 100B
(Eq. 4-2)
17
-------
6
(tl10 Btu)(tons coal) - tons coal
100t/$ ~ - 106 Btu
(1~0)(2000)(2)(0.95) = 38S
1 b 2000 1 b coa 1 2 1 b S02 1 b S02
(100 lb coal)( tons coal )(. lb )(0.95 S to S02)* ~ tons coal
(Eq. 4-3)
*
Assumes 95 percent of sulfu~ is converted to S02. The balance of the sulfur
is emitted in the fly ash or combines with the slag or ash in the furnace.
This is consistent with October 21, 1983, proposal calculations.
The mean S02 emission level (18-month average) was calculated for each
unit. Figure 5 is an example of the individual monthly S02 emissions for a
selected plant. Appendix C lists the 18 monthly S02 emission levels for each
of the 49 compliance coal-fired units included in this study.
Company name: Alabama Power
Plant name: Miller
Number of units:
1
State: AL
MONTHLY AVERAGE EMISSION RATE:
[lb S02/106 Btu]a,b
Jan. 82: 0.951 ." Jul. 82: 0.947 Jan. 83: 0.894
Feb. 82: 1.005 Aug. 82: 0.937 Feb. 83: 0.867
Mar. 82: 0.980 Sept. 82: 0.914 Mar. 83: 0.867
Apr. 82: 0.919 Oct. 82: 0.895 Apr. 83: 0.928
May 82: 0.904 Nov. 82: 0.892 May 83: 0.933
Jun. 82: 1. 001 Dec. 82: 0.921 Jun. 83: 0.880
aAssumes 95 percent sulfur to S02 conversion rate.
bMean = 0.924, maximum value = 1.005, and minimum value = 0.867.
Figure 5.
Example of individual monthly S02 emissions from January 1982
through June 1983.
18
-------
In order'to determine if there was any significant difference between
the S02 emissions fr~m plants in the East versus those in the West, the list
of plants with only Subpart D units was further subdivided into those plants
located in the East and those located in the West. The eastern plants were
designated as th6~e in States that border the Mississippi River on the west
plus all States lo~ated east of the Mississippi River. Those designated as
western plants are in the States making up the balance of the continiguous
United States. A map showing the dividing line for eastern and western plants
for the purpose of this study is presented in Appendix D. In general, the
plants with the lowest S02 emission levels were located in the West and those
with the highest S02 emission levels were located in the East.
Table 3 summarizes the number of units included in this analysis by loca-
tion (East versus West). Table 4 also summarizes, by location, the typical
S02 emissions at the Subpart D compliance-coal-fired units included in this
analysis. In general, long-term average emissions from eastern units averaged
approximately 0.90 lb S02/106 Btu and emissions from western units averaged
approximately 0.80 lb S02/106 Btu. Tables 5 and 6 present the minimum month,
maximum month, and average (18-month) S02 emission rates for eastern ~nd
western units, respectively. Table 7 summarizes the long-term average S02
emission rate for eastern and western Subpart D utility units (compliance coal).
TABLE 3.
TOTAL SUBPART D COAL-FIRED UNIT'INVENTORya
" Number of uni ts by location
Technology East West Total
Compliance coal 40b 38c 78
FGD system 33 29 62
To ta 1 73 67 140d
aConfirmed via CDS or EPA Regional Office.
bSixteen of the 40 units are at plant sites where all units are compliance-
coal-fired Subpart D units.
cThirty-three of the 38 units are at plant sites where all units are com-
pliance-coal-fired Subpart D units.
dThe 140 coal-fired Subpart D units are located at 99 power plants.
19
-------
TABLE 4. MONTHLY S02 EMISSIONS AT SUBPART D (COMPLIANCE COAL) UNITSa,b
Emissions, lb S02/106 BtuC
Combined average Range of
Unit Number of of all 18 monthly Range of 18-month maximum monthly
location un i ts values average values values
East 16 0.88 0.68 to 0.98 O. 72 to 1. 32
West 33 0.81 O. 60 to 1. 04 O. 65 to 1. 19
Total 49 0.84 O. 60 to 1. 04 0.65 to 1.32
aNon-FGD. Based on published DOE lias receivedll fuel data.
bOnly includes S02 emissions data from power plants where all units at the
plant are sUbject to Subpart D and all units are using complying coal. Does
not include any Subpart D units at any power plants where any units at the
plant site are subject to SIP regulations. Therefore, the analysis focused
on only 49 units out of the 78 compliance-coal-units originally identified.
cAssumes 95 percent sulfur-to-S02 conversion.
20
-------
TABLE 5. MONTHLY S02 EMISSIONS FOR EASTERN COMPLIANCE COAL-FIRED
UNITS SUBJECT TO SUBPART Da
N
......
Monthl \ b' 6 .
No. emissions, lb S02/10 Btu
of Type No. i nc Average
Company name Plant units Sta te coal sample Minimum Maximum Averaqe sulfur, %
Alabama Power Company Mi 11 er 1 AL BIT 18 0.867 1.005 0.924 0.61
Arkansas Power & White Bl uff 2 AR BIT 18 0.759 1.070 0.962 0.44
Light Co.
Southwestern Electric Fl i nt Creek 1 AR BIT 18 0.621 0.841 0.777 0.35
Power Co.
Georgia Power Co. Scherer 1 GA BIT 18 0.864 1.052 0.951 0.66
Iowa Southern Ottumwa 1 IA SUB 18 0.660 0.719 0.681 0.30
Util ities Co.
Cajun Electric Power Big Cajun 2 2 LA SUB 14 0.801 1.036 0.968 0.41
Coop., Inc.
Mississippi Power Co. Daniel, 2 MS BIT 18 0.874 0.968 0.919 0.57
Vi c to r J.
Kansas City Power and I a ta n 1 MO BIT 17 0.581 0.794 0.727 0.34
Li ght Company
Dayton Power and Ki 11 en 1 OH BIT 18 0.852 0.930 0.887 0.59
Light Company, The Station
Appalachian Power Co. Mountaineer 1 WV BIT 18 0.884 0.969 0.925 0.60
(1301)
Wisconsin Electric Pleasant 1 ' WI SUB 18 0.716 0.890 0.830 0.33
Power Company Prairie
Central Louisiana Rodemacher 1 LA SUB 18 0.736 1.069 0.962 0.44
Electric Co., Inc.
(continued)
-------
TABLE 5 (continued)
No. Monthh emissions,b lb S02/106 Btu
of Type No. i n Average
Company name Pl ant units State coal samplec Minimum Maximum AveraQe sulfur, %
Gulf States Utilities Nelson, R.S. 1 LA SUB 18 0.858 1. 315 ,0.981 0.45
Company
aIn-service date of 1975 or later and a capacity> 23 MW and confirmed via CDS or EPA Regional Office.
- e
bPlant average S02 emissions were cal:culated because only plant average fuel data are available. The
emission calculations assumes a 95 percent sulfur to S02 conversion as provided in October 21, 1983 proposal.
cNumber of monthly values included in the average percent sulfur and average emission calculation.
N
N
-------
TABLE 6. MONTHLY S02 EMISSIONS FOR WESTERN COMPLIANCE COAL-FIRED
UNITS SUBJECT TO SUBPART Da
N
W
.
No. Month 1 \ emissions,b lb S02/106 Btu
of Type No.' i nc Average
Company name Plant units S ta te coal sample Minimum Maximum Averaqe sulfur, %
Colorado Springs, Ray D. Nixon 1 CO BIT 18 0.629 0.750 0.684 0.38
City of
Kansas City Board of Nearman 1 KS OIT 17 0.695 0.940 0.821 0.36
Public Utilities Creek
Hastings Utilities Hastings 1 NE BIT 15 0.857 1.188 0.981 0.41
Energy Ctr.
Nebraska Publ ic Gentleman 2 NE BIT 18 0.668 0.796 0.750 0.35
Power District
Omaha Public Power Nebraska 1 NE BIT 18 0.628 0.952 0.806 0.35
District City
Sierra Pacific North Valmy 1 NV BIT '18 0.510 0.726 0.621 0.37
Power Company
Grand River Dam GRDA 1 1 OK BIT 15 0.628 0.958 0.841 0.36
Authori ty
Oklahoma Gas and Muskogee 2 OK BIT 18 0.685 0.802 0.743 0.35
Electric Company
Sooner 2 OK BIT 18 0.667 0.796 0.750 0.35
Public Service Co. Northeastern 2 OK BIT 18 0.846 1 . 041 0.959 0.42
of Oklahoma
Western Farmers Hugo 1 .OK SUB 18 0.876 1.129 1.043 0.45
El ec'tri c Coop.
Portland General Boa rdman 1 OK BIT 12 0.733 1. 076 0.856 0.36
El ectri c Co.
(continued)
-------
TABLE 6 (continued)
N
~
No. Monthl emissions,b lb S02/106 Btu
of Type No. in Average
Compa ny name Plant units State coal samplec Minimum Maximum Averaqe sulfur, %
Central Power and Coleto Creek 1 TX BIT 18 0.524 0.650 0.597 0.34
Li ght Company
Houston Lighting and Parish, W.A~ 4 TX BIT 18 0.710 0.985 0.868 0.39
Power
Lower Colorado River Sam K. 2 TX BIT 18 0.725 0.824 0.776 0.37
Authority Seymour,
Jr.
San Antonio Public Deely, J. 1. 1 TX BIT 15 0.677 0.890 0.748 0.33
Service Board
Southwestern Electric Welsh 3 TX BIT 17 0.745 0.802 0.780 0.34
Power Company
Southwestern Public Harrington 3 TX BIT 18 0.652 0.895 0.819 0.39
Service Company
Grand Island Water Platte 1 NE SUB 11 0.736 1. 134 0.956 0.41
and Li ght Dept.
Southwestern Public Tolk 1 TX BIT 10 0.648 0.863 .0.751 0.35
Service Company
Public Service Co. Pawnee 1 CO BIT 17 0.657 0.865 0.767 0.34
of Colorado
aIn~service date of 1975 or later and a capacity ~ 23 MWe and confirmed via CDS or EPA Regional Office.
bPlant average S02 emissions were calculated because only plant average fuel data are available. The emis-
sion' calculations assumes a 95 percent sulfur to S02 conversion as provided in October 21, 1983 proposal.
cNumber of monthly values included in the average percent sulfur and average emission calculation.
-------
TABLE 7.
LONG-TERM AVERAGE S02 EMISSION RATE FOR EASTERN AND WESTERN
SUBPART 0 UTILITY UNITS (COMPLIANCE COAL)
Long-term average S02 emission rate,
lbs S02/million Btua
Unit locationb
Eastern
Western
0.60
0.62
0.68
0.73
0.74
0.75
0.77
0.78
0.81
0.82
0.83
0.84
0.86
0.87
0.89
0.92
0.93
0.95
0.96
0.97
0.98
1.04
I-unit
I-unit
I-unit I-unit
I-unit
2-units
6-units
I-unit
I-unit 5-units
I-unit
4-units
I-unit
I-unit
I-unit
4-units
I-unit
3-units
I-unit
I-unit
3-units 3-units
2-units
I-unit I-unit
I-unit
aBased upon 18 months of DOE fuel quality data per unit (coal sampling and
data analysis data, not CEM data).
bEastern units include all-units located in States east of the Mississippi
River plus one State west of the Mississippi River.
25
-------
SECTION 5
ESTIMATED SULFUR DIOXIDE EMISSION
Estimates of the 3-h, 24-h, 7-day rolling, and 30-day rolling average
S02 emissions are based on a series of statistical procedures and assumptions
associated with previously developed relationships for the 3-h, 24-h, 7-day,
and 30-day S02 emission 1evels.5 .
. 5.1
ESTIMATION OF 3-H, 24-H, 7-DAY ROLLING, AND 30-DAY ROLLING AVERAGE S02
EMISSIONS
The S02 emissions generated by the direct combustion of compliance (low-
sulfur) coal vary naturally, in part because of fluctuations in sulfur 'content
and heating value of the coal resulting from the manner in which the coal was
formed. Normally, a unit operates at a predetermined average level of S02
emissions and the actual minute-by-minute or hour-by-hour operation varies
above and below the average level. Figure 6 shows a hypothetical S02 emission
. b .1 . t 5
varla 1 1 Y curve.
Two terms are used to describe the variability of S02 emissions: standard
deviation and autocorrelation. Standard deviation is loosely described as
the size of a typical difference between a set of observations and the average
of these observations, assuming a random system variability. The standard
deviation is often expressed as a percentage of the average value, or the RSD.
The RSD (i.e., standard deviation divided by the mean) is a relative measure
of system variability.
Autocorrelation is a measure of the association or dependence between
periodic observations or measurements taken one after another in time. An
autocorrelation near 1.0 indicates that successive observations are similar
in value. An autocorrelation near zero indicates there is little relation-
ship between successive observations or measurements.S
Ideally, when a series of 1-h average S02 emission
calculation of the 3-h, 24-h, 7-day, and 30-day average
levels are available,
S02 emission levels
26
-------
N
.......,
EMISSION LIMIT
\
- -
- --
- -
- -
--
--
ACTUAL ~
EMISSIONS
OBSERVATIONS
tc
TIME
Figure 6. Typical S02 emission variability.5
-------
for a given unit is relatively straightforward. With these data, one can
calculate the mean, standard deviation, RSD, and autocorrelation for the data
set. It is, however, more difficult to estimate the 3-h, 24-h, and 7-d~y .
emission levels given only the 3D-day or monthly SD2 emission levels and the
3D-day average RSD. Lacking information on the relationships that may exist
with respect to a given data set, one must use theory and a series of assump-
tions to describe the expected relationship.
The basic assumptions used in estimating 3-h, 24-h, and 7-day average
S02 emissions, given a 3D-day emission level, are as follows:
1.
The unknown I-h emission levels at each plant (unit) can be repre-
sented by an AR(l) process with an arithmetic mean ~, relative
deviation RSD1' and an autocorrelation p.
The arithmetic means of the associated 3-h, 24-h, 168-h (7-day),
and 72D-h (3D-day) average values are also equal to ~.
The distributions of the 3-h, 24-h, and 7-day average values are
normal.
2.
3.
4.
The RSD of the 3D-day rolling average values is equal to that of
the monthly average values for the same period.
The RSD of aro" ing average of length n can be estimated from the
RSD of the 1-h time series:
5.
RSDn = fn(p)~ RSDI.
6.
The autocorrelation of the rolling average time series can be esti-
mated from the autocorrelation of the I-h time series:
p = In)(1-p2) - Cl+p2)(1-ph)
n .(n2)(l-p)2 fn(p)
7.
