FLUE GAS DESULFURIZATION
PROCESS COST ASSESSMENT
PEDCo ENVIRONMENTAL
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PEDCo-ENVIRONMENTAL
SUITE 13 • ATKINSON SQUARE
CINCINNATI. OHIO 45246
513 /771-4330
FLUE GAS DESULFURIZATION
PROCESS COST ASSESSMENT
Prepared by
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-01-3150
Technical Series Area 4
Task No. 2
EPA Project Officer: James Speyer
Prepared for
Office of Planning and Evaluation
U.S. ENVIRONMENTAL PROTECTION AGENCY
Washington, D.C.
May 6, 1975
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This report was furnished to the Environmental Protection
Agency by PEDCo-Environmental Specialists, Inc., Cincinnati,
Ohio, in fulfillment of Contract No. 68-01-3150, Technical
Series Area 4, Task No. 2. The contents of this report are
reproduced herein as received from the contractor. The
opinions, findings, and conclusions expressed are those of
the author and not necessarily those of the Environmental
Protection Agency.
11
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ACKNOWLEDGMENT
This report was prepared for the Office of Planning and
Evaluation of the U.S. Environmental Protection Agency. The
EPA Project Officer was Mr. James Speyer. PEDCo appreciates
the direction provided by both Mr. Speyer and Mr. James
Ferry, also of the Office of Planning and Evaluation.
PEDCo also appreciates the assistance provided by the
Edison Electric Institute's Clean Air Coordinating Com-
mittee, its consultant, the National Economic Research
Associates, and several utility representatives, partic-
ularly Mr. Edward E. Galloway of the Cincinnati Gas and
Electric Company, who reviewed early drafts of the report.
The PEDCo Project Director was Timothy W. Devitt. Mr.
Robert S. Amick was Project Manager. Technical support and
analysis were provided by Messrs. Atul Kothari, David Noe,
Thomas C. Ponder, Yatendra Shah, and Lario V. Yerino. Mr.
Chuck'Fleming was responsible for final report preparation
and assembly.
111
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TABLE OF CONTENTS
ACKNOWLEDGMENT iii
LIST OF FIGURES vii
LIST OF TABLES ix
SUMMARY xi
1.0 INTRODUCTION 1-1
2.0 COST COMPONENTS FOR FLUE GAS DESULFURIZATION 2-1
SYSTEMS
2.1 Capital Cost Components 2-2
2.1.1 Plant Equipment and Installation 2-2
for S02 Control
2.1.2 Indirect Costs 2-4
2.2 Annual Operating Costs 2-5
2.3 Replacement Capacity and Energy Penalties 2-6
3.0 COST ESTIMATES FOR FLUE GAS DESULFURIZATION 3-1
SYSTEMS
3.1 Capital Costs 3-6
3.1.1 Model Plants 3-6
3.1.2 Factors Affecting Capital Costs 3-6
3.2 Annualized Costs 3-19
3.2.1 Model Plants 3-19
4.0 NATIONWIDE FLUE GAS DESULFURIZATION COST ASSESS- 4-1
MENT
5.0 MANUFACTURER ESTIMATES OF FGD SYSTEM COSTS 5-1
6.0 UTILITY INDUSTRY SURVEY 6-1
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TABLE OF CONTENTS (continued)
Paqe
APPENDIX A SLUDGE FROM FLUE GAS DESULFURIZATION A-l
SYSTEMS - AN OVERVIEW
APPENDIX B PROCEDURE FOR CONVERTING UTILITY INVEST- B-l
MENT AND EXPENSE INTO ANNUAL REVENUE
REQUIREMENTS
APPENDIX C SAMPLE COMPUTER PRINTOUTS OF FGD COSTS C-l
APPENDIX D BASIS OF LIME - LIMESTONE PROCESS DESIGN D-l
APPENDIX E BASIS OF WELLMAN-LORD PROCESS DESIGN E-l
APPENDIX F FLUE GAS DESULFURIZATION COST ESTIMATING F-l
METHODOLOGY COST SUMMARY FOR SELECTED
U.S. POWER PLANTS
APPENDIX G DETAILS OF UTILITY INDUSTRY SURVEY COST G-l
ADJUSTMENTS
VI
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LIST OF FIGURES
Figure Page
3.1 Incremental Effect of Sulfur Content of Coal on 3-9
Model Plant Capital Cost
3.2 Incremental Effect of Flue Gas Volumetric Flow 3-11
Rate on Model Plant Capital Cost
3.3 Effect of Redundancy (Spare Scrubbing Train) in 3-15
FGD Systems on Capital Cost
3.4 Impact of Cost Escalation 3-20
3.5 Effect of Boiler Remaining Life and Correspond- 3-23
ing Capacity Factor on Model Plant Annual Cost
3.6 Effect of Sulfur Content of Coal on Model Plant 3-25
Annual Cost
3.7 Incremental Effect of Flue Gas Volumetric Flow 3-26
Rate on Model Plant Operating Cost
4.1 National Coal Association Regions 4-5
D.I Typical Process Flow Sheet of Wet Limestone - D-3
S03 Scrubbing System
E.I Typical Process Flow Sheet of Wellman-Lord SO,, E-3
Scrubbing System
VI1
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LIST OF TABLES
Table Page
1 Summary of Model Plant FGD System Costs
2 Typical Capital Cost Variations for Site xiii
3 Range of Costs Reported for Flue Gas Desul- xvi
furization Systems
2.1 Major FGD System Equipment Summary 2-3
2.2 Comparison of Replacement Power Costs 2-10
3.1 Summary of Model Plant FGD Costs 3-2
3.2 Summary of Characteristics and Assumptions for 3-4
Model Plants
3.3 Model Plants Capital Costs 3-7
3.4 Typical Capital Cost Variations for Site 3-8
Specific Conditions
3.5 Typical Capital Cost Variation with Various 3-13
Retrofit Requirements
3.6 Costs of Typical Sludge Disposal Options 3-17
3.7 Typical Relationship Between Boiler Capacity 3-18
Factor and Remaining Life
3.8 Model Plants Annualized Costs 3-21
4.1 Regional and National FGD Cost Summary 4-3
4.2 Regional and National FGD Cost Summary of Plants 4-4
Requiring Greater Than 25% S02 Control
4.3 Regional Composition by State 4-6
5.1 Summary of Manufacturer Estimates of FGD 5-1
System Costs
IX
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LIST OF TABLES (continued)
Table Page
5.2 Manufacturer's Capital Costs Summary for Lime- 5-3
stone System
5.3 Manufacturer's Annualized Cost Summary for 5-4
Limestone System
6.1 Utility Industry Results 6-5
A.I Comparative Annual Land and Solid Waste Impact A-4
of 1,000 MW Electric Energy System
A.2 Sludge Production at Current FGD Installations A-6
A.3 Sludge Generation - 1,000 MW Plant A-7
A.4 Comparison of Trace Elements Analyses Between A-12
Raw Sludge and Leachate from that Sludge
After Chemical Conditioning by Fixation
A.6 Impact of Various Subset Sludge Disposal Options A-14
on the Annualized Cost of Sludge Disposal
A.5 Sludge Disposal Costs for the Model Plants A-15
F.I Assumed Values for Regional Variables that F-3
Affect FGD System Cost
F.2 Flue Gas Desulfurization Summary for Selected F-5
U.S. Power Plants
x
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SUMMARY
This study was sponsored by the U.S. Environmental
Protection Agency in preparation for Congressional hearings
on possible revisions to the Clean Air Act. The study
represents part of a joint effort being conducted by EPA and
the Edison Electric Institute's Clean Air Coordinating
Committee (EEI/CACC) to determine the cost of flue gas
desulfurization (FGD) systems.
The capital investment and annualized costs of FGD
systems were estimated using a model plant approach. The
costs associated with particulate emission control were
deliberately excluded to determine the incremental costs of
SO9 emission control only. The results of the model plant
analysis are presented in Table 1. These costs include the
cost of the FGD system and its ancillaries, and sludge
disposal, but do not include replacement power costs (ca-
pacity penalty) or cost escalation through project com-
pletion.
Site-specific factors which can influence the cost of
FGD systems include the amount of S02 to be removed, flue
gas volume treated, type of application (new vs retrofit),
degree of system redundancy, particulate emission control
XI
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Table 1. SUMMARY OF MODEL PLANT PGD SYSTEM COSTS
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New , ^ .','*.. S
Retrofit, 0.6% S
New, 0,6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital costs
Limestone
$ MM
20.2
16.5
18.6
14.7
35.1
29.2
32.3
26.4
69.5
56.8
64.4
52.0
?/KW
81
66
74
59
70
58
65
53
69
57
64
52
Wcllman-Lord
$ MM
30.5
23.8
23.5
17.5
56.9
45.0
44.0
33.4
104.2
85.7
79.9
64.3
$/KW
122
95
94
70
114
90
88
67
104
86
80
64
Annualized costs
Limestone
$ MM/yr
6.8
5.5
5.9
4.6
11.2
9.7
9.6
8.0
22.0
18.6
18.9
15.7
mills/KWH
5.18
4.17
4.47
3.46
4.27
3.68
3.63
3.05
4.18
3.54
3.59
2.97
Wellir.an-Lord
$ MM/yr
8.9
6.7
7.0
5.1
15.3
12.3
12.1
9.4
28.1
23.3
22.0
18.0
mills/KWH
6.76
5.06
5.33
3.86
5.83
4.66
4.59
3.56
5.34
4.44
4.18
3.41
X
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requirements and sludge disposal method. The impact on
total system capital costs due to each of these factors is
summarized in Table 2.
Table 2. TYPICAL CAPITAL COST VARIATIONS
FOR SITE SPECIFIC CONDITIONS
Factor
SO2 removal requirements
Flue gas flow rate
Installation status3 (new vs.
retrofit)
Conditions of terrain and sub-
surfacea
FGD system redundancy
Particulate control requirements
Sludge disposal requirements3
(nonregenerative processes)
Typical
cost
15
10
10
3
10
25
10
total capital
impact, %
- 20
- 30
- 40
- 15
- 40
- 35
- 30
Variations in capital cost are from a model plant
500 MW/existing/3.5% S boiler.
Variations in capital cost for 250 to 1000 MW model
plants.
As part of the EEI/CACC effort, a survey was conducted
of the cost of FGD systems currently installed, under con-
struction or planned. As anticipated, a wide range of
costs, $33 to $197/KW, was obtained because of the varia-
bility in site and system design characteristics. Lime and
limestone based system costs ranged from $34 to $116/KW.
These costs were adjusted to reflect the incremental cost
Xlll
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for S0~ control only (e.g. excluded the costs for particu-
late control, added indirect costs, expressed all costs in
January 1975 dollars etc.). The adjusted costs ranged from
$50 to $87/KW and averaged $70/KW for lime and limestone
based systems and are essentially in agreement with the
costs computed via the model plant approach.
The costs for FGD systems were also estimated by two
member companies of the Industrial Gas Cleaning Institute
(IGCI). These cost estimates range from $37 to $74/KW for
new plants and $42 to $78/KW for retrofit applications. The
IGCI costs for new plants are generally within 10 percent of
those computed using the model approach whereas IGCI's
estimate of retrofit plant cost are an average of 20 percent
below the model plant costs.
Approximately 130 plants were identified by EPA's
Office of Planning and Evaluation on the basis that their
coal shipments in the first 6 months of 1974 had an average
sulfur content greater than that implied by the projected
S09 emission regulation. The cost for FGD systems for each
£
of these plants was roughly estimated based upon available
plant data for the sole purpose of computing regional and
national cost estimates for flue gas desulfurization systems.
It's emphasized that because of the multitude of site
specific factors which could not be incorporated in such a
time and budget limited evaluation, these costs can not be
considered accurate for any specific plant. The FGD system
XIV
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costs for individual plants ranged from about $50/KW to over
$250/KW- The average regional costs varied between $56 and
$68/KW treated, on a megawatt averaged basis. The national
average was $64/KW. These costs are somewhat lower than the
average model plant costs primarily because of the limited
amount of SO,, control required.
Conclusions
There is considerable variation in the costs reported
for flue gas desulfurization systems. This variation is due
primarily to the differing site conditions and design bases,
and the inclusion or exclusion of cost components, as
illustrated previously by Table 2. Table 3 summarizes the
range of values presented in this report for the model
plants, and for the manufacturer and utility industry
surveys. The model plant costs provide the most realistic
estimates of the incremental cost of S0_ control by flue gas
desulfurization for "typical" plants. Costs for individual
FGD installations will vary above and below these norms.
xv
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H-
Table 3. RANGE OF COSTS REPORTED FOR FLUE GAS DESULFURIZATION SYSTEMS
($/KW)
FGD
Process
Regenerable
Nonregenerable
( 1 ime/1 imes tone )
Manufacturers
New
33-74
Retrofit
42-78
PEDCo
New
64-95
52-66
Retrofit
80-122
64-81
Utility industry
As reported
New
107a
33-129
Retrofit
33-197
40-115
Adjusted
New
95a
50-81
Retrofit
115-205
59-87
Only one plant reported in this category.
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1.0 INTRODUCTION
In preparing for Congressional hearings on possible
amendments to the Clean Air Act, the U.S. Environmental
Protection Agency (EPA) is preparing estimates of the total
costs of air pollution controls for the electric utility
industry. One area of substantial controversy is the cost
of flue gas desulfurization (FGD) systems for sulfur dioxide
emission control. To develop realistic estimates of the
capital and annualized costs of FGD systems, EPA initiated
two data gathering activities. First, EPA asked the elec-
tric utility industry, through the Edison Electric Institute
Clean Air Coordinating Committee (EEI/CACC), to conduct a
survey to determine the costs incurred by those utilities
that are installing or planning to install FGD systems.
Second, EPA contracted with PEDCo-Environmental Specialists,
Inc. to prepare estimates of the costs of FGD systems for
representative or model power plants.
Section 2 of this report presents a brief discussion of
capital and annualized cost components in flue gas desul-
furization systems. Section 3 presents an analysis of FGD
system costs for typical boiler sizes and identifies varia-
tions in these costs due to site-specific conditions.
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Section 4 presents, on a regional basis, estimates of the
total capital and annualized costs for power plants iden-
tified by the Office of Planning and Evaluation as poten-
tially requiring S02 emission control. Section 5 presents
cost estimates prepared for the Industrial Gas Cleaning
Institute by member companies that manufacture FGD systems.
Results of the FGD cost survey conducted by the EEI/
CACC are presented in Section 6. Key plant and FGD process
factors are noted. Costs for individual facilities are
analyzed and compared with the cost estimates presented in
Section 3.
1-2
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2.0 COST COMPONENTS FOR FLUE GAS DESULFURIZATION SYSTEMS
Total costs of flue gas desulfurization systems include
both capital and annualized costs. Capital costs are direct
and indirect. Direct costs are those of plant equipment,
instrumentation, piping, electrical and structural mate-
rials, site work, insulation, painting, and pilings, and the
accompanying costs of installation or application. Indirect
costs include interest assessed during construction; con-
tractors fees and expenses; engineering, freight, and off-
site expenses; taxes, allowances, and contingencies.
Annualized operating costs are both fixed and variable.
Variable costs include those of utilities, labor, mainte-
nance, and in some cases overhead. Fixed costs include
those of depreciation, interim replacement, insurance,
taxes, and capital charges. The various components of
capital and annualized cost are discussed in greater detail
in Sections 2.1 and 2.2.
The major items included as representing the cost of
flue gas desulfurization must be clearly identified. Four
major cost elements are typically included, each of which
includes both a direct and indirect cost component:
2-1
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0 S02 emission control
0 Particulate emission control
0 Sludge disposal or by-product regeneration/re-
covery system
0 Replacement power
Our analysis excludes consideration of particulate
emission control, since the purpose of the study is to
identify the incremental costs of S02 emission control.
Consideration of sludge disposal and by-product regenera-
*
tion/recovery are included. Cost of replacement power or
"capacity penalty" may be treated in several ways that
impinge upon both capital and annualized costs. Because of
the interest in this cost element, it is discussed sepa-
rately in Section 2.3.
2.1 CAPITAL COST COMPONENTS
The major capital cost components of an FGD system
consist of plant equipment, installation, and site develop-
ment; and indirect costs.
2.1.1 Plant Equipment and Installation for SO,, Control
Table 2.1 lists the major process equipment required
for regenerative and nonregenerative FGD systems. Instal-
lation of this equipment requires foundations; steel work
for support; buildings; piping and ducting for effluents,
slurries, sludge, steam, overflows, acid, drainage, and
make-up water; control panels; instrumentation; insulation
of ducting, buildings, piping, and other equipment; paint-
* Appendix A presents a brief discussion of methods of sludge
disposal.
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Table 2.1 MAJOR FGD SYSTEM EQUIPMENT SUMMARY
Equipment
Description
to
I
u>
Material handling-raw
materials
Feed preparation-raw
materials
SO_ scrubbing
Flue gas reheat
Gas handling
Sludge disposal
Utilities
Cake processing
Regeneration
Purge treatment
Equipment for the handling and transfer of raw materials includes unloading
facilities, conveyors, storage areas and silos, vibrators, atmospheric emission
control associated with these facilities, and related accessories.
Equipment for the preparation of raw materials to produce a scrubbing slurry
consists of feed weighers, crushers, grinders, classifiers, ball mills, mixing
tanks, pumps, agitators, and related accessories.
Equipment of a nonregenerative system for scrubbing the S02~laden flue gas in-
cludes scrubbers, demisters, effluent hold tanks, agitators, circulating pumps,
pond water return pumps, and related accessories. In addition, scrubbing equip-
ment for a regenerative system includes converter, catalyst storage, conveyors,
and related accessories.
To increase plume buoyancy and minimize condensation the scrubber exhaust gas is
heated from about 125° to 175°F. Equipment required includes an economizer,
air/steam or fluid heaters, condensate tanks, pumps, soot blower, and related
accessories.
Equipment to handle the boiler flue gas includes booster fans, ductwork, flue
gas bypass system, turning vanes, supports, platforms, and related accessories.
Nonregenerative FGD systems require a clarifier, pumps, vacuum filtration, sludge
fixation equipment, and related accessories.
Equipment to supply power to the FGD equipment consists of switch-gear, breakers,
transformers, and related accessories.
Equipment for processing the by-product of regenerative FGD systems includes a
rotary kiln, fluid bed dryer, conveyor, storage silo (MgSO3, etc.), vibrator,
combustion equipment and oil storage tanks, waste heat boiler, hammer mills etc.
Or, evaporators, crystallizers, strippers, tanks, agitators, pumps, compressors,
etc. Or H2S04 absorber and cooling, mist eliminator, pumps, acid coolers, tanks,
etc.
Equipment for regeneration of the scrubber medium of a regenerative system consists
of: coke material handling system, storage, weight feeder, conveyor, rotary kiln,
fluid bed calciner, dust collector, storage silo (MgO, etc.), vibrator, combustion
equipment and oil storage tanks, waste heat boiler, hammer mill, etc. Or, evapo-
rators, crystallizers, strippers, tanks, agitators, pumps, compressors, etc. Or
H2SO. absorber and cooling, mist eliminator, pumps, acid coolers, tanks, etc.
Equipment for the removal of sodium sulfate includes refrigeration, pumps, tanks,
crystallizer, centrifuge, dryer, dust collector, conveyors, storage, and related
equipment.
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ing; and, in some instances, piling. Site development
includes right-of-way for sludge disposal? site clearing and
grading; construction of access roads and walkways; estab-
lishment of rail, barge, or truck facilities, and parking
facilities; landscaping; and fencing.
2.1.2 Indirect Costs
Indirect costs include the following elements:
Land required for the FGD process, including sludge
waste or regeneration facility, storage, right-of-ways.
Interest accrued during construction on borrowed
capital.
Contractor's fee and expenses, including costs for
field labor payroll; supervision field office; per-
sonnel; construction offices; temporary roadways;
railroad trackage; maintenance and weld shops; parking
lot; communications; temporary piping and electrical
and sanitary facilities; safety security of all types—
fire, material, medical, etc; construction tools and
rental requipment; unloading and storage of materials;
travel expenses; permits; licenses; taxes; insurance;
overhead; legal liabilities; field testing of equip-
ment; start-up; labor relations.
Engineering Costs, including administrative, process,
project, and general; design and related functions for
specifications; bid analysis; special studies; cost
analysis; accounting; reports; consultant fees; pur-
chasing; procurement; travel expenses; living expenses;
expediting; inspection; safety; communications; mod-
eling; pilot plant studies; royalty payments during
construction; training of plant personnel; field engi-
neering; safety engineering; and consultant services.
Legal expenses, including those for securing permits,
right-of-way sections, etc.
Freight, including delivery costs on FGD process and
related equipment shipped F.O.B.
Off-site expenditures, including those for power house
modifications; interruption to power generation; and
service facilities added to the existing plant facil-
ities.
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Taxes, including sales, franchise, property, and
excise taxes.
Insurance, covering liability for equipment shipped and
at site; fire, other casualty, personal injury, and
death; damage to property embezzlement; delay; and
noncompliance.
Shakedown and contingency costs, including those of
malfunctions; alterations to design equipment; premium
time for repairs; start-up utilities; materials for
process; price changes due to inflation; and wage scale
increases.
Spare parts stock to permit 100 percent process avail-
ability, including pumps, valves, controls, special
piping and fittings, instruments, spray nozzles, and
similar items.
2.2 ANNUAL OPERATING COSTS
Annual operating costs of a flue gas desulfurization
system are comprised of:
Raw materials, including those required by the FGD
process for sulfur dioxide control, system loss, and
sludge fixation.
