United States Industrial Environmental Research EPA-600/7-79-026
Environmental Protection Laboratory January 1979
Agency Research Triangle Park NC 27711
Typical Costs for Electric
Energy Generation and
Environmental Controls
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that, the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion'Service, Springfield, Virginia 22161.
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EPA-600/7-79-026
January 1979
Typical Costs for Electric
Energy Generation and
Environmental Controls
by
M.G. Klett
Gilbert Associates, Inc.
P.O. Box 1498
Reading, Pennsylvania 19603
Contract No. 68-02-2605
Task No. 2
Program Element No. EHE624
EPA Project Officer: Vincent W. Uhl
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
Capital and annualized cost data are presented in tabular
form for various conventional and advanced electric energy
generation systems. The data are organized into three gen-
eral categories:
1. Cost of Base Generation System (not including
fuel or environmental control)
2. Incremental Fuel Costs
3. Incremental Environmental Control Costs
Total costs can be computed for a particular configuration by
adding the appropriate incremental costs for fuel and environ-
mental control to the cost of the base generation system. Costs
assigned to environmental central include systems for the control
of sulfur, particulates, NO , and thermal discharges. Two examples
of the use of the data are included. The accuracy of each esti-
mate is indicated by a range of uncertainty. The cost figures
are intended to provide an overviev/ of environmental control
costs for various electric energy generation options. Costs
for actual installations would depend a great deal on site
specific considerations.
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CONVERSION TABLE
EPA policy is to express all measurements in Agency documents
in metric units. Implementing this practice results in
difficulty in clarity; therefore, conversion factors for non-
metric units used in this document are as follows:
British Metric
1 Btu/kWh 1.055 kJ/kWh
1 $/106 Btu 0.948 $/106 kJ
-m-
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TABLE OF CONTENTS
Page
Abstract ii
Conversion Table iii
Tables v
Acknowledgement vi
1
3
6
9
10
4.0 Data Sources 17
4.1 Base Generation Systems / 17
4.2 Fuel 18
4.3 Environmental Control Technology 18
References 20
1.0
2.0
3.0
3.1
3.2
Introduction
Methodology
Cost Tables
Example A .
Example B
- IV -
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TABLES
Number Page
1 Typical Electric Energy Generation Systems Capital 8
and Annualized Costs
2 Escalation Factors Used to Adjust all Costs to 11
Mid-1975 Price
3 Range of Investment Estimates for Base Load Fuel 12
Conversion Plants 1000 MWe - No Pollution Control
Mid-1975 Dollars
4 Range of Incremental Investment Estimates for 13
Environmental Control Technology (1000 MWe Size)
5 Base Generation Systems Annualized Cost 14
6 Environmental Control Technology Annualized Costs 15
for 1000 MWe Installations
7 Fuel Costs (Based on 10,000 Btu/kWh Heat Rate) 16
-v-
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ACKNOWLEDGMENTS
The contribution of Mr. A. W. Hawkins for his statistical
analysis of the ranges reported in Example A and B is
gratefully acknowledged. The advice and counsel of the
EPA Project Officer, Dr. Vincent Uhl, were invaluable in
the performance of this work.
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1.0 Introduction
An electric utility today has several options for electric energy
generation, each of which requires a different mix of environmental control
technology. The cost of environmental control will vary markedly, depending
upon the base generation system used and the availability of the energy source.
This report consists of data in tabular form which can be used to compare incre-
mental environmental costs for each base generation system option considered. Base
generation systems include both conventional and advanced electric energy
generation options. The cost figures are intended to provide an overview of
environmental control costs for various electric energy generation options.
The data are organized into three general categories:
1. Cost of Base Generation System (not including fuel or environmental
control)
2. Incremental Fuel Costs
3. Incremental Environmental Control Costs
Data are given for generating stations of 1000 and 500 MWe capacity. The
environmental control costs are based on meeting present New Source Perform-
ance Standards. ' With the cost organized in these three categories, total
costs can be computed for a particular configuration by adding the appropriate
incremental costs for fuel and environmental control technology to the cost
of the base generation system. Examples are provided for specific kinds of
power plant, fuel, and control technology.