The function fn(p) can be estimated as:
~
fn(p) = (n)(l-p)
8.
The 18 month average is equivalent to the long-term mean.
Based on the assumptions presented, the maximum estimated 3-h, 24-h,
7-day rolling, and 3D-day rolling average emission levels were calculated for
each of the eastern and western plants where all units at the plant were
28
-------
subject to Subpart D. The estimates are based on. one exceedance in 10 years,
one exceedance per year, four exceedances per year for the 24-h, 7-day rol-
ling, and 30-day rolling averages (99% compliance level), and 29 exceedances
per .year for the 3-h average (99% compliance level). Tables 8 and 9 summarize
the estimated or projected 3-h average emission levels assuming 24-h RSDls of
10, 15, and 20 percent, a 24-h autocorrelation of 0.7; 29 exceedances.per year
(99% compliance level); one exceedance per year; and one exceedance in 10 years
for the eastern and western units. Three projected S02 emission levels are
presented for each unit based on a range of statistical assumptions. The
projected 3-h a~erage 502 emissions ranged from 0.76 to 1.32 lb S02/106 Btu
for a 24-h RSD of 10 percent, a 24-h autocorrelation of 0.7, and 29 exceedances
per year; from 0.84 to 1.46 lb S02/106 Btu for a 24-h R5D of 15 percent, a
24-h autocorrelation of 0.7, and one exceedance per year; and from 1.17 to
2.03 lb S02/10.6 Btu for a 24-h RSD of 20 percent, a 24-h autocorrelation of
0.7 and one exceedance in 10 years.
Tables 10 and 11 summarize the estimated or projected 24-h average emis-
sion levels based on assumed 24-h RSDls of 10, 15, and 20 percent; a 24-h
autocorrelation of 0.7; four exceedances per year (99% compliance level); one
exceedance per year; and one exceedance in 10 years for the eastern and western
units. The 24-h average S02 emissions ranged from 0.74 to 1.28 lb S02/106
Btu for a 24-hRSD of 10 percent, a 24-h autocorrelation of 0.7, and four
6
exceedances per year; from 0.77 to 1.33 lb S02/10 Btu for a 24-h RSD of 10
percent, a 24-h autocorrelqtion of 0.7, and one exceedance per year; and from
1.01 to 1.76 lb S02/106 Btu for a 24-h RSD of 20 percent, a 24-h autocorrela-
tion of 0.7, and one exceedance in 10 years.
Tables 12 and 13 summarize the estimated or projected 7-day rolling
average emission levels based on assumed RSDls of 10, 15, and 20 percent, a
24-h autocorrelation of 0.7; and four exceedances per year; one exceedance
per year; and one exceedance in 10 years for the eastern and western units.
The 7-day rolling average for S02 emissions ranged from 0.67 to 1.16 lb S02/
106 Btu for a 24-h RSD of 10 percent, a 24-h autocorrelation of 0.7, and four
. 6
exceedances per year; from 0.68 to 1.19 lb S02/10 Btu for a 24-h RSD of 10
percent, a 24-h autocorrelation of 0.7, and one exceedance per year; and from
0.80 to 1.39 lb S02/106 Btu for a 24-h RSD of 20 percent, a 24-h autocorrela-
tion of 0.7, and one exceedance in 10 years.
29
-------
w
a
TABLE 8. MONTHLY AVERAGE AND PROJECTED 3-H AVERAGE S02 EMISSIONS FOR EASTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da .
SO? emissions. lb/l06 Btu
No. Avg. of Maximum projected 3-h S02 emissions, lb/l06 Btud
of 18 mon~h~y RSD = RSD = RSD =
Company name Plant units State values' 10 percent 15 percent 20 percent
Alabama Power Co. Mi 11 er 1 AL 0.92e 1 17f I.30f 1. 43 f
. 9 1. 47~ 1. 67~
1. 29h
1. 35 1. 59 1. 79
Arkansas Power & White Bluff 2 AR 0.96e 1 04f 1.16f 1 27f
Li ght Co. . 9 .1. 31~ . 9
1. 15h 1. 48h
1. 21 1.40 1. 60
Southwestern Elec- Flint Creek 1 AR 0.78e 0 99f 1. 10 f 1. 21 f
tric Power Co. . 9 1.25g. 1. 41~
1. 09h 1. 33h
1.15 1. 52
Georgia Power Co. Scherer 1 GA 0.95e 1 21f 1 34f 1. 47 f
. 9 . 9 1. 72~
1. 33h 1. 52h
1.40 1.62 1.85
Iowa Southern Ottumwa 1 IA 0.68e 0 86f 0.96f 1. 05 f
Utilities Co. . 9 1. 09~ 1. 23~
0.95h
1. 00 1.16 1. 33
Cajun Electric Big Cajun 2 2 LA 0.97e 1 23f 1 37f 1. 50 f
Power Coop. , . 9 . g 1. 76~
1. 36h 1. 55h
Inc. 1. 43 1. 66 1. 89
Mississippi Daniel, 1 17f 1.30f 1 43f
Power Co. Victor J. 2 MS 0.92e . 9 1. 47~ . 9
1. 29h 1. 67 h
1. 35 1. 57 1. 79
Kansas. City Power Iatan 1 MO 0.73e 0 93f 1. 03 f 1 13f
& Li ght Co. . 9 1. 17~ . 9
1. 02h 1. 32h
1. 07 1. 25 1. 42
(continued)
-------
TABLE 8 (continued)
w
......
I , .
S02 emissionst lb/106 Btu
No. Avg. of Maximum projected 3-h S02 emissionst lb/106 Btud
. of 18 mon~h!y RSD - RSD - RSI:J -
Company name Plant units State values t 10 percent 15 percent 20 percent
Dayton Power & Killen 1.13~ f 1 38f
0.8ge 1. 25g . 9
Li ght Co. t The Station 1 OH 1. 25h 1. 42h 1. 61h
1. 31 1. 52 1. 74
Appalachian Power Mountaineer 1 18f 1 31f 1 44f
0.93e . 9 . 9 . 9
Co. (1301) 1 WV 1. 30h 1. 49h 1. 68h
1. 37 1. 59 1.81
Wisconsin Electric Pleasant 1. 05~ f 1 29f
1.17 9
Power Co. Prairie 1 WI 0.83e . 9
1. 16h 1. 33h 1. 50h
1. 22 1.42 1. 62
Central Louisiana 1 22f f 1 49f
Electric CO't . 9 1. 35 9 . 9
0.96e 1. 34h 1. 54h 1. 74h
Inc. Rodemacher 1 LA 1.41 1. 64 1. 87
Gulf States Nelsont 1 24f f 1. 52 f
1. 38g
Utilities Co. R.S. 1 LA 0.98e . 9 1. 77~
1. 37 h 1. 57 h
1.44 1. 68 1. 91
. ,.
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
COata from January 1982 through June 1983.
dprojections are based on 24-h RSO.s of lOt 15t 20 percentt 24-h autocorrelation of 0.7 and 29
per yeart one exceedance per year and one exceedance in 10 years.
eSubject to Subpart 0 as listed in CDS or based on conversation with EPA Regional Office.
fAssumes 29 exceedances per year (99% compliance level).
gAssumes one exceedance per year.
hAssumes one exceedance in 10 years.
exceedances
-------
TABLE 9.
MONTHLY AVERAGE AND PROJECTED 3-H AVERAGE S02 EMISSIONS FOR WESTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
W
N
. . .
SO? emissions. lb/l06 Btu
No. Avg. of Maximum projected 3-h S02 emissions, lb/106 Btud
of 18 monhhly RSD = RSD = RSD -
Company name Plant units State values,' 10 percent 15 percent 20 percent
Colorado Springs, Ray D. 0 86f 0.96f 1 05f
City of Nixon 1 CO 0.68e . 9 1. 09~ . 9
0.95h 1. 23h
1. 00 1.16 1. 33
Kansas City Board 1 04f 1 16f 1 27f
of Public Nearman . 9 . 9 . 9
1. 15h 1. 31h 1. 48h
Utilities Creek 1 KS 0.82e 1. 21 1.40 1. 60
Hastings Utilities Hastings 1 24f 1 3Bf 1 52f
. 9 . 9 . 9
Energy 0.98e 1. 37 h 1:57h 1. 77 h
Center 1 NE 1.44 1. 68 1. 91
Nebraska Public 0.95f 1 06f 1.16f
Power District Gentleman 2 NE 0.75e 1. 05~ . 9 1. 36~
1. 20h
1.10 1. 28 1.46
Omaha Public Nebraska 1 03f 1 14f 1 26f
Power District City 1 NE 0.81e . 9 . 9 . 9
1. 13h 1. 30h 1. 47 h
1.19 1. 39 1. 58
Sierra Pacific North 0 79f 0.87f 0.96f
Power Company Val my 1 NV 0.62e . 9 0.99~ 'g
0.87h 1. 12h
0.91 1. 06 1. 21
Grand River Dam 1. 07 f 1 18f 1 30f
Authority GRDA 1 1 OK 0.84e g . 9 . 9
1. 18h 1. 34h 1. 52h
1. 23 1.44 1. 64
Oklahoma Gas & 0 94f 1 04f 1. 15 f
Electric Co. Muskogee 2 OK 0.74e . 9 . 9 1. 33~
1. 04h 1. 18h
1. 09 1. 27 1.44
(continued)
-------
TABLE 9 (continued)
w
w
I . I
S02 emissions, lb/106 Btu
No. Avg. of Maximum projected 3-h S02 emissions, lb/106 Btud
of 18 mon~h~y RSD - RSD - RSD .:...
Company name Plant units State values' 10 percent 15 percent 20 percent
Sooner 2 OK 0.75e 0.95f 1 06f 1. 16 f
9 . 9 1. 36~
1. 05h 1. 20h
1.10 1. 28 1. 46
Public Service Co. North- 1 22f 1 35f 1. 49 f
of Oklahoma eastern 2 OK 0.96e . 9 . 9 1. 74~
1. 34h 1. 54h
1. 41 1. 64 1.87
Western Farmers 1 32f f 1 61f
1. 47 9
Electric Coop. Hugo 1 OK 1.04e . 9 . 9
1. 46h 1. 66h 1. 88h
1. 53. 1. 77 2.03
Portland General 1.09~ 1 21f 1. 33 f
Electric Co. Boardman 1 OR 0.86e . 9 1. 56~
1. 20h 1. 38h
1. 26 1.47 1. 68
Central Power & Coleto 0 76f 0 85f 0.93f
Li ght Co. Creek 1 TX 0.60"e . 9 . 9 1. 09~
0.84h 0.96h
0.88 1. 02 1.17
Houston Lighting Parish, 1 10f 1 23f 1. 35 f
& Power W.A. 4 TX 0.87e . 9 . 9 1. 57~
1.22h 1. 39h
1. 28 1.49 1. 70
Lower Colorado Sam K. 0 99f 1. 10 f "1. 21 f
River Authority Seymour, . 9 1.25~ 1. 41~
0.78e 1. 09h
Jr. 2 TX 1.15 1. 33 1. 52
San Antonio Public Deely, 0.95f 1. 06 f 1. 16 f
Service Board J.1. 1 TX 0.75e 1. 05~ 1. 20~ 1. 36~
1.10 1. 28 1.46 "
Southwestern f 1. 10 f "1. 21 f
0.99
Electric 1. 09~ 1. 25~ 1. 41~
Power Co. Welsh 3 TX 0.78e 1.15 1. 33 1. 52
(continued)
-------
TABLE 9 (continued)
.S09 emissions. lb/106 Btu
No. Avg. of Maximum projected 3-h S02 emissions, lb/106 Btud
of 18 mon&h;!y RSO - RSO - RSO -
Company name Plant units State values' 10 percent 15 percent 20 percent
Southwestern f . 1 16f 1 27f
Public Service 1.04g . 9 . 9
1. 15h 1. 31h 1. 48h
Company Harrington 3 TX 0.82e 1. 21 1.40 1. 60
Grand Island Water 1.04~ 1 16f 1 27f
& Li ght Oept. Platte 1 NE 0.96e . 9 . 9
1. 15h 1. 31h 1.48h
1. 21 1.40 1. 60
Southwestern 0 95f 1 06f 1. 16 f
Public Service . 9 . 9 1. 36~
0.75e 1. 05h 1. 20h
Co. Tolk 1 TX 1.10 1. 28 1.46
Public Service 0 98f 1 09f 1 19f
Co. of Colorado Pawnee 1 CO 0.77e . 9 . 9 . 9
1. 08h 1. 23h 1. 39h
1.13 1. 32 1. 50
.
w
.f::>
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
COata from January 1982 through June 1983.
dprojections are based on 24-h RSO's of 10, 15, 20 percent, 24-h autocorrelation of 0.7, and
per year, one exceedance per year, and one exceedance in 10 years.
eSubject to Subpart 0 as listed in CDS or based on conversation with EPA Regional Office.
fAssumes 29 exceedanc~s per year (99% compliance level).
gAssumes 1 exceedance per year.
h
Assumes 1 exceedance in 10 years.
29 exceedances
-------
TABLE 10. MONTHLY AVERAGE AND PROJECTED 24-H AVERAGE S02 EMISSIONS FOR EASTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
W
<.TI
T S09' emissions. lb/l06 Btu
No. Avg. of Maximum projected 24-h S02 emissions. lb/l06 Btud
of 18 mon~hlY RSD = RSD = RSD =
Company name Plant units State values. 10 percent 15 percent 20 percent
Alabama Power Co. Miller 1 AL 0.92e . 1.13~ 1 24f 1. 35 f
. 9 1.45~
1. 18h 1.31h
1. 24 1.40 1. 56
Arkansas Power & White Bl uff 2 AR 0.96e f 1 30f 1. 41 f
1.18g
Light Co. . 9 1. 50~
1. 23h 1. 37 h
1. 30 1. 46 1. 62
Southwestern Elec- Flint Creek 1 AR 0.78e f 1 05f 1 15f
0.96g
tric Power Co. . 9 . 9
1. OOh 1. Ilh . 1. 22h
1. 05 1.18 1. 31
Georgia Power Co. Scherer 1 GA 0.95e 1 17f 1 28f 1. 40 f
. 9 . 9 1. 50~
1. 22h 1. 35h
1. 28 1.4A 1. 61
Iowa Southern Ottumwa 1 IA 0.68e 0 84f 0 92f 1. 00 f
Utilities Co. . 9 . 9 1. 07~
0.87h 0.97h
0.92 1. 03 1.15
Cajun Electric Big Cajun 2 2 LA, 0.97e 1 19f 1 31f 1. 43 f
Power Coop. . . 9 . 9 1. 53g .