Utilities, including water for slurries, cooling and
cleaning; electricity for pumps, fans, valves, lighting
controls, conveyors, and mixers; fuel for reheating of
flue gases; and steam for processing.
Operating labor, including the supervisory and skilled
and unskilled labor required to operate, monitor and
control the FGD process.
Maintenance and repairs, consisting of both manpower
and materials to keep the unit operating efficiently.
The function of maintenance is both preventive and
corrective to keep outages to a minimum.
Overhead; a business expense that is not charged
directly to a, particular part of a, process, but is
allocated to it. Overhead costs include administra-
tive, safety, engineering, legal, and medical services,
payroll; employee benefits; recreation; and public
relations.
Fixed charges, which continue for the estimated life of
the process, include costs of the following:
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0 Depreciation - the charge for losses in physical
assets due to deterioration (wear and tear,
erosion and corrosion) and other factors, such as
technical changes making the physical assets
obsolete.
0 Interim replacement - costs expended during the
year for temporary or provisional replacement of
equipment that has failed or malfunctioned.
0 Insurance - costs of protection from loss by a
specified contingency, peril, or unforeseen event.
Required coverage could include losses due to
fire, personal injury or death, property damage,
embezzlement, explosion, lightning, or other
natural phenomena.
0 Taxes, including franchise, excise, and property
taxes leveed by a city, county, state, or Federal
government.
0 Capital costs due to interest on borrowed funds.
Credits, which are negative charges for marketable by-
products primarily from regenerative systems and
occasionally from nonregenerative systems.
Appendix B presents a procedure for translating utility
investment and expense into annual revenue requirements. It
is based upon the practices followed by regulatory author-
ities in the United States and on statute law with respect
to income tax and the deductability of various items of
expense in calculating the amount of such taxes.*
2.3 REPLACEMENT CAPACITY AND ENERGY PENALTIES
There is both an energy and replacement capacity penalty
associated with flue gas desulfurization systems. Replace-
ment capacity is the additional power-generating capacity
required to compensate for the power used by the flue gas
desulfurization system. The energy penalty is the increased
* Prepared under subcontract to PEDCo by Foster Associates.
2-6
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number of BTU's required to produce a kilowatt-hour of
electricity.
Approximately 1.5 to 4 percent of a plant's gross
energy input is required to run a flue gas desulfurization
system; an additional 1 to 2 percent may be required for
particulate emission control using venturi scrubbers.
Alternatively, less than 0.5 percent would be required if an
electrostatic precipitator were used in place of the venturi
scrubber. It should be noted that there is an apparent
trend towards the use of electrostatic precipitators because
of the FGD process chemistry complications created by par-
ticulate scrubbers.
The power requirement for an FGD system is approxi-
mately equivalent to the power required to run the boiler
feed pumps and fans in the power plant. Thus to generate a
net of 1000 MW, a plant must have a gross rating of approxi-
mately 1080 MW (allowing 40 MW to run the plant and 40 MW to
run the FGD system).
The energy consumed by the FGD system is about equally
split between energy for stack gas reheat and electricity to
run the process equipment (of which about half is to over-
come the system pressure drop and the remainder is for
operation of pumps, ball mills, and the like). The amount
of energy consumed for stack gas reheat varies with the
amount of reheat required and also somewhat with the type of
reheat system used. Some types of reheat systems will not
2-7
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cause the plant to be derated in terms of KWH of electricity
produced (i.e., there will be only an energy penalty, not a
capacity penalty). For example, if the plant power pro-
duction is turbine-limited (as opposed to boiler-limited),
the excess steam produced by the boiler can be used to
reheat the stack gases. Similarly, if a direct-fired re-
heater is used, plant capacity will not be derated although
the energy consumption per KWH generated will increase in
the same manner as if the unit were derated. Furthermore,
many plants may operate without flue gas reheat or combine
scrubbed and unscrubbed flue gases to attain desired reheat
temperatures. It is not known how many plants are turbine
limited or how many will be able to use bypassed flue gas
for reheat. It is unlikely that a significant number of
plants will be able to use direct reheat since either fuel
oil or natural gas, both premium fuels, would be required.
For regenerative processes, additional energy, which
would usually not result in a generating capacity derating,
is required. For example, the Wellman-Lord process requires
approximately 8 pounds of steam for every pound of S02
recovered and, if elemental sulfur is produced as the by-
product, requires between 15 million and 80 million SCFH of
natural gas, depending upon the sulfur content of the coal
and efficiency of the sulfur recovery plant. The total
energy requirement for the regeneration facility would be
approximately 3 percent of the total heat input to the
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boiler. For the Mag-Ox process, approximately 3 percent of
the heat input to the boiler would be required to run the
calciner and crystal dryer in addition to the 1.5 to 4 per-
cent required to run the FGD system and for reheat. Energy
requirements for the Cat-Ox process would depend upon
whether the catalytic conversion section is installed before
or after the air preheater. If it is installed after the
air preheater, approximately 3 percent of the total station
heat input may be required to reheat the flue gases to the
temperature required for catalytic conversion. Thus the
capacity replacement penalty for a regenerable process would
also be between 1.5 and 4%, but the energy penalty would be
between approximately 3 and 5%.
Among the alternative methods for determining capacity
replacement costs are the following:
(1) Capacity replaced by conventional fossil-fuel-
fired plants at plant costs of approximately
$350/KW (1975 dollars).
(2) Capacity replaced by conventional fossil-fuel-
fired plants but at the incremental cost for
expanding a 1000-MW station in a power system to a
1500-MW station to provide for lost capacity at
several stations.
(3) Capacity replaced by peaking turbines. Existing
units would operate at higher capacity factors to
compensate for the derating, and peaking turbines
would make up for the lost capacity at peak demand
periods. Although the peaking units would entail
a much higher operating cost, they would operate
for only short periods of time. The primary
advantage is their much lower capital cost of
approximately $135/KW.
2-9
-------
Computed replacement power costs for each of these
three alternatives are presented in Table 2.2.
Table 2.2 COMPARISON OF REPLACEMENT POWER COSTS3
Replacement capacity method
Capital
cost, $/KW
Annualized
cost, mills/KWH
Conventional coal-fired
plant at $350/KW
Conventional coal-fired
plant at incremental
cost of $300/KW
Peaking turbines at
$135/KW and operating
costs of 21 mills/KWH
7.00-14.00
6.00-12.00
2.70- 5.40
0.31-0.62
0.28-0.59
0.29-0.65
Lower figures are based upon 2% electric power derating
of station capacity whereas the higher numbers are based
upon a 4% derating.
Based upon a 20% capacity factor for peaking turbine
operation and the same net KWH output from the sum of
the turbine and derated boiler outputs as the boiler
before derating due to FGD system installation.
2-10
-------
3.0 COST ESTIMATES FOR FLUE GAS DESULFURIZATION SYSTEMS
The capital and annualized costs of flue gas desul-
furization systems can vary significantly depending upon
design philosophy and site-specific factors. Factors having
a major cost impact are plant size (capacity), remaining
life, and capacity factor; FGD process and design; sulfur
content and heating values of the coal; maximum allowable
S02 emission rate; status of FGD installation (new plant or
retrofit); particulate control requirements; and replacement
power requirements.
To present unencumbered cost estimates and illustrate
the impact of site and process factors on total installed
and annualized costs of FGD systems, model plants have been
defined and cost estimates have been prepared for each. A
summary of the results is presented in Table 3.1. These
costs are in January 1975 dollars and do not include escal-
ation through project completion. In Section 5 these esti-
mates are compared with those prepared by manufacturers of
control systems and in Section 6, with the costs reported by
utilities that are either installing or planning to install
FGD systems.
3-1
-------
Table 3.1 SUMMARY OF MODEL PLANT FGD COSTS
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0,6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital costs
Limestone
$ MM
20.2
16.5
18.6
14.7
35.1
29.2
32.3
26.4
69.5
56.8
64.4
52.0
$/KW
81
66
74
59
70
58
65
53
69
57
64
52
Wcllman-Lord
$ -MM
30.5
23.8
23.5
17.5
56.9
45.0
44.0
33.4
104.2
85.7
79.9
64.3
$/KW
122
95
94
70
114
90
88
67
104
86
80
64
Annualized costs
Limestone
$ MM/yr
6.8
5.5
5.9
4.6
11.2
9.7
9.6
8.0
22.0
18.6
18.9
15.7
mills/KWH
5.18
4.17
4.47
3.46
4.27
3.68
3.63
3.05
4.18
3.54
3.59
2.97
Wellman-Lord
$ MM/yr
8.9
6.7
7.0
5.1
15.3
12.3
12.1
9.4
28.1
23.3
22.0
18.0
mills/KWH
6.76
5.06
5.33
3.86
5.83
4.66
4.59
3.56
5.34
4.44
4.18
3.41
OJ
I
NJ
-------
The 12 model plants analyzed for FGD costs were se-
lected to incorporate four varying cost factors: plant size
(capacity), installation status, FGD system type, and degree
of S0? control required. Boiler capacities of 250 MW, 500
MW, and 1000 MW were' selected to cover a range representa-
tive of U.S. power plant boilers. Both new and existing FGD
systems applications were considered for each boiler size.
Wellman-Lord (sodium solution scrubbing) and limestone
scrubbing FGD systems were analyzed for each size plant to
determine costs for both regenerative and nonregenerative
processes. Each plant size was also analyzed for two S0_
control requirements: high-sulfur coal (3.5%) with an S02
limitation of 1.2 lb/10 BTU (Federal New Source Performance
Standard), and low-sulfur coal (0.6%) with an SO2 limitation
of 0.15 lb/106 BTU.
Other variables such as remaining plant life and plant
capacity factor were selected to be representative of each
model plant. Operating costs for such components as raw
materials and utilities, which vary with geographical
location, were selected to be representative of a midwest
location. Table 3.2 identifies the characteristics and
major assumptions for the model plants.
Printouts for the model plant cost estimates are
presented in Appendix C. Appendices D and E present de-
scriptive design information, including process flow sheets,
equipment lists, standard scrubber module sizes, etc. for
the limestone and Wellman-Lord systems, respectively.
3r3
-------
Table 3.2 SUMMARY OF CHARACTERISTICS AND ASSUMPTIONS FOR MODEL PLANTS
Model plant parameters
Characteristics and assumptions
00
I
Plant capacities, megawatts
Plant status
Coal characteristics
S0~ control requirement
Location
Boiler data
Capacity factor
Heat rates, flue gas flow
rates and remaining life
250, 500, and 1000 (single boilers)
New and existing (retrofit)
Low sulfur coal: 0.6%, 9000 BTU/lb
High sulfur coal: 3.5%, 12,000 BTU/lb
Low sulfur coal: 0.15 lb/10g BTU
High sulfur coal: 1.2 lb/10 BTU (Federal New Source
Performance Standard)
Midwest Location-East North Central Region
Assumed 0.6 for all 12 plants
Capacity,
MW
250 new
250 existing
500 new
500 existing
1000 new
1000 existing
Heat rate,
BTU/KWH
9,200
9,500
9,200
9,200
8,700
9,000
Flue gas
flow rate,
ACFM/MW
3,175
3,275
3,080
3,140
2,980
3,080
Remaining
boiler
life, yrs.
35
15
35
20
35
25
Assumed 310°F for all plants
Flue gas temperature
Detailed Cost Estimated for Advanced Effluent Desulfurization Processes, prepared for
Control Systems Laboratory, Office of Research and Development, U.S. Environmental
Protection Agency, under Interagency Agreement EPA IAG-134(d) Part A, by G. C.
McGlanery, et.al, Tennessee Valley Authority, pp. 66,60. May 1974.
-------
Table 3.2 (continued). SUMMARY OF CHARACTERISTICS AND ASSUMPTIONS FOR MODEL PLANTS
Model plant parameters
u>
en
Operating cost factors
Raw materials
Limestone cost
Soda ash cost (Wellman-Lord)
Sulfuric acid credit
(Wellman-Lord)
Salt cake credit (Wellman-
Lord)
Electricity cost
Taxes
Capital cost
Sludge disposal
FGD system life
Retrofit characteristics
Characteristics and assumptions
Based on East North Central Regional averages
$6.00/ton delivered
$55.00/ton
$20.00/ton
$40.00/ton
15 mills/KWH
4%
9%
Assumed on-site disposal of stabilized (fixed) sludge.
Assumed 20 years for depreciation purposes.
Longer duct runs, tight space constraints, increased
construction labor costs.
-------
3.1 CAPITAL COSTS
3.1.1 Model Plants
Capital costs for the 12 model plants are shown in
Table 3.3. Costs for the limestone system assume on-site
sludge disposal. Comparison of costs reveals that costs for
the Wellman-Lord system costs are 15 to 50 percent higher
than those for limestone. Costs per kilowatt for the four
different plants within each size category diminish for both
new and existing plants by about 50 percent as size in-
creases from 250 to 500 MW; it levels off from 500 to 1000
MW for new plants and existing plants, respectively. The
decrease in kilowatt cost is due primarily to such factors
as economy of scale. The higher cost of retrofit instal-
lations in each of the three size groups is due to the extra
cost of adapting an FGD system to the fixed conditions of an
existing plant.
3.1.2 Factors Affecting Capital Costs
The capital costs presented in Table 3.3 can be sub-
stantially modified by varying S02 removal requirements and
flue gas rates, difficulty of retrofit, conditions of ter-
rain and subsurface, system redundancy, particulate control
requirements, remaining plant life, boiler life, and escala-
tion or inflation. The impact of these factors on capital
costs is discussed in this section. Table 3.4 presents a
summary of these results.
3-6
-------
Table 3.3 MODEL PLANTS CAPITAL COSTS
U)
I
-j
Model plant
chn t fie.* t.ci i l.iiLicj:!
2^0 Marjawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Limestone
Scrubbing
5/KW
40
30
38
29
35
28
34
27
36
29
34
28
Sludge ^
disposal
S/KW
6
8
4
5
5
5
3
3
4
4
2
2
Indirect
costsc
5/KW
35
28
32
25
30
25
28
23
30
24
28
22
Total
?/KW
81
66
74
59
70
58
65
53
70
57
64
52
$ MM
20.2
16.5
18.6
14.7
35.1
29.2
32.3
26.4
69.5
56.8
64.4
52.0
Wellman-Lord
Scrubbing
v/KW
64
50
51
38
61
48
48
37
56
46
44
35
ny-
Product
Recovery
C-/KW
8
8
4
4
6
6
3
3
5
4
2
2
Indirect
costsc
?/KW
49
37
40
29
47
36
37
27
43
35
34
27
Total
$/KW
122
95
94
70
114
90
88
67
104
86
80
64
$ MM
30.5
23.8
23.5
17.5
56.9
45.0
44.0
33.4
104.2
85.7
79.9
64.3
a Includes limestone preparation system (conveyors, storage silo, ball mills, pumps, motors, and storage tank) and scrubbing
system (absorbers, fans and motors, pumps and motors, tanks, reheaters, soot blowers, ducting, and valves).
Sludge disposal costs do not include associated indirect charges.
c Includes interest during construction, field labor and expenses, contractor's fees and expenses, engineering, freight,
offsite, spares, taxes, contingency, and allowance for shakedown.
Includes soda ash preparation system (storage silo, vibrating feeder, storage tank, agitators, and pumps and motors) and
scrubbing system (absorbers, fans and motors, pumps and motors, reheaters, soot blowers, ducting, and valves) purge treat-
ment (refrigeration unit, heat exchanger, tanks, dryer, elevator, pumps and motors, centrifuge, crystallizer, storage silo
and feeder) and regeneration system (pumps and motors, evaporators and reboilers, heat exchangers, tanks, stripper, and
blower).
-------
Table 3.4 TYPICAL CAPITAL COST VARIATIONS
FOR SITE SPECIFIC CONDITIONS
Factor
SO-j removal requirements
Flue gas flow rate
Installation status-^- (new vs.
retrofit)
Conditions of terrain and sub-
surface
FGD system redundancy
Particulate control requirements
Sludge disposal requirements
(nonregenerative processes)
Typical
cost
15
10
10
3
10
25
10
total capital
impact, %
- 20
- 30
- 40
- 15
- 40
- 35
- 30
Variations in capital cost are from a model plant
500 MW/existing/3.5% S boiler.
Variations in capital cost for 250-1000 MW model
plants .
Removal Requirements
The quantity of S02 to be removed at an FGD installa-
tion is the difference between the actual S02 emission rate,
which varies directly with the coal's sulfur content, and
the rate allowed by the applicable requlation.
The S02 removal requirement affects the size of the
sludge facilities, including treatment and disposal, re-
quired by nonregenerative systems. The effect of S0?
removal requirements on capital cost is illustrated in
Figure 3.1, which shows the incremental kilowatt cost
3-8
-------
CO
I
VQ
•fa*)-
+40
+30
+20
+10
U-
o
o
-10
-20
CL
«t
0 -30
-40
LOCATION OF MODEL PLANT
CHARACTERISTICS
I
123456
SULFUR CONTENT OF COAL, wt.%
Figure 3.1 Incremental effect of sulfur content of coal on model plant capital
Cost (model plant characteristics; 500 MW/existing).
-------
differential for the model 500 MW/existing plant over a
range of coal sulfur contents (allowable 302 emission rate
of 1.2 Ib/MM BTU). Total capital costs vary from $58 to $70
per kilowatt and $70 to $128 per kilowatt, respectively for
the limestone and Wellman-Lord systems for this model plant.
As the figure shows, capital costs of the regenerative
Wellman-Lord system is much more sensitive to S0_ removal
requirements than is the costs of the nonregenerative lime-
stone process.
Flue Gas Flow Rate
Flue gas flow rate is expressed in terms of actual
cubic feet per minute (ACFM). This flow rate directly
affects the size of FGD equipment required for both re-
generative and nonregenerative systems. It varies pri-
marily with boiler design, including such factors as opera-
ting temperature and exit gas temperature, percent excess
air, and efficiency; coal characteristics, including ash,
sulfur, and moisture contents and heating value; and size
and age of the boiler. In general, the flow rate decreases
with increasing boiler age. The effect of flue gas flow
rate on capital cost is illustrated in Figure 3.2, which
shows the incremental kilowatt cost differential for the
model plant 500 MW/existing/3.5% S boiler over a range of
flow rates. The limestone and Wellman-Lord capital cost
differentials behave similarly, the limestone differential
increasing at only a slightly faster rate. Total capital
3-10
-------
+50
+40
+30
S +20
UJ
00
^ £,
o
+10
< °
o
-10
-20
LOCATION OF MODEL PLANT CHARACTERISTICS
I
1
2800 3000 3200 3400 3600 3800
acfm AT 310-F PER MW
4000
4200
4400
4600
Figure 3.2 Incremental effect of flue gas volumetric flow rate on model plant capital
cost (model plant characteristics: 500 MW/Existing/3„5% sulfur coal) .
-------
costs vary from $60 to $100 per kilowatt and $94 to $145 per
kilowatt, respectively for the limestone ctnd Wellman-Lord
systems for this model plant.
Installation Status (new and retrofit applications)
Higher capital costs are often required for application
of FGD systems to existing plants than for application to
similar new plants. An FGD system for a new plant can be
incorporated into the overall design of the plant, whereas a
retrofit application requires that the system be adapted to
the rigid configurations of the existing plant; the retrofit
system must be built within fixed space limitations and in a
manner that does not interfere with operation of the plant.
Configuration of equipment in the existing plant
governs the location of the FGD system. For instance, if
the boiler stack is on the roof of the boiler house, as it
is in many older plants, the FGD system may have to be
placed at ground level; this location could entail long
ducting runs from ground level to the stack or could require
a new stack. At some plants the stack is situated directly
adjacent to the boiler house or particulate control de-
vice, a placement that often necessitates locating the FGD
system at some distance, even hundreds of feet away. At
some plants, especially those located in urban areas, not
enough space is available at ground level to accommodate the
entire FGD system. In such cases either the FGD scrubber
units must be stacked, one on top of the other, or addi-
tional land must be acquired adjacent to the plant property.
3-12
-------
Other capital cost components that can be increased
because of space restrictions are construction labor and
expenses, interest charges during construction (because of
longer construction periods), contractor fees and expenses,
and allowances for shakedown. Table 3.5 presents a summary
of the capital cost impact of several retrofit conditions.
Table 3.5 TYPICAL CAPITAL COST VARIATION WITH
VARIOUS RETROFIT REQUIREMENTS
Capital cost
Retrofit requirements increase, %
Long duct runs 4-7
Tight space 1 -18
Delayed construction (1 year delay) 5 -15
New stack 6-20
Overall 1 -60
a For a model plant 500 MW/existing/3.5% S boiler.
Varies with escalation rate during period(s) of delayed
construction.
Condition of Terrain and Subsurface
The terrain of the power plant site affects the capital
cost of the FGD system as well as the cost of the entire
power plant by the sitework and structural requirements it
imposes. Hilly terrain requires considerable grading and
filling to prepare the site for construction of foundations
and possible additional structural components. Increase in
capital costs for installation of an FGD system in hilly
terrain can amount to 10 percent, including labor.
3-13
-------
Subsurface conditions can necessitate piling to provide
adequate support for the concrete foundations of the FGD
system. Additional capital costs for piling can amount to
4 percent, including labor.
Redundancy
Reliability of an FGD system can be increased by
providing spare process components that become integral
parts of the system when one of their counterparts fails.