-1-
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The primary sources for cost data are conceptual design studies sponsored
by EPRI, EPA, and DOE and the National Science Foundation's Energy Con-
version Alternatives Study (EGAS). Other basic data came from a number
of individual manufacturers. Specific data sources are given in
Section 4.0.
The cost of a designated system can vary widely because of many factors.
Because of differing requirements that govern feedstock conditions,
efficiencies, and throughputs, comparison between specific systems is
not easy. Differences in the stage of development of the various
electric energy generation options make it difficult to precisely pre-
dict cost, operability and reliability. Consistency is the key, yet
this is difficult to achieve when estimates come from different sources
(as in this study). The procedure described in Section 2.0 attempted
to put all costs on a consistent basis. The accuracy, of course,
depends on the quality of the cost data and on the judgment used in
adjusting the cost data to a consistent basis. The accuracy of each
estimate was considered separately, and indicated by the range of
uncertainty assigned to each.
-2-
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2.0 Methodology
Published data on the cost of base generating systems, fuels, and environ-
mental control technology were compiled from conceptual design studies
performed under the auspices of EPRI, EPA, DOE and NSF. Other data came
from individual vendors. Specific information sources are given in
Section 4.0. The procedure used to make cost comparisons consistent for
conceptual designs and costs from different sources is similar to one used
(2)
in a recent EPRI studyv ' which identified sulfur removal costs for various
coal conversion options. The procedure used in this study was:
1. For each cost study of an individual power generating systems, total
plant capital investment (not including escalation, interest during
construction (IDC), working capital, or contingency) was divided
into power plant investment and environmental control investment.
Several cost studies were available for most of the different power
generation systems.
Environmental control investment included costs for the control of
sulfur, particulates, NO , and thermal discharges. For pressurized
A
fluidized-bed combustion, hot gas cleanup was considered a power
plant cost, since clean gas for the turbines is a power plant
requirement.
2. Power plant capital costs (not including environmental costs) were
adjusted to a single base year (mid 1975 was used since all but a
-3-
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few of the original studies use this as a basis) and a base
size (1000 MWe). Escalation factors were used to adjust all costs
to a mid-1975 price. Scaling to the base size was done by using an
exponential factor of 0.85 which was used by both EPRP ' and
(4)
Bechtel in recent studies.
3. A single base power plant investment was selected as representative.
In each case, this figure consists of total construction cost of the
power plant; it excludes environmental control investment. As noted
under "1", above, the power plant investment does not contain con-
tingency, escalation, working capital, and interest during construc-
tion (IDC).
4. A contingency was then added with the amount obtained by the degree
of definition; for each technology, a range or band of uncertainty
was assigned; wider bands were attributed to less developed options.
Interest during construction, together with startup costs, was
applied to each plant investment at a rate of 30 percent. (For the
liquid fuel options, a rate of 22 percent was used because of a sig-
nificantly shorter construction period.) These are the factors
(2)
used in the EPRI studyv , they are equivalent to construction times
of approximately 6 and 4 years at an interest rate of 10 percent.
The total cost gives the probab'le range of capital requirements for
each plant without environment controls.
5. Annualized costs were calculated for base load operation (0.65
capacity factor). This consisted of a fixed capital charge and an
operations and maintenance (O&M) charge (fuel charges are broken
-4-
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out separately under incremental costs). A fixed charge rate of
18 percent per year was applied to the range of capital costs
calculated in "4". This covers interest on debt, return on equity,
depreciation, insurance, and property and income taxes, both federal
and local. Current utility experience in the U.S. shows this fixed
(2)
charge rate varies from 15 to 22 percent. Both the EPRIV ' and
(5)
ECASV ' studies also used a fixed charge rate of 18 percent.
Typical O&M charges were added to capital charges to obtain
annualized costs.
6. Scaling of costs to a 500 MWe size was done using an exponential
factor of 0.85 (i.e. (500/1000)0'85 - 0.555).