1.24h 1. 38h 1. 64 h
Inc. 1. 31 1. 47
Mississippi Daniel. 1 13f 1 24f 1. 35 f
Power Co. Victor J. 2 MS 0.92e . 9 . 9 1. 45~
1. 18h 1. 31h
1. 24 1.40 1. 56
Kansas City Power Iatan 1 MO 0.73e 0 90f 0 99f 1. 07 f
& Light Co. . 9 . 9 1. 14~
0.93h 1. 04h
0.98 1.11 1. 23
(continued)
-------
TABLE 10 (continued)
w
'"
so? emissions. lb/106 Btu
No. Avg. of Maximum projected 24-h S02 emissions. lb/106 Btud
of 18 monbh~y RSD = RSD - RSD -
Company name Plant units State values. 10 percent 15 percent 20 percent
Dayton Power & Kill en 1 09f 1 20f 1 31f
0.8ge . 9 . 9 . 9
Li ght Co.. The Station 1 OH 1. 14h 1. 27 h 1. 40h
1. 20 1. 35 1. 50
Appalachian Power Mountaineer 1 14f 1. 26 ~ 1. 37 ~
0.93e . 9
Co. (1301) 1 WV 1. 19h 1. 33h 1.45h
1. 25 1. 41 1. 56
Wisconsin Electric Pleasant 1 02f 1. 12~ 1 22f
Power Co. Prairie 1 WI 0.83e . 9 . 9
1. 06h 1. 18h 1. 30h
1.12 1.26 1.40
Central Louisiana 1 18f 1. 30 ~ . 1. 41~
Electric Co.. . 9
0.96e 1. 23h 1. 37 h 1. 50h
Inc. Rodemacher 1 LA 1. 30 1.46 1. 62
Gulf States Nelson. 1. 21~ 1. 32~ f
1.44g
Util ities Co. R.S. 1 LA 0.98e 1. 25h 1. 40h 1. 54h
1. 32 1.49 1. 66
. .
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
c
Data from January 1982 through June 1983.
dprojections are based on 24-h RSDls of 10. 15. 20 percent. 24-h autocorrelation of 0.7.
excBedances per year. one exceedance per year. and one exceedance in 10 years.
eSubject to Subpart D as listed in CDS or based on conversation with EPA Regional Office.
fAssumes 4 exceedances per year (99% compliance level).
9Assumes one exceedance per year.
hAssumes one exceedance in 10 years.
and four
-------
TABLE 11.
MONTHLY AVERAGE AND PROJECTED 24-H AVERAGE S02 EMISSIONS FOR WESTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
w
......
SO? emissions. lb/106 Btu
No. Avg. of Maximum projected 24-h S02 emissions, lb/106 Btud
of 18 mon~h!y RSD = RSD = RSD =
Company name Plant units State values' 10 percent 15 percent 20 percent
Colorado Springs, Ray D. 0 84f 0 92f 1.00f
0.68e . 9 . 9 1. 08~
City of Nixon 1 CO 0.87h 0.97h
0.92 1. 03 1.16
Kansas City Board 1 01f 1 11f 1. 21 f
of Public Nearman . 9 . 9 . 1. 29g
1. 05h 1. 18h
Ut il it i es Creek 1 KS . 0.82e 1.11 1. 25 1. 39h
Hastings Uti 1 ities Hastings 1 21f 1. 32 f 1.44f
Energy . 9 1. 40g . 1. 54~
0.98e 1. 25h 1. 49h
Center 1 NE 1. 32 1. 66
Nebraska Public 0.92f 1 01f 1. 10 f
Power District Gentleman 2 NE 0.75e 0.96~ . 9 1. 18~
1. 07 h
1. 01 1.14 1. 27
Omaha Public Nebraska 1 OOf 1 09f 1 19f
Power District City 1 NE 0.81e . 9 . 9 . 9
1. 04h 1. 16h 1. 26h
1. 09 1. 23 1. 36
Sierra Pacific North 0 76f 0 83f 0.91f
Power Company Val my 1 NV 0.62e . 9 . 9 0.98~
0.79h 0.88h
0.83 0.94 1. 05
Grand River Dam 1 03f 1 13f 1. 23 f
Authority GRDA 1 1 OK 0.84e . 9 . 9 1.32~
1. 07 h 1. 20h
1.13 1. 28 1. 42
Oklahoma Gas & 0 9lf 1 OOf 1. 09 f
Electric Co. Muskogee 2 OK 0.74e . 9 . 9 1.17~
0.95h 1. 05h
1. 00 1.12 1. 26
(continued)
-------
TABLE 11 (continued)
w
())
S02 emissions. lb/l06 Btu
No. Avg. of Maximum projected 24-h S02 emissions, lb/l06 Btud
of 18 mon&ht!y RSD - RSD - RSD -
Company name Plant units State values' 10 percent 15 percent 20 percent
Sooner 2 OK 0.75e f 1. 01 f 1 16f
0.92g 1. 07~ . 9
0.96h 1. 18h
1. 01 1.14 1. 27
Public Service Co. North- 1 18f 1 30f 1 41f
of Oklahoma eastern 2 OK . O.96e . 9 . 9 . 9
1. 23h 1. 37 h 1. 50h
1. 30 1.46 1. 62
Western Farmers 1 28f 1 40f 1 53f
Electric Coop. Hugo 1 OK 1.04e . 9 . 9 . 9
1. 33h 1. 49h 1. 64h
1.40 1. 58 1. 76
Portland General 1 06f 1 16f . 1 26f
Electric Co. Boardman 1 OR 0.86e . 9 . 9 . 9
1. 10h 1. 23h 1. 35h
1.16 1. 31 1. 45
Central Power & Coleto 0 74f 0 81f 0 88f
Light Co. Creek 1 TX 0.60e . 9 . 9 . 9
0.77h 0.86h 0.94h
0.81 0.91 1. 01
Houston Lighting Parish, f 1 17f 1 29f
1. 07 9
& Power W.A. 4 TX 0.87e . 9 . 9
1. Ilh 1. 24h 1. 37 h
1.17 1. 32 1.47
Lower Colorado Sam K. 0.96~ 1. 05 f 1 14f
River Authority Seymour, . 9 . 9
0.78e 1. OOh 1. Ilh 1. 22h
Jr. 2 TX 1. 05 1.18 1. 31
San Antonio Public Deely, f 1. 01 f 1 10f
0.92g
Service Board J.T. 1 TX 0.75e 1. 07~ . 9
0.96h 1. 18h
1. 01 1.14 1. 27
Southwestern 0 96f 1 05f 1 15f
Electric . 9 . 9 . 9
Power Co. Welsh 3 TX 0.78e 1. OOh 1. Ilh 1. 22h
1. 05 1.18 1. 31
(continued)
-------
TABLE 11 (continued)
. . I
SO? emissions. lb/l06 Btu
No. Avg. of Maximum projected 24-h S02 emissions. lb/l06 Btud
of 18 mon~htY RSD = RSD = RSD =
Company name Plant units State values. 10 percent 15 percent 20 percent
Southwestern f 1.10~ 1. 21~
1. 01g
Public Service 0.82e 1. 05h 1. 18h 1. 29h
Company Harri ngton 3 TX 1.10 1. 25 1. 39
Grand Island Water 1. 18 ~ 1. 30~ 1 41f
& Li ght Dept. Platte 1 NE 0.96e . 9
1. 23h 1. 37 h 1. 50h
1. 30 1.46 1. 62
Southwestern 0 92f 1 01f 1 10f
Public Service . 9 . 9 . 9
0.96h 1. 07 h 1. 18h
Co. Tolk 1 TX 0.75e 1. 01 1.14 1. 27
Public Service 0.95~ f 1.13~
1.04g
Co. of Colorado Pawnee 1 CO 0.77e 0.99h 1. 10h 1. 26h
1. 04 1.17 1. 30
,
W
\.0
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
c
Data from January 1982 through June 1983.
dprojections are based on 24-h RSD's of 10. 15. 20 percent. 24-h autocorrelation of 0.7.
exceedances per year. one exceedance per year. and one exceedance in 10 years.
eSubject to Subpart D as listed in CDS or based on conversation with EPA Regional Office.
fAssumes four exceedances per year (99% compliance level).
gAssumes one exceedance per year.
hAssumes one exceedance in 10 years.
and four
-------
TABLE 12. MONTHLY AVERAGE AND PROJECTED 7-DAY (ROLLING) 502 EMISSIONS FOR EASTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
~
a
SO? emissions. lb/106 Btu
Avg. of Maximum proiected 7-dav 509 emissions, lb/106 Btud
No. 18 mon~h!y
Company name Plant units State values' RSD =10 percent RSD = 15 percent RSD = 20 percent
Alabama Power Co. Mi 11 er 1 AL 0.92e 1.03f 1.08f 1 13f .
g. 1. 11~ . 9
1. 05h 1. 18h
1. 08 1.16 1. 23
Arkansas Power & White Bluff 2 AR 0.96e 1.08f 1. 12 f 1 18f
Li ght Co. 1. 09~ 1. 16~ . 9
1. 23h
1.12 1. 21 1. 29
Southwestern Elec- Flint Creek 1 AR 0.78e 0.87f 0.91f 0 96f
tric Power Co. 0.89~ O. 94~. . 9
1. OOh
0.91 0.98 1. 05
Georgia Power Co. Scherer 1 GA 0.95e 1. 06 f . 1. 11 f 1.17 f
1. 08~ 1. 15~ 1. 22~
1.11 1. 20 1. 27
Iowa Southern Ottumwa 1 IA 0.68e 0.76f 0.80f 0 84f
Utilities Co. 0.78~ 0.82~ . 9
0.87h
0.80 0.86 0.91
Cajun Electric Big Cajun 2 2 LA 0.97e 1. 09 f 1.13f 1 19f
Power Coop. , 1. 11~ 1. 17~ . 9
1. 24h
Inc. 1.13 1. 22 1. 30
Mississippi Daniel, 2 MS 0.92e 1. 03 f 1.08f 1 13f
Power Co. Victor J. 1. 05~ 1. 11~ . 9
1. 18h
1. 98 1.16 1. 23
Kansas City Power Iatan 1 MO 0.73e 0.82f 0.85f 0 90f
& Light Co. 0.83~ 0.88~ . 9
0.93h
0.85 0.92 0.98
(continued)
-------
TABLE 12 (continued)
~
-
. . .
SO? emissions. lb/l06 Btu
Avg. of Maximum projected 7-dav S02 emissions. lb/l06 Btud
No. 18 monbh~y
Company name Plant units State values' RSD - 10 percent RSD - 15 percent RSD - 20 percent
Dayton Power & Killen 1 OH 0.8ge 1.00f 1 04f 1.09f
Light Co., The Station 1. 01~ . 9 1. 14~
1. 08h
1.04 1.12 1.19
Appalachian Power Mountaineer 1 MV 0.93e 1.04f 1 09f 1. 14 f
Co. (1301) 1. 06~ . 9 1. 19~
1. 13h
1.09 1.17 1. 25
Wisconsin Electric Pleasant 1 WI 0.83e 0.93f 0 97f 1.02 f
Power Co. Prairie 0.94~ ' 9 1. 06~
1. OOh
0.97 1. 05 1.11
Central Louisiana Rodemacher 1 LA 0.96e 1 08f 1 12f' 1.18f
Electric Co., . 9 . 9 1. 23~
1. 09h 1. 16h
Inc. 1.12 1. 21 1. 29
Gulf States Nelson, 1 LA 0.98e 1. 10 f 1 15f 1. 21 f
Utilities Co. R.S. 1. 12~ . 9 1. 25~
1. 19h
1.15 1. 23 1. 31
.
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
COata from January 1982 through June 1983.
dprojections are based on 24-h RSO's of 10, 15, 20 percent, 24-h autocorrelation of 0.7, and four
exc~edances per year, one exceedance per year, and one exceedance in 10 years.
eSubject to Subpart 0 as listed in CDS or based on conversation with EPA Regional Office.
fAssumes four exceedances per year (99% compliance level).
gAssumes one exceedanGe per year.
hAssumes one exceedance in 10 years.
-------
TABLE 13.
MONTHLY AVERAGE AND PROJECTED 7-DAY (ROLLING) AVERAGE S02 EMISSIONS FOR WESTERN
. ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
+:-
N
. -
SO? emissions. lb/106 Btu
Avg. of Maximum projected 7-day SO? emissions. lb/106 Btud
No. 18 mon~hlY
Company name Plant units State values' RSD ; 10 percent RSD; 15 percent RSD = 20 percent
Colorado Springs, Ray D. 0.76f 0.80f 0.84f
City of Nixon 1 CO 0.68e 0.78~ 0.82~ 0.87~
0.80 0.86 0.91
Kansas City Board 0.92f 0 96f 1. 01 f
of Public Nearman 0.93~ . 9 1. 05~
0.99h
Utilities Creek 1 KS 0.82e 0.96 1. 03 1.10
Hastings Utilities Hastings 1 10f 1 15f 1. 21 f
. 9 . 9 1. 25~
Energy 0.98e 1. 12h 1. 19h .