For example, spare pumps are frequently included in the
system; this is simply good design practice, and such costs
are included in the model plant estimates. Some plants,
however, are considering spare absorber trains. For ex-
ample, an FGD system design with four absorbing trains might
incorporate a redundant fifth train.
Figure 3.3 illustrates the effect of a spare scrubbing
train on the capital costs of FGD systems by showing the
capital cost increase per kilowatt over a range of boiler
capacities (existing model plants burning coal with 3.5
percent S and allowable S02 emissions of 1.2 lb/10 BTU).*
The effect of redundancy decreases with increasing capacity,
since only one scrubber train is added throughout the
capacity range and the number of trains required for the
system increases with increasing capacity, (for example, a
redundant 300-MW system has three trains instead of two,
whereas a redundant 900-MW system has seven absorbers in-
stead of six).
* A train consists of: ducting, absorber, holding tank,
agitators, recirculation pump(s), demister, reheater,
soot blowers, ducting shut-off valves, piping, and
controls.
3-14
-------
i
M
cn
30
20
C£
O
OO
O
O
< 10
Q-
-------
Particulate Control
If additional particulate control is required, a
venturi scrubber could be incorporated into the FGD system
prior to each scrubber train. This would add about 30
percent ($21 per kilowatt for the limestone system and $34
per kilowatt for the Wellman-Lord system) to the capital
cost of a model plant 500 MW/existing/3.5% sulfur boiler.
The cost for an electrostatic precipitator for particulate
emission control would generally range between $20 and $40
per kilowatt depending upon coal properties and the degree
of control required.
Sludge Disposal Options (nonregenerative processes)
The amount of sludge generated by a given plant is a
function of the sulfur and ash contents of the coal, coal
usage, load factor, mole ratio of additive, SO~ removal
efficiency, composition of the sludge, and moisture content
of the sludge. Several methods are now used for disposal of
scrubber sludge. The most common are ponding of untreated
sludge and landfilling of treated and untreated sludge.
The capital and annualized costs of several sludge
dipsosal options for a model plant 500 MW/3.5% sulfur boiler
are presented in Table 3.6.
Remaining Life of Plant and Related Capacity Factor
Total boiler life is typically estimated to be 30 to 40
years; remaining life of a boiler is generally estimated
from the current age of the plant, unless more accurate
3-16
-------
Table 3.6 COSTS OF TYPICAL SLUDGE DISPOSAL OPTIONS
Options
Capital cost
impact,a
$/KW
Total annual!zed
cost impact^-
mills/KWH
I
H
~J
On-site ponding
Unstabilized sludge, water return
Stabilized sludge, water return
Off-site pond (7 miles from the plant)
Pumping, water return
Pumping, stabilization, water
return
Trucking from on-site settling
basin to pond, unstabilized
sludge
Trucking from on-site settling
basin, stabilization
3.55
3.80
9.80
10110
4.00
4.25
0.17
0.47
0.46
0.74
1.46
1.49
Model plant 500 MW, existing 3.5% S
-------
information is available on the boiler's retirement.
Capacity factor represents the fraction of actual annual
usage compared with potential annual usage at maximum
output. The capacity factor of a boiler decreases with age,
since the boiler's efficiency declines, maintenance and
overhaul needs increase, and newer, more economical boilers
are added to the plant. An approximate relationship between
capacity factor and remaining boiler life is shown in Table
3.7.
Table 3.7 TYPICAL RELATIONSHIP BETWEEN BOILER
CAPACITY FACTOR AND REMAINING LIFE
Remaining life, Typical capacity
years factor range
40 - 31 0.70 - 0.85
30 - 21 0.35 - 0.70
21 - 16 0.25 - 0.35
16-0 0.18 - 0.25
The capital cost of an FGD system is affected by re-
maining life of the boiler in that the remaining boiler life
determines the size of the sludge pond for a nonregenerative
FGD system.
Escalation
Installation of an FGD system from initial design
through construction and subsequent acceptance tests re-
quires approximately 3 years. Price escalation during this
3-18
-------
period directly affects the total capital cost of the
project; consequently, cost estimates must account for some
percentage of increase in costs. Since progress occurs at
different rates throughout the life of the project, so too
does the outlay of expenditures. Figure 3.4 illustrates the
effect of escalation on capital cost by showing the percent
increase of capital cost for a range of escalation rates
over a 3-year construction period. The expenditure rate
assumes 14 percent of the total installed cost expended at
the end of 14 months, 24 percent at the end of 20 months,
and 100 percent at the end of 3 years.
3.2 ANNUALIZED COSTS
3.2.1 Model Plants
Annualized costs for the 12 model plants for operating
of the Wellman-Lord and limestone FGD systems are presented
in Table 3.8. Costs for the limestone system assume on-site
sludge disposal. Comparison reveals that annual costs for
the Wellman-Lord process are 5 to 25 percent higher than
those for limestone. The higher annual costs for retrofit
application in all three size groups are due to the effects
of the corresponding higher capital costs for retrofitting.
3.2.2 Factors Affecting Operating Costs
The operating cost components directly affected by
independent factors are raw materials, utilities, operating
labor, and by-products (credits for regenerative FGD systems)
Costs of raw materials contribute 3 to 15 percent and 2 to 5
3-19
-------
50
45
40
UJ
GO
CO
in 35
30
CO
o
GO
£
0
o
LU
Q_
25
20
15
10
i i i i
i i i
3 YEARS
(START TO COMPLETION)
i i i i I i i i i
I
i i i
5 10 15
ANNUALIZED COST ESCALATION RATE, %
20
Figure 3.4 Impact of cost escalation.
3-20
-------
Table 3.8 MODEL PLANTS ANNUALIZED COSTS
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Limestone
Operating
and
Maintenance
raills/KWH
1.75
1.54
1.31
1.10
1.49
1.33
1.07
0.91
1.44
1.26
1.04
0.87
Fuel
and .
Electricity0
mills/KWH
0.30
0.29
0.29
0.28
0.29
0.28
0.27
0.27
0.28
0.27
0.27
0.26
Fixed.
costs'
mills/KWH
3.13
2.34
2.87
2.08
2.49
2.07
2.29
1.87
2.46
2.01
2.28
1.84
Total
mills/KWH
5.18
4.17
4.47
3.46
4.27
3.68
3.63
3.05
4.18
3.54
3.59
2.97
$ MM/YR
6.8
5.5
5.9
4.6
11.2
9.7
9.6
8.0
22.0
18.6
18.9
15.7
Wellman-Lord
Operating
and
Maintenance
mills/KWH
1.24
0.90
1.30
0.99
1.04
0.74
1.11
0.84
0.93
0.70
1.02
0.81
Fuel
and .
Electricity0
mills/KWH
0.81
0.79
0.40
0.39
0.75
0.74
0.36
0.35
0.72
0.70
0.33
0.32
Fixed
costs3
mills/KWH
4.71
3.37
3.63
2.48
4.04
3.18
3.12
2.37
3.69
3.04
2.83
2.28
Total
mills/KWH
6.76
5.06
5.33
3.86
5.83
4.66
4.59
3.56
5.34
4.44
4.18
3.41
$ MM/YR
8.9
6.7
7.0
5.1
15.3
12.3
12.1
9.4
28.1
23.3
22.0
18.0
I
N)
b
Includesi raw materials; watori operating labor, maintenance, ami ovorhoad.
Includes: power and steam (electricity and fuel costs). Based upon approximately a 1.2% capacity derating plus a
1.6% energy penalty.
i iloi>< ou InLlcjii j in La vim lai'iauomaiiL, LaxaB, inaujjaiice, and (Jdpitai CO BUB.
-------
percent of the total operating costs for limestone and
Wellman-Lord systems, respectively; these costs depend
primarily on the quantity of S02 to be removed. Costs of
utilities contribute 5 to 10 percent and 7 to 15 percent of
the annual operating costs for limestone and Wellman-Lord
systems, respectively; these depend primarily on the cost of
electricity, amount of S02 to be removed, and the process
water and horsepower requirement. The horsepower require-
ment is determined primarily by the size of the boiler (ACFM
to be treated). Operating labor contributes 1 to 5 percent
of the total operating costs and depends primarily on the
size of the boiler.
Other operating costs - maintenance, overhead, and
fixed costs - are basically dependent on the fixed invest-
ment of the FGD system and the costs for operating labor and
raw materials. Depreciation, a fixed cost, also varies with
remaining life of the boiler. Figure 3.5 illustrates the
effect of remaining boiler life on operating costs of lime-
stone and Wellman-Lord FGD systems. This analysis differs
somewhat from the model plant cost in which the capacity
factor was assumed constant at 60%.
The following factors also affect operating costs:
S00 Removal Requirements
^
The amount of SO- to be removed affects annual oper-
ating costs appreciably, since it is the major factor that
affects the cost of raw materials and utilities. In addi-
3-22
-------
27
26
25
24
23
22
21
20
.19
18
i 17
(SI
16
E
in
8 14
! 13
J1
In
10
9
8
7
6
5
n i I i i i i rn i i i
i i i i i i i i i i I i i i i r
I i
CtL
o
-
•f.
0
0.6
0.5
0.4
0.3
0.2
0.1
0,
'0
5 10 15 20 25 30
REMAINING LIFE, yrs
WELLMAN-LORD
LIMESTONE
10 15 20 25
BOILER REMAINING LIFE, yrs
30
Figure 3.5 Effect of boiler remaining life and corresponding
capacity factor on model plant annual cost (model plant
characteristics: 500 MW/existing/3.5% sulfur coal).
3-23
-------
tion, since capital costs are also affected by S02 removal
requirements, this impact is reflected in the fixed charges.
Figure 3.6 illustrates the effect of SO- removal re-
quirements on annual FGD system operating costs for the
model 500 MW/existing plant over a range of sulfur contents
(allowable S02 emission rate =1.2 lb/10 BTU). Operating
cost of the Wellman-Lord system is more sensitive to SO,,
removal requirements than is operating cost of the limestone
process. For the model plant the variation in total annual
cost amounts to 100 percent for Wellman-Lord and 45 percent
for limestone. It should be noted that a large part of the
increase in annual operating cost due to increased S0?
control requirements is the fixed cost component, which
increases simultaneously with the increasing capital cost.
Flue Gas Flow Rate
Since the volumetric flow rate directly affects the
amount of FGD system equipment required, it also affects the
fixed operating cost components. Horsepower and utility
requirements are also influenced by flow rate. Figure 3.7
graphically illustrates the effect of flue gas flow rate on
annual operating cost, by showing the incremental kilowatt
cost differential for a model 500 MW plant, 3.5% sulfur
existing boiler over a range of flow rates.
3-24
-------
U)
I .
NJ
Ui
+2.0
+1.
+1.0 —
+0.5
-0.5
-1.0
-1.5
1
LOCATION OF MODEL PLANT
CHARACTERISTICS
I
I
I
1 2 3 4 5 6
SULFUR CONTENT OF COAL, wt %
Figure 3.6 Effect of sulfur content of coal on model plant annual cost
(model plant characteristics: 500 MW Existing).
-------
OJ
I
K)
CTl
CfL
00 f>
o •—
:z>
•z.
•ZL
=t
+2.6
+2.4
+2.2
+2.0
+1.8
+1.6
+1.4
+1.2
+1.0
+0.8
+0.6
+0.4
+0.2
0
-0.2
-0.4
•**' WELLMAN-LORD _
LOCATION OF MODEL PLANT CHARACTERISTICS
I
I
I
I
I
I
I
LIMESTONE —
\ j 1 .1 ^ 1 .__ . ft *- ' '
2800 3000 3200 3400 3600 3800 4000 4200 4400 4600
acfm AT 310°F PER MW
Figue 3.7 Incremental effect of flue gas volumetric flow rate on model plant operating
cost (model plant characteristics: 500 MW/Existing/3.5% sulfur coal).
-------
4.0 NATIONWIDE FLUE GAS DESULFURIZATION COST ASSESSMENT
Capital and annualized costs of flue gas desulfuriza-
tion systems were estimated for 126 power plants in the
United States. These plants were selected by EPA's Office
of Planning and Evaluation (OPE) on the basis that they re-
ceived shipments of coal in the first six months of 1974
with an average sulfur content greater than that permitted
by projected S0~ emission regulations. Inclusion of a
particular plant does not necessarily reflect its legal
compliance status and it must be emphasized that the list of
plants may be changed as more accurate information becomes
available.
Methodology
Data for estimating capital and operating costs of FGD
systems for the selected plants were acquired from published
sources of power plant data (e.g., capacity, load factors)
and in-house files developed by conducting plant inspections
for EPA. Some discrepancies in the data from the various
sources were apparent and "most reasonable" values were
selected for conducting the evaluation. Because of time and
budget constraints, site-specific factors could not be
included in the cost estimates. Therefore, the costs can
not be considered accurate for any individual plant. The
4-1
-------
sole purpose of preparing such estimates was to aggregate
the individual estimates to develop regional and national
estimates of FGD system costs.
Appendices D and E present design details of the lime-
stone and Wellman-Lord systems used in this assessment.
Appendix F presents a list of plants with associated cost-
determining characteristics and cost estimates, plus a
description of the cost estimating methodology.
Cost Assessment Results
Results of the FGD cost assessment are summarized on a
regional and national basis in Table 4.1 for all selected
plants. Table 4.2 summarizes the costs for only those
selected plants requiring 25 percent or more control. The
regions are those established by the Economics and Statis-
tics Division of the National Coal Association and are
illustrated in Figure 4.1. States within each region are
listed in Table 4.3. The capital and operating costs were
determined by selecting the lower of the capital costs of
the two FGD systems analyzed. The operating cost of that
system was also used for the summary, even if the more
expensive system gave a lower annual operating cost.
Regional capital cost varies from $56/KW to $73/KW with an
average of $64/KW. Individual plants varied from $48/KW to
$259/KW with the same average. Capital costs for the lime-
stone system were lower than those for the Wellman-Lord
4-2
-------
Table 4.1 REGIONAL AND NATIONAL FGD COST SUMMARY
Region
Number of Plants
Capacity, megawatts
Total3
Units scrubbed3
Remining life of units scrubbed
Capital costs
$ MM3
$/KW scrubbed13
Annualized costs
Total $ MM/yra
Mills/KWH15
Fuel & electricity, $ MM/yra
Mills/KWHb
Operation & maintenance
$ MM/yra
Mills/KWHb
New
England
1
965
695
25
41.0
59
14.7
3.1
2.2
0.5
4.9
1.1
Middle
Atlantic
16
386
192
25
14.0
73
4.9
4.6
0.4
0.4
1.9
1.8
East
North
Central
60
692
366
29
24.4
67
8.8
5.0
0.6
0.3
3.5
2.0
West
North
Central
7
682
220
31
14.9
67
5.0
5.3
0.3
0.2
2.2
2.1
South
Atlantic
22
837
390
33
22.8
64
8.6
4.5
0.4
0.2
3.5
1.8
East
South
Central
17
1173
803
27
47.8
60
15.6
3.9
0.9
0.2
5.8
1.4
West
South
Central
0
-
-
.
-
-
-
-
-
Mountain
3
1520
990
37
70.0
56
16.7
4.0
1.4
0.3
4.9
1.2
Pacific
0
-
-
.
-
-
-
-
-
National
126
765
416
29
26.6
64
9.2
4.5
0.6
0.3
3.6
1.7
I
U)
Plant average
Average weighted by capacity
-------
Table 4.2 REGIONAL AND NATIONAL FGD COST SUMMARY OF PLANTS
REQUIRING GREATER THAN 25% SO2 CONTROL
Region
Number of plants
Capacity, megawatts
Total3
Units scrubbed
Remaining life of units scrubbed
Capital costs
$ MMa
$/KW scrubbed13
Annualized costs
Total $ MM/yra
Mills/KWHb
Fuel & electricity, $ MM/yra
Mills/KWH**
Operation & maintenance
$ MM/yra
Mills/KWH*3
New
England
1
965
695
25
41.0
59
14.7
3.1
2.2
0.5
4.9
1.1
Middle
Atlantic
7
479
364
25
26.3
72
9.3
4.5
0.8
0.4
3.4
1.75
East
North
Central
44
700
455
28
29.7
65
10.8
4.8
0.7
0.3
4.3
1.9
West
North
Central
5
630
284
31
18.6
66
6.4
5.2
0.3
0.2
1.9
2.1
South
Atlantic
18
740
433
32
27.5
64
9.7
4.4
0.5
0.2
4.0
1.9
East
South
Central
16
1214
847
27
50.3
59
16.4
3.9
0.9
0.2
6.1
1.4
West
South
Central
0
-
m» *
.
-
.
-
-
-
-
Mountain
3
1520
990
37
70.0
56
16.7
4.0
1.4
0.3
4.9
1.2
Pacific
0
-
-
.
-
—
-
-
-
-
National
94
804
521
29
33.3
64
11.4
4.4
0.7
0.3
4.4
1.7
Plant average
Average weighted by capacity
-------
I
U1
WEST NORTH ]
CENTRAL j
EASTNCTH
CENTRAL
/ MOUNTAIN I
ATLANTIC-
—-xs&s.
5
EASTj SOUTH
CETRAL
Figure 4.1 National Coal Association Regions.
-------
Table 4.3 REGIONAL COMPOSITION BY STATE
New England
1. Connecticut
2. Maine
3. Massachusetts
4. Rhode Island
5. Vermont
6. New Hampshire
Middle Atlantic
1. New Jersey
2. New York
3. Pennsylvania
East North Central
1. Illinois
2. Indiana
3. Michigan
4. Ohio
5. Wisconsin
West North Central
1. Iowa
2. Kansas
3. Minnesota
4. Missouri
5. Nebraska
6. North Dakota
7. South Dakota
South Atlantic
1. Delaware
2. District of Columbia
3. Florida
4. Georgia
5. Maryland
6. North Carolina
7. South Carolina
8. Virginia
9. West Virginia
East South Central
1. Alabama
2. Kentucky
3. Mississippi
4. Tennessee
West South Central
1. Arkansas
2. Louisiana
3. Oklahoma
4. Texas
Mountain
1. Arizona
2. Colorado
3. Montana
4. Nevada
5. New Mexico
6. Utah
7. Wyoming
Pacific
1. California
2. Oregon
3. Washington
4-6
-------
system for about 90 percent of the plants. Operating costs
for the limestone system were lower than those for Wellman-
Lord for about 85 percent of the plants.
4-7
-------
5.0 MANUFACTURER ESTIMATES OF FGD SYSTEM COSTS
Manufacturer estimates of flue gas desulfurization
costs consistent with the model plant characteristics de-
scribed in Section 3 were provided by two member companies
of the Industrial Gas Cleaning Institute (IGCI) for lime-
stone systems. Table 5.1 presents a combined summary of
these estimates.
Table 5.1 SUMMARY OF MANUFACTURER ESTIMATES OF FGD SYSTEM COSTS
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Limestone
Capital
costs
$/KW
61-78
56-74
55-58
50-57
55-68
49-68
49-51
43-51
48-66
43-62
42-48
37-48
Annualized
costs
mills/KWH
4.30
4.27
3.33
3.41
3.66
3.76
2.80
2.91
3.47
3.37
2.88
2.67
5-1
-------
One of these member's cost estimates included a break-
down for capital and annual costs; summaries of these item-
ized capital and annual costs are presented in Tables 5.2
and 5.3, respectively.
Average manufacturer estimated capital costs for new
plants are an average of 8 percent lower than the new model
plant costs and an average of 20 percent lower for existing
plants. The larger variation in retrofit costs is primarily
due to the differences in assumed retrofit difficulty.
Manufacturer estimates of annual costs are an average
of 4 percent lower than model plants for new installations
and an average of 20 percent lower for retrofit applica-
tions. Again, the larger variation in costs for retrofit
applications is primarily due to differences in assumed
retrofit difficulty.
5-2
-------
Table 5.2 MANUFACTURER'S CAPITAL COSTS SUMMARY FOR LIMESTONE SYSTEM
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Scrubbing
$/KW
39
38
31
30
37
36
29
29
37
35
29
29
Sludge
disposal
$/KW
8
8
4
4
6
6
3
3
5
5
2
2
Indirect
costs
$/KW
31
28
23
23
25
26
19
19
24
22
17
17
Total
$/KW
78
74
58
57
68
68
51
51
66
62
48
48
$ MM
19.4
18.6
14.6
14.2
34.2
33.8
25.7
25.3
65.6
61.9
48.5
48.0
Ul
I
CO
-------
Table 5.3 MANUFACTURER'S ANNUALIZED COST SUMMARY FOR LIMESTONE SYSTEM
Model plant
characteristics
250 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 Megawatt Capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Operating
and
Maintenance3
mills/KWH
1.53
1.47
1.17
1.15
1.20
1.20
0.87
0.87
1.08
1.01
1.06
0.73
Fuel
and .
Electricity
mills/KWH
0.17
0.30
0.20
0.35
0.17
0.29
0.20
0.34
0.16
0.28
0.19
0.33
Fixed
costs0
mills/KWH
2.60
2.50
1.96
1.91
2.29
2.27
1.73
1.70
2.23
2.08
1.63
1.61
Total
mills/KWH
4.30
4.27
3.33
3.41
3.66
3.76
2.80
2.91
3.47
3.37
2.88
2.67
$ MM/YR
5.7
5.6
4.4
4.5
9.6
9.9
7.4
7.6
18.0
17.7
15.1
14.0
(Jl
I
Includes:
b Includes:
c
Includes:
raw materials; water; operating labor, maintenance, and overhead.
power and steam (electricity and fuel costs).
depreciation, interim replacement, taxes, insurance, and capital costs,
-------
6.0 UTILITY INDUSTRY SURVEY
A utility industry survey was conducted by the EEI/CACC
to determine the costs for FGD systems. All utilities known
to have an FGD system that was operational, under construc-
tion or planned were contacted by the Edison Electric
Institute and requested to complete a fourteen page ques-
tionnaire. The questionnaire requested information describ-
ing the FGD system and its costs. Responses were received
for forty-three systems and analyzed by the National Eco-
nomic Research Associates (NERA), EEI/CACC's consultant.