7. Environmental control technology investment and annualized costs
were developed from representative base costs in the same manner
as power plant costs.
8. Fuel costs for physically cleaned, chemically cleaned, solvent
refined, and liquefied coals include plant charges for processing.
Fuel costs are based on a heat rate of 10,000 Btu/kWh. Actual
fuel costs will depend on the efficiency or heat rate of the power
generation option and are adjusted by the ratio of the actual heat
rate of the power generation option to 10,000. A typical heat
rate was selected for each base generation system.
-5-
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3.0 Cost Tables
Table 1 presents the results for the base general"!on systems, fuels and
environmental controls considered. Using this table, costs can be computed
for a particular configuration by adding the appropriate incremental costs
for fuel and enviornmental control technology to the cost of the base
generation system. Two examples are provided for specific kinds of power
plant, fuel, and control technology.
Fuel costs are based on a heat rate of 10,000 Btu/kWh (an efficiency of
3412.2/10,000 = .34122). Typical heat rates for each base generation
option are listed in Table 1. As shown in the examples, fuel costs can be
adjusted to the specific base generation heat rate.
The data used to compile Table 1 are in Tables 2 through 7. Table 2 shows
the escalation factors used to adjust all costs to mid-1975 dollars.
Table 3 and 4 show the base cost, contingency, uncertainty, interest during
construction, and startup factors used to obtain typical base generation
and environmental control technology investments. Investment costs are
for new plant construction; no attempt was made to determine typical
costs for retrofit applications.
Published cost data, after adjustments, formed the basis for selection of
the base investment figures. In general, base investment spreads in
studies of conventional technologies were narrow; a median figure, con-
sistent with other base systems, was selected. Spreads in the advanced
technologies were greater and required engineering judgment in selecting
the base investment. This was also reflected in the use of larger
-6-
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contingency and uncertainty factors. As these technologies come closer
to commercialization, plant investment estimates will become firmer.
Table 5 and 6 show base generation and environmental control technology
annualized costs. Annualized costs were calculated for base load opera-
tion (0.65 capacity factor) and consist of a fixed capital charge of 18
percent and a typical O&M charge. The sum of these two is the total
annualized cost in Table 1. Typical utility capital charges are:
Cost of capital (capital structure assumed to
be 50 percent debt and 50 percent equity)
Bonds at 8 percent interest 4.00
Equity at 12 percent return to stockholder 6.00
Taxes
Federal (50 percent of gross return or same as
return on equity) 6.00
State (national average for states in
relation to Federal rates) 2.00
Total rate applied to depreciation base 18.00
Table 7 shows the fuel costs used in this study.
-7-
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TABLE 1
TYPICAL ELECTRIC ENERGY GENERATION SYSTEMS CAPITAL AND ANNUALIZED COSTS
Basis: Mid 1975 Dollars
iase Generation System (Typical Heat Rate,
Btu/kWh)
Conventional Fossil Fired Boilers
High Sulfur Eastern Coal (9800)
Low Sulfur Western Coal (9200)
Liquid Fuel (9200)
Conventional Nuclear
Light Water Reactor (10400)
Combined Cycle
Liquid Fuel (7500)
Low Btu Gasification (8400)
Medium Btu Gasification (8200)
Fluidized Bed Combustion (FBC)