Center 1 NE 1.15 1. 23 1. 31
Nebraska Public 0.84f 0 88f 0.92f
Power District Gentleman 2 NE 0.75e 0.86~ . 9 0.96~
0.91h
0.88 0.95 1. 01
Omaha Public Nebraska 0.91f 0 95f 1.00f
Power District City 1 NE 0.81e 0.92~ . 9 1. 04~
0.98h
0.95 1. 02 1.09
Sierra Pacific North 0.69f 0.73~ 0.76f
Power Company Valmy 1 NV 0.62e 0.71~ 0.75h 0.79~
0.73 0.78 0.83
Grand River Dam 0.94f 0 98f 1. 03 f
Authority GRDA 1 1 OK 0.84e 0.96~ . 9 1. 08~
1. 02h
0.98 1. 06 1.13
Oklahoma Gas & 0.83f 0 87f 0.91f
Electric Co. Muskogee 2 OK 0.74e 0.84~ . 9 0.95~
0.90h
0.87 0.93 0.99
(continued)
-------
TABLE 13 (continued)
~
w
so? emissions. lb/106 Btu
Avg. of Maximum projected 7-day so? emissions. lb/106 Btud
No. 18 mon&htY
Company name Pl ant, units State values' RSD = 10 percent RSD = 15 percent RSD = 20 percent
Sooner 2 OK 0.75e 0 84f 0.88f 0.92f
. 9 0.91~ 0.96~
0.86h
0.88 0.95 1. 01
Public Service Co. North- 1 08f 1. 12 f 1.18f
of Oklahoma eastern 2 OK 0.96e . 9 1. 16~ 1. 23~
1. 09h
1.12 1. 21 1. 29
Western Farmers 1.16f 1. 22 f 1.28f
Electric Coop. Hugo 1. OK 1.04e . 9 1. 26~ 1. 33~
1. 19h
1. 22 1. 31 1. 39
Portland General 0 96f 1. 01 f 1 05f
Electric Co. Boardman 1 OR 0.86e . 9 1.04~ . 9
0.98h 1. 10h
1. 01 1. 08 1.15
Central Power & Coleto 0 67f 0 70f 0 74f
Li ght Co. Creek 1 TX 0.60e . 9 . 9 . 9
0.68h 0.73h 0.77h
0.70 O. 76 0.80
Houston Lighting Parish, 0.97f 1 02f 1. 07 f
& Power W.A. 4 TX 0.87e 0.99~ . 9 1.11~
1.05h
1. 02 1.10 1.17
Lower Colorado Sam K. 0.87f 0 91f 0.96f
River Authority Seymour, 0.89~ ' 9 1. OO~
0.78e 0.94h
Jr. 2 TX 0.91 0.98 1. 05
San Antonio Public Deely, 0.84f 0.88f 0.92f
Service Board J. T. 1 TX 0.75e 0.86~ 0.91~ 0.96~
0.88 0.95 1. 01
Southwestern 0.87f 0.91f 0.96f
Electric 0.89~ 0.94~ 1. OO~
Power Co. Welsh 3 TX 0.78e 0.91 0.98 1. 04
(continued)
-------
TABLE 13 (continued)
+=-
+=-
, .
SO? emissions. lb/106 Btu
Avg.. of Maximum projected 7-day S02 emissions. lb/106 Btud
No. 18 mon~htY
Company name Plant units State values. RSD - 10 percent RSD - 15 percent RSD - 20 percent
Southwestern 0.92f 0 96f 1. 01 f
Public Service 0.93~ ' 9 1. 05~
0.99h
Company Harri ngton 3 TX 0.82e 0.96 1. 03 1.10
Grand Island Water 1 08f 1.12f 1.18f
& Light Dept. Platte 1 NE 0.96e . 9 1. 16~ 1. 23~
1. 09h
1.12 1. 21 1. 29
Southwestern 0.84f 0 88f 0.92f
Public Service 0.86~ ' 9 0.96~
0.91h
Co. Tolk 1 TX 0.75e 0.88 0.95 1. 01
Public Service 0 86f 0 91f 0.95f
Co. of Colorado Pawnee 1 CO 0.77e . 9 . 9 g'
0.88h 0.93h 0.99h
0.91 0.97 1. 03
. I
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean. . .
COata from January 1982 through June 1983.
dprojections are' based on 24-h RSD's of 10. 15. 20 percent. 24-h autocorrelation of 0.7. and four
exceedances per year. one exceedance per year. and one exceedance in 10 years.
eSubject to Subpart D as listed in CDS or based on conversation with EPA Regional Office.
fAssumes four exceedances per year (99% compliance level).
gAssumes one exceedance per year.
hAssumes one exceedance in 10 years.
-------
Tables 14 and 15 summarize the estimated or projected 30-day rolling
average emission levels based on assumed RSD's of 10, 15, and 20 percent, a
24-h autocorrelation of 0.7; four exceedances per year; one exceedance per
year; and one exceedance in 10 years for the eastern and western units. The
30-day rolling average for S02 emissions ranged from 0.63 to 1.09 lb S02/106
Btu fOr a 24-h RSD of .10 percent, a 24-h autocorrelation of 0.7, and four
exceedances per year; from 0.64 to 1.11 lb S02/106 Btu for a 24-h RSD of 10
percent, a 24-h autocorrelation of 0.7, and one exceedance per year; and from
0.70 to 1. 22 1 b S02/106 Btu for a 24-h RSD ~f 20 'percent, a 24-h autocorrel a-
tion of 0.7, and one exceedance in 10 years.
5.2 EVALUATION OF COMPLIANCE WITH SUBPART D LIMITS ON A 3-H, 24-H, 7-DAY,
AND 30-DAY BASIS
Based on the statistical assumption~ and procedures presented in Section
5.1, several calculations were performed to estimate the mean S02 emissions
in lb/106 Btu that would be required to meet the Subpart D limit of 1.2 lb/l06
Btu on a 30-day, 7-day, 24-h, and 3-h basis. Table 15 summarizes the results
of these calculations. These calculations are based on a 24-h RSD of 0.20
and a 24-h autocorrelation of 0.7. For a 24-h RSD of 20 percent, a 24-h auto-
correlation of 0.7, and one exceedance in 10 years, long-term averages of
1.02,0.89, 0.72, and 0.62 lb S02/106 Btu are needed to ensure compliance
with a 30-day, 7-day, 24-h, and 3-h average emission limit of 1.2 lb 106/Btu,
respectively. For a 24-h RSD of 10 percent, a 24-h autocorrelation of 0.7,
and one exceedance in 10 years, long~term averages of 1.10, 1.02,0.89, and
0.81 lb S02/106 Btu are needed to ensure compliance with a 30 day, 7-day,
24-h, and 3-h average emission limit of 1.2 lb S02/106 Btu, respectivel~. If
one exceedance per year is permitted, the projected annual S02 emission levels
required to meet the 1.2 lb 502/106 Btu standard at the various averaging
times are approximately 2 to 8 percent higher depending on the averaging time
and the RSD. If a 99 percent compliance level is assumed, the projected annual
S02 emission' levels required to meet the 1.2 lb S02/106 Btu standard at various
averaging times are approximately 3 to 24 percent higher depending on the
averaging time and the RSD.
Because the assumptions used in the projections presented in T~ble 15
were based on limited data, a sensitivity analysis was conducted to determine
45
-------
TABLE 14.
MONTHLY AVERAGE AND PROJECTED 30-DAY (ROLLING AVERAGE) S02 EMISSIONS FOR EASTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
+=-
0'1
.
SO? emissions. lb/l06 Btu
No. Avg. of Maximum projected 30-day S02 emissions. lb/l06 Btud
of 18 monbhly RSD = RSD = RSD =
Company name Plant units State values» 10 percent 15 percent 20 percent
Alabama Power Co. Mi 11 er 1 AL 0.92e 0 97f 1 Oof 1. 03 f
. 9 . 9 1. 05~
0.98h 1. 01h
1. 00 1. 04 1. 08
Arkansas Power & 1 01f 1 05f 1.08f
Light Co. White Bl uff 2 AR 0.96e . 9 . 9 1. 09~
1. 03h 1. 06h
1. 05 1. 08 1.12
Southwestern Elec- 0 82f 0 "85 f 0 87f
tric Power Co. Flint Creek 1 AR 0.78e . 9 . 9 . 9
0.83h 0.86h 0.89h
0.85 0.88 0.91
Georgia Power Co. Scherer 1 GA 0.95e 1 OOf 1 04f . 1. 06 f
. 9 . 9 1. 08~
1. 02h 1.05h
1. 04 1. 07 1.11
Iowa Southern 0 71f 0 74f 0.76f
Util ities Co. Ottumwa 1 IA 0.68e . 9 . 9 0.78~
0.73h 0.75h
0.74 0.77 0.80
Cajun Electric 1 02f 1 06f 1. 09 f
Power Coop. . . 9 . 9 1. 11~
0.97e 1. 04h 1. 07 h
Inc. Big Cajun 2 2 LA 1. 06 1.10 1.13
Mississippi Daniel. 0 97f 1 OOf 1 03f
Power Co. Victor J. 2 MS 0.92e . 9 . 9 . 9
,O.98h 1. 01h 1. 05h
1.00 1. 04 1. 08
Kansas City Power 0 nf 0 80f . 0.82f
& Light Co. Iatan 1 MO 0.73e . 9 . 9 0.83~
0.78h 0.81h
0.80 0.82 0.85
(continued)
-------
TABLE 14 (continued)
-&:>
""-J
so? emissions. lb/106 Btu
No. Avg. of Maximum projected 30-day 502 emissions, lb/106 Btud
of 18 mon~h~y RSD = RSD = RSD =
Company name Plant units State values' 10 percent 15 percent 20 percent
Dayton Power & Killen 0 93f 0 97f 1.00f
0.8ge . 9 . 9 1.01~
Light Co., The Station 1 OH 0.95h 0.98h
0.97 1. 01 1. 04
Appalachian Power Mountaineer 0 98f 1 01f 1.04f
Co. (1301) 1 WV 0.93e . 9 . 9 1. 06~
1. OOh . 1. 02h
1. 01 1. 05 1. 09
Wisconsin Electric Pleasant 0 87f 0 90f 0.93f
Power Co. Prairie 1 WI 0.83e . 9 . 9 0.95~
0.89h 0.91h
0.90 0.94 0.97
Central Louisiana 1 01f 1 05f 1.08f
Electric Co., '. 9 . 9 1. 09~
0.96e 1. 03h 1. 06h
Inc. Rodemacher 1 LA 1. 05 1. 08 1.12
Gulf States Nelson, 1. 03~ 1 07f 1 10f
0.98~ . 9 . 9
Util ities Co. R.S. 1 LA 1. 05h 1. 08h 1. 12h
1. 07 1.11 1.15
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
CData from January 1982 through June 1983.
dprojections are based on RSD's of 10, 15, 20 percent, autocorrelation of 0.7 and four exceedances
per. year, one exceedance per year, and one exceedance in 10 years.
eSubject to Subpart D as listed in CDS or based on conversation with EPA Regional Office.
fAssumes four exceedances per year (99% compliance level).
gAssumes one exceedance per year.
h
Assumes one exceedance per 10 years.
-------
TABLE 15.
MONTHLY AVERAGE AND PROJECTED 30-DAY (ROLLING AVERAGE) SO EMISSIONS fOR WESTERN
ELECTRIC GENERATING UNITS SUBJECT TO SUBPART Da
.t:-
oo
. I I
S02 emissions. lb/106 Btu
No. Avg. of Maximum projected 30-day S02 emissions, lb/106 Btud
of 18 mon&hly RSD - RSD - RSD -
Company name Plant units State values' 10 percent 15 percent 20 percent
Colorado Springs, Ra~ D. 0.71f 0 74f 0.76f
City of Nixon 1 CO 0.68e O. 73~ . 9 0.78g
0.75h 0.80h
0.74 0.77
Kansas City Board 0.86f 0 89f f
0.92
of Public Nearman 0.88~ ' 9 ,0. 93~
0.90h
Ut i1 it i es Creek 1 KS 0.82e 0.89 0.93 0.96
Hastings Utilities Hastings 1. 03 f 1. 07 f 1. 10 f
Energy 1. 05~ 1. 08g , 1. 12~
Center 1 NE 0.98e 1. 07 1. 11 h 1.15
Nebraska Public 0.79f 0 82f 0.84f
Power District Gentleman 2 NE 0.75e 0.80~ . 9 0.86~
0.83h
0.82 0.85 0.88
Omaha Public Nebraska 0.85f 0.88f 0.91f
Power District City 1 NE 0.81e 0.87~ 0.89~ 0.92~
0.88 0.92 0.95
Sierra Pacific North 0.65f 0 68f 0.69f
Power Company Valmy 1 NV 0.62e 0.66~ . 9 0.71~
0.69h
0.68 0.70 0.73
Grand River Dam 0.88f 0 92f 0.94f
Authority GRDA 1 1 OK 0.84e 0.90~ . 9 0.96~
0.92h
0.92 0.95 0.98 :
Oklahoma Gas & 0.78f 0 81f 0.83f
Electric Co. Muskogee 2 OK 0.74e O. 79~ . 9 0.84~
0.82h
0.81 0.84 0.87
(continued)
-------
TABLE 15 (continued)
~
~
.
SO? emissions. lb/106 Btu
No. Avg. of Maximum projected 30-day S02 emissions, lb/106 Btud
of 18 mon~hlY RSD = RSD = RSD =
Company name Plant units State values' 10 percent 15 percent 20 percent
Sooner 2 OK 0.75e 0.79f 0 82f 0 84f
0.80g. . 9 . 9
0.82h 0.83h 0.86h
0.85 0.88
Public Service Co. North- 1. 01 f 1 05f 1 08f
of Oklahoma eastern 2 OK 0.96e 1. 03~ . 9 . 9
1. 06h 1. 09,
1. 05 . 1. 08 1. 12 )
Western Farmers 1. 09 f 1. 13 f 1.16f
Electric Coop. Hugo 1 OK 1.04e 1.11~ 1. 14~ 9
1. 19h
1.13 1.18 1.2.2
Portland General 0.90f 0 94f 0 96f
Electric Co. Boardman 1 OR 0.86e 0.92~ . 9 . 9
0.95h 0.98h
0.94 0.97 1. 01
Central Power & Coleto 0.63f 0 64f 0.67f
Li ght Co. Creek 1 TX 0.60e 0.64~ . 9 0.68~
0.66h
0.65 0.68 0.70 )
Houston Lighting Parish, 0.91f 0 95f 0 97f
& Power W.A. 4 TX 0.87e 0.93~ . 9 . 9
0.96h 0.99h
0.95 0.98 1. 02
Lower Colorado Sam K. 0.82f 0 85f 0.87f
Ri ver Authority Seymour, 0.83~ ' 9 0.89~
0.78e 0.86h
Jr. 2 TX 0.85 0.88 0.91
San Antonio Public Deely, 0.79f 0 82f 0.84f
Service Board J. T. 1 TX 0.75e 0.80~ . 9 0.86~
0.83h
0.82 0.85 0.88
Southwestern 0.82f 0 85f 0 87f
Electric . 9 . 9 . 9
0.83h 0.86h 0.89h
Power Co. Welsh 3 TX 0.78e 0.85 0.88 0.91
(continued)
-------
TABLE 15 (continued)
.
SO? emissions. lb/106 Btu
No. Avg. of Maximum projected 30-day S02 emissions. lb/106 Btud
of 18 mon&h~y RSO = RSO = . RSO -
Company name Plant units State values. 10 percent 15 percent 20 percent
Southwestern 0.86~ 0 89f 0.92f
Public Service . 9 0.93~
0.88h 0.90h
Company Harrington 3 TX 0.82e 0.89 0.93 0.96
Grand Island Water 1 01f 1. 05 f 1.08f
& Light Dept. Platte 1 NE 0.96e . 9 1. 06~ 1. 09~
1. 03h
1. 05 1. 08 1.12
Southwestern 0 79f f 0.84f
0.82
Public Service . 9 9 0.86~
0.80h 0.83h
Co. Toll< 1 TX 0.75e 0.82 0.85 0.88
Public Service 0 81f 0 84f 0 86f
Co. of Colorado Pawnee 1 CO 0.77e . 9 . 9 . 9
0.82h 0.85h 0.88h
0.84 0.87 0.90
. .