The range of control system costs and averages were computed
for different system types and applications (new vs retrofit)
The results of their final analysis, however, are not yet
available.
The EEI/CACC sent copies of the questionnaires to PEDCo
for technical analysis. As anticipated, the reported costs
covered a broad range due to both site-specific factors and
the lack of uniformity with respect to items included in the
cost estimates.
Forty-seven responses were received. Forty-three
questionnaires pertained to FGD systems, 3 to particulate
scrubber systems only and one responded that no scrubber
6-1
-------
system was either installed or being considered. The
responses covered 30 utilities, 32 plants and 68 boilers for
a total capacity of 32,120 MW. The reported costs ranged
from 33 to 197 $/KW with an average of $94/KW (a = 39.83).
Of these, 22 were lime or limestone based systems. The cost
for these systems ranged from 34 to 116 $/KW with an average
of $78/KW (a = 26.56).
PEDCo's analysis of the data centered on adjusting the
estimates to a common basis. The costs were analyzed solely
to determine representative costs for flue gas desulfuriza-
tion systems, not to critique the design or reasonableness
of the costs reported by any utility. Adjustments focused
primarily on the following items:
0 Costs were adjusted to January 1975 dollars.
Costs were reported in dollar values ranging from
the years 1970 to 1980.
0 Particulate control costs were deducted. Since
the purpose of the study was to estimate the
incremental cost for SC>2 control, particulate
control costs were deducted using either data
contained in the cost breakdowns or as a per-
centage of the total direct equipment cost. The
percentage reduction varied depending upon system
design.
0 Indirect charges were adjusted, usually upward, to
provide adequate funds for engineering, field
expenses, overheads, interest during construction,
start-up, and contingency.
0 Replacement power costs were deducted since only a
few utilities reported such costs and these were
presented using a variety of methods. Thus the
adjusted costs do not include replacement power.
0 Sludge disposal costs were adjusted to reflect the
costs of SC>2 scrubber sludge disposal only (i.e.,
not fly ash) and to provide for disposal over the
6-2
-------
anticipated lifetime of the FGD system. This
latter correction was necessary since several
utilities reported costs for demonstration sludge
disposal systems that would last only a fraction
of the FGD system life.
0 Regeneration facility and acid or sulfur recovery
facility costs were added for those regenerable
systems not reporting such costs.
To the extent possible, all cost adjustments were made
using the cost breakdown data provided on the questionnaire.
Where such data were inadequate, costs adjustments were made
based upon system design parameters. In some cases, no
adjustments were possible because of insufficient data while
in others, no adjustments were warranted because of the
unique conditions of the system (e.g., demonstration unit
with funds included for experimentation).
The adjusted costs for all systems with sufficient data
(30 systems), ranged from 50 to 205 $/KW with an average of
$91/KW (a = 33.90). Both the upper end of the range and the
average costs are high because of an exceptionally high cost
reported by the New England Power Company for a prototype
FGD system; the utility stated that their reported values
should be considered "upper limits." Excluding the costs
reported by New England Power Company, the costs range from
50 to 137 $/KW with an average value of $85/KW. Adjusted
costs for lime and limestone based systems reported by
nineteen utilities ranged from 50 to $88/KW with an average
of $70/KW (a = 9.48). These adjusted costs are in sub-
stantial agreement with those developed using the model
plant approach.
6-3
-------
The values reported by the individual facilities, the
factors considered in making the cost adjustments, and the
adjusted costs are presented in Table 6.1. Details of the
cost adjustments for the individual plants are presented in
Appendix G.
6-4
-------
Table 6.1 UTILITY INDUSTRY RESULTS
Company
Plant
Location
Alabama Electric Cooperative
Tombigbee Units 2 & 3
Jackson, Alabama
Process - Limestone
Status - Under Consideration
Start-up Date: 3/78, 1/79
Allegheny Power Service Corp.
Pleasants Power Station Units 1 & 2
Willow Island, West Virginia
Process - Lime
Status - Under Consideration
Start-up Date: 8/78, 8/79
Arizona Public Service Company
Choi la Unit 1
Joseph City, Arizona
Process - Limestone
Status - Operational
Start-up Date: 12/73
Boston Edison Company
Mystic Station
Charlestown, Massachusetts
Process - Magnesium Oxide
Status - Operational
Start-up Date: 4/72
Central Illinois Public Service Co.
Newton Station Unit 1
Newton, Illinois
Process - Lime/Limestone
Status - Evaluating Bids
Start-up Date: 12/77
Capacity
MW
357
510
1236
1236
59:9
119.8
150
150
600
600
Reported Costs
Caoital
$ Millions
40.464 .
(1975)
6.55
5.01
(Actual
Costs)
$/KW
113.34
109.35
33.4
Comments
1. Deleted costs for particulate control
1 . No costs available
1. Adjusted costs from 1973 to 1975
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
2 years to 22 years
4. Added limestone preparation and
sludge disposal costs
5. Considered costs for system representa-
tive for treating full 119.8 MW;
only difference between the modules is
that module B is not packed
1. Added regeneration system costs
2. Added reheat costs
3. Added acid plant costs
4. Increased costs from demonstration
unit to permanent installation
1. No costs available; bids being
evaluated
1975 Adjusted Costs
Capital
£ Millions
29.047
7.036
17.005
$/KW
81.36
58.73
113.37
I
Ol
a Top number Is the F6D system capacity; bottom number 1s the total capacity of the units to which the FGO system 1s applied.
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Cincinnati Gas & Electric Company
Miami Fort Station Unit 8
North Bend, Ohio
Process - Lime
Status - Planned
Start-up Date: 1/78
Columbus & Southern Ohio Electric Co.
Conesville Generating Station
Units 5 & 6
Conesville, Ohio
Process - Lime
Status - Under Construction
Start-up Date: 5/75, 5/76
Dallas Power & Light Company
Texas Electric Service Co.
Texas Power & Light Co.
Martin Lake Steam Electric
Station Units 1, 2, 3, & 4
Rusk County, Texas
Process - Limestone
Status - Under Construction
or Planned
Start-up Date: 2/77, 8/77,
12/76, 12/79
Dallas Power & Light Company
Texas Electric Service Co.
Texas Power & Light Co.
Monticello Steam Electric
Station Unit 3
Titus County, Texas
Process - Limestone
Status - Planned
Start-up Date: 12/78
Capacity
MW
500
500
822
822
1500 (1 & 2)
1500
750
750
Reported Costs
Capital
$ Millions
40.702
(1978)
38.661
(1975)
50.436
(1974)
$/KW
81.40
47.03
33.62
Comments
1. Adjusted costs from 1978 to 1975
2. Added sludge disposal and trans-
portation costs
3. Deleted replacement capacity cost
1. Added indirect costs
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
5 years to 33 years.
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate control
3. Added indirect costs
4. Adjusted pond life and costs from
' 7 years to 35 years
5. Costs are identical for Unit 2;
costs given for Units 3 & 4 were
incomplete
6. 1500 MW of capacity
1. Costs given were incomplete
1975 Adjusted Costs
T.;»pif;»l
$ Millions
36.616
61.563
75.082
$/KW
73.23
74.89
50.12
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Detroit Edison Company
St. Clair Power Plant Unit 6
Belle River, Michigan
Process - Limestone
Status - Under Construction
Start-up Date: 5/75
Detroit Edison Company
Monroe Units 1 , 2, 3, & 4
Monroe County, Michigan
Process - Limestone
Status - Under Construction
Start-up Date: 1981
Duquesne Light Company
Frank R. Phillips Station
Units 1, 2, 3, 4, 5, & 6
Wireton, Pennsylvania
Process - Lime
Status - Operational
Start-up Date: 1973
General Public Utilities Service
Corp. (Penna. Electric Co. & N.Y.
State Electric & Gas Company)
Homer City Station Unit 3
Homer City, Pennsylvania
Process - Lime
Status - Planned
Start-up Date: 10/77
Illinois Power Company
Wood River Unit 1
East Alton, Illinois
Process - Catalytic Oxidation
Status - Operational
Start-up Date: 8/74
Capacity3
MW
170
325
3000
3000
138.3
414.9
650
650
103
103
Reported Costs
Capital
$ Millions
13.088
(1975)
344.0
(1981)
32.346
(1974)
60.192
(1977)
8.2957
(1975)
$/KW
80.54
114.67
77.96
92.60
80.54
Comments
1. Increased costs from test module to -
permanent installation
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
1 year to 20 years
4. Added limestone preparation costs
1. Adjusted costs from 1981 to 1975
2. Detailed cost breakdown was not
available
1. Adjusted costs from 1974 to 1975
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
3 years to 20 years
1. Adjusted costs from 1977 to 1975
2. Decreased costs for 25% system redun-
dancy
3. Added interest costs
4. Added contingency and start-up costs
5. Deleted replacement power costs
1. Adjusted costs from 1970 to 1975
2. Added interest costs
3. Electrostatic precipitator costs
allowed since the system requires
essentially ash free flue gas
1975 Adjusted Costs
Capital
$ Millions
13.693
262.6
10.456
47.750
10.649
$/KW
80.55
87.53
75.60
73.46
103.39
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Indianapolis Power & Light Co.
Petersburg Generating Station
Unit 3
Petersburg, Indiana
Process - Limestone
Status - Planned
Start-up Date: 4/77
Kansas Power & Light Co.
Lawrence 4 & 5
Lawrence, Kansas
Process - Limestone Injection
Status - Operational
Start-up Date: 1/68, 6/71
Kentucky Utilities Company
Green River Power Station
Units 1, 2, S 3
Central City, Kentucky
Process - Lime
Status - Under Construction
Start-up Date: 5/75
Montana Power Company
Col strip Units 1 & 2
Col strip, Montana
Process - Lime
Status - Under Construction
Start-up Date: 7/75, 5/76
New England Power Company
Brayton Point Unit 1
Somerset, Massachusetts
Process - Metal Oxide
Status - Under Construction
Start-up Date: 1/77
Capaci ty
MM
532
532
525
525
60
60
716
716
75
250
Reported Costs
Capital
$ Millions
32.856
(1974)
3.966
(1975)
65.266
(1975)
14.811
(1975)
$/KW
61.76
66.10
91.15
197.48
1
Comments
1. Adjusted costs from 1974 to 1975
2. Deleted costs for particulate control
3. Increased contingency
4. Added sludge disposal costs
1 . No costs available
1. Turnkey contract costs reported
2. Insufficient cost breakdown to
permit cost adjustments
1. Deleted costs for particulate control
2. Added sludge disposal costs - pond
and equipment.
1. Added start-up costs
2. Demonstration unit; costs not
representative of full scale system
1975 Adjusted Costs
Capital
$ Millions
39.120
3.966
51.990
15.341
$/KW
73.53
66.10
72.61
204.55
I
•3
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
New England Power Company
Brayton Point Unit 3
Somerset, Massachusetts
Process - Metal Oxide
Status - Under Construction
Start-up Date:
Northern Indiana Public Service Co.
Dean H. Mitchell Plant Unit 11
Gary, Indiana
Process - Wellman-Lord
Status - Under Construction
Start-up Date: 12/75
Northern States Power Company
Sherburne County Generating Plant
Units 1 & 2
Becker, Minnesota
Process - Limestone
Status - Under Construction
Start-up Date: 5/76, 5/77
Ohio Edison Company
Bruce Mansfield Plant Units 1 & 2
Shippingport, Pennsylvania
Process - Lime
Status - Under Construction
Start-up Date: 12/75, 4/77
Philadelphia Electric Company
Eddystone Generating Station Unit 1
Chester, Pennsylvania
Process - Magnesium Oxide
Status - Under Construction
Start-up Date: 6/75
Capacity3
MW
654
654
115
115
1360
1360
1834
1834
103.3
325
Reported Costs
Capital
$ Millions
95.0
(1975)
13.441
(1975)
60.0
(1975)
213.2
(1977)
20.189
$/KW
145.26
116.88
44.12
116.25
186.42
Comments
1. Added start-up costs
2. Utility states that these costs
reported should be considered the
upper limit
1. Wellman-Lord system with Allied
Sulfur recovery process
2. Insufficient cost breakdown to
permit cost adjustments.
1. Added indirect costs
2. Decreased costs for 9% system redundancy
3. Adjusted pond life and costs from
12 years to 30 years
4. Increased sludge disposal costs
5. Available cost breakdown insufficient
to permit proper adjustments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Decreased costs to remove approximately
20% system redundancy
4. Reduced pond cost to account for S02
control only. Original pond & sludge
transport treatment system cost was 42%
of total direct capital cost compared
to typically reported values of 10-15%
1. Adjusted costs from 1972 to 1975
2. Deleted costs for particulate removal
3. Added interest
4. Added acid plant & ancillaries
1975 Adjusted Costs
Capit 1
$ Millions
98.4
13.441
95.689
142.599
14.837
$/KW
150.46
116.88
70.36
77.81
137.00
I
10
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Potomac Electric Power Company
Dickerson Unit 3
Dickerson, Maryland
Process - Magnesium Oxide
Status - Operational
Start-up Date: 9/73
Public Service of New Mexico
San Juan Station Unit 1
Waterflow, New Mexico
Process - Wellman-Lord
Status - Planned
Start-up Date: 12/76
Public Service of New Mexico
San Juan Station Unit 2
Waterflow, New Mexico
Process - Wellman-Lord
Status - Planned
Start-up Date: 6/77
Public Service of New Mexico
San Juan Station Unit 3
Waterflow, New Mexico
Process - Wellman-Lord
Status - Under Consideration
Start-up Date: 5/78
Public Service of New Mexico
San Juan Station Unit 4
Waterflow, New Mexico
Process - Wellman-Lord
Status - Under Consideration
Start-up Date: 5/80
Capacity3
MW
95
184 .
350
350
350
350
550
550
550
550
Reported Costs
Caoital
$ Millions
6.500
(1973)
44.755
(1974)
44.755
(1974)
59.199
(1974)
71.137
(1980)
$/KW
68.42
127.87
127.87
107.63
129.34
Comments
1. Adjusted costs from test module to
permanent installation
2. Adjusted costs from 1973 to 1975
3. Added interest costs
4. Added regeneration and acid plant costs
1. Adjusted costs from 1976 to 1975
2. Decreased costs for 33% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized: no cost
adjustment made
1. Adjusted costs from 1977 to 1975
2. Decreased costs from 33% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1. Adjusted costs from 1978 to 1975
2. Decreased costs for 25% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1. Adjusted costs from 1980 to 1975
2. Decreased costs for 25% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1975 Adjusted Costs
Capital
$ Millions
13.68
39.348
39.348
52.431
52.431
$/KW
144.00
112.42
112.42
95.33
95.33
a\
I
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Salt River Project
Navajo Generating Station
Units 1, 2 & 3
Process - Lime/Limestone
Status - Under Construction
Start-up Date:
South Carolina Public Service Auth.
Winyah Generating Station Unit 2
Georgetown, South Carolina
Process - Limestone
Status - Planned
Start-up Date: 5/77
South Mississippi Elec. Power Ass.
R. D. Morrow Sr. Generating Plant
Purvis, Mississippi
Process - Limestone
Status - Planned
Start-up Date: 6/77
Southern California Edison Company
Mohave Generating Station Unit 2
South Point, Nevada
Process - Lime
Status - Operational
Start-up Date: 1/74
Southern California Edison Company
Mohave Generating Station Unit 1
South Point, Nevada
Process - Limestone
Status - Operational
Start-up Date: 10/74
Southern California Edison Company
Highgrove Generating Station
Col ton, California
Process - Lime,
Status - Operational
Start-up Date: 1/73
Capacity3
MM
2250
2250
140
280
275.28
444
169.85
790
169.85
790
10
45
Reported Costs
Caoital
$ Millions
6.819
(1975)
7.80
(1975)
17.1
(10/74)
0.400
(1973)
$/KW
48.71
45.92
100.68
40.00
Comments
1 . No costs available
1. Deleted costs for particulate removal
2. Added interest costs
3. Added sludge disposal costs
4. Added utilities & services costs
1 . No costs available
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1975 Adjusted Costs
Capital
$ Mill ions
'
7.756
"
'
$/KW
'•
55.40
'
'
(Ti
I
H
H
-------
Table 6.1 (continued). UTILITY INDUSTRY RESULTS
Company
Plant
Location
Southern California Edison Company
Mohave Generating Station Units 1 & 2
South Point, Nevada
Process - Lime
Status - Planned
Start-up Date: 6/77
Southern California Edison Company
Kaiparowits Generating Station
Units 1, 2, 3 & 4
Page, Arizona
Process - Lime
Status - Under Consideration
Start-up Date: 1980
Tennessee Valley Authority
Widows Creek Steam Plant Unit 8
Stevenson, Alabama
Process - Limestone
Status - Under Construction
Start-up Date: 2/77
Virginia Electric & Power Company
Mt. Storm
Mt. Storm, Virginia
Process - Limestone
Status - Under Construction
Start-up Date: 12/77
Capacity
MW
1580
1580
3000
3000
550
550
1147.11
1662.48
Reported Costs
Caoital
$ Millions
129.0
(1977)
300
(1980)
55.636
(1977)
85.739
(1978)
$/KW
81.65
100.00
101.16
74.74
Comments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Decreased costs for 25% system
redundancy
4. Added sludqe pond costs
5. Adjusted sludge disposal costs
1. Adjusted costs from 1980 to 1975
2. No cost breakdown available to
permit proper adjustments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Increased sludge disposal costs
1. Adjusted costs from 1977 to 1975
2. Increased indirect costs
3. Added sludge disposal costs for S02
disposal for 23 years
4. Deleted coal refuse from sludge
disposal costs
1975 Adjusted Costs
Caoital
$ Millions
94.891
189.05
37.681
84.873
$/KW
60.06
63.02
68.51
73.99
CTl
I
M
M
-------
APPENDIX A
SLUDGE FROM FLUE GAS DESULFURIZATION SYSTEMS
AN OVERVIEW
A-l
-------
APPENDIX A
SLUDGE FROM FLUE GAS DESULFURIZATION SYSTEMS -
AN OVERVIEW
Sludge disposal is the major potential environmental
impact associated with flue gas desulfurization systems.
Sludge is produced, however, only by nonregenerable FGD
processes. This brief overview describes the quantities of
sludge produced, sludge properties and their environmental
impacts, disposal methods to reduce the environmental
impacts, and the costs of environmentally acceptable sludge
disposal methods.
SLUDGE GENERATION RATES
A 1000-megawatt coal-fired power plant would produce
approximately 345,000 tons per year (dry basis) of sludge.
The same plant would produce approximately 307,000 tons per
year (dry basis) of coal ash (3% sulfur, 12% ash). The
following figures may provide perspective from which to view
the sludge disposal issue. The amount of sludge generated
by controlling 35 percent of the coal-fired power plant
generating capacity in Ohio would be 8.5 million metric tons
(dry basis) annually by 1978. By comparison:
Adapted from: Disposal of Lime/Limestone Sludges. Radian
Corporation. Prepared for the U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, under Con-
tract No. 68-02-0046, Task No. 12. September 1973.
A-2
-------
0 36 million tons of phosphate rock slime from
fertilizer manufacture were disposed of by ponding
in 1967;
0 25 million tons of gypsum from fertilizer manu-
facture were disposed of in 1973 by ponding and
surface piles;
0 18 million tons of Ohio municipal refuse were
disposed of in 1973 by landfill and incineration;
0 10 million tons of fly ash from Ohio power plants
were disposed of by ponding and landfilling in
1973.
Thus, in terms of quantity, the estimated production of
sludge from Ohio's scrubbers in 1978 would present a dis-
posal problem similar to that of the current disposal of fly
ash. In terms of weight, the present disposal of phosphate
rock slime and gypsum from fertilizer manufacturing in
Florida alone presents a problem 4 to 6 times that of dis-
posal of scrubber sludge in Ohio.
Approximately 25 acres is required per 100 MW of plant
capacity to dispose of the scrubber sludges generated over
the 30-year period of life of a power plant (assuming 30-
foot depth). This requirement is approximately equivalent
to the total area occupied by the power plant proper. On a
broader basis, as indicated in Table A.I, it is approxi-
mately one percent of the total area required for power
production (i.e., land for mining, transportation, power
2
plant siting, fly ash disposal).
2
Environmentally Acceptable Disposal of Flue Gas Desul-
furization Sludges: The EPA Research and Development
Program. J. W. Jones presented at the Symposium on
Flue Gas Desulfurization, Atlanta, Georgia, November
1974.