Atmospheric FBC (9500)
Pressurized FBC (8800)
Incremental Costs
Fuel*
High Sulfur Eastern Coal
Low Sulfur Western Coal
Physically Cleaned Coal
Chemically Cleaned Coal
Solvent Refined Coal
Liquefied Coal
Liquid Fuel
Uranium
Environmental Control Technology
Sulfur Control
Flue Gas Desulfurization
Limestone
Wellman Lord
Magnesia
Dual Alkali
Fuel Gas Cleanup
Low Btu Gas
Medium Btu Gas
Fluidized Bed Combustion
Limestone or Dolomite
Particulate Control
ESP-Cold
ESP-Hot
Fabric Filter
Wet Scrubber
NOX Control
Combustion Modifications
Selective Catalytic Reduction
Water Injection for Turbines
Thermal Discharge Control
Evaporative Cooling Tower
Fossil
Nuclear
1000 MWe
Capital
($/k:we)
385-470
405-495
240-295
605-740
215-265
525-710
530-720
420-565
505-760
61-82
70-95
72-108
75-112
113-152
99-135
16-27
22-27
25-34
36-48
42-52
10-12
22-37
3-5
14-17
18-22
Annual ized
(Mills/kWh)
13-16
14-17
8-10
20-25
8-10
18-24
18-25
15-19
18-26
8-12
11-15
10-14
14-22
25-30
30-35
15-25
5-6
3.1-3.8
3.2-4.0
3.3-4.4
4.1-5.3
4.6-5.8
3.8-4.9
1.1-1.5
0.9-1.0
1.1-1.4
1.5-1.9
1.7-2.0
0.4-0.5
1.2-1.7
0.6-0.7
0.7-0.8
1.1-1.2
500 MWe
Capital
($/kWe)
430-520
450-550
265-330
670-820
240-295
585-790
590-800
465-625
560-845
68-91
78-105
80-120
83-124
125-169
110-156
18-30
24-30
28-38
40-53
57-58
11-13
24-41
3-6
16-19
20-24
Annualized
(Mills/kWh)
15-18
15-19
9-11
23-27
9-11
21-27
21-27
16-21
20-29
8-12
11-15
10-14
14-22
25-30
30-35
15-25
5-6
3.5-4.2
3.5-4.4
3.6-4.9
. 4.5-5.5
5.1-6.5
4.2-5.5
1.2-1.6
0.9-1.1
1.2-1.5
1.7-2.1
1.9-2.3
0.4-0.5
1.3-1.9
0.6-0.7
0.8-0.9
1.2-1.3
* Based on a heat rate of 10,000 Btu/kWh. See example for adjustment to Base Generation System heat rate.
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3.1 Example A
For a 1000 MW coal fired boiler burning high-sulfur Eastern coal having
a heat rate of 9,800 Btu/kWh, how much would the capital investment and
annualized costs increase as a result of environmental control for
particulates, NO , SO and thermal discharges?
X A
Capital Annualized
System ($/kUh) (mills/kWh)
1000 MW Conventional Coal Fired Boiler 385-470 13-16
Fuel
High Sulfur Eastern Coal, y^ x (8-12) - 7.8-11.8
Subtotal (Base + Fuel) 385-470 21.8-26.8*
Environmental Controls
Limestone FGD Process - SOY 61-82 3.1-3.8
A
Cold ESP - Particulates 22-27 0.9-1.0
Combustion Modifications - NO 10-12 0.4-0.5
A
Fossil Cooling Tower - Thermal 14-17 0.7-0.8
Subtotal (Environmental Controls) 112-133* 5.2-6.0*
TOTAL 534-566* 27.4-32.4*
Percentage Increase in Costs Due to
Environmental Control
o Capital Investment, E"vi™™ental x 100 25-33*
o Annualized Cost, Environmental 1riri ori „,.
Base + Fuel x 10° 20~26
* Ranges of calculated values obtained as sums and quotients were calculated
by use of standard deviations: see, e.g. Ferencz^/).
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3.2 Example B
For a 1000 MW pressurized fluidized-bed combustor burning high-sulfur
Eastern coal having a heat rate of 8,800 Btu/kWh, how much would the
capital investment and annualized costs increase as a result of environ-
mental controls?
Capital Annualized
System ($/kVI (mllls/kMh)
1000 MW Pressurized FBC 505-760 18-26
Fuel
High Sulfur Eastern Coal, IQ'QQ x (8-12) - 7.0-10.6
Sub-total (Base + Fuel) 505-760 26.4-35.2*
Environmental Controls
In Situ - SO 16-27 1.1-1.5
X
Particulates+
NO , not applicable
X
Fossil Cooling Tower - Thermal 14-17 0.7-0.8
Sub-total (Environmental Controls) 31-43* 1.8-2.3*
TOTAL 535-804* 28.5-37.2*
Percentage Increase in Costs Due to
Environmental Control
o Capital Investment, Envi^nta1 x 10Q 4.3_7.4*
o Annualized Cost, x 10° 5.5-7.8*
+Due to turbine requirements, hot gas particulate control assigned to
power system costs.