Ul
o
aIn-service date of 1975 or later and a capacity> 23 MW .
- e
bMeasured arithmetic mean.
COata from January 1982 through June 1983.
dprojections are based on RSO's of 10. 15. 20 percent. autocorrelation of 0.7. and four exceedances
per year. one exceedance per year. and one exceedance in 10 years.
eSubject to Subpart 0 as listed in CDS or based on conversation with EPA Regional Office.
fAssumes four exceedances per year (99% compliance level).
gAssumes one exceedance per year.
hAssumes one exceedance in 10 years.
-------
TABLE 16. PROJECTED ANNUAL S02 EMISSION LEVELS REQUIRED
TO MEET 1.2 lb S02/106 Btu AT VARIOUS AVERAGING TIMESa
Annual average 502 emission (lb 502/106 Btu)
Averaqinq time R5D = 10% RSD = 15% RSD = 20%
30-daye b b b
1. 13e l.10e 1. 07 c
1. 12d 1.09d 1.05d
1.10 1.06 1.02
7-daye b b 0.97~
1.08e 1.02c
1. 05d 0.99d 0.94d
1.02 0.95 0.89
24-hourf b b b
0.97e 0.8ge 0.82c
0.94d 0.85d 0.77d
0.89 0.79 0.71
f b b b
3-hour O.94e 0.85e 0.77c
0.86d 0.75d 0.66d
0~81 0.70 0.62
aRSD and autocorrelation are for 24-h average. Autocorrelation is 0.7.
bFor 3-h, 29 exceedances per year are assumed and for 24-h, 7-day, and 30-day,
four exceedances per year are assumed (99% compliance level).
cOne exceedance per year.
dOne exceedance in 10 years.
eRolling average.
fDiscrete nonoverlapping average.
what effect (if any) the RSD, autocorrelation, the one exceedance criteria,
and the assumption that the 3-h and 24-h 502 values are normally distributed
versus .1 ognorma lly di stributed, mi ght have on these estimates.
The results in Table 16 clearly indicate that RSD has a significant
impact on the projected long-term average that would be needed to meet the
Subpart D limit on a 3-h or 24-h basis. For example, a unit firing coal that
has an RSD of 10 percent (low variability) could emit 0.81 and 0.89 lb S02/
106 Btu (long-term average) if it wanted to ensure that it would not exceed
the 1.2 lb/106 Btu limit more than once in 10 years on a 3~h or 24-h basis,
respectively. A unit firing coal that has an RSD of 20 percent (relatively
high variability), however, could only emit 0.62 and 0.71 lb 502/106 Btu
51
-------
(long-term average) without exceeding the 1.2 lb/l06 Btu limit more than once
in 10 years on a 3-h or 24-h basis, respectively.
The results in Table 16 also indicate that whether the unit is allowed
to exceed the 1.2 lb/l06 Btu limit once per year, more than once per year or
only once in 10 years has an impact on the projected long-term average that
would be needed to meet the Subpart 0 limit on a 3-h and 24-h basis. Even
when the variability is relatively low (i.e., 10%), a unit could only emit
0.81 lb S02/106 Btu or less without exceeding the 1.2 lb/l06 Btu limit on a
3-h basis more than once in 10 years. A uni't could emit 0.86 or 0.94 lb
S02/106 Btu on a 3-h basis, however, if it were allowed to exceed the limit
once per year or 29 times per year (99% compliance level), respectively.
As noted in Table,16, the calculations are based on the assumption that
the 24-h autocorrelation is 0.7. This auto~orrelation indicates that the I-h
val ues are reasonably well correl ated. For determination of impact of the
autocorrelation assumption of 0.7, two additional autocorrelation assumptions
were evaluated: 0.5 and 0.8.
Tables 17, 18, 19, and 20 sumnarize the projected annual S02 emission
levels required to meet 1.2 lb S02/106 Btu on a 3-h, 24-h, 7~day, and 30-day
rolling average basis, respectively, assuming autocorrelations of 0.5, 0.7,
and 0.8; 24-h, RSD's of 10, 15, and 20 percent; one exceedance in 10 years,
one exceedance per year and 99 percent compliance level. The results in
Tables 17, 18, 19, and 20 indicate that the projected emissions are less
sensitive to the autocorrelation assumptions than to the RSD and the ex-
ceedance criteria assumptions.
The last assumption to be tested in terms of its impact on the projected
long-term emissions needed to meet the 1.2 lb S02/106 Btu standard on a 3-h,
24-h, 7-day, and 30-day rolling average basis is that the data are normally
distributed. As a test of the significance of this assumption, the values in
Tables 17, and 18 were recalculated on the assumption that the 3-h and 24-h
data are lognormally distributed. Tables 21 and 22 sumnarize the results of
the recalculation and compare these results with the values based on the assump-
tion that the data are normally distributed. A review of Table 21 indicates
that a unit can only emit 0.52 lb 502/106 Btu and still meet 1.2 lb/106 Btu
on a 3-h basis if the data are lognormally distributed, the 24-h RSO is 20
percent, the 24-h autocorrelation is 0.5, and the unit is permitted to exceed
52
-------
TABLE 17. PROJECTED ANNUAL S02 EMISSION LEVELS REQUIRED TO MEET
1.2 LB 502/106 BTU ON A 3-H BASI5
Annual a~erage 502 emissions (lb S02/106 Btu)a
Exceedance R5D = 10 percent R5D = 15 percent RSD = 20 percent
cd teri a 0=0.5 p=0.7 0=0.8 0=0.5 p=O.7 p=0.8 p=0.5 p=0.7 0=0. 8
Once in 10 years 0.77 0.81 0.83 0.65 0.70 0.72 0.56 0.62 0.64
Once per year 0.81 0.86 0.87 0.70 0.75. 0.77 0.61 0.66 0.68
.
29 per year 0.90 0.94 0.95 0.80 0.85 0.87 0.72 0.77 0.79
aNormal distribution.
TABLE 18. PROJECTED ANNUAL S02 EMISSION LEVELS REQUIRED TO MEET
. 1.2 LB 502/106 BTU ON A 24-H BASIS
Annual average 502 emissions (lb S02/106 Btu)a
Exceedance RSD = 10 percent RSD = 15 percent RSD = 20 percent
criteria p=0.5 p=0.7 0=0.8 0=0.5 0= O. 7 p=0.8 p= 0 . 5 0=0.7 p=O. 8
Once in 10 years 0.89 0.89 0.89 0.79 0.79 0.79 0.71 0.71 0.71
Once per year 0.94 0.94 0.94 0.85 0.85 0.85 0.77 0.77 0.77
4 per year 0.97 0.97 0.97 0.89 0.89 I 0.89 0.82 0.82 0.82
.-
aNormal distribution.
TABLE 19. PROJECTED ANNUAL S02 EMISS.ION LEVELS REQUIRED TO MEET
1.2 LB S02 ON A 7-DAY (ROLLING AVERAGE) BASIS
Annual average S02 emissions (lb 502/106 Btu)a
Exceedance RSD = 10 percent RSD = 15 percent RSD = 20 percent
criteria 0=0.5 p=0.7 0=0.8 p=0.5 p=O. 7 0=0.8 0=0. 5 p= 0 . 7 0=0.8
Once in 10 years 1.04 1.02 1.01 0.98 0.95 0.93 0.92 0.89 0.87
Once per year 1.07 1.05 1.02 1.02 0.99 0.97 0.97 -0.94 0.92
4 per year 1.09 1.08 1.07 1.04 1.02 1.00 1. 00 0.97 0.95
I
aNormal distribution.
53
-------
TABLE 20. PROJECTED ANNUAL 502 EMISSION LEVELS REQUIRED TO MEET
1.2 LB S02/106 BTU ON A 30-DAY (ROLLING AVERAGE) BASIS
Annual average S02 emissions (lb 502/106 Btu)a
Exceedance RSD = 10 Dercent RSD = 15 percent RSD = 20 percent
cri teri a 0=0.5 p=O. 7 0= 0 . 8. 0=0. 5 p=0.7 p=0.8 p=O. 5 0=0. 7 0=0. 8
Once in 10 years 1.12 1.10 1.09 1.08 1.06 1.04 1.04 1.02 1.00
Once per year 1.13 1.12 1.11 1.10 1.09 1. 07 1.09 1.07 1.06
4 per year 1.14 1.13 1.12 1.12 1.10 1.09 1.09 1.07 1.06
aNormal distribution.
TABLE 21. PROJECTED ANNUAL 502 EMISSION LEVELS REQUIRED TO MEET
1.2 LB S02/106 BTU ON A 3-H BASIS ASSUMING NORMAL
VERSUS A LOGNORMAL DISTRIBUTION
Annual average 502 emissions (lb 502/106 Btu)
Exceedance RSD = 10 percent RSD = 15 percent RSD = 20 Dercent
criteria Distribution .p=0.5 0=0.7 0=0. 8 0=0.5 D=O. 7 0= O. 8 p=0.5 p=0.7 p= 0 . 8
Once in
10 years Normal 0.77 0.81 0.83 0.65 0.70 0.72 0.56 0.62 0.64
Once; n .-
10 years Lognormal 0.72 0.76 0.78 0.61 0.65 0.68 0.52 0.58 0.60
Once per
year Normal 0.81 0.86 0.87 0.70 0.75 0.77. 0.61 0.66 0.68
Once per
year Lognormal . 0.76 0.81 0.82 0.65 0.71 0.72 0.57 0.62 0.64
29 per
year Normal 0.90 0.94 0.95 0.80 0.85 0.87 0.72 0.77 0.79
29 per
year Lognormal 0.85 0.88 0.89 0.75 0.80 0.82 0.68 0.72 0.74
54
-------
TABLE 22. PROJECTED ANNUAL S02 EMISSION LEVELS REQUIRED TO MEET
.1.2 LB S02/106 BTU ON A 24-H BASIS ASSUMING NORMAL
VERSUS A LOGNORMAL DISTRIBUTION
Annual averaqe S02 emissions (lb S02l106 Btu)
Exceedance RSD = 10 percent RSD = 15 percent RSD = 20 percent
criteria Distribution 0=0.5 p=O. 7 p=0.8 p=0.5 0=0.7 0=0.8 p=O. 5 p=0.7 p=0.8
Once in
10 years Normal 0.89 0.89 0.89 0.79 0.79 0.79 0.71 0.71 0.71
Once in
10 years Lognormal 0.89 0.89 0.89 0.77 0.77 0.77 0.67 0.67 0.67
Once per
year Normal 0.94 0.94 0.94 0.85 0.85 0.85 0.77 0.77 0.77
Once per
year Lognormal 0.94 0.94 0.94 0.85 0.85 0.85 0.76 0.76 0.76
4 per
year Normal 0.97 0.97 0.97 0.89 0.89 0.89 0.82 0.82 0.82
4 per
year Lognormal 0.97 0.97 0.97 0.89 0.89 0.89 0.81 0.81 0.81
the 1.2 lb/106 Btu limit once in 10 years. On the other hand, a unit could
emit as much as 0.87 lb S02/106 Btu if the data were normally distributed, the
24-h RSD is 10 percent, the 24-h autocorrelation is 0.8, and the unit is per-
mitted to exceed the limit once per year and 0.95 lb S02/106 if the data were
normally distributed, the 24-h RSD is 10 percent, the 24-h autocorrelation is
0.8, and the unit were permitted to exceed the limit 29 times per year.
A review of Table 22 indicates that a unit can emit 0.67 lb S02/106 Btu
and still meet 1.2 lb S02i106 Btu on a 24-h basis if the data are log-
norma 11y di stri buted, the 24-h RSD is 20 percent, the 24-h autocorrel ati on is
0.5, and the unit is permitted to exceed the 1.2 lb S02/106 Btu limit once in
10 years. On the other hand, a unit could emit as much as 0.94 lb S02/106
Btu if the data were normally distributed, the 24-h RSD is 10 percent, the
24-h autocorrelation is 0.8, and the unit is permitted to exceed the limit
once per year and 0.97 lb S02/106 Btu if the data were normally distributed,
the 24-h RSD is 10 percent, the 24-h autocorrelation is 0.8 and the ~nit were
permitted to exceed the limit four times per year (99% compliance level).
55
-------
REFERENCES
1.
U.S. Department of Energy. Inventory of Power Plants in the United
States - 1981 Annual. DOE/EIA-0095(81), September 1982.
2.
U.S. Department. of Energy. Inventory of Power Plants in the United
States - 1982 Annual. DOE/EIA-0095(82), June 1983.
3.
U.S. Department of Energy. Cost and Quality of Fuels for Electric.
Utility Plants. DOE/EIA-0075(82/01 to 82/12), January 1982 through
December 1982.
4.
U.s. Department of Energy. Electric Power Quarterly.
1Q), June 1983. DOE/EIA-0397(82/2Q), September 1983.
DOE/EIA-0397(83/
5.
DuBose, D. A., W. D. Kwapil, andE. F. Aul, Jr. Statistical Analysis
of ~et Flue Gas Desulfurization Systems and Coal Sulfur Content.
Volumes I and II. Prepared by Radian Corporation for the U. S. Envi ron-
mental Protection Agency under Contract No. 68-02-3816, August 1983.
56
-------
APPENDIX A
LISTING OF COAL-FIRED POWER PLANTS WITH ALL SUBPART D (NSPS) UNITS
(COMPLIANCE COAL AND FGD)a.b
U1
'-J
.
In Plant
Unit Capacity. serv1~e locat1onc fGO used
Company name Plant County State 'number HWe date E W Yes No
Alabama Power Miller Jefferson Al 1 105.5d 1918 x x
Ari zona Electric Apache Sta- Cochise AZ 2 194.1d 1919 x x
Power Coop.. Inc. tion 3 204.0d 1919 x x
Salt River Proj. Agr1. Coronado Apache AZ 1 410.9d 1919 x x
Imp. Power Olst. 2 410.9d 1980 x x
Arkansas Power and White Bluff Jefferson AR 1 800.0d 1980 x x
light Co. 2 800.0d 1981 x x
Southwestern Elec. flint Creek Benton AR 1 512. 3d 1978 x x
Power Co.