A-3
-------
Table A-l. COMPARATIVE ANNUAL LAND AND SOLID WASTE IMPACT OF 1,000 MW
ELECTRIC ENERGY SYSTEM (0.75 LOAD FACTOR)
Land Affected,
acres"
Solid Waste
Produced ,
short tons
En vi r onme nt al
Impact
Typical Tech-
nique (s) Avail-
able to
Minimize
Impact
Mining (Coal)
Deep
9,120
9~,141 (wet,
97% solids)
(101,3^6
with acid
drainage
sludge)
l) potential
land degra-
dation due
to subsi-
dence; 2)acic
mine drainage
water pollu-
tion problem;
l)no well
developed
cost-effec-
tive tech-
nology to
control sub-
sidence;
2)neutraliza-
tion of mine
drainage
with lime
Surface
1U.010
2,762,000 (wet,
98% solids)
(2,762,328
with acid
drainage
sludge)
1) mined land
made barren
precluding
wildlife
habitat ,
recreation
and most
other uses;
2)acid mine
drainage
water pollu-
tior. problems
1) intensive
land recla-
mation can
restore most
strip-mined
land;2) neu-
tralization
of mine drair
with lime
Processing
161
1»5^,092 (wet,
59% solids)
1 ) culm piles;
2) water pollu-
tion: a) acid
drainage ;
b)siltation;
3)air pollu-
tion: a)Dts-
charges S02, CO
&HpS; b)potentia
spontaneous com-
bustion
compacting in
holes, mines,
quarries, etc.
age
Transport
2,213
0
use of land for
railroad beds
1
N/A
Conversion
(plant site)
350
0
use of land for
power plant site
N/A
Limestone FGD
System
Untreated
Ponded Sludge
367
(30 ft. deoth)
l,UUo,000 (wet,
50% solids)
l) potential
groundwater
pollution
problems;
2)land poten-
tially made
useless if
sludge not
treated or
permanently
•lewatered
l) although
reclamation is
feasible, no
well developed,
cost-effective
technology has
been demonstrat
2) sound pond ma
ment, use of im
able pond
liner and opera
of FGD system i
closed-loop mod
n-ir.imize water
ponding, chemic
to have potenti
and land reclarn
Transmission
17,188
0
use of land for
transmission
line right of
way
N/A
Totals
Deep
29,399
1,991,233
N/A
N/A
Surface
34,289
14,656,092
N/A
H/A
ed;
nage-
perme-
tion
n
e can
pollution. (As an alternative to
al fixation with landfill appears
al for solving both water pollution
aticn problems . )
>
-------
Variables Affecting Sludge Quantities
The amount of sludge generated by a given plant is a
function of the sulfur and ash contents of the coal, coal
usage, load factor, mole ratio of scrubbing additive, SO-
removal efficiency, composition of the sludge, and moisture
content of the sludge.
Limestone scrubbing processes ordinarily produce sludge
containing CaSO -1/2 H_0, CaSCK •2 H-O, and CaCO . For coal-
fired installations where efficient particulate removal is
not installed upstream of the wet scrubber, such sludges can
contain large quantities of coal ash.
Variations in state emission regulations cause sulfur
dioxide removal efficiency to vary from one flue gas desul-
furization system to the next. Removal efficiencies of in-
stalled units vary from approximately 60% to 80%. Sludge
production is a direct function of the pounds of sulfur
dioxide removed.
Since unreacted limestone is disposed of with the
sludge, the stoichiometric ratio of limestone addition
(CaCO3/SO2 mole ratio) influences the amount of sludge
generated. The stoichiometric ratio varies from system to
system but is generally in the range of 1.0 to 1.5 Ib moles
of limestone per Ib mole of S02 removed.
The sulfite to sulfate ratio in the sludge effects the
weight of sludge product since CaSO.*2 H20 is heavier than
CaSO^'1/2 H20. Various FGD systems have sludges of almost
A-5
-------
100% sulfite while other systems have 100% sulfate sludge.
Few if any, plants directly control the sulfite to sulfate
ratio. Table A.2 illustrates the variations in the quan-
tities of sludge produced for existing facilities with their
differing sulfite/sulfate ratios and stoichiometric ratios.
Table A.2 SLUDGE PRODUCTION AT CURRENT FGD INSTALLATIONS
Sludge Produced - Dry Basis (excludes fly ash)
Plant
Lawrence 4 and 5
Hawthorn 3-
Hawthorn 4
Will County
Stock Island
La Cygne
Cholla
Paddy 'a Run
Mohave
CaS03-l/2 H20
Ibs/lb S02
removed
0.510
1.046
1.007
1.648
1.702
1.577
1.011
1.968
0.041
CaS04'2 H20
Ibs/lb S02
removed
1.574
1.308
1.362
0.494
0.425
0.591
1.348
0.056
2.654
CaC03
Ib/lb SO2
removed
0.254
0.262
0.888
0.659
6.298
1.183
0.000
0.000
0.000
Total
Ibs/lb S02
removed
2.338
2.616
3.257
2.801
8.425
3.351
2.359
2.024
3.064
Table A.3 illustrates the typical quantities of sludge
produced by an FGD system on a 1000 MW plant for both the
lime and limestone systems for two different sulfur content
coals.
SLUDGE PROPERTIES/ENVIRONMENTAL IMPACTS
The environmental impacts of sludge disposal are
dictated by its chemical and physical characteristics.
These characteristics vary considerably depending upon such
factors as coal chemistry including its sulfur content,
A-6
-------
Table A.3 SLUDGE GENERATION - 1000 MW PLANT
Sludge generation
rate
Stoichiometric
ratio
TONS/HR
Dry
60% Solids
50% Solids
With flyash
45% ash/60% solids
65% ash/60% solids
TONS/YR (thousands)
Dry
60% Solids
50% Solids
With flyash
45% ash/60% solids
65% ash/60% solids
TONS/YR/KW
Dry
60% Solids
50% Solids
With flyash
45% ash/60% solids
65% ash/60% solids
High Sulfur, 3.5%
Lime
1.1
39.5
65.9
89.1
119.9
188.3
208
346
415
630
989
0.208
0.346
0.415
0.630
0.989
Limestone
1.3
61.3
102.2
122.6
185.8
291.9
322
537
644
976
1533
0.322
0.537
0.644
0.976
1.533
Low Sulfur 0.6%
Lime
1.1
10.1
16.9
20.2
30.7
48.3
53
89
107
163
255
0.053
0.089
0.107
0.163
0.255
Limestone
1.3
15.7
26.2
31.4
47.6
74.8
83
138
166
252
395
0.083
0.138
0.166
0.252
0.395
Notes:
High sulfur coal meets a 1.2 MM/BTU emission regulation.
Low sulfur coal meets a 0.15 MM/BTU emission regulation.
Capacity factor is 60%.
Limestone system produces 3.14 Ibs dry sludge/lb S02
removed.
Lime system produces 2.01 Ibs dry sludge/lb S02 removed.
Ash percentages refer to the ash percent by weight of the
dry solids in the sludge/fly ash mixture.
A-7
-------
reactant and system water chemistry, scrubber operating
conditions, ash content, and sludge pH. A sludge's chemical
properties have the greatest potential for impacting directly
on the environment. The physical properties of untreated
sludges may make land reclamation impossible.
Important chemically related sludge characteristics
which could impact on the environment include:
0 Soluble toxic compounds and elements.
0 Chemical oxygen demand.
0 High total dissolved solids.
0 High levels of compounds or elements not generally
thought to be toxic.
0 High suspended solids.
Physical properties of sludges also vary widely. These
properties must be considered in the design of the scrubbing
system since they determine the difficulty in handling,
transporting, and treating the sludge. Scrubber sludges can
be thixotropic in nature, have poor load bearing character-
istics, and retain water. The sulfite concentration in the
sludge determines its physical properties. High sulfite
sludges have low bearing strength and rewater readily.
Tests for comparing physical properties of sludges
include: particle size measurements, the total surface area
of dry solids (Elaine Index), viscosity, bulk density, gel
strength, shrinkage, penetration, and compression.
A-8
-------
Environmental Impact
The disposal of scrubber sludges entails potential
pollution of land, air, and water. Surface waters such as
rivers, streams, lakes, and ponds can be contaminated by
leaching and percolation of sludge liquor into the ground-
water through soil and sludge storage areas. Large areas of
land could deteriorate from the storage of amounts of
sludge materials that typically contain 50 to 75 percent
water. This land could be made useless by the nonsettling
characteristics of untreated sludge.
Leachates and runoffs from scrubber sludges pose poten-
tial water pollution problems. Trace elements in these
leachates may exceed the standards for drinking water.
Although these elements are present in ash pond overflows
they are more concentrated in sludge liquors. The chemical
oxygen demand is higher due to the large quantities of
sulfites. Excess dissolved solids are also a problem.
Since it may take years to detect contamination in ground-
water (and years for it to dissipate) contamination must be
avoided. In the past, other types of pond effluent overflow
into receiving streams was permitted with little treatment
beyond neutralization, skimming, and settling. New reg-
ulations will likely reduce or eliminate this practice. The
use of closed loop (no discharge into a receiving body) will
be required for scrubbing systems.
A-9
-------
Air pollution by scrubber sludges may be a problem if
the materials can not support vegetation. A barren sludge
pond could be a potential source of fugitive dust emissions.
At present, no attempts have been made to reclaim sludge
disposal areas. The tendency of untreated dried sludge to
rewater and its. limited load bearing strengths are major
drawbacks in land reclaimation.
SLUDGE DISPOSAL AND TREATMENT METHODS
Several methods are now used for disposal of scrubber
sludge. The most common are ponding of untreated sludge and
landfilling of treated and untreated sludge. An alternative
to disposing of scrubber sludge is commercial utilization.
This technique is practiced extensively in Japan, where
scrubber sludges are oxidized to form the long fiber gypsum
necessary for wallboard production. Although such tech-
niques could be applicable in the United States if the
economic incentives were adequate, at best they would
account for only a minor fraction of sludge requiring
disposal.
Ponding
Sludge disposal in a pond without providing environ-
mental protection (such as chemical fixation or impervious
liners) against seepage to water supplies constitutes a
potential water quality hazard. The degree of hazard depend
upon such site specific characteristics as topography,
weather, soil characteristics, and proximity of ground and
A-10
-------
surface waters to the disposal site. In addition, there
exist a significant number of other disposal variables
(e.g., chemical constituents of the sludge and the condition
of sludge disposal) that may impact the potential hazard
posed by such a sludge pond.
Pond linings have been finding greater favor in recent
years. Lining is an effective method to prevent groundwater
contamination. On many areas, clay, concrete, wood or metal
have been used as liners. Synthetic materials are finding
increased use. These synthetic materials include polyvinyl
chloride, rubber, synthetic rubber, polyethylene, propylene,
and nylon. Since economics is a major factor, clay and
synthetics will be the primary materials used for sludge
liners. To be useful, liners must have long-life, endured-
temperature variations, and remain flexible. Several manu-
facturers are offering acceptable liner materials.
Landfilling
The second method for disposal of scrubber sludges is
use of either a dewatered or a stablilized ("fixed") sludge
for landfill. Sludges can be dewatered by vacuum filtration
or centrifugation to form a solid material that can be used
for landfill. Since these dewatered sludges can reabsorb
moisture and regain their original water content if un-
treated, chemical and physical stabilization or fixation
processes are increasingly being used.
A-ll
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Chemical fixation of scrubber sludge is currently
offered by several commercial groups including Dravo Corpo-
ration, I.U.C.S., Inc., Chicago Fly Ash, and The Chemfix
Corporation. These commercial systems use fly ash, lime,
silicates, and polyvalent metal ions (usually about 5 per-
cent of the amount of sludge on a dry weight basis) to form
a low-grade concrete. The product is a stable, inert mate-
rial that will not release toxic metal ions or soluble
species. It has sufficient strength to support buildings
and will support vegetation. Table A.4 presents data on the
leachate rate bearing data for chemically stabilized sludges.
Chemical fixation processes and landfilling represent the
most suitable method for scrubber sludge disposal.
Table A.4 COMPARISON OF TRACE ELEMENTS ANALYSES BETWEEN RAW
SLUDGE AND LEACHATE FROM THAT SLUDGE AFTER CHEMICAL
CONDITIONING BY FIXATION3
Constituents
Arsenic (As)
Cadmium (Cd)
Chlorides (Cl~)
Total chromium (Cr)
Copper (Cu)
Iron (Fe)
Lead (Pb)
Mercury (Hg)
Nickel (Ni)
Zinc (Zn)
Phenol (C6H5OH)
Cyanide (CN~)
Sulfate (S04~)
TVA Shawnee
TCA limestone
raw sludge
(ppm)
2.2
0.30
2,000
2.8
1.5
120
26
<0.10
3.5
16
<0.25
<0.10
>10,000
Leachate water from
conditioned sludge
(ppm)
<0.10
<0.10
64
<0.25
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
400
Disposal of Byproducts from Nonregenerable Flue Gas De-
sulfurization Systems. Aerospace Corporation, El Segundo,
California. Prepared for the U.S. Environmental Protection
Agency. Research Triangle Park, North Carolina under
Contract No. 68-02-1010. May 1974.
A-12'
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DISPOSAL COSTS
The following factors affect the capital and annualized
operating costs of sludge disposal:
1. Capital Cost
a. Pond location
b. Lining requirement
c. Leachate monitoring
d. Overall size
e. Dewatering method
2. Annualized Operating Cost
a. Fixation chemicals
b. Utilities
c. Trucking
The split between capital and annual costs is not clearcut.
For example, several firms will operate sludge disposal
systems on a per ton basis. The utility will not be re-
quiredxto invest capital in the system. However, these
contracts normally have "take or pay" clauses to protect the
sludge disposal firm's capital investment. In essence, turn
key disposal merely shifts the fixed charges of sludge
disposal to direct operating expenses. In addition, pumping
sludge instead of trucking sludge increases capital but
reduces annual costs. Sluice lines and pumps are part of
the capital costs borne by utility, while trucks to haul
sludge are normally borne by trucking contractors. Another
area which affects capital and annualized operating costs is
dewatering. Horsepower requirements are reduced if ponding
is used to dewater sludge instead of vacuum filtration or
centrifugation. Capital costs increase however, since the
pond must be larger and more complicated.
A-13
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Table A.5 depicts the disposal costs for the 250, 500
and 1000 MW model plants used in this study. Capital costs
include clarification, vacuum filtration, chemical fixation,
and a clay lined pond with a life equal to the remaining
plant life. Annualized costs include fixation chemicals,
utilities, operating labor, supervision, maintenance,
supplies, overhead, and fixed charges. Sludge is disposed
of on-site and there are no trucking charges.
Table A.6 identifies the annualized cost impact of
various subset conditions for sludge disposal for a new 500
MW plant burning high sulfur coal.
Table A.6 IMPACT OF VARIOUS SUBSET SLUDGE DISPOSAL OPTIONS
ON THE ANNUALIZED COST OF SLUDGE DISPOSAL3
Base Case
Synthetic Lining
Fixation
Trucking - 5 miles
Trucking - 10 miles
Trucking - 15 miles
Pumping - 5 miles
Pumping - 10 miles
Pumping - 15 miles
Retrofit
Low Sulfur
Mills/KWH
0.463
0.451
0.204
1.023
2.046
3.069
0.224
0.336
0.448
(0.040)b
(0.337)
$/Dry Ton
7.54
7.35
3.32
16.67
33.33
50.00
3.65
5.47
7.30
(.65)
7.17
$/Wet Ton
4.53
4.41
2.00
10.00
20.00
30.00
2.19
3.28
4.38
(.39)
4.30
The various costs shown are additive to the "Base Case"
cost which is an unlined pond without chemical fixation.
Numbers in parentheses are negative.
A-14
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Table A.5 SLUDGE DISPOSAL COSTS FOR THE MODEL PLANTS'
Capital Cost
$/KW
Annualized Cost, mills/KWH
Fixation chemicals
Electricity
Water
Labor
Supervision
Maintenance
Supplies
Overhead:
Plant
Payroll
Fixed costs
Total, mills/KWH
S,.ton, Dry
$/ton, wet
250 MW
3.5% S
Retrofit
11.0
0.216
0.012
0.001
0.014
0.002
0.083
0.013
0.056
0.003
0.425
0.825
12.74
7.64
New
13.3
0.209
0.011
0.001
0.021
0.003
0.101
0.015
0.071
0.005
0.472
0.909
14.50
8.70
0.6% S
Retrofit
6.65
0.055
0.011
0.001
0.010
0.001
0.051
0.008
0.035
0.002
0.258
0.432
25.94
15.57
New
7.70
0.054
0.010
0.001
0.014
0.002
0.058
0.009
0.042
0.003
0.272
0.465
28.83
17.30
500 MW
3.5% S
Retrofit
8.05
0.210
0.011
0.001
0.006
0.001
0.062
0.009
0.039
0.001
0.287
0.627
10.00
6.00
New
8.93
0.204
0.010
0.001
0.008
0.001
0.068
0.010
0.044
0.002
0.319
0.667
10.87
6.52
0.6% S
Retrofit
4.55
0.054
0.010
0.001
0.004
0.001
0.034
0.005
0.021
0.001
0.160
0.291
18.04
10.82
New
5.07
0.053
0.010
0.001
0.005
0.001
0.038
0.006
0.025
0.001
0.179
0.319,
20.22
12.13
1000 MW
3.5% S
Retrofit
6.13
0.204
0.010
0.001
0.004
0.001
0.046
0.007
0.029
0.001
0.216
0.519
8.46
5.08
New
6.13
0.198
0.010
0.001
0.004
0.001
0.046
0.007
0.029
0.001
0.217
0.514
8.66
5.20
0.6% S
Retrofit
3.33
0.053
0.010
0.001
0.002
0.001
0.025
0.004
0.016
0.001
0.119
0.232
14.70
8.82
New
3.33
0.051
0.009
0.001
0.002
0.001
0.025
0.004
0.016
0.001
0.118
0.228
14.95
8.96
l-»
en
U Capital costs include associated indirect costs. Indirect costs for the total FGD system were reported as a separate
category in Table 3.3.
-------
APPENDIX B
PROCEDURE FOR CONVERTING UTILITY INVESTMENT AND
EXPENSE INTO ANNUAL REVENUE REQUIREMENTS
B-l
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APPENDIX B
PROCEDURE FOR CONVERTING UTILITY INVESTMENT AND EXPENSE
INTO ANNUAL REVENUE REQUIREMENTS
Introduction
This report describes the development of a
procedure for translating utility investment and expense
into annual revenue requirements. It is based upon the
practices followed by regulatory authorities in the United
States and statute law with respect to income tax and the
deductability of various items of expense in calculating
the amount of such taxes. The important variations in
methodology between jurisdictions are pointed out.
Typical parameters have been selected to illustrate the
procedure with a quantative example.
Plant Investment
Plant investment refers to the initial investment
in utility plant having a useful life greater than one year.
No adjustment is made for the effect of regulatory practices
which modify the value of plant for rate making purposes to
take into account the effects of inflation and changes in
technology. This is not to be inferred as a disparagement
of the fair value approach in determining plant investment.
In the interest of a simplified analysis of alternative
plans, such refinements have been avoided. This is believed
to be a reasonable approach. It is doubtful that any
utility planner in a so-called "fair value" rate jurisdiction
includes in a projection of revenue requirements outside the
pale of a rate case, changes in the fair -value of plant
a) Prepared by R.H. Sarikas of Foster Associates under sub-
contract to PEDCo-Environmental Specialists,
B-2
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investment through time. Plant investment is identified
as item P in table V of this report. That table has been
identified as Table V so as to conform to a similar table
in a report prepared by another organization.
Life Estimates
i"*"*
The procedure provides for separate estimates of
I
physical, book, and tax life. While conformity is possible
a framework for alternative calculations wherein these
lives differ is more realistic. The estimate of physical
and book life are discussed in the following paragraphs.
The estimate of life for income tax depreciation is discussed
in a later section of the report dealing with the calculation
of the revenue requirement for income taxes.
Physical Life
Retirement history is not available for flue gas
desulfurization equipment since only a few test installations
are in existence and these have only been installed for a
relatively few years. The estimated life used in this
report is fifteen years. It is identified as item Lp in
Table V of this report. Equipment for the manufacture of
chemicals and allied products that is similar in nature
typically is depreciated over a somewhat shorter period.
The selection of a life estimate for that purpose is very
likely influenced by the possibility of plant retirement
due to obsolescence of the particular process. This
estimate is about one-half of the physical life normally
B-3
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attributed to a fossil fired steam electric generating
station.
Life for Book Depreciation
An estimated life of thirty years is used for
book depreciation purposes. It is identified as item Lfo
in Table V of this report. This is generally in line with
the life estimate commonly used by utilities to depreciate
fossil fired electric generating plant. The flue gas de-
sulfurization equipment would normally be depreciated at
the rate applicable to the entire steam production plant
/
or the rate specifically applicable to Account 312, Boiler
Plant Equipment.
Construction Time
A construction time of two years has been assumed
for the flue gas desulfurization equipment. This is less
than one half of the construction time of a typical fossil
fired power plant. However, it is believed to be a fair
estimate of the time required for the construction of such
a device. It is identified as item N in Table V of this
report.
Interest Rate During Construction
The Interest rate During Construction (IDC) also
identified in current literature as the Allowance for Funds
used During Construction (AFDC) is normally established at
a rate lower than current debt cost. While ideally the
figure should be representative of total rate of return on
B-4
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the utility plant investment, the lower rate provides some
recognition of the fact that this rate is an after-tax
rate and has no bearing upon the calculation of the amount
of federal income taxes. The regulatory justification for
AFDC is that it avoids having present day rate payers
contribute for cost incurred .to construct plant which will
benefit future rate payers. This goal is achieved by
capitalizating or adding to the cost of plant the amount
of IDC. There are, of course, minor exceptions to this
practice in certain regulatory jurisdictions. This
practice has distorted the operating earnings picture
for a number of electric utilities since a substantial
amount of what is identified as earnings in financial
statments actually is a result of this practice of charging
interest during construction and adding the amount to
reported book earnings. This item is identified as ic in
Table V of this report.