*Ranges of calculated values obtained as sums and quotients were calculated
by use of standard deviations: see, e.g. Ferencz(^7)>
-10-
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TABLE 2
ESCALATION FACTORS USED TO ADJUST
ALL COSTS TO MID-1975 PRICE
De-escalation
(a)
Escalation^)
Year
Factor
July 1978 0.8396
July 1977 0.8900
July 1976 0.9434
Year
July 1975
January 1975
July 1974
January 1974
July 1973
January 1973
July 1972
January 1972
July 1971
January 1971
July 1970
January 1970
July 1969
January 1969
Factor
1.000
1.052
1.176
1.353
1.433
1.500
1.554
1.610
1.669
1.751
1 . 838
1.929
2.025
2.126
(a)Based on 6% escalation rate per year ^ '.
on escalation rate of 5% for material and 8% for labor
compounded per year
-11-
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TABLE 3
Range of Investment Estimates For Base Load Fuel Conversion Plants 1000 MWe -
No Pollution Control - Mid-1975 Dollars
Base
Investment Contingency
Plant $/kW %
Conventional
Eastern Coal
Western Coal
Liquid Fuel
Nuclear
Combined Cycle
Liquid Fuel
Low Btu Gas
Medium Btu Gas
300
315
200
450
170
395
400
+ 10
+ 10
+ 10
+ 15
+ 15
+ 20
+ 20
Uncertainty
± 10
* 10
- 10
± 10
± 10
- 15
± 15
IDC* &
Startup
Factor
1.30
1.30
1.22
1.30
1.22
1.30
1.30
Total
Capital
Cost
$/kW
385-470
405-495
240-295
605-740
215-265
525-710
530-720
Atmospheric
Fluidized-Bed
315
20
± 15
1.30
420-565
Pressurized
Fluidized-Bed 405
+ 20
± 20
1.30
505-760
* Interest during construction
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TABLE 4
Range of Incremental Investment Estimates for Environmental Control Technology
(1000 MWe Size)
Sulfur Control
FGD
Limestone
Wellman lord
Magnesia
Dual Alkali
Fuel Gas Cleanup
Low Btu Gas
Medium Btu Gas
Base
Investment
($/kW
50
55
58
60
85
75
Contingency Uncertainty
'
10
15
20
20
20
20
±15
J15
±20
±20
±15
±15
IDC* &
Startup
Factor
1.30
1.30
1.30
1.30
1.30
1.30
Capital
Investment
($/kW
61-82
70-95
72-108
75-112
113-152
99-135
Fluidized Bed Combustion
Limestone or Dolomite
14
20
±25
1.30
16-27
Particulate Control
ESP - Cold
ESP - Hot
Baghouse
Wet Scrubber
18
22
30
35
10
10
15
10
±10
±15
±15
±10
1.22
1.22
1.22
1.22
22-27
25-34
36-48
42-52
NOX Control
Combustion - Mod 8
Selective Catalytic Reduction+ 20
Water Injection for Turbines 3
15
20
10
±10
±25
±15
1.22
1.22
1.22
10-12
22-37
3-5
Thermal Discharge Control
Evaporative Cooling Tower
Fossil
Nuclear
11
14
10
10
±10
±10
1.30
1.30
14-17
18-22
*Interest during construction
+(SCR)
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TABLE 5
BASE GENERATION SYSTEMS ANNUALIZED COST
Plant
Conventional
High Sulfur Coal
Low Sulfur Coal
Liquid Fuel
Light Water Reactor
Capital
(mills/kHh)
12.17-14.86
12.80-15.65
7.59-9.33
19.13-23.39
O&M
(mins/kWh)
1.00
1.06
0.47
1.20
Total
Annualized
(mins/kWh)
13-16
14-17
8-10
20-25
Combined Cycle
Liquid Fuel
Low Btu Gas
Medium Btu Gas
6.80-8.38
16.60-22.44
16.75-22.76
1.64
1.83
1.74
8-10
18-24
18-25
Fluidized Bed Combustion