Colorado Springs, Ray D. El Paso CO 1 201.0d 1980 x x
City of Nixon
Colorado.- UTE Elec. Craig Moffat CO . 1 441.0d 1980 x x
Assn. I Inc. 2 441.0d 1979 x x
Public Service 507.0d
Co. of Colorado Pawnee Morgan CO 1 1981 x x
lakeland, City of Mcintosh,
Dept. of Electric C.O. 364.0d xe
and Water Polk Fl 3 1982 x
Georgia Power Co. Scherer Heard GA 1 891. Od 1982 x x
Wansley Heard GA 1 952.0 1976 x x
2 952.0 1978 x x
(continued)
-------
. .
In Plant c
Unit Capacity, servi5e location FGD used
Company name Plant County :»tate number MWe date E W Yes No
Central Illinois Duck Creek fylton Il 1 441.0d 1976 x x
light Co.
Central Illinois Newton Jasper Il 1 617. 4d 1977 x x
Public Service Co. 2 617. 4d 1982 x x
Hoosier Energy, Ind. Herom Sullivan IN 1 490.0d 1982 x xe
Statewide Rec. 2 490.0d 1982 x x
Southern Indiana 265.2d
Gas and Electric A. B. Brown . Posey IN 1 1979 x x
Iowa Southern 726. Od
Utilities Co. Ottumwa Wape 11 0 IA 1 1981 x x
Kansas City Board of Nearman 262.0d
Public Util. (KS) Creek Wyandotte KS 1 1981 x x
Kansas Power and Jeffrey PottawatomiE KS 1 720.0d 1978 x. .x
light Co. 2 720.0d 1980 .x x
Big Rivers Electric Green Webster KY 1 242.1d 1979 x x
Corp. 2 242.1d 1980 x x
Cincinnati Gas and 669.0d xe
Electric Co. East Bend Boone KY 2 1981 x
Cajun Electric Power Big Pointe lA 1 559.0d 1981 x x
Coop. Inc. Cajun 2 Coupee 2 559.0d 1981
x x
Central Louisiana 558.0d
Electric Co.. Inc. Rodemacher Rapides lA 2 1982 x x
U1
CO
(continued)
-------
U1
lO
In Plant c
Unit Capaci ty, servi~e location FGD used
Company name Plant County State number MWe date E W Yes No
Gulf States Utilities Nelson, 614.{)f
Company RS Calcasieu LA 6 1982 x x
Northern States Power Sherburne Sherburne MN 1 720.0d 1976 x x
Co. - 720. Od
2 1977 x x
Mississippi Power Co. Daniel, Jackson MS 1 548. 3d 1977 x x
Victor 2 548. 3d 1981 x x
J JR.
South Mississippi Morrow Lamar HS 1 200.0d 1978 x x
Elec. Power Assn. 2 200.0d 1978 x x
Independence, City of Hi ssouri Clay HO 1 23.0 1982 x x
City 2 23.0 1982 x x
Kansas City Power and 725.8d
light Co. latan Platte MO 1 1980 x x
Sikeston 80ard of 251. Od
Municipal Utilities Sikeston Scott MO 1 1981 x x
Springfield Utilities 194.0d
(MO) Southwest Greene MO 1 . 1976 x x
Union Electric Co. Rush Jefferson MO 1 620.5 1976 x x
(MO) Island 2 620.5 1977 x
x
Montana Power Co. , Colstrip Rosebud HT 1 358.0d 1975 x x
The 2 358.0d 1976
x x
Grand Island Water 109.8d
and light Dept. Platte Hall NE 1 1982 x x
(continued)
-------
In Plant
Unit Capacity, servi~e locationc FGD used
Company name Plant County State number MWe date E W Yes No
Hastings Utilities Hastings Adams NE 1 76.3d 1981 x x
Energy Ctr.
Nebraska Public Power Gentleman linco 1 n NE 1 650.0f 1979 x x
District 2 628.0f 1982 x x
Omaha Public Power Nebraska 565.0d
District City Otoe NE 1 1979 x x
Sierra Pacific Power North 270.0d
Co. Valmy Humboldt NV 1 1981 x x
Cooperative Power Coal Creek Mclean NO 1 550.0d 1979 x x
Association 2 550.0d 1981 x x
Montana-Dakota 450.0d
Utilities Co. Coyote Hercer NO 1 1981 x x
Dayton Power and Ki Hen
light Co. I The Station Adams OH 2 661. Od 1982 x x
Grand River Dam 490.0d
Authori ty GRDA 1 Mayes OK 1 1981 x x
Oklahoma Gas and Huskogee Huskogee OK 4 550.0d 1977 x x
Electric Co. 5 550.0d 1978
x x
Sooner Noble OK 1 568.8d 1979 x x
2 568.8d 1980 x x
Public Service Co. of North- Rogers OK 3 472.5d 1979 x x
Oklahoma eastern 4 472.5d 1980
x x
Western Farmers 445.5d
Electric Coop. (OK) Hugo Choctaw OK 1 1982 x x
en
a
(continued)
-------
In Plant
Unit Capaci ty, servi~e locationc FGD used
Company name Plant County State number MWe date E W Yes No
.
Portland General 560.5d
Electric Co. 80ardman Horrow OR 1 1980 x x
Otter Tail Power
Co. 8i9 Stone Grant SO 1 456.0 1976 x x
Central Power and Coleto 600.4d
light Co. Creek Go li ad TX 1 1980 x x
Houston lighting Parish, Fort 8end TX 5 636.1d 1977 x x
and Power W.A. 6 636.1d 1979
x x
7 551.1d 1980 x x
8 614.6d 1982 x x
lower Colorado River Sam K. Fayette TX 1 600.0d 1979 x x
Authority Seymour, Jr. 2 600.0d 1980 x x
San Antonio Public 447.0d
Service 80ard Deely, J. T. 8exar TX 2 1978 x x
Southwestern Electric Welsh Ii tus TX 1 512. 3d 1977 x x
Power Co. 2 512.3d 1980
x x
3 558.0d 1982 x x
Southwestern Public Tolk 568.0d
Service Co. Station lamb TX 1 1982 x x
Southwestern Public
Service Co. Celanese Hutchinson TX 2 37.0 1979 x x
Southwestern Public Harrington Potter TX 1 360. Old 1976 x x
Service Co. 2 360.0d 1978
x x
3 360.0d 1980 x x
0'1
t-'
(continued)
-------
0'\
N
In Plant
Unit Capacity. servi~e locationc FGD used
Company name Plant County State number MWe date E W Yes No
Texas Power and Light 591. Od
Co. Sandow Mi 1 an TX 4 1981 x x
Texas Utilities Martin Lake Rusk TX 1 793.3 1977 x x
Co. 2 793.3 1978 x x
3 793.3 1978 x x
San Miguel Electric 448.0d
Coop. San Miguel Atascosa TX 1 1982 x x
Utah Power and light Hunter Emery UT 1 446.4d 1978 x x
Co. (Emery) 2 446.4d 1980 x x
Appalachian Power Mountaineer 1300. Od
Co. (1301) Hason WV 1 1980 x
Monongahela Power Pleasants Pleasants .WV 1 684.0d 1979 x x
Co. 2 684.0d 1980 x
x
Wisconsin. Electric Pleasant 617 . Od
Power Co. Prairie Kenosha WI 1 1980 x
Basin Electric Power Laramie Platte WY 1 570.0d 1980 x x
Coop. '. Inc. River 2 '570.0d 19B1 x x
3 570.0d 1982 e
x x
(continued)
-------
In Phnt c
Unit Capaci ty. servise location FGO used
Company name P hnt County State number HWe date E W Yes No
Pacific Power and
Ught Co. WYOOAK Campbell WY 1 331. 9 1978 x x
aListing only includes Subpart 0 units located at power plants with all Subpart 0 units with in-service date of
1975-1982 and a capacity> 23 MWe. Plant sites with both Subpart 0 and SIP units are not included.
b -
Reference: Inventory of power plants in the United States 1981 and 1982 Annual - DOE and Cost and Quality of
Fuels for Electric Utility Phnts - DOE.
cEastern locations includes units located in all States east of the Mississippi River and one State west of the
Mississippi River. E; Eastern and W ; Western.
dSubject to Subpart 0 as listed in EPA's Compliance Data System (CDS). .
eper Flue Gas Oesulfurization Information System (FGOIS):
fSubject to Subpart 0 per telephone conversation with EPA Regional Office.
m
w
-------
0'1
+:>
I
APPENDIX B
LISTING OF COAL-FIRED POWER PLANTS WITH BOTH SIP AND SUBPART D (NSPS) UNITSa,b
In Phnt
Unit Capac f ty. servfce 10catfonc FGD used
Company name P1ant County State number MWe date E W Tes No
A1abama E1ectrfc Corp., Inc. Tombfgbee Washfngton AL 1 75 1969 x x
2 235d 1978 x x
3 235d 1980 x x
.
Arfzona Pub1fc Servfce Cho11 a Navajo AZ 1 113.6 1962 x x
Company 2 288.9d 1978 x x
3 288.9d 1980 x x
4 414.0 1981 x x
Sa1t Rfver PROJ AGRI IMP PMR Navajo Coconfno AZ 1 803.0 1974 x x
DIST 2 803.0 1975 x x
3 803.0 1976 x x
C010rado-UTE E1ectrfc Assn., Uayden Routt CO 1 190.0d 1965 x x
Inc. 2 275.4 1976 x x
Pub1fc Servfce Company of Comanche Pueb10 CO 1 382.5d 1973 x x
Co 1 orado 2 396.0 1976 x x
De1marva Power and Lfght Indfan Sussex DE 1 81.6 1957 x x
Company of De hware Rfver 2 81.6 1959 x x
3 176.8d 1970 x x
4 403.0 1980 x x
F10rfda Power Corp. Crysta1 Citrus FL 1 440.5 1966 x x
Rfver 2 523.8d 1969 x x
4 793.3 1982 x x
Gafnsvf11e-A1achua Company Deerhaven Ahchua FL 1 83.0d 1972 x x
, 2 243.0 1981 x x
(contfnued)
-------
0'\
U1
In Plant c
UnH CapacHy, serv1ce locat1on FGO used
ComDanv name PI ant Countv State number "We date E W Yes No
Tampa Electric Company B19 Bend H111sborou9h Fl 1 445.5 1970 x x
2 445.5 1973 x x
3 445.5 1976 x x
Georgia Power Company Bowen Bartow GA 1 805.8 1971 x x
2 78B.8 1972 x x
3 952.0 1974 x x
4 952.0 1975 x x
Commonwealth Ed1son Company Powe'rton Tazewell Il 5 893.0 1972 x x
6 893.0 1975 x x
1111n01s Power Company Baldw1n Randolph Il 1 623.0 1970 x x
2 634.5 1973 x x
3 634.5 1975 x x
1111nois Power Company Havana Hason Il 1 46.0 1947 x x
2 46.0 1947 x x
3 46.0 1948 x x "
4 46.0 1950 x x
5 46,0d 1950 x x
6 488.5 1978 x x
Southern 1111n01s Power Coop. Har10n Will1amson Il 1 33.0 1963 x x
2 33.0 1963 x x
3 33,0d 1963 x x
.4 211.0 1978 x x
City of Spr1ngf1eld Da Ilman Sangamon Il 1 90.3, 1967 x x
2 90.3d 1972 x x
3 207.4 1978 x x
(continued)
-------
(J)
(J)
In Plant c
Unit Capacity, service location FGD used
Company name Plant County State number HWe date E W Yes No
Indianapolis Power and Light Petersburg Pike IN 1 253.4 1967 x x
Company 2 471.0d 1969 x x
3 574.4 1977 x x
Northern Indiana Public Schahfer, Jasper IN 14 521.0d 1976 x x
Service Company R.M. 15 511.0 1979 x x
Public Service Co. of Gibson Gibson IN 1 668.1 1976 x x
I nd I a na. I nc. 2 668.1 1975 x x
3 668.0 1978 x x
4 668.0d 1979 x x
5 668.0 1982 x x
Interstate Power Company Lansing All ama kee IA 1 15.0 1948 x x
2 11.5 1949 x x
3 37.5d 1957 x x
4 274.5 1977 x x
~"es. City of Electric Ames Story IA 5 7.5 1950 x x
Utilities 6 12.6 1958 x x
7 33.0d 1968 x x
8 65.0 1982 x x
Iowa Power and Light Company Council Pottawattamle IA 1 49.0 1954 x x
Bluffs 2 81. 6d 1958 x x
3 650.0 1978 x . x
Iowa Public Service Company Neal, Woodbury IA 1 147.0 1964 x x
George 2 349.0 1972 x x
3 550.0d 1975 x x
4 640.0 1979 x x
(conti nued)
-------
m
-...,J
In Plant c
UnH CapacHy. service location fGO used
Company name Plant County State number HWe date E W Yes No
Kansas City Power and light La Cygne Linn KS 1 8n.od 1973 x x
Company 2 686.0 1977 . x x
East Kentucky Power Coop. Spurlock. Hason KY 1 305.5d 1977 x x
H.l. 2 508.0 1981 x x
Kentucky Utilities Company Ghent Ca rro 11 KY 1 556.9d 1974 x x
2 556.4d 1977 x x
3 556.4 1981 x x
Louisville Gas and Electric Hill Creek Jefferson KY 1 355.5 1972 x x
Company 2 355.5 1974 x x
3 462.6e 1978 x x
4 543.6e 1982 x x
Consumers Power Company Campbe 11 . Ottawa HI 1 267.0 1962 x x
J.H. 2 385.0d 1967 x x
3 718.5 1980 x x
Upper Penisula Generating Presque Ha rquette HI 1 25.0 1955 x x
Company Isle 2 37.5 1962 x x
3 57.8 1964 x x
4 57.8 1966 x x
5 90.0 1974 x x
6 90.0d 1975 x x
7 90.0d 1978 x x
8 90.0d 1978 x x
9 90.0 1979 x x
(continued)
-------
0\
(»
-
In Phnt c
Unit Capacity, service 10cation FGD used
Company name Phnt Count v State number MWe date E W Yes No
Minnesota Power and Light Boswe11, Itasca MN 1 75.0 1958 x I(
Company Chy 2 75.0 1960 x x
3 364.5d 1973 x x
4 558.0 1980 x x
Associated E1ectric Coop., New Madrid New Madrid MO 1 600.0 1972 x x
Inc. 2 600.0 1977 x x
Thomas H111 RandoH MO 1 171. 7 1966 x x
2 272.0d 1969 x x
3 630.0 1982 x x
Fremont Dept. of Uti1ities Fremont 12 Dodge NE 6 16.0 1957 x x
7 22.0d 1963 x x
8 91.0 1977 x x
Nevada Power Company Gardner, C1ark NV 1 114.0 1965 x x
Reid 2 114.0d 1968 x x
3 114.0 1976 x x
Pub1ic Service Company of San Juan San Juan NM 1 347.4d 1976 x x
New Mexico 2 328.7d 1973 x x.