Capitalization
The capital structure is frequently defined in
terms of capitalization ratios, that is the ratio of
debt to total capital, as well as the ratio of preferred
stock to total capital and common equity to total capital.
The choice of these ratios is determined by factors such
as the times interest earned coverage of debt expense as
well as the coverage ratio with respect to preferred stock
dividends. The ratio is also dependent upon the degree of
financial leverage desired by the firm. Coverage ratios
B-5
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have been lower in recent years as a result of combination
of higher interest rates and reduced equity earnings. The
maintenance of satisfactory bond ratings are important in
maintaining the ability of a utility to attract needed
reasonable capital at a reasonable cost. Suggested
parameters are shown in Table V of this report and are
identified as d, p, and c. Suggested parameters are 50,
15, and 35% respectively. Recently available 'figures
for investor owned electric utilities are as shown below:
Type of Capital Capitalization Ratio
Long term debt 53.7%
Preferred Stock 11.7
Common Stock Equity 34.6
Total Capitalization 100.0%
The source of this information is Table 55 S of
the Edison Electric Institute Statistical Yearbook for
1972. The above figures are in reasonable conformance
with the recommended input parameters, especially when
the need for adequate coverage interest and preferred
dividend ratios are taken into account. Imbedded rates
are expected to increase in future years as a result of a
preponderance of new issues in total debt capitalization.
Interest Rate on Debt
The interest rate on long term debt will depend
upon the overall level of interest rates for the entire
economy and also upon the bond rating of the particular
B-6
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utility. This latter item is associated with the 'financial
and business risk individual utility. While the factors
affecting the risk of a particular utility are numerous,
the more significant include coverage ratios or the
amount of earnings in excess of the bond interest. The
percent of total capitalization that is debt, the type of
customers, (i.e. mix of residential, commercial, and
industrial sales) stability of revenue, particular utility,
regulatory climate and related items. Recent (November,
1974) yields on public utility issues for the various
bond ratings are shown below:
Rating Interest Percent per
Annum
Aaa 9.08%
Aa 9.51
A 10.43
Baa 11.39
Source of the yield data is Moody's Public Utility Manual
and Bond Survey.
The interest rate on debt is identified as i^
in Table V of this report. An input parameter of 10%
has been selected.
Dividend Yield on Pf. Stock
The dividend yield on preferred stock will depend
upon many of the same factors which affect the level of
interest rates. Recent (September, 1974) yields on public
utility issues for the various preferred stock issues are
B-7
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shown below:
Rating Dividend Yield
High Grade 10.34
Medium Grade 10.85
Source of the data is Moody's Preferred Stock
Yields. While the dividend payment is not deductible
for income tax purposes by the utility, the use of
preferred capitalization aid in providing the interest
coverage. The attractiveness of such issues to corporate
investors is that utility preferred dividends are partially
deductible for tax purposes. The interest payments of
the more secure utility bonds are not. Dividend yield is
identified as rp in Table V of this report. An input
parameter of 101 has been selected.
Percent Return on Common Equity
The percentage return on common equity must be
adequate to properly compensate owners of the stock in
line with comparable risk securities in unregulated business.
For a growing utility, and most electric utilities have been
growing at a rate which doubles their electrical load every
decade, this rate of return must be also adequate to attract
capital from new investors. This is probably the most
significant and argumentative item in any electric rate
case. It is generally accepted that this rate of return
must exceed the interest rate on debt because of the greater
risk of equity investment. It must also be comparable to
B-8
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the equity rate of return earned by comparable risk non-
regulated businesses if the utility is to be able to sell
its common ;>tock issues and raise the requisite amounts
of capital. Equity rate of return is identified as rc in
Table V of this report. A rate of return of 151 has been
used as an input parameter.
Income Tax Rate
The statutory federal income tax rate for a
corporation is a normal tax of 22% with a surtax of 26%
on all taxable income over $25,000. Since virtually every
utility will have taxable income in excess of $25,000, the
incremental tax rate is the sum of those two components or
48%. In addition, a number of the states have levied an
income tax on corporations. The magnitude of the rate
depends upon the particular jurisdiction. In most
instances, the federal income tax liability is not deduct-
ible for state income tax purposes. However, in
computing the amount of the federal income tax, state income
tax is always a deductible item. Assuming a state income
tax of 4% the composite tax rate would be 50% (or more
precisely 50.08%) calculated as follows:
Composite Tax Rate = f + s - fs =
= 0.48 + 0.04 - 0.48 x 0.04 = 50.08%
where
f = Federal income tax rate =48%
s = State income tax rate = 4%
B-9
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For that reason, an input parameter for this item of 50%
is recommended. The item is identified as t in Table V
of this report.
Life for Tax Depreciation
In any individual situation the income tax
depreciation rate is dependent upon the rate actually
approved for the particular utility by the Internal Revenue
Service (IRS). This, in turn, is based upon figures
published in guidelines issued by IRS and the ability of
the tax payer to demonstrate the justification for any
departure from these guidelines. This is accomplished by
means of plant life studies using well-known statistical
techniques. With respect to flue gas desulfurization
equipment, the tax depreciation rate which may be applied
depends in part upon the installation date of the electric
generating station with which it will be associated. An
agreement between the taxpayer and the IRS with respect
to useful life is made on IRS Form 2271. It is binding
on both parties and can be modified only upon proof of the
existence of facts or circumstances which were not taken
into consideration when the agreement was made. Normally,
in the case of a new generating plant, the utility will
depreciate its property under the Class Life Asset
Depreciation Range System (ADR). This is a system of
broad industry classes of assets. A tax payer using ADR
B-10
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does not have to justify his retirement and replacement
policies. However, the depreciation period selected
cannot be changed during the remaining period of use of
the asset. All classes of assets have a range of years
called the Asset Depreciation Range that extends 201 above
and below the asset guideline.period. Presumably the util-
ity would select a life that is the minimum permissible
under ADR. With respect to electric generating equipment,
the asset guideline period is 28 years, with the lower
limit at 22.5 years. Thus, if the facility is part of the
power plant, the utility could use a 22.5 year life unless
it could demonstrate to the satisfaction of the IRS that
some other life is more appropriate.
If the facility is placed in service before 1975,
and is associated with a plant placed in operation before
1969 and remaining life is fifteen years or less the environ-
mental project can be written off over a five year period.
If the remaining life exceeds fifteen years the amount of
the five year write-off is adjusted by the ratio of fifteen
to the remaining life in years. If the plant is installed
after 1969 the life for tax depreciation is the same as
plant itself.
A tax life of 23 years has been selected as an
input parameter. This is identified as item Lt in Table V
of this report. The guideline life parameter, required
for normalization and identified as Lg is assumed to be
28 years.
B-ll
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Operating Expense
Operating expense includes all expenditures for
labor and materials having a useful life less than one
year. Items includable under this category are labor
required for maintenance and operation, plus raw materials
less any credit for by-products sold. This item is
identified as E in Table V of this report.
Land
Investment in land is normally set up in a
separate category when calculating revenue requirements.
For most purposes, land is assumed to be non-depreciable
for book and income tax purposes. In other ivords, it is
assumed to have infinite life. In this analysis, separate
.input parameters are provided for the amount of land
required, measured in appropriate units such as square
feet or acres with the unit cost of land measured in terms
of the same units. Total land required is identified as
item q, the unit cost of land is identified as item n in
Table V of this report.
Property Tax Rate
Most state and local jurisdictions levy a
property tax on all real estate and personal property
owned by the utility. This rate is normally not uniform
throughout the utility's territory but is dependent upon
the methods used for appraising the value of the plant for
i
tax purposes and the tax levy which is in turn related to
the tax revenue needs of the particular jurisdiction. A
B-12
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typical input parameter of 1.51 has been included for
this component. The item is identified as A in Table V
of this report. For a particular utility it could be
calculated by dividing the amount of such tax paid by
gross plant investment. Ideally, it should be based upon
an estimate of the tax liability of a particular facility
prepared by the utility's tax department.
Cross Receipts Tax Rate
Many state and local jurisdictions apply a
public utility tax on the gross receipts of the utility.
This corresponds to a sales tax on other transactions.
As an example, a state may levy a 5% tax on gross receipts.
This means that 5% of the revenues collected are turned
over to the state. In some jurisdictions, this is not
identified as revenue by a utility, although the tax is
collected as part of the customer's bill. Since the
amount to cover expenses and plant related cost must
ultimately be derived from revenues, the revenue require-
ments must be appropriately increased to provide for this
amount of tax. As an example, given a public utility tax
of 4°o, the revenue which must be collected to pay $1 of
expense is 1 = $1.0417. A figure of 4% has been
(1-0. 04)
selected as an input parameter. It is identified as item G
in Table V of this report.
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Insurance
Another plant related cost is the expense of
providing insurance. The cost of insurance will depend
upon the evaluation of risk by the underwriter. Usually
a utility has a substantial deductible provision in order
to minimize the premium. The recommended figure of 0.1%
is typical of generating plant coverage with the exception
of nuclear liability insurance. This item is identified as
U in Table V of this report.
Percent Return on Rate Base
Percent return on rate base is calculated by
the general formula shown in the table. Thus, it depends
upon the various capitalization ratios as well as the
interest rate, preferred dividend yield, and rate of
return on common equity. For the sample input parameters
the total rate of return is 11.75% calculated as follows:
r = 0.5 x 10 + 0.15 x 10 + 0.35 x 15 = 11.75%.
This is shown as item r in Table V of this report.
Total Land Cost
Total land cost is merely the product of the
number of units of land required and the unit cost, of the
land. It is identified as B in Table V of this report.
B-14
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Working Capital
Working capital for an electric utility typically
consists of the inventory of maintenance materials and
fuel as well as items such as cash on hand required for
transactions, plus amounts to take into account the lag in the
payment of expense as compared to the receipts of revenues.
With respect to flue gas desulfurization equipment, working
capital would consist primarily of maintenance materials
and the inventory of raw materials used in the process.
A figure of 12.51 of expenses has been suggested as an
input parameter. This item is identified as W in Table V
of this report.
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Start Up Requirements
Start up expenses refer to labor and maintenance
cost required to obtain satisfactory operation of the
equipment prior to commercial operation. This amount is
normally capitalized and added to the investment, rather
than being expensed in the year in which it is incurred.
This item may be highly variable depending upon the
difficulties encountered. A figure of 251 of annual
expenses has been recommended as an input parameter.
This item is identified as S in Table V of this report.
Interest during Construction
The general formula for IDC assumes that plant
expenditures are uniformly incurred over the construction
period. It also assumes that IDC is applied only to
plant investment exclusive of land. The past practice of
many utilities has been to include IDC on land plus plant
investment. The current trend is to omit land from that
calculation. If the previous recommendations with respect
to input parameters are accepted, calculated IDC is equal
to 91 of plant investment. This item is identified as
item I in Table V of this report.
Total Capital Requirement
The total capital requirement for plant is the
sum of plant investment, IDC, working capital and start-
up cost. The total capital requirement for land is B.
These two items are identified as Cp nd C^ in Table V of
this report.
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Depreciation Annuity
The depreciation annuity is the level annual
percentage of depreciable plant, which when added to
the rate of return on rate base and applied to the plant
investment in each year, will have the same lifetime
present worth revenue requirement as the return on net
plant in each year, plus straight line depreciation.
This latter combination of return and depreciation would
be a non-uniform series. Straight line depreciation
would be a constant. However, return on rate base would
decrease each year since rate base is equal to initial
investment less accumulated depreciation. This latter
figure would increase each year as depreciation charges
are accumulated in the reserve for depreciation. Use of
rate of return on the rate base, plus straight line
depreciation would overstate the revenue requirement for
those two cost components in every year except the initial
year of plant life. Use of the sinking fund annuity in
calculating the depreciation component of levelized
revenue requirements in no way implies the existence of
sinking fund depreciation for book or tax purposes. The
life use in this calculation is the physical life. If the
figure is 11.751 is substituted for r and physical life
of 15 years is substituted for Lp in the general formula
shown in Table V, the resulting annuity is 0.027 on a per
unit basis or 2.7% of the total capital requirement for
plant. Since land is nondepreciable the depreciation
B-17
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annuity for land is zero. The item is identified as D in
Table V of this report.
SYD Annuity
The general formula for the calculation of the
SYD annuity is given in Table V. This parameter is needed
in the formula for the income tax annuity involving
accelerated depreciation which is subsequently presented.
A tabular calculation of this expression, using the
previously indicated parameters, is provided in Appendix A
to this report.
Income Tax Annuity
The income tax annuity is shown for three
alternatives, namely, straight line depreciation for book
and tax purposes; straight line depreciation for book
purposes, accelerated depreciation for tax purposes, with
deferred taxes normalized; and straight line depreciation
for book purposes, accelerated depreciation for tax purposes
with flow through of the tax saving. The composite tax
annuity is applied to capital investment in plant or land
as appropriate in order to compute the revenue requirement
for income taxes.
A minor discrepancy is incurred when the tax
annuity is applied to total capital investment which
includes interest during construction.
B-18
-------
Such a calculation infers that there is a revenue
requirement for income tax associated with capitalized
interest during construction. Actually, this is not the
case, since the revenue requirement for return and
depreciation on the portion of plant represented by capitalized
interest during construction is excluded when calculating
income taxes. Since the present worth of return and
depreciation over one life cycle is equal to initial
investment, the present worth of interest during construction
added to net income is exactly equal to the present worth
of return and depreciation on the capitalized interest
over one life cycle. Also since income tax was not paid
on the amount of IDC added to net income, it is inappropriate
to consider tax depreciation as applicable to that component
of plant investment.
The error introduced by applying the tax annuity
to total plant capital requirement in the general formula
in Table V is minor and will help to offset the error
introduced by not considering the revenue requirement for
interest during construction, which precedes the initial
service date of the plant from which point physical life
and book life is estimated.
Income Tax Annuity-Straight Line
The general formula for the income tax annuity,
assuming straight line depreciation for book and tax
B-19
-------
depreciation is given in Table V of this report. The
item is identified as T in that table. It is no longer
j
a common practice for utilities to use straight line tax
depreciation except for plant installed prior to 1954 ,
or used equipment acquired since that date. The formula
is provided for completeness. It is also used to calculate
the tax annuity for land which is non-depreciable for
both book and tax purposes. The calculation, using the
previously developed parameters,is given in Appendix B to
this report. A tax life equal to the guideline life of 28
years was used. If the 23 year life were to be elected it
would be necessary to normalize the difference in tax lives
as described for accelerated depreciation.
Income Tax Annuity-Normalized
The next formula given in Table V is the formula
for the income tax annuity assuming straight line depre-
ciation for books, SYD depreciation for taxes, with the
deferred taxes normalized. The calculation, using the
previously developed parameters, is given in Appendix C
of this report. The current practice of the Federal Power
Commission with respect to utilities under its jurisdic-
tion is to allow deferred taxes to be normalized. Under
that approach, income is calculated by treating as income
tax expense the sum of current and deferred taxes. The
amount of the deferred tax, which is the difference between
B-20
-------
taxes computed on a straight line basis and taxes computed
on the basis of SYD depreciation, is set up in a tax re-
serve (balance sheet account) as a liability. The straight
line tax rate is required by tax regulations to be the
guideline life or book life. Current regulatory practice
is to deduct the amount of the deferred taxes from the
rate base in calculating return on rate base. In the gen-
eral formula, the deferred tax is the expression t(Dt-_l).
Lg
The general formula assumes that the quantity to be
normalized is the difference between tax depreciation on
a straight line and on an accelerated basis. It would also
be possible to normalize differences between book and tax
lives if desired. However, suitable modifications would
have to be made to the general formula for the income tax
annuity,
Income Tax Annuity-Flow Through
The next formula shown in Table V is the expres-
sion for the income tax annuity assuming straight line
depreciation for books, SYD depreciation for taxes, with
deferred taxes flowed through to income. This method of
tax treatment is used in a number of the state jurisdic-
tions. However, the intent of congress as expressed in
recent tax legislation favors the normalized approach.
The levelized tax annuity is identical with the results
B-21
-------
obtained using the normalized approach if there is no debt
in the capital structure. The calculation of this annuity
using the previously developed parameters is given in
Appendix D to this report.
Investment Tax Credit
The investment tax 'credit can be claimed on the
flue gas desulfurization equipment unless the rapid (5 year)
amortization is claimed. At the present time the credit
for utility property is 4%. The intent of Congress is that
this credit be normalized and not flowed through. Also, it
is not to be deducted from rate base. Tax regulations re-
quire that tax life for other purposes be used in computing
the investment tax credit. The formula for the investment
tax credit annuity identified as T is given in Table V of
this report.
The legislative history of the investment tax
credit is unlikely to inspire long-run confidence in its
future availability.
The Investment Tax Credit was introduced by the
Revenue Act of 1962, suspended by the Suspension Act of
1966, restored by the Restoration Act of 1967, and repealed
by the Tax Reform Act of 1969. A revised Investment Tax
Credit was reinstated by the Revenue Act of 1971. Recent
proposals by the Administration again call for changes in
B-22
-------
the Investment Tax Credit. In view or the foregoing, the
investment tax credit was omitted from the calculation of
total revenue requirements. It can be included by off-
setting the amount of the credit from the income tax annuity,
Total Levelized Annual Revenue Requirement
The general formula for the total levelized annual
revenue requirement for plant and for land is shown in
Table V. Note that the expression is divided by 1 minus
the gross receipts tax. This is to provide revenues suffi-
cient to cover the gross receipts tax plus the other com-
ponents. If it is desired to determine the portion of the
carrying charge rate on investment attributable to the gross
receipts tax, this can be dpne by evaluating the expression
shown in the general formula both with and without the ex-
pression (1-G) and computing the difference. Note that the
sum of the various components of the fixed charge rate such
as return, depreciation, and taxes is applied to total in-
vestment Cp . This implies depreciation of working capital
and other similar components of total capital, which is not
strictly correct. However, this is commonly done because
the refinements to determine precise revenue requirements
would unduly complicate the analysis.
B-23
-------
TABLE V
COST ANALYSIS PROCEDURE
FOR
FLUE GAS DESULFURIZATION
ITEM
w
I
to
Input Paramaters
Total plant investment
Plant life estimate
Physical Life
Book depreciation
Construction time
Interest rate during construction
Capitalization
Debt fraction
Preferred Stock fraction
Common Stock fraction
Interest rate on debt
Dividend yield on preferred stock
Percent return on common equity
Income Tax rate
Plant life estimate for tax depreciation
Net operating expense
GENERAL FORMULA
TYPICAL PARAMETERS
From cost estimates
15 years
30 years
2 years
9%
50%
15%
35%
10%
10%
15%
0.50 (48% Federal, 4% State)
23 years
28 years
From cost estimates
-------
TABLE V
Continued
ITEM
03
I
to
U1
Input Parameters(cont'd.)
Total Land required
Unit cost of land
Property Tax rate
Gross Receipts tax rate
Insurance
Calculated or Input Parameters
Percent return on rate base
Total land cost
Working capital
Startup Expenses
Interest during construction
Total capital requirement
Plant
Land
Depreciation annuity
GENERAL FORMULA
A
G
U
* Prp
qn
W
S
C = P + I + W + S
CB = B
rj = _
(1 + r)S - 1
TYPICAL PARAMETERS
From cost estimates
From cost estimates
1.5%
4%
0.1%
r=ll.75%
0.125E
0.25E
0.09P
Cp = 1.09 P + 0.375E
0.027C,,
-------
a
i
to
ITEM
Calculated or Input Parameters (cont'd)
Sum of Years Digits (SYD) Annuity
Income Tax Annuity
Assuming straight-line depreciation
for books and taxes
for books, SYD depreciation for
taxes, with deferred taxes normalized
Assuming straight-line depreciation
for books, SYD depreciation for
taxes, with deferred taxes flowed
through to income
Investment tax credit
Total levelized annual revenue requirements ,
Plant
TABLE V
Continued
GENERAL FORMULA
r(l+r)LP ^fzCLt - a+l)}{ 1 }~1
(l+r)LP - 1 °| Lc(Lt + 1) (l+r)Lt 1
where a = any year between o and Lt
[i ~) 1 1
Lb r 1 Lg Lb
t P 1 1~] dic 1
N VT > IT T u J t^Ut , JIv-*- I c<.ut , /
1-t Lb L8 I r Lg
F ~ 1-t Lb r ' Lg I
T ( t j! 0-04r(l+r)(Lg~1) + O.OA |
C 1-t 1 (l+r)LS~' Lg 1
L_ * J
/- + D + T + A + U-i r
(1 - G)
(r + D + T + A} r
(1 - G)
TYPICAL PARAMETERS
0.0675
0.0615 Cp
0.0675 CB
On^ftft r
0.0321 Cp
-0.00583 Cp
0.2313 Cp using Ts,
0.2076 using TN,
0.2006 using Tp
0.2083 CB
-------
APPENDIX C
COMPUTER PRINTOUTS OF FGD SYSTEM COSTS
FOR THE MODEL PLANT ANALYSIS
C-l
-------
STC< 2bO US KLTKOF1T
LlhECT COSTS
PKEPAKAIION
.CONVEYORS
STORAGE SILO
PUWPS AND MOTORS
_STp!ur. P S-.AN P._MO.Tp.RJS.
SLUO&E POfviU
MOBILE EGUIPMEMT
.TOTAL C =.
201302.
190354.
7328.
2bb75.
51468,
1033U21.
bfa740.
I). PAKTICULATE REMOVAL
VEWTURI SCKUBBEK
_TAIiKS
PUMP'S AND MOTORS
"TOTAL7"o~-
o.
o.
o.
o.