Atmospheric (AFBC) 13.28-17.86
.Pressurized (PFBC) 15.96-24.03
1.36
2.06
15-19
18-26
-14-
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TABLE 6
ENVIRONMENTAL CONTROL TECHNOLOGY ANNUALIZED COSTS
FOR 1000 MWe INSTALLATIONS
Sulfur Control
FGD
Limestone
Wellman Lord
Magnesia
Dual Alkali
Fuel Gas Cleanup
Low Btu Gas
Medium Btu Gas
Fluidized-Bed Combustion
Limestone or Dolomite
Capital
(mills/kNh)
1.93
2.21
2.28
2.37
3.57
3.13
2.59
3.00
3.41
3.54
4.81
4.27
O&M
(mills/kWh)
0.51 - 0.85
1.20
0.95
T.OO
1.72
1.04
0.64
0.60
Total
Annualized
(mills/kHh)
3.1
3.2
3.3
4.1
4.6
3.8
3.8
4.0
4.4
5.3
5.8
4.9
1.1 - 1.5
Particulate Control
Electrostatic Precipatator
Electrostatic Precipatator
Fabric Filter
Wet Scrubber
NO Control
A
Combustion Modifications
Selective Catalytic Reduction
Water Injection For Turbines
Hot
Cold
i
0.70
0.79
1.14
1.33
0.32
0.70
0.09
- 0.85
- 1.07
- 1.52
- 1.64
- 0.38
- 1.17
- 0.16
0.15
0.30
0.36
0.40
0.10
0.50
0.50
0.9 -
1.1 -
1.5 -
1.7 -
0.4 -
1.2 -
0.6 -
1.0
1.4
1.9
2.0
0.5
1.7
0.7
Thermal Discharge Control
Cooling Tower
Fossil
Nuclear
0.44
0.57
0.54
0.70
0.30
0.50
0.7 - 0.8
1.1 - 1.2
-15-
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TABLE 7
FUEL COSTS (BASED ON 10,000 BTU/kWh HEAT RATE)
$/106 Btu Mills/kt-Jh
High Sulfur Coal 0.80 - 1.20 8-12
Low Sulfur Coal 1.05 - 1.95 11 - 15
Physically Cleaned Coal 1.00 - 1.40 10 - 14
Chemically Cleaned Coal 1.40 - 2.20 14 - 22
Solvent Refined Coal 2.50 - 3.00 25-30
Liquefied Coal 3.00 - 3.50 30 - 35
Liquid Fuel 1.50 - 2.50 15 - 25
Uranium 0.45 - 0.55 5-6
-16-
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4.0 Data Sources
The primary sources for cost data are conceptual design studies performed
under EPRI, EPA and DOE sponsorship and EGAS conducted by NSF. Other
data came from individual manufacturers. The specific data sources are
discussed below:
4.1 Base Generation Systems
Capital investment estimates for conventional fossil fired plants were
compared from several sources. These included studies by Ebasco^ ' and
Bechtel^ for EPRI, ECAS^7' 8^, a study by TVA for EPA(9\
and a Gilbert study for DOE^ . After adjustments to a common basis
and removing environmental control costs, the base power plant costs
varied - 7 percent. Representative base costs were selected for each of the
options based on this comparison. Capital investment estimates for the
conventional nuclear option were based primarily on the Ebasco study^ '.
Combined cycle capital investment data were compared using a Gilbert study^ '
for DOE and Stone & Webster^1^ and GE^'2^ studies for EPRI. Capital
investments varied up to 40 percent between the studies depending mainly upon
the type of process chosen. The cost figures used were based primarily
upon the Gilbert study which assumed a low pressure, two-stage, entrained-
bed gasifier. The wider range in the estimates is reflected by a higher
contingency and range of uncertainty.