3 517 .Od 1979 x x
4 534.0 1982 x x
Car01ina Power and light Roxboro Person NC 1 410.9 1966 x x
Company 2 657.0 1968 x x
3 745.2d 1973 x x
4 745.0 1976 x x
Duke Power Company Be1ews Stokes NC 1 1080.0 1974 x x
Creek 2 1080.0 1975 x x
(continued)
-------
m
1.0
In Plant c
UnH CapacHy, service location fGO used
ComDanv name Plant CountY State number MWe date E W Yes No
Basin Electric Power Coop., le lands 01 ds Mercer NO 1 216.0 1966 II II
Inc. 2 440.0 1975 II II
Minnkota Power Coop., Inc. Young, Oliver NO 1 257. 0d 1970 II II
Hilton R. 2 416.2 1977 II II
Buckeye Power, Inc. Cardinal Jefferson OH I 590.0 1967 II II
2 590.0 1968 II II
3 615.0 1977 II II
Cincinnati Gas and Electric Hi ami fort lIamllton 011 5 100.0 1949 II II
Company 6 163.2 1960 II II
7 557.1d 1975 II II
8 557.0 1978 II II
Columbus and Southern Ohio Conesv Ole Coshocton OH 1 148.0 19,59 II II
Electric Company 2 136.0 1957 II II
3 162.0 1962 II II
4 842,0d 1973 II II
5 444.0d 1976 II II
6 444.0 1978 II II
Painsville Municipal light Painsvil1e lake OH 1 3.0 1941 II x
Plant (0Ii) 2 3.0 1946 II II
3 8.0 1953 II II
4 8.0 1953 x II
5 17 .Od 1965 x x
6 25.0 1976 II x
AEP: Ohio Power Company Gavin Gen. Ga 111a OH 1 1300. 0 1974 x II
J.M. 2 1300.0 1975 x x
(continued)
-------
-...,J
a
In Plant c
' Unft Capacfty, service location FGO used
Comoanv name Plant Count v State number MWe date E W Yes No
GPU: Pennsylvania Electric Homer CHy Indiana PA 1 660.0 1969 x x
Company 2 660.0d 1971 x x
3 692.0 1917 x x
Pennsylvania Power Company Mansfield, Deaver. PA 1 934.9 1976 x x
Druce 2 934.9d 1917 x x
3 871.4 1980 x x
South Carolina Public Wi nyah : Georgetown SC 1 315.0d 1975 x x
Service Authority 2 315.0d 1917 x x
3 315.0d 1981 x x
4 315.0 1981 x x
Texas Utilities Company Monticello 11 tus TX 1 593.4 1974 x x
2 593.4e 1975 x x
3 793.3 1978 x. x
Utah Power and light Company Huntington Emery UT 1 446.4e 1977 x x
Ca nyon 2 446.4 1974 x x
Oairyland Power Coop. Alma (J.P. Duffalo WI 1 17.3 1947 x x
Madgett) 2 17.3 1947 x x
3 17.3 1951 x x
4 54.4 1957 x x
5 81.6d 1960 x x
6 387.0 1979 x x
Wisconsin Power and light Co lumbia Columbia WI 1 556.0d 1975 x x
Company 2 556.0 1978 x x
Wisconsin Public Service Corp. Weston Marathon WI 1 60.0 1954 x x
2 75.0d 1960 x x
3 321. 6 1981 x x
(continued)
.1
-------
In Plant
UnH CapacHy, service locationc fGO used
ComDanv name Plant County State number MWe date E W Yes No
Pacific Power and light Bridger, Sweetwater WY 1 508.6 1974 x x
Company Jim 2 508.6 1975 x x
3 508.6d 1976 x x
4 508.6 1979 x x
alisting includes plants with both Subpart O. (units with in-service date of 1975 to 1982 and a capacity >23 MWe) and
SIP units. Units marked with footnote "d" or "e" are subject to Subpart 0 and units that are unmarked are subject to
SIP requirements.
bReferences: "Inventory of Power P1ant~ in the United States 1981 and 1982 Annual" and "Cost and Quality of fuels for.
Electric Utility Plants."
cEastern locations include units located in all states east of and one state west of the Mississippi River.
dSubject to Subpart 0 as listed in EPA's compliance data system (COS).
eSubject to Subpart D per telephone conversation wit~ EPA Regional Office.
........
~
-------
APPENDIX C
MONTHL Y S02 EMISSIONS FOR SUBPART D UNITS
.......
N
- --
S02 emissions (lb/l06 Btu)
No. 'Ill 2 82 3 8l 4 82 5 8l 6 82
of Type Percent I Percent Percent Percent Pe rcen t Pe rcen t
ComDanv name Plant units State coal su I fur Em15s10ns sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emissions
Alabama Power Co. 141 ller 1 AL BIT 0.62 0.951 0.65 1. 005 0.64 0.980 0.60 0.919 0.61 0.904 0.66 1. 001 .
Arkansas Power & Wh ite 2 AR BIT 0.44 0.995 0.47 1.042 0.48 1.070 0.44 0.983 0.44 0.969 0.42 0.928
LIght Co. Bluff
Southwes tern Flint 1 AR BIT 0.33 0.746 0.33 0.758 0.33 0.753 0.33 0.748 0.33 0.759 0.33 0.800
Elec. Power Co. Creek
Colorado Springs. Ray O. 1 CO BIT 0.41 0.725 0.37 0.668 0.36 0.656 0.37. 0.678 0.39 Q.711 0.41 0.750
City of Nixon
Georgia Power Co. Scherer 1 GA BIT 0.67 0.971 0.70 1. 028 0.65 0.946 0.63 0.911 0.64 0.924 0.65 0.934
Iowa Southern Ottumwa 1 fA SUB 0.30 0.680 0.30 0.681 0.30 0.672 0.30 0.673 0.30 0.675 0.30 0.676
Utilities Co.
Kansas City (KANS) Nearman 1 KS 81T 0.35 0.825 0.40 0.933 0.39 0.89~ 0.30 0.701 0.31 0.723
DO of Public
Utilities
--
-------
.........
w
S02 emissions Ilb/106 Btul
No. 1 82 8 82 9 82 10 82 11 82 12, 82
of Type Percent Percent Percent Percent Pe rcen t Percent
ComDanv name Plant units State coal sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emi ss ions
Alabama Power Co. Hi lIer 1 AL BIT 0.63. 0.941 0.62 0.931 0.63 0.914 0.60 0.895 0.59 0.892 0.61 0;921
Arkansas Power & White 2 AR 81T 0.46 1.014 0.46 1.012 0.42 0.931 0.46 1. 008 0.46 1. 008 0.45 0.999
light Co. Bluff
Southwes tern Flint 1 AR 81T 0.35 0.798 0.35 0.795 0.35 0.799 0.35 0.621' 0.35 0.787 0.35 0.790
Elec. Power Co. Creek
Colorado Springs, Ray D. 1 CO BIT 0.39 0.704 0.42 0.752 0.36 0.656 0.37 0.665 0.37 Q.658 0.38 0.679
CI ty of Nixon
Georgia Power Co. Scherer 1 GA BIT 0.66 0.956 0.67 0.967 0.65 0.948 0.63 0.887 0.63 0.864 0.64 0.896
Iowa Southern Ottumwa 1 IA SUB 0.30 0.667 0.30 0.671 0.30 0.676 0.30 0.660 0.30 0.674 0.30 0.676
Kansas City (KANS) Nearman 1 KS BIT 0.37 0.862 0.31 0.718 0.39 0.907 0.36 0.837 0.36 0.828 0.31 0.695
BD of Public
Utilities
--
-------
'"
.po
~ -
S02 emissions [lb/l06 Btu)
No. 1/83 2 83 3 83 4 8] 83 6 83
of Type ercent Il'ercent Percent Percent Percent Percent
Comllanv name Plant un Its State coal suHur Emlss Ions suI fur Emissions suHur Emissions su Hur Emissions suHur Eml ss Ions suHur Emissions
Alabama Power Co. M111er 1 Al BIT 0.59 0.894 0.57 0.867 0.57 0.867 0.61 0.928 0.62 0.933 0.58 0.880
Arkansas Power & Wh Ite 2 AR BIT 0.35 0.759 0.38 0.815 0:46 0.992 0.44 0.940 0.43 0.917 0.43 0.920
light Co. Bl uff
Southwes tern F1 Int 1 AR BIT 0.35 0.796 0.35 0.799 0.35 0.799 0.35 0.801 0.]5 0.797 0.37 0.841
Elec. Power Co. Creek
Colorado Springs, Ray O. 1 CO BIT 0.36 0.647 0.35 .0.629 0.38 0.676 0.39 0.695 0.40 0.717 0.]6 0.650
CI ty of Nixon
Georgia Power Co. Scherer 1 GA BIT 0.64 0.904 0.67 0.950 0.69 0.990 0.72 1. 052 0.70 1.019 0.67 0.974
Iowa Southern Ottunwa 1 lA SUB 0.32 0.718 0.31 0.697 0.30 0.675 0.30 0.673 0.32 0.719 0.31 0.698
Utilities Co.
Kansas City (KANS) Nea nnan 1 KS BIT 0.32 0.744 0.38 0.882 . 0.35 0.812 0.33 0.759 0.39 0.900' 0.41 0.940
BO of Public
Utilities
-
-------
"'-J
U1
S02 emissions [lb/l06 Btu)
No. 1 'B2 --,- If:> 3 82 4" 82 5, '82 6 82
of Type Percent Percent Percent Percent Percent I Percent
Comoanv name Plant nits State coal suI fur Emls s Ions sulfur Emlss Ions sulfur Emissions sulfur Emissions sulfur Emissions sulfur Emissions
Cajun Elect. Big Cajun 2 LA SUB 0.44 1. 036 0.40 0.938
Power Coop., 2
Inc.
Mississippi Daniel, 2 MS BIT 0.59 0.962 0.60 0.96B 0.58 0.932 0.58 0.933 0.56 0.891 0.58 0.933
Power Co. Victor J.,
Jr.
Kansas City Power latan 1 HO BIT 0.36 0.780 0.37 0.794 0.36 0.779 0.35 0.751 0.34 0.725
and LI9ht Co.
Hastings Utilities Has t Ings 1 NE BIT 0.50 1. 188 0.48 1.143 0.44 1.052 0.44 1.052
Ene rgy
Ctr.
Nebraska Public Gen tl eman 2 NE BIT 0.36 0.783 0.37 0.796 0.35 0.756 0.36 0.784 0.35 0.750 0.35 0.745
Power 01 strict
Omaha Pub I i c Nebraska 1 NE BIT 0.35 0.819 0.32 0.752 0.37 0.B60 0.36 0.841 0.27 0.629 0.27 0.628
Power Olstrlct City
Sierra Pacific North 1 NV BIT 0.30 0.510 0.38 0.635 0.37 0.623 0.38 0.635 0.39 0.654 0.39 0.663
Power Co. Valmey
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.......
0'1
- - -- - -- -- -
S02 emissions Ilb/l06 Btu)
No. 1 82 8 82 9 82 10 82 11 82 12 82
of Type Percent Il'ercent Il'ercent Percent ercent Percent
Company name Plant units State coal sulfur Emissions sulfur [missions sulfur Emissions sulfur Emissions sulfur Emissions suI fur Emissions
Cajun Elect. Big Cajun 2 LA SUB 0.34 0.801 0.42 0.992 0.39 0.918 0.43 1.010 0.39 0.918 0.41 0.963
Power Coop.. 2
Inc.
~ltsslsslppi Daniel. 2 HS BIT 0.57 0.907 0.57 0.916 0.55 0.B74 0.56 0.904 0.56 0.902 0.56 0.900
Power Co. Victor J..
Jr.
Kansas City Power latan 1 HO BIT 0.35 0.748 0.35 0.744 0.36 0.773 0.36 0.581 0.33 0.720 0.34 0.754
and Light Co.
lIastings Utilities lIastings 1 NE BIT 0.43 1.028 0.45 1. 076 0.39 0.932 0.38 0.907 0.39 0.928
Energy
Ctr.
,
Nebras ka Pub 11 c Gentleman 2 NE BIT 0.35 0.744 0.35 0.751 0.36 0.774 0.36 0.773 0.36 0.771 0.35 0.752
Power 01 s trl ct
Omaha Public Nebraska 1 NE BIT 0.36 0.838 0.35 0.807 0.36 0.833 0.37 0.860 0.36 0.834 0.38 0.882
Power District City
Sierra Pacific North 1 NV BIT 0.38 0.637 0.36 0.602 0.36 0.604 0.35 0.586 0.37 0.623 0.40 0.677
Power Co. Valmey
-
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'-J
'-J
-
S02 emissions (lb/l06 8tu)
No. 1 83 2 83 3 83 4 83 5 83 6 83
of Type Percent Percent Percent Percent Percent Percent
Company name Plant nits State coal su lfur Emissions sulfur Emissions sulfur Emlss ions sulfur Emissions sulfur Emissions sulfur Eml 55 Ions
Cajun Elect. 81g Cajun 2 LA SU8 0.40 0.942 0.43 1.014 0.44 1.032 0.41 0.975 0.43 1.008 0.43 1. 007
Power Coop., 2
Inc.
Mississippi Oanlel, 2 MS BIT 0.58 0.936 0.56 0.903 0.56 0.901 0.56 0.897 0.58 0.92B 0.60 0.962
Power Co. Victor J. .
Jr.
Kansas City Power latan 1 MO 81T 0.34 0.726 0.33 0.709 0.35 0.760 0.31 0.670 0.33 0.709 0.30 0.641
and light Co.
lIastings Utilities lIastlngs 1 NE BIT 0.38 0.905 0.38 0.904 0.38 0.904 0.37 0.881 0.36 0.857 0.40 0.952
Energy
Ctr.