COSTS" FOR LIMESTONE FGD SYSTEM FOR 250 MW/3.5% SULFUR/RETROFIT MODEL PLANT
-------
GKANO TOTAL FUR IliSTALLLU UlKEtT CbST^
******»***************»**<
, **********
IN01KECT COSTS
DUKIMG CONSTRUCTION
FIEl-0 OVERHEAD
CONTRACTORS FEE ArJO EXPENSES
___ __
FKEIhHT
_ OFFSlTt
TAXEs
SPAl,}34.
171604.
S7201.
b7i:Ul3.
b 1 1 fa 9 7 0 .
3371419.
~ -------
2022bo94.
4267.
60.91
-------
OI'LKAI llMli
f'uK Lli-lLbTuNL bLKUbUINb b
A. HAW C,A1LKIAL
FIXATION CHEMICALS
D.. . UTILITIES
ELECTRICITY
WATEK
KCHLAT
UUAN1ITY
11.0
TON/H
_3183,_ .KW.
82.5 GAL/MN
36.6 MM bTU/H
UNIT COS!
b.oo I/TON
2.0U S/TON
15.0 nlLLS/KWH
O.Olo i/MGAL
0.761* $/MM bill
ANNUAL COST($)
_251003._
"
C. OPEKATING LABOR
DIRECT LABOR
2 MEN/DAY
8.00 i/MANHUUH
IbSi OF UIKIiCT LAbOK
140160.
O
LABOR ANO MATERIALS
SUPPLIES
OVEKhF.AO
PLANT
RAYKOLI
H* OF FIXED INVESTMENT
Ibfc OF LABOR AND MATERIALS
5056 OF OPERATION AND MAINTENANCE.
208. OF OPERATING LABOR
809117.
121372.
515851.
32236.
F. FIXEo COSTS
DEPRECIATION
_INTE«IM REPLACEMENT
TAXES
.INSURANCE..
CAPITAL COSTS
TOTAL FIXED CHARGES
&.£>&%
0.35S
1.00%;
0.3 %
9.00%
20.31%
1109796.
TOTAL ANNUAL COST
6810011.
MILLS PER MLOWATT-HOUR
5.18
-------
PLA^T MAf'.c.-
STO 250 HS
DlKtlCT COSTS
.. I ilfl-S T-0 Ivi i_HkEEAKAXiO N_
CGfvvLYORS
STORAGE-SILO
BALL MILLS
-£Un HS-A ivO~!4 O-I-OHS-
rtbt; TA.MIvS
TOTAL A =
351219.
1173501.
I
<£_
SCRUBBING
FANS AND MOTORS
-gimps AND iviC|T0RS
TANKS
-Ki.HCfi.TEkS
SOOT bLOWERS
,-OUCTIlVG. A,4a_.
TnT'[_ f =
342755.
233586.
271936.
.961123._
-C.. SLUOGE^.DISPOSAt...
CLAKIFIL'KS
-VACuUf, FILTLRS
TANKS fit-iD KIXE.RS
-FIXAT.lOt-i ChLi1ICAL_STjQ&AGE
PUF'.PS A.xiD MOTORS
t-.-PQNU
MOkiJLE EQUIPMENT
TOTAL C =
1U0136.
. ..180567..
1890471.
PARTICULATE KCMOVAL
. V'ENTIJRI..SCKUSbEli
TANKS
BiiKP^ QMt.
0.
0.
J.O.T-AI 0_s 0.
CQSff-S FOR LIMESgQNE-fGD- SYSTEM -FOR-2 50 -MW/J-.-5*- -SWJUR-/NBW
-------
TOTAt INSTALLED DlKLCf COSTS =
**********».
INDIRECT COSTS
DURING CONSTRUCTION
RHEAD ......
COMIKACTORS FEE AND EXPENSES
FRElGHT
OFFSiTE -
SPARES
FOR SHAKEDOWN
TOTAL INDIKECT COSTS =
CONTINGENCY
TOTAL INSTALLED COSTS =
-TOTAL- HORSEPOWER
COST PER KILOWATT
9t0659.
9
-------
OPERATING COSTS FOK LIMESTONE SCRUBBING SYSTLM
A, RAW r-,ATERU>L
LIMESTONE
FIXATION
10.6 TOM/h
3 £ i TI \ i\i / l-i
UNIT COST
6.00
2 Qu 1-^J.0J-l_
ANNUAL COST(S).
33691*5,
B. UTILITIES
ELECTRICITY
3060. KW
15.0 hILLS/KWH
OQ16
REHEAT
35.5 l"ih bTU/H
0.76"* »/Hh faTU
.S.00 S/MflMHOUA.
SUPEijCE
CAPITAL COSTS
TOTAL F1XE13 CHARSf-S
0.35'A
H.OOi
0.3 %
3079504,
TOTAL..ANNUAL COST
5H90&96..-
MILLS PER >>ILOulATT-HOUR
t.17
-------
STD 25U LS KLTKOFIT
DIKLCT COSTS
LIKESTC/KE PREPARATION
.COfviVf.YORS.
STOKAL.E SILO
JLALL MILLS
PUI",PS AND MOTORS
_STORAbE TANKS
_.TC_TAL..A._=_. .
529U26.
76951.
1126113.
SCKUBQING
AbSORBEKS
FANS AM) MOTOKS
PUMPS AND MOTORS
TANKS
REHEATEhS
Y SOOT tfLOVoERS
00 DUCTliviG AND VALVES
4079199.
400327.
2fa2i>98.
88b763.
299U40.
, ...ff""":
TOTAL B =
SLUDGL DISPOSAL
CLARIF-IEHS ________________
VACUUM FILTERS
TANKS AND MIXERS
FIXATION CHEMICAL STORAGE
SLUDGE PONO
_NOBILE .EQUIPMENT
_TOTAL. .C. =
102071.
217008.
17413.
955189.
0.
PARTICULATE REMOVAL
SCRUBUEK
TANKS
AND MOTOKS
0.
0.
0.
TOTAL D = 0.
COSTS FOR LIMESTONE FGD SYSTEM FOR 250 MW/0.6% SULFUR/RETROFIT MODEL- PLANT—
-------
GKANU TOTAL FCK INSTALLED OIKECT COSTb = l Ub236i! 1.
INDIRECT COSTS
1NTEKEST UUKlNb CONSTRUCTION
OVERHEAD
FE1E AlxiU EXF'E.NStS
FREIGHT
OFFbiTt.
TAXES
FOK SHAKEDOWN
n
i
TOTAL INDIRECT COT S =
CONTINGENCY
TOTAL INSTALLED COSTS =
TOT.AL..HORSLPOWEK .
Illbb25.
bb77fc2.
157o57.
b\ibl9.
52bl91.
t985029.
3101370.
10606i;20.
COST-DOLLAKS PEK KILOWATT 74.13
***************»*******«***|t********>******* ******
-------
CI'LKAllUb LUSTS (-UK LliSLSlO(\;L liCKUlibiNO
A. RAW MATLKIAL
FIXATION CHEMICALS
UUANT 11 Y
2.8 TON/h
fa.9 TON/H
UNIT CUt.T
(..on S/TON
il.OC i/TON
ANNUAL COST(S)
72924.
.B. .UTILITIES
ELECTRICITY...
WATEh
2^66. KUi
8^.1 GAL/MIM
36.6 MM DTU/H
15,0 MILLS/KWH
O.OlU i/rfbAL
U.76"* 4/Hi"l bTU
233905._
C. OPERATING LABOR
DIRECT LABOR
2 MEN/DAY
6.00 $/^AUHOUR
Ib4, OF DIKLCT LABOK
140160.
21024.
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
485 UF FIXED INVESTMENT
158. OF LABOK AND MATERIALS
744328.
111649.
E. OVERHEAD
PLA^T
PAYROLL. ...
5CS OF OPERATION AND MAINTENANCE
20S OF OPERATING LABOR
508581.
32236.
F. FIXEo COSTS
DEPHE.CIATIuN
INTERIM REPLACEMENT
.INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
4.00%
0.3 ^
20.31%
3780570.
TOTAL ANNUAL COST
5632672.
MILLS PER KILOWATT-HOUR
4.47
-------
PLAM
STQ £50 LS
... UIHEXT-_CGSTSr
AR AT I G
COhVEYCRS
-STORAGE-S1LCX
HALL ISILLS
Pl^'.PS AND fiOTORS
STORAGE TAT.'KS
TOTAL A =
31<+.3fo2.
47313.
O~
SCRUBBING
-ABSORBERS
FA'MS AiVO MOTORS
-jaimnS—AfeUj MOTORS
TANKS
SOOT
TOT/vLB~
i si i n7 1
233b8b.
27193&!
^ SLUDGE-DISPOSAL.
CLAKIFIE.RS
-VACUUM FILTERS 19B071..
TAi\KS AiMD MIXERS 3>798.
.FIXATION CHEM1CAL_SIQRAGE ... 15755..
PUP"PS AND MOTORS 23702.
MO&ILE EQUIPMENT
TOTAL C =
1104566.
PARTICULATE REMOVAL
TAKKS
PUMPS
0.
0.
"OTQBS
-TOTAL Q~- . . 0. . .
COSTS FOR LIMESTONE FGD SYSTEM FOR 250 MW/0.6% SULFUR/NEW MODEL PLANT
-------
TOTAL INSTALLED L>I*LC1 COSTS =
6370*06,
*************************************************
INUIKECT COSTS
INTEREST DURING CONSTRUCT ION
FIEL^ OVERHEAD -
CONTRACTORS FEE AMU EXPENSES
FREIGHT
OFFSjTC
SPAKES - • -
ALLOWANCE FOR SHAKEDOWN
TOTAL INDIRECT COSTS =
CONTINGENCY
TOTAL INSTALLED COSTS =
837020.
837620.
__B37a2Q»_
104727.
251346.
•UtoSlO.
11703753.
TOTAL -HORSEPOWER
3665.
COST HER KILOWATT 56,
*********************»**************•».************
-------
OHU
T.OTAL ANNUAL COST.,
MLLS PER KILOWATT-HOUR
-------
PLA^T MAf.E- .
STD 50U
US RETROFIT
L/1KLCT GUSTS
LIMESTONE PREPARATION
.CONVEYORS
STORAGE. SILO
_UALL_cJl LkS
PUKPS ANO MOTORS
bb2b66.
107o91.
230265.
__T_QT.A.L .A._=
1820912.
B.
SCRURBINti
TOTAL B =
1572799t.
SLUDGE. DISPOSAL
CLARIFILRS
VACUUM FILTERS
TANKS AND illXEKS
FIXATION CtlEMlCAL STORAGE
PUM P S_A N D _ r, p TO_K_S
SLUDGE POND
MOL'ILE EOUIPMEIMT
280102.
19b232.
9707.
ibafcl.
83126.
1661050.
AbSORBtRS
FAI\IS A(MD MOTORS
PUMPS AND MOTORS
TAfMKS
RtHEATE.KS
Q SOOT BLOWLRS
1 DUCTING AND VALVES
M
78822^9.
789015.
336b33.
4fa7u75.
1711567.
41US60.
t09097t.
TOTAL C =
2323821.
PAKTICULATE REMOVAL
SCRUBBER
TANKS
PUMPS AND MOTORS
0.
0.
0.
TOTAL D = 0.
COSTS FOR LIMESTONE FGD SYSTEM FOR 500 MW/3.5% SULFUR/RETROFIT MODEL PLANT
-------
TOTAL FOR INSTALLED DIRI.CT cobTS=i9672727.
INDIRECT COSTS
INTEhEST DURING CONSTRUCTION
FIELD OVERHEAD
CONTRACTORS FEE AMU EXPENSES
FREU-HT
_______________ _____ ; OFFSiTEI
TAXES
ALLOWANCE FOR
TOTAL IIVDIKECT COSTS =
O
-I—
CONTINGENCY.
TOTAL INSTALLED COSTS =
...TOTAL.. HOkSEHOlwER
210fa309.
1U53254.
202/U16.
24B409.
29dU90.
99363.
993636.
COST-DOLLARS PER KILOWATT
9409736.
585b492.
36138957.
7972.
70.27
-------
OPERATING CuSTS FOR LIMESTONE SCRUHblUU SYSTEM
A...RAW.MATERIAL
FIXATION CHEMICALS
@_» UTILITIES
ELECTRICITY
WATEh
UUANTlTY
21.3 ToN/H
52.2 TON/H
5947. KU
lt»9.4 GAL/NIN
70.6 MM bTU/H
UNIT CUbl
6.00
2.CO S/TON
15.0 MILLS/KWH
0.010 i/MGAL
0.764 S/MH bTU
ANNUAL COST<$)
673679._
~54~9157.
J*68925.
950.
2faH707,
C. OPERATING LAbOR
LABOR 2 MEN/DAY. 8.00 i/MAUhOUK
SUPERVISION 15s. OF UIKECT LttBOK
F. MAINTENANCE
IABOR AM; fiATtRIALS "t» OF "FIXED INVESTMENT
SUPPLIES .... iss OF LABOR AND MATERIALS
.
E. OVERHEAD
PLANT boji""b"F" "OPERATION ANU "MAI'NIENA'NCE
PAYROLL __ 2U* OF OPERATING LABOR
FT FIXED COSTS
DEPRECIATION 5.0USS
INTERIM REPLACEMENT 0.355S
TAXES H.OOK
INSUKANCE._ 0.3 %
"CAPITAL COSTS 9.oca
140160.
21024.
X405558.
210833.
688788.
32236.
TOTAL FIXED CHARGES
6553415.
TOTAL ANNUAL COST
11229437.
MILLS HER MLOwATT-HOUR
4,27
-------
PLANT MANE-
STO 500 HS
DIRECT CuSTS
_LmEST-OWE. PKEPftRATION
CONVEYORS
-STCKAGt SILO
BALL MLLS
_fiU#pS-ftND f.-,c^I-aH5
STORAGE TAiiKS
TOTAL A =
399990.
9bb87.
1513*56.
SCRUBBING
AtSORbLKS
FAMS AND MOTORS
PUiv-PS /•, ;\j Q i"i Q T 0 R S
TA;*JKS
-REHE
SOOT BLOWLKS
r^.AfMD_VAL-V-ES-
T 0 T >\ L B ^_
703UH81.
670^77.
407^0'*.
C._._._ SLUUGE..DISPOSAL.
CLARISIEKS
VACUUM FILTERS ...
TANKS AND MIXEKS
FIXATION CHEMICAL STOKAbE
PUf'iPS AfJD MOTORS
MOBILE EQUIPMENT
TOTAL C =
177603.
o745.
3i:196.
-Xai6.7J£u^.
5341b.
D. PARTICIPATE KEMOVAL
. _ ..VLi'JTUKI SCKubBE-K
TAf-KS
piiMps AMU HnTLiks
XO.TJVL U = .
0. . . .
C.
o ,
o.
COSTS FOR LIMESTONE FGD SYSTEM FOR 500 MW/3.5% SULFUR/NEW MODEL PLANT
-------
TOTAL INSTALLED DlKECT COSTS =
IfjDlKECT COSTS
IWTEfjLST DURING CONSTRUCTION Ibfabbdb.
FIEL(.: -OVERHEAD - 16bbb85.
CONTACTORS FEE At\iD EXPENSES 832792.
ENG-ItxCLR-UOG . Lfafaib65_
FHElGHT 206190.
_ OFPSjTtL. .. ... ......_._.... t9«Jo75.
TAXES 2t9637.
SRARtS 03279.
ALLOWANCE FOR SHAKEDOWN 832792.
TOTAL INDIRECT COSTS = 7703331.
_Q CONTINGENCY . - - - 1871636.
M
TOTAL INSTALLED COSTS = 29231020.
TOTAL-HORSEPOWER _ .. 7609.
COST PER KILOWATT 58.
****:|^**********************»********************
-------
OPERATING COSTS FOR LIMESTONE. SCRUbbING SYSTEM
A. RAW MATERIAL
LIMESTONE.
UUANTllY
20.9 TOU/H
-bl^-1 TON/h
UNIT COST
6.00 4/TON
-_2..-Q-0 sy TON-
ANNUAL COST(S)
659261,
B. UTILITIES
ELECTRICITY
WJX-TCw
REHEAT
5626. KW
MM BTU/H
15.0 MILLS/KWH
£U 01*—-i/fiGAI
0.7bf i/HM BTU
t5932S.
279267.
C.---OPERATIMG-LABOR
^ ADOR
SUPERVlSlOi\j
-D.. — MAINTENANCE
I AROH Afcfl M&TFKTALK
SUPPLIES
E-.._. OVERHEAD..
>i OF CilKECT LABOR
2102t.
OF FIXED INVESTMENT
OF LAbOR AND MATERIALS
NTENANCE
1169240.
175586.
7529Q5t
PAYROLL
F, FIXLb COSTS
nrpRFClATiorj
INTERIM REPLACEMENT
TAXES
INSURANCE
- _ CAPITAL COSTS
TOTAL Fivrp CHARTS
20S OF OPERATING LABOR 32236.
5.00-^
0.35*
4.00S
0.3 %
9.00^
18.65K 54515Q5.
TOTAL ANNUAL COST .
__9678736.
MILLS PER KILOWATT-hOJR
3.68
-------
PLANT NAME-
S'! U 'jUO Lii HLIKUf II
UlKECf Co-STS
LIMESTONE PREPARATION
CONVEYORS 449529.
STORAGE: SILO 6o24«.
BALL .BILLS 555665.
PUMPS ANO MOTORS 97191.
.STORAGE.TANKS. .._.._ 56695.
.TOTAL. A. =. ._.. 1219530.
J3_. SCRUHBIMG.
"AHSORUERS "
FATviS AiMU HOT.OKS 789015...
PUMps AMU MOTOKS 33db33.
TANKS.. . _ 467075.
REHEATEKS 1711567.
S.OQT .BUO.WEHS ._ ^tabto.
DUCTING AND VALVES t09097U.
TOTAL B _ 1572799*».
~C.SLUDGE DISPOSAL"""
CLARIFIERS „_ _...._ 1H2090.
VACUUM FILTERS ~"" " 204055.
TANKS AMD MIXERS _ 5503.
FIXATION CHEMICAL STOWAGE 20062.
PUHPJS_ANU_MOT_ORS H<«bi6.
SLUDGE PONO 842615.
MOBILE EQUIPMENT 58740.
__TOTAL .C..=
1316385.
PAKTICULATE REMOVAL
VENTURI SCRUtlBEK
...TANKS
PUMPS AND MOTOKS
"T'OT'AL "D ~="
o.
o.
o.
o.
"COSTS"FOR LIMESTONE FGD SYSTEM FOR 500 MW/0.6% SULFUR/RETROFIT MODEL PLANT
-------
GkAND TOT/.L FOR INSTALLLO OIKF.LT COST S =
INDIRECT COSTS
INTEREST UURIMG CONSTRUCTION
FIElLu OVERHEAD
CONTHACTORS FEE ANO EXH'.NSES
ELNG liSiEEB. 1I1&_
______________ OFFilTL
TAXES
________ SPARES
FOR SHAKEOOWlM
I
to
-1-*-
TOTAt INOIKFCT COSTS =
..CONTINGENCY .
TOTAL IlMSTALLEU COSTS =
TOTAL HORSEPOWER^
COST-UOLLARS PER KILOWATT
182fab91.
1936106.
1663122.
226323.
517977.
91329.
913295.
5382963.
"32297702 J""
7395.
-------
OHLKA1
A. KAW P.AILKIAL
LIMLSTUNE
FIXATION CHEMICALS
(JUAMITY
3.4 TOU/H
13.4 TON/H
COST
6.00 S/TON
2.00 I/TON
ANNUAL COST(S)
173359.
I«fl315.
..B._.UTILIT1ES. ..
ELe.ClB.lC.IJ.1L
WATER
RCMEAT
5517. KW
(iAL/MIN
70,tt MK BTU/H
15.U hlLUS/KWH
0.010 S/MGAL
0.764 */«M 6TU
134970.
y»9."
264707.
C. OPEKATING LABOR
LABOR
SUPERVISION
2 MEN/LAY
8.00 i/MANHOUR
IbSb OF UIKC.CT LABOK
140160.
21024.
O
-4—
to
0.
LABOK AND KATERIALS
SUPPLIES
E. OVERHEAD
PLANT
FAYHOLI
4S OF FIXEO INVESTMENT
OF LAbOR AND MATERIALS
50S OF OPERATION ANO MAINTENANCE
204 OF OPERATING LABOR
1291911.
193766.
32236.
F. FIXED COSTS
DEPHtCIATION
liMTERIM.REf.LACLMENT.
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
3.00%
0.35S*
4.00%
0.3 *>
9.00i8
6023536.
TOTAL ANNUAL COST
9561398.
MILLS PER KILOWATT-HOUR
3.63
-------
PLANT NA^E- STU 500 LS New
UlKLCT COSTS
COIWEYOKS 326471.
STORAGE SILC — b4459.
BALL MILLS 504205.
,-Mfj-TQR-£-
STOKAGL TANKS
TOTAL A = 1016234.
B. SCRUBBING
ABSORBERS
FAKS AND MOTORS 670277.
pnypg AMC MQTnR-S . 2.64.5.2SU.
TANKS
REHEATERS
._. SOOT BLOWERS 407904.
l|i OU.C.T IN.G ..A^U...VALVES 2254706 ^
to
W TOTAL U =
_CL. S.UUOGE.D.ISP.OSAU
CLARIFIERS 127768.
VACUUM FILTERS 1U6552.