The source for investment estimates for fluidized bed combustion (FBC)
included the ECAS studies^7'8), a Gilbert study for DOE^13^, a TVA study
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for EPA( 9 •), and a GE study for EPRI^1^. After adjustments to a common
basis, investments for atmospheric units ranged within 10 percent and for
pressurized with 15 percent. Representative costs were selected for each
system based on a comparison of these studies.
Conventional fossil fired O&M costs were taken from a Gilbert study for
^ ' and were based on the Federal Power Commission publication "Steam
xpe
(3)
v
( 14)
Electric Plant Construction and Annual Production Expenses' . O&M costs
for a nuclear option were taken from an EPRI reportv
C\r>}
Combined cycle and AFBC O&M costs were obtained from the GE study for EPRP -'
PFBC O&M costs were obtained from the EGAS study
4.2 Fuel
For coal, petroleum and uranium, costs from published data^ ' ' and present
prices information^ ' were compiled and representative values selected.
Because of transportation costs, low sulfur coal was estimated to cost
$0.25/106 Btu more than high sulfur coaP2^.
Fuel costs for physically cleaned, chemically cleaned, solvent
refined and liquefied coals are based on high sulfur feed coal, but
also reflect charges for plant investment including capital charges plus
operating and maintenance costs. Battelle^ ' coal cleaning costs were
used. Solvent refined and liquefied coal costs were from a report
by Gilbert^13).
4.3 Environmental Control Technology
In addition to the conceptual design studies, flue gas desulfurization
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costs were obtained from studies by PEDCCr , the Federal Power Commission^ '
and Davy Power Gas^ . Representative capital and O&M costs were selected
after a comparison of these studies. The Wellman Lord FGD process is based
on sulfuric acid as the product. Fuel gas cleanup capital and O&M costs
;rol
.(7)
were based primarily on the Gilbert costs study^ '. Sulfur control costs
for fluidized-bed combustion were estimated from the EGAS studies
Particulate control cost data were obtained, in addition to the conceptual
(21)
design studies, from an Industrial Gas Cleaning Institute Study for EPAX '
(22)
and published cost models by Research-Cottrellv . Again, a comparison
of these studies was made and representative costs selected.
Data for NO control was taken from EPA published data for combustion
(23) (24)
modifications and selective catalytic reduction^ . Data for
water injection for turbines were obtained from the standard support
(25)
document .
Cost data for cooling towers were based on costs reported in the conceptual
/
design studies and a recent EPA studyv
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REFERENCES
1. "Standards of Performance for New Stationary Sources". Federal
Register 36 (247), December 23, 1971, pp. 24876-24895.
2. "Clean Coal: What Does it Cost at the Busbar". EPRI Journal,
November 1976, p. 6.
3. Rudasill, C. L., Coal and Nuclear Generation Costs. EPRI PS-455-SR,
April 1977.
4. Bechtel Power Corporation, Coal Fired Power Plant Capital Cost Estimates.
January 1977, EPRI AF-342.
5. Lewis Research Center, Evaluation of Phase 2 Conceptual Designs and
Implementation Assessment Resulting from ECAS. Cleveland, OH for NASA,
April 1977.
6. Ebasco Services, Inc., Fossil and Nuclear 1000 MH Central Station Power
Plants Investment Estimates. EPRI IPS 75-601, September 1975.
7. Corman, J. C., et al, Energy Conversion Alternative Study - ECAS-General
Electric Phase II Final Report. Schenectady, NY, RE, Corporate R&D for
U.S. ERDA, NASA CR-134949, 1977
8. Beecher, D. T., et al, Energy Conversion Alternative Study - ECAS-Westing-
house Phase II Final Report. Pittsburgh, PA, Westinghouse Electric Corp.
for U.S. ERDA. NASA-CR-134942, 1976
9. U.S. TVA, Utility Boiler Design/Cost Comparison: FBC vs FGD. Chattanooga,
TN for U.S. EPA. November, 1977. EPA-600/7-77-126
10. Patrick, R. G., et al. Assessment of Fossil Energy Technology for
Electric Power Generation. Reading, PA, Gilbert Associates, Inc. for
U.S. ERDA, Office of Program Planning and Analysis. March, 1977.