Nebraska Public Gentleman 2 NE BIT 0.35 0.748 0.35 0.751 0.33 0.706 0.33 0.710 0.34 0.732 0.31 0.668
Power Oistrlct
Omaha Public Nebraska 1 NE BIT 0.34 0.789 0.41 0.952 0.33 0.767 0.32 0.737 0.36 0.826 0.37 0.852
Power Oistrict City
Sierra Paci flc North 1 NV BIT 0.39 I 0.661 0.43 0.726 0.38 0.649 0.38 0.649 0.32 0.536 0.31 0.517
Power Co. Va I mey
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(X)
-- -
502 emissions (lb/l06 Btu)
No. 1 '82 2(82 3 82 4 82 5 '82 6 82
of Type Percent Percent Percent Pe rcen t Percent Percent
Companv name Plant units State coal sulfur Emissions sulfur Emi 55 ions sulfur Emiss ions sulfur Emissions suI fur Emissions sulfur Emissions
Dayton Power & I( ill en 1 OH 81T 0.60 0.906 0.58 0.909 0.57 0.884 0.57 0.881 0.57 0.865 0.59 0.883
Light Co.. The Station
Grand RI ver Dam GRDA 1 1 01( 81T 0.34 0.797 0.27 0-.628 0.31 0.721
Authority
Oklahoma Gas & Muskogee 2 01( 81T 0.35 0.760 0.37 0.791 0.36 0.782 0.37 0.802 0.36 0.773 0.34 0.722
Electric Co.
Soone r 2 01( BIT 0.35 0.759 0.36 0.772 0.36 0.781 0.34 0.738 0.37 0.796 0.j5 0.743
Public Service North- 2 01( illT 0.42 0.977 0.44 1.022 0.45 1.041 0.43 1.001 0.45 1. 035 0.39 0.909
Co. 0 f Ok !ahoma eas tern
Wes tern Fanners . HUGO 1 01( SUB 0.44 1. 024 0.47 1.097 0.46 1. 069 0.42 0.967 0.38 0.876 0.45 1. 064
Elec. Coop (01()
Portland General Boardman 1 OR COAL 0.34 0.770 0.39 0.893 0.37 0.851 0.36 0.819 0.39 0.896 0.39 0.887
Electric Co.
Centra I Power & Coleto 1 TX BIT 0.36 0.636 0.36 0.644 0.29 0.524 0.31 0.561 0.32 0.569 0.37 0.650
Li ght Co. Creek
- - --
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.....,
I.D
.. -
S02 em1ss10ns [lb/l06 Btu)
No. 'B2 8182 9 82 10 8~ 11 '82 12 82
of Type Percent Il'ercent Percent Percent Percent . Percent
Company name Plant un its State coal sulfur Em1ss10ns sulfur Emiss 10ns sulfur Emissions sulfur Emiss10ns sulfur Emissions su lfur Emissions
Dayton Power & K 111 en 1 OH BIT 0.57 0.877 0.63 0.930 0.58 0.867 0.59 0.892 0.60 0.895 0.59 0.886
Li9ht Co.. The Stat10n
Grand RI ver Dam GRDA 1 1 OK BIT 0.39 0.907 0.33 0.764 0.38 0.883 0.40 0.927 0.36 0;830 0.35 0.813
Authority
Oklahoma Gas & Huskogee 2 OK BIT 0.33 0.701 0.36 0.775 0.35 0.750 0.36 0.770 0.35 0.750 0.35 0.753
Electric Co.
Sooner 2 OK BIT 0.36 0.768 0.36 0.772 0.36 0.776 0.37 0.792 0.34 0.730 0.36 0.771
Public Service North- 2 OK BIT 0.40 0.914 0.43 . 0.992 0.40 0.926 0.41 0.934 0.41 0.937 0.42 0.962
Co. of Ok! ahoma eas tern
Western Fanners HUGO 1 OK SUB 0.4B 1.097 0.46 1.046 0.45 1.027 0.42 0.963 0.43 0.994 0.42 0.965
Elec. Coop (OK)
Portland General 60ardman 1 OR COAL 0.32 0.733 0.36 0.677 0.35 1.076 0.39 0.885 0.33 0.758 0.36 0.823
Electric Co.
Centra 1 Power & Coleto 1 TX 6IT 0.36 0.636 0.32 0.573 0.31 0.557 0.32 0.570 0.37 0.650 0.36 0.633
Light Co. Creek
. - . - - -. - -- -- '~' -
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())
o
- - - - -
S02 emissions' Ilb/l06 BtuJ
No. 83 2 83 3 83 4 83 83 6 83
of Type ercent Percent Percent Percent I Percent Percent
Company name Plant units State coal sulfur Emlss Ions sulfur Emissions sulfur Emissions su lfur Emissions sulfur Emissions sulfur Emissions
Dayton Power & K j] I en 1 011 BIT 0.58 0.858 0.56 0.852 0.57 0.865 0.59 0..897 0.59 0.902 0.60 0.916
light Co.. The Station
Grand River Dam GRDA 1 1 OK 81T" 0.38 0.878 0.41 0.958 0.34 0.793 0.39 0.895 0.41 0~944 0.38 0.873
Authorl ty
Oklahoma Gas & Huskogee 2 OK BIT 0.35 0.748 0.34 0.725 0.33. 0.708 0.32 0.688 0.32 0.685 0.32 0.688
Electric Co.
Sooner 2 OK BIT 0.37 0.795 0.34 0.729 0.34 0.727 0.32 0.691 0.32 0.686 0.31 .0.667
Public Service North- 2 OK BIT 0.39 0.889 0.38 0.846 0.42 0.947 0.43 0.975 0.43 0.969 0.44 0.988
Co. of Oklahoma eas tern
Western Fanners HUGO 1 OK SUB 0.44 1.014 0.47 1.076 0.49 1. 116 0.47 1. 099 0.48 1. 127 0.49 1. 129
Elec. Coop (OK)
Portland General Boardman 1 OR COAL
Electric Co.
Central Power & Coleto 1 TX BIT 0.31 0.552 0.31 0.550 0.35 0.621 0.37 0.646 0.33 0.586 0.33 0.592
light Co. Creek
-- --
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00
.......
-
S02 emissions Ilb/l06 Btul
No. I 82 2 82 3 82 4 82 5 82 6 82
of Type Percent Percent Percent Percent Percent Percent
Company name Plant units State coal sulfur Emissions sulfur Emiss Ions sulfur Emissions sulfur Emissions su I fur Emissions sulfur Emissions
liouston Lighting Parish, 4 TX BIT 0.40 0.930 0.40 0.903 0.40 0.867 0.39 0.859 0.39 0.852 0.39 0.867
& Power W.A.
Lower Colorado Sam K. 2 TX BIT 0.38 0.779 0.39 '0.796 0.36 0.739 0.38 0.780 0.35 0; 725 0.37 0.774
RI ver Authority Seymour,
Jr.
San Antonio Deely, 1 TX BIT 0.32 0.720 0.31 0.699 0.32 0.729
Public Service J. T.
80
Southwestern Welsh 3 TX BIT 0.33 0.745 0.33 0.757 0.33 0.755 0.33 0.747 0.33 0.751 0.35 0.798
Elec. Power Co.
Southwes tern Harrington 3 TX BIT 0.42 0.B95 0.41 0.B69 0.41 0.B73 0.36 0.760 0.40 0.B59 0.37 0.794
Public Service
Co.
Appalachian Power Mountaln- 1 WV BIT 0.59 0.922 0.60 0;918 0.60 0.928 0.60 0.930 0.62 0.948 0.61 0.938
Co. eer (1301)
Wisconsin Elec. Pleasant 1 WI COAL 0.37 0.852 0.38 0.871 0.36 0.828 0.39 0.890 0.39 0.889 0.38 0.868
Power Co. Prairie
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(X)
N
.- -
S02 emissions [lb/l06 Btu!
No. I 8l 8 8l 9 8l 10 82 11 82 12 82
of Type Percent Percent Percent Percent Percent Pe rcen t
Companv name Plant nits State coal sulfur Emissions sul fur Emissions su 1 fur Emissions su lfur Emissions sulfur Eml ss ions sulfur Emissions
Houston Lighting Parish, 4 TX BIT 0.39 0.866 0.38 0.865 0.37 0.829 0.37 0.832 0.40 0.911 0.40 0.904
& Power W.A.
Lower Colorado Sam K. 2 TX BIT 0.37 0.759 0.37 0.760 0.37 0.769 0.38 0.788 0.35 0;731 0.39 0.823
River Authority Seymour,
Jr.
San Antonio Deely, 1 TX BIT 0.33 0.732 0.31 0.699 0.40 0.890 0.38 0.855 0.31 0.698 0.39 0.883
Public Service J. T.
BO
Sou thwes te m Welsh 3 TX BIT 0.35 0.796 0.35 0.802 0.35 0.794 0.35 0.792 0.35 0.797
Elec. Power. Co.
Southwes te rn Harrlngto~ 3 TX BIT 0.37 0.778 0.38 0.800 0.42 0.886 0.38 0.812 0.39 0.823 0.40 0.842
Public Service
Co.
Appalachian Power Mountain- 1 WV BIT 0.61 0.944 0.58 0.923 0.59 0.910 0.61 0.930 0.61 0.926 0.60 0.914
Co. eer (1301)
Wi scons In E1 ec. Pleasant 1 WI COAL 0.39 0.822 0.31 0.716 0.38 0.879 0.38 0.876 0.34 0.784 0.33 0.769
Power Co. Prairie
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OJ
W
.~
S02 emissions (lb/106 Btu)
No. 1 B3 -,- 03 3 B3 4 B3 5 83 6 83
of Type Percent pe rcen t Percent Percent Percent Percent
Comoanv name Plant units State coal sulfur Emissions sulfur Emissions su lfur Emissions sulfur Emissions sulfur Emissions su lfur Emissions
/Jous ton li9htlng Parish, 4 TX BIT 0.36 0.806 0.36 0.800 0.44 0.985 0.43 0.958 0.39 0.872 0.32 0.710
& Power W.A.
Lower Colorado Sam K. 2 TX BIT 0.38 0.794 0.36 0.751 0.37 0.771 0.38 0.802 0.38 0;801 0.39 0.824
River Authority Seymour,
Jr.
San Antonio Deely, 1 TX BIT 0.37 0.838 0.32 0.719 0.31 0.700 0.30 0.677 0.30 0.682 0.31 0.700
Public Service J. T.
BO
Sou thwes te rn Welsh 3 TX BIT 0.35 0.796 0.35 0.798 0.35 0.795 0.35 0.B01 0.33 0.747 0.35 0.794
[lee. Power Co.
Southwes tern /Jarrl ngtol 3 TX BIT 0.40 0.844 0.40 0.851 0.40 0.840 0.40 0.848 0.34 0.724 0.31. 0.652
Public Service
Co.
Appalachian Power Mountain- 1 WV BIT 0.60 0.908 0.60 0.905 0.60 0.916 0.58 0.884 0.61 0.931 0.64 0.969
Co. eer (1301)
Wisconsin Elec. Pleasant 1 WI COAL 0.32 0.742 0.35 0.818 0.37 0.866 0.33 0.767 0.37 0.853 0.34 0.767
Power Co. Prairie
- - ~
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co
~
- -" - --.- ".
S02 emissions [lb/l06 BtuJ
No. 7 82 B 82- 9 82 10 8? 11 '82 12 82
of Type Percent I'ercent Percent Percent i Percent Pe rcen t
Company name Plant nits State coal sulfur Emlss ions sulfur Emls"s ions sulfur Emissions sulfur Emissions su I fu r Emissions sulfur Emi ss Ions
Central Louisiana Rodemacher 1 LA SUB 0.44 0.968 0.47 1.026 0.39 0.871 0.44 0.891 0.41 0.903 0.38 0.845
Elec. Co.. Inc.
Gulf States Nelson. 1 LA sua 0.49 1. 084 0.47 1.035 0.40 0.888 0.40 0.885 0.40 0;0880 0.40 0.925
Utl1ttles Co. R. S.
Grand Island PI a tte 1 NE SUB 0.31 0.736 0.40 0.948 0.38 0.898 0.42 0.987 0.45 1.067
Water & light
Oept.
Southwes tern Tolk 1 TX BIT 0.36 0.775 0.36 0.765 0.38 0.812 0.37 0.803 0.37 0.816
Public Service
Co.
Public Service Pawnee 1 CO BIT 0.34 0.774 0.36 0.812 0.29 0.657 0.33 0.746 0.33 0.747 0.35 0.791
Co. of Colorado
n '. -
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00
U1
-
S02 emissions Ilb/l06 Btul
No. 82 82 '3 82 4 82 5 82 6 82
of Type Percent Percent Percent Percent Percent Pe rcen t
Companv name Plant units State coal suHur Emissions suHur Emissions su Hur Emissions suHur Emissions sulfur Emissions suHur Emissions
Central Louisiana Rodemacher 1 LA SUB 0.48 1. 069 0.48 1.061 0.44 0.976 0.44 0.981 0.48 1. 062 0.46 1.018
Elec. Co., Inc.
GuH States Nelson, 1 LA SU8 0.40 0.890 0.47 1. 041 0.45 0.995 0.40 0.894 0.60 1. 315 0.55 1.203
Utl1ltles Co. R. S.
Grand I s I and Platte 1 NE SUB
Water & light
Dept.
Sou thwes te rn Tolk 1 TX BIT
Public Service
Co.
Public Service Pawnee 1 CO BIT 0.36 0.812 0.38 0.865 0.33 0.752 0.37 0.833 0.33 0.752 0.37 0.836
Co. of Colorado
-- - - -
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(X)
0'\
- -.
S02 emissions [lb/l06 Btul
No. 1'83 2 83 3 83 4 83 5 83 6 83
of Type Percent Percent Percent Percent Percent Percent
COllioanv name Plant nits State coal sulfur Emissions sulfur Emissions su1fur Emissions su1fur Emis 51 ons su I fur Emissions su I fur- Emi 5 5 Ions
Central Louisiana Rodemacher 1 LA SUB 0.34 0.736 0.45 0.966 0.47 1.013 0.45 0.961 0.47 1. 002 0.45 0.961
Elec. Co.. Inc.
Gu1f States He 15on. 1 LA SUB 0.40 0.863 0.40 0.860 0.40 0.858 0.46 0.982 0.48 1.024 0.48 1. 035
Utilities Co. R. S.
Grand 151 and PI aUe 1 NE SUB 0.48 1.134 0.41 0.957 0.36 0.B52 0.41 0.970 0.40 0.939 0.44 1. 024
Wa ter & LI ght
Dept.
Sou thwes te rn Tolk 1 TX BIT 0.30 0.656 0.30 0.652 0.40 0.863 0.30 0.648 0.33 0.717
Public Service
Co.
Public Service Pawnee 1 CO BIT 0.33 0.746 0.32 0.716 0.34 0.765 0.32 0.718 0.32 0.718
Co. of Colorado
.. -
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APPENDIX D
MAP DENOTING BOUNDARY BETWEEN
EASTERN AND WESTERN UNITS
87
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(X)
(X)
~/ESTERN
EASTERN
MONT ANA
WYOMING
UTAH
COLORADO
NEW MEXICO
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