GAI Report #1940
11. Stone and Webster Engineering Corporation, Comparative Evaluation of
High and Low Temperature Gas Cleaning for Coal Gasification - Combined
Cycle Power Systems. April 1977, EPRI AF-416.
12. General Electric Co., Comparative Study and Evaluation of Advanced
Cycle Systems. EPRI AF-664, February 1978.
13. Gilbert Associates, Inc., Reading, PA, Fossil Energy Technology Source
Book: Liquids. U.S. DOE, Office of Program Planning and Analysis,
January 1978. Draft
14. U.S. Federal Power Commission, Steam Electric Plant Construction Cost
and Annual Production Expenses - 26th Annual Supplement - 1973.
Washington, DC, FPC, 1973.
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15. "1977 Generation Planbook". Power Engineering, pp. 156. 1977
16. "FERC Report: Plant by Plant Deliveries of Fossil Fuels to Utilities".
Electrical Week. April 24, 1978, p. 12
17. Hall, E. H., Physical Coal Cleaning for Utility Boiler S0? Emission
Control. Columbus, OH, Battelle Memorial Institute for UTS. EPA,
February 1978, EPA-600/7-78-034.
18. PEDCO Environmental Specialists, Inc., Particulate and SCL Emission
Control Cost Study of the Electric Utility Industry - Preliminary
Draft. Cincinnati, OH for U.S. EPA.
19. U.S. Federal Power Commission, The Status of FGD Applications in the
U.S. Washington, D.C., 1977.
20. Gaur, K. S., "Pollution Control With S02 Recovery", Pollution
Engineering, May 1978.
21. IGCI, Inc., ESP Costs for Large Coal-Fired Steam Generators, for USEPA,
February 1977.
22. Bubenck, D. V., "Economic Comparison of Selected Scenarios for ESP and
Fabric Filters", JAPCA, Vol. 28, No. 3, March 1978.
23. Shimizu, A. B., et al, NO Combustion Control Methods and Costs for
Stationary Sources. September 1975, EPA-600/2-75-046.
24. Mobley, J. D. and Stein, R. D., "Status of Flue Gas Treatment Technology
for Control of NO and Simultaneous Control of SO and NO ". Proceedings
of the Second Stationary Source Combustion Symposium. Jufy 1977, EPA-
600/7-77-073C.
25. U.S. EPA, Standard Support and Environmental Impact Statement, Volume 1:
Proposed Standards of Performance for Stationary Gas Turbines. September
1977, EPA-450/2-77-017a.
26. Hu, M. C., et al, Water Consumption and Costs for Various Steam Electric
Power Plant Cooling Systems. August 1978, EPA-600/7-78-157.
27. Ferencz, P., "Statistics Can Put More Meaning Into Your Cost Estimates",
Chemical Engineering 59: 4 (1952) 143.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-026
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Typical Costs for Electric Energy Generation and
Environmental Controls
5. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
M.G. Klett
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Gilbert Associates, Inc.
P.O. Box 1498
Reading, Pennsylvania 19603
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2605, Task 2
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 4-11/78
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL-RTP project officer \s Vincent W. Uhl, Mail Drop 63, 919/
2815.
IB. ABSTRACT Tne report gives typical costs for electric power generating plants and
their environmental controls for installations of 1000 and 500 MWe capacity, inclu-
ding the expected range of uncertainty. Total annualized costs for a particular con-
figuration can be computed by adding the appropriate incremental costs for fuel and
environmental control equipment to the cost of the base generation system. Fixed
charges are computed on the basis of 18% of the capital investment; cost data are
corrected to mid-1975. Two examples of the use of the data are included. The data
and method are intended to provide an overview. Actual installation costs may differ
widely from those found from information in this report because of site-specific
considerations.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Cost Estimates
Electric Power Generation
Capitalized Costs
Operating Costs
Pollution Control
Stationary Sources
13 B
05A, 14A
10A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
28
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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