TAI^KS Ai\iO MIXERS 4960.
FlXATlCU CHEMICAL .STORAGE __. _.. .16135...
PUMPS AND MOTORS
SL
MOBILE EQUIPMENT 53416.
TOTAL C = 1429678.
PARTICULATE REMOVAL
VENTUKI SCKUBBER 0.
TANKS 0.
PUMPS AI\iD hOTORS D.»_
JTOTAL-O-S . . - 0.
COSTS FOR LIMESTONE FGD SYSTEM FOR 500 MW/0.6% SULFUR/NEW MODEL PLANT
-------
TOTAL INSTALLED DIRECT COSTS =
i502UU7fl.
****************************
INUIRECT COSTS
INTEREST DURING CONSTRUCTION 1502007.
FIELo OVERHEAD - - 1502007.
CONTRACTORS FEE A NO EXPENSES 761003.
-£WGl,JEeH-tW6 1502007..-
FREIiHT 187750.
OFFSiTE -— -- -- - 150602.
TAXES 225301.
SPARES- - - -- 75100.
ALLOWANCE FOR SHAKEDOWN 751003.
TOTAL INDIRECT COSTS = 6946766.
CONTINGENCY - - .4393i72.
TOTAL INSTALLED COSTS = 26360237.
TOTAL-HORSEPOWER ...._. . ... 7260.
COST PER KILOWATT 52.
*************************************************
-------
CPE.KATING COSTS FOK LIMESTONE bCRUB&IiMG SYSTEn
A. RAW MATERIAL
tUAIwTITY
5.3 TOIO/M
8. UTILITIES
ELECTRICITY
5116. KW
ur.n COST
b.OO S/TON
2.UU-—
15.0 MILLS/KWH
0 -, 0-18 $y-W6AU
ANNUAL COST(S>
169561.
437025.
REHEAT
fa9.<* MM BTU/h
0.76H $/«M BTU
2792fa7.
-C. OPERATING-LABOR
MKM/nAY
.J) n
158i OF C'.IRECT LABOR
21021.
0.-- -MAINTENANCE
__ Af'jp MATERIALS
OF FlXEil
SUPPLIES
158i OF LABOR AND MATERIALS
153161.
-RLAK-T
FAYKuLL
^, OF OPERaTIOM flMD MAINTENANCE
666677.
2CJS OF OPERATING LABOR
32236.
_ FIXEu.COSTS__
I.'-JTERIM REPLACEMENT
TAXES _______
INSURANCE
CAPITAL-COSTS-^
0.35*;
1.00£
U.3 £
9.00?d
-TOTAL FIXED CHAKEFS-
4916181,
TOTAL ANNUAL COST
OQ2.1058i.._.
MILLS PER KILOWATT-HOUR
3.05.
-------
PLANT NAKE-
STD 1000 HS RETROFIT
LIMESTONE PREPARATION
CONVEYORS
STORAGE SILO
BALL MLLS
PU;viPS AND' MOTORS
STORAGE TANKS
TOTAL A =
B. SCRUBBING
ABSORbERS
FANS AND MOTORS
PUMPS AND MOTORS
TANKS
REHEATERS
SOOT BLOWERS
DUCTING AND VALVES
O
I TOTAL B =
to
C. SLUDGE DISPOSAL
CLARIFIERS
VACUUM FILTERS
TANKS AND MIXERS
FIXATION CHEMICAL STORAGE
PUMPS AND MOTORS
SLUDGE POND
MOBILE EQUIPMENT
TOTAL C =
D. PARTICULATE REMOVAL
VENTURI SCKUBBEK
TANKS
PUMPS AND MOTOKS
TOTAL 0 =
693215.
" 166838. ... -
9192i>0.
4l488i.
540613.
2736799.
-
,
15463305.
15"*7876.
712644.
966654.
33S7723.
1046640.
9997973.
33094217.
391063.
193601.
13053.
£>fe22£.
14b690.
23ye09».
58740.
3457471.
u.
0.
u.
0.
COSTS FOR LIMESTONE FGD SYSTEM FOR 1000 MW/3.5% SULFUR/RETROFIT MOUh^
-------
GRAND TOTAL FOR INSTALLED DIRECT COSTS=39268488.
1NUIKLCT COSTS ~~
INTfc-REST DURING CDf-lbTKUC I ION
FIELD OVERHEAD
TR E TG H T
OFFSiTE
TAXt-S
SPARES
"ALTWATJCT
TOTAL ISTDIRECT CO~STS"
20622897"
tooy'+as.
^9iioer
1178654.
5B5327T"
19&H42.
O
CONTINGENCY
"TOTAL rN"S
COSTS =
11578317.
TOTAL HORSEPOWER
KILOWATT
15351,
-------
OPERATING COSTS FOR LIMESTONE SCRUBBING SYSTEM
A. RAW hATERIAL
LIMESTONE
FlXAtlCW'CBEMlCALS"
"-QUANTITY""
tl.8 TON/H
102.2 TON/H
UNIT COST
6.00 */TON
2.00 S/TON
ANNUAL COST(S)
1318526.
1074812.-
B. UTILITIES
ELECTRICITY 11<»52. KW 15.0 MiLLS/KWH 902883.
fcWTEK ~ J12;7 GAL/MIN " 0.018 S/MGAL 1864.
REHEAT 136.9 MM BTU/H °_>76JL_l./'lfl EI^1 55653f.
~CT~ OPERATING" LABOR~' '" ""' " " "
DIRE1CT"LABDR ~ 3""HEN/DAY "'" " 8.00 S/MANHOUR —r" 2102<«0.-
SUPEKVISION 158S_ OF IJlRf^TJ-^BOR _3jL5i5_l
"DV""~MAINTENANCE ' - --. .- .. -
L ABOK "ANCTITATER lAtTS : "»K OF FIXED INVESTMENT " 2778796-.-
SUPPLIES ISK^OF LABOR AND MATERIALS f!6819.
~ET~ "OVERHEAD " "" ~
PLANT ! 50So"X)F-OPERATION ANIT'MftlNTENANCE-- r7rB6"95T"
PAYRQLL 20a OF OPERATING LABOR t6355.
~T~. FIXEcTCOSTS
nm svrros ' •
REPLACEMENT 0.35%
TAXES4.00S
JNSURANCE 0.3 %
"TOTAL FIXETT~CTiAK5E5 1B.&5%
nrrsL~ANwoAU"T:osT
MILLS PER KILOWATT-HOUR
t.18
-------
DIRECTCOSTS=323^3031.
--»**-*-* *"*^*v* *******************"*******************
...... ----INDIRECT COSTS- —
COWSI KUCTIOT3 3231 303";
FIELD OVERHEAD 3234303.
CONTRACTORS-FEE' ANCrrXPENSES ' --------------- ...... --------- 1617151.
ENGINEERING 3231+303.
:~FRElGHT "~ ...... " 40H267.
OFFSiTL __ ____ 970290.
T'AxTs '
SPAKES 161715.
...... ' 1617151.
TOTAC~INDIRECT~C'OSTS~=
CONTlNGENCY
o
N> T OTA L~I NS T ALLE cTCfO"Srs~~=56762020.
vo
TOTAL HORSEPOWER 14858.
TO~ST-. DOLL AR'STPrfTKTl.O WATT 5"6776
-------
PLANT N/Vf,l -
iTU 10UO Mf. NLW
JjIRECT COSTS—- -
A. LIMESTONE PREPARATION '
CONVEYORS
STORAGE. SILO
BALL MILLS
PUMPS AND MOTORS
STORAGE TANKS
TOTAL A =
B. SCRUBBING
AbSOKBERS
FANS AND MOTORS
PUMPS AND MOTORS
TANKS
REHEATERS
SOOT BLOWERS
DUCTING AND VALVES
o
I TOTAL B =
u>
C. SLUDGE DISPOSAL
CLARIFIERS
VACUUM FILTERS
TANKS AND MIXERS
FIXATION CHEMICAL STORAGE
PUMPS AND MOTORS
SLUOGE POND
MOBILE EUUIPMENT
TOTAL C =
D, PARTICULATE REMOVAL
VENTURI SCRUBBER
TANKS
PUMPS "AND" MOTOKS
*»97162.
i«*97<+b.
823212.
327277.
«»672J*2.
2261671.
lie>ui)211.
1297030.
518502.
8196,66.
29bH2b1.
815608.
6bb06ba.
26571333.
350357.
1/blO I .
11690,
t9665.
117090.
27^8^98.
5ifl6.
3507026.
0.
0.
0.
TOTALl) =
0.
COSTS FOR LIMESTONE FGD SYSTEM FOR 1000 MW/3.5% SULFUR/NEW MODEL PLANT
-------
OPERATING COSTS FOR LIMESTONE SCRUBBING SYSTEM
0
1
U)
M
A. RAW MATERIAL
LIMESTONE
FIXATION CHEMICALS
B. UTILITIES
ELECTRICITY
WATER
REHEAT
C. OPERATING LABOR
DIRECT LABOR
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
E. OVERHEAD
PLANT
PAYROLL
F. FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
QUANTITY UNIT COST ANNUAL COS! IS)
HO. 4 TON/H 6.0U 5/TON 1274577.
98.8 TON/H 2". 00 "S/TON . - j.038985.
11084. KW 15.0 MILLS/KWH 873881.
302.6 GAL"/PI1N 0.016 5/PIGAL 1803.
134.4 MM BTU/h 0.764 i/MM BTU 540400.
3 FILN/UAY 8.00 4/MANHOUR 210240.
1555 OF DIRECT LABOR 31535.
.
4S OF FIXED INVESTMENT 2270480.
15S OF LAbOR AND MATERIALS 340572.
bOfc OF OPERATION ANU MAINTENANCE 1426414.
20fe OF OPERATING LABOR 48355.
5.0 OS
0.3555
4.00%
0.3 K
9. DOS" ' " " "
16.65K I0ti6bllb.
TOTAL ANNUAL COST ' " 18643363.
MILLS PER KILOWATT-HOUR 3.54
o
-------
PLANT NAME- STD 1000 LS KETROFIT
D"I R ETCT~CO"ST5="- - -
CIWESTONE-PREPARATION—
CONVEYORS
"STORAGE SILO"
BALL KILLS
"PUMP S~A N D~ M OTOTCS"
STORAGE TANKS
TOTAL A =
483226.
75966.
600294.
•16110"*.
101897.
SCRUBBING
ABSORBERS
FANS AND MOTORS
PUMPS AMD MOTORS
TANKS
REHEATERS
SOOT BLOWERS
DUCTING AND VALVES "
o
1 TOTAL B =
U)
15463305.
1547876.
712044.
968654.
33!>7723.
1046640.
9997973.
33094217.
CLARIFIERS
VACUUM FILTERS
TANKS ANU MIXERS
FIXATION CHEMICAL STORAGE
PUMPS AND T10TORS
SLUDGE POND
MOBILE EQUIPMENT
TOTAL C =
196732.
19flb2i!.
7250.
25296.
70309.
1317616.
58740.
1&76468.
PARTICULATE REMOVAL
"VENTURI S'CWJD3ETT
TANKS
0.
"PTJWPS AND MOTORS
TOTAL 0 =
COSTS FOR LIMESTONE FGD SYSTEM FOR 1000 MW/0.6% SULFUR/RETROFIT MODEL PLANT
-------
o
1
oo
OJ
• GRAND TOTAL FoR INSTALLED DIRECT
*********************»***************4
INDIRECT COtJTS----
1NTEKEST DURING CONST RUC1 IUN
FIELo OVERHEAD
CONTRACTORS FEE AND EXPENSES
ENGINEERING
•FREIGHT
OFFSITE
7AXE-S
SPARES
ALLOWANCE FOR SHAKEDOWN
TOTAL INDIRECT COSTS =
CONTINGENCY
TOTAL INSTALLED COSTS =
TOTAL HORSEPOWER
COST-DOLLARS PER KILOWATT
•c"OSTS=36i»'01177.
t***********
ibHOll 1 .
aesabz1*.
19i9ibi.
5712920.
4bb01!4.
1092035.
S46U17.
182U05.
1620058.
172^5^57.
10727427.
&';ib'*5&2.
14236.
64. 5fa
-------
OPERATING COSTS FOR LIMESTONE SCRUBBING SYSTEM
QUANTITY
A. RAW MATERIAL
LIMESTONE
"FIXATION" CHEMTC'ALS "
10.7 TON/H
"26.2 TON/H
B. UTILITIES
ELECTRICITY
WATER -"
REHEAT
10620. KW
3I"2.6~~"GAU7
138.9 MM 8TU/H
UNIT COST
6.00 S/TON
2.00 S/TON
15.0 MILLS/KWH
0.018S/MGAL
0.761 S/MM 3TU
ANNUAL" C0STT5T
339122.
276139Y-
837334.
1863V
558531.
C.~-""OPERATING~ LABOR
DTR ECT"LABOR
SUPERVISION
"3—MEN/DAY
-- 8.00 S/MANHOUR
15* OF DIRECT LABOR
210210V
31535.
TJ-; MAI N T EWA NC ET"
'"LABOR
SUPPLIES
" UK OF FIXED INVESTMENT-
15S OF LABOR AND MATERIALS
2571582V
386187.
n
I
00
""OVERHEATT'
'IPLAMT 7
PAYROLL
OF OPERATION AND" HAINTENANCE-
20% OF OPERATING LABOR
-T.601272.
18355.
INTERIM REPLACEMENT
TAXES
INSURANCE
TOTAL FIXED CHARGES
0 . 35%
0.3
-9YOOS
10.65%
-1700J990V
'TOTAL~ANNUAL~ COST"
T.-8869159.-
MILLS PER KILOWATT-HOUR
3.59
-------
"**»*********V* ***********************************
•---«-! NDI RECT"COSTS----
FIELD OVERHEAD
CONTRACTORS FEE AND EXPENSES
ENGINEERING
FKE.IGHT
OFFSiTE
SPARES
"•ALLOWANCE FOR SHAKEDOWN '
1 2964845; " " ~" "'"" ' '" " " "
"1482422. ~ "' '
.2964645.
370fe05. " " " " "
869453.
444726.
146242.
1482422. • • •-• -- -• - --
) T A L T N DIR ECT~COST S~=
O
CONTINGENCY
8672172.
52033033.'
TOTAL HORSEPOWER
13787.
~C0STVcrotiTARS~PER KILOWATT
52. T) 3^
-------
PLANT NAf,C-
STO 1000 LS
IMLW
-CIIRE.CT C05TS----
CONVEYORS
BALL HILLS
~PW.PS~XlTO
STORAGE TANKS
319856.
"68lOt.'
500.
22678.
56689.
~l"3T938«r
VACUUM FILTERS
TANKS AND MIXERS
"FIXATION rHEMICAL~~3TOKA5ir
PUMPS AND MOTORS
~"STU 0 G E~P O'ND
M05ILE EQUIPMENT
TOTAL C =
18915«H.
D. PARTICIPATE REMOVAL
VENTURI SCRUBBER
TANKS
PUMPS AND MOTORS
0.
0.
o. --
TOTAL 0 =
COSTS FOR LIMESTONE FGD SYSTEM FOR 1000 MW/0.6% SULFUR/NEW MODEL PLANT
-------
OPERATING COSTS FOR LIMESTONE! SCRUBBING SYSTEM
A. RAW MATERIAL
LIMESTONE
FIXATION CHEMICALS
B. UTILITIES
ELECTRICITY
WATUt
REHEAT
C. OPERATING LAbOK
DlKt-CT LABOK
SUPERVISION
D. MAINTENANCE
LAUUR AND MATERIALS '
SUPPLIES
0 E. OVERHEAD
OJ PLANT
-J PAYROLL
P. FIXED" COSTS
DEPKECIATIOM
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
"
UUANTIIT UNIT CCJiJT
10.3 TON/H 6.00 S/TON
25.4 TON/H 2.00""S7TON
10285. KW 15.0 MILLS/KWH
302.5 GAL/MIN 0.016 4/MGAL
131. <» MM BTU/H 0.76t S/MM BTU
3 MEN/DAY a. 00 3./MANHOUR
15K OF DIRECT LABOR
t& OF FIXED INVESTMENT
15S OF LABOR AND MATERIALS
SOK OF OPERATION AND MAINTEMANCE
20* OF OPERATING LABOR
5.00%
0.35^0
4.00%
0.3 %
9.00%
16.65%
TOTAL ANNUAL COST - -. .
MILLS PER KILOWATT-HOUR
ANNUAL LObl JS)
327795.
267<;ub. ' '
810910.
1603.
540400.
210240,
31535.
2U81321.
312198.
1317647.
40355.
97041bO.
15&55S74.
2.97
-------
PLANT
STD 1000 LS NEW
i-.-PIRECT'CaSTS1
"A".' 'NA2C03 PREPARATION
STORAGE SIUO
VIBRATING 'FEEDER' ' " " '
STORAGE TANK
AGITATORS ' -
PUMPS + MOTOR
TOTAL A =
4533.
47021.
16126. -
1456.
117605.
S02 SCRUBBING
e-
FANS + MOTORS
'PUMPS + 'MOTWS"
REHEATERS
ISOOT^DLUWETRS
DUCTING
VALVES
TT917550T"
16JJ133.
~ 524419.
3131510.
—2175488V
"28^36069.
PUKGE TRLATMENT
REFRIGERATION UNIT
b09ttbl.
HLAT EXCHANGER
TANKS
UKYER
ELEVATOR
PUMPS + MOTOK
CENTRIFUGE
CRYSTALL1ZER
STORAGE SILO
FEtUEK
TOTAL C =
53167.
23104.
12140.
331 ?3H.
1019703.
1223644.
56014.
bb2U.
3314167.
COSTS FOR WRT.T.MAN-T.QRn FGD SYSTEM FOR 1000 MW/0.6% SULFUR/NEW MODEL PLANT
-------
D. REGENERATION
PUMPS + MOTORS
EVAPORATORS + REBOILERS
HLAT EXCHANGERS
TANKS
STRIPPER
BLOWER
TOTAL 0 =
E. PARTICIPATE REMOVAL
VtNTURI SCRUbbtK
TANKS
PUMPS + MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
O
U)
2b2«*33.
28i7<*|*5.
367919.
<»7fa99.
103b2b.
119700.
3708721*.
0.
0.
0.
D.
35476567.
O
-------
IMTFULST UUKIluG COUSTHUCTlON ib"«7bbf>.
FJCLD LABOK AND EXPENSES 35H7656.
CONTRACTORS FEE AND EXPANSES 1773028.
ENGINEERING 3547656.
FREIGHT <*H3457.
---- 1D64297.-
SPARES 177382.
TAXES " '"• 532116.
ALLOWANCE FOR SHAKEDOWN 1773828.
"ACID PLANT ............ ~ ......... 1661990.
TOTAL INDIRECT COST = 16072902.
CONTINGENCY 10709693.
GKAND TOTAL
8I9ST
2955."
STEAM-PROCESS (BTU/HRJ
365^532771
COST-DOLLARS PER KILOWATT
-------
WELLMAN-LORD ANNUALIZEO COSTS
A. RAW MATERIALS
SODA ASH
B. UTILITIES
ELECTRICITY
PROCESS WAtER
COOLING WATER
REHEAT STEAM
PROCESS STEAM
C. OPERATING LABUK
DIRECT LABOR
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
9 E. OVERHEAD
I-1 PLANT
PAYROLL
F. FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXEs
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
6. CREDITS
SULFuRIC ACID
NA2S04
"QUANTITY
O.S3 IUTJ/H
6677. KW
295^.0 GAL/MIN
1159.5 MGAL/KIN
112.5 MM BTU/H
119.6 MM BTU/H
1 MEN/DAT
50%
5.002
0.3555
1.00%
0.3 85 .
9.008 ' "
18.658"
7.43 TON/H
0.53 TON/H
UNII CU5.
55.00 S/TON
15.0 KILLS/KwH
0.001 i/MGAL
0.761 S/Mn BTU
0.764 S/MM BTU
8.UU »/l"iAlMI1K
1585 OF DIRECT LABOR
IS OF FIXEU iNVt-b 1 Plt-IM 1
155» OF LABOR AND MATERIALS
UP OPERATION AND MAINTENANCE
20% OF OPERATING LABOR
"TOTAL COST "
20.00 S/TON
40.00 'S/TON ^
TOTAL CREDITS '
IMLl «NNUAU tUST
KILLS"PER KILOWATT-HOUR
ANNUAL tUiil ( * J
155768.
526191.
17612.
16993.
601147.
12048.
385556.
64473.
11984371.
1U857131. "
781833.
113286.
-- - • - - 895119. - -
' 17962011.
A. HI
-------
PLANT NA«E-
STO 1000 LS RETROFIT
DIRECT COSTS----
" A". '"NA2C03 PREPARATION
STORAGE SILO
VIPHATING FEEDER
STORAGE TANK
AGITATORS
PUMPS + MOTOR
TOTAL A =
B. S02 SCRUBBING
AbSORdERS
FANS •»• MOTORS
PUMPS + MOTORS
REHEATERS
SOOT bLOWERS
DUCTING
VALVES
TOTAL & =
1
I^J C. PURGE TREATMENT
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUMPS "+ "MOTOR
CENTRIFUGE
CRYSTALLIZER
STORAGE SILO
FEEDER
TOTAL c =
COSTS FOR WELLMAN-LORD
5<*617.
5007.
55096.
18703. "
1762.
135107.
197070.
3559187!
239232U.
3122356.
2639070.
S59ZMS*.
579183.
8b922.
59974.
25639.
13350.
377030.
1156966.
1390760.
6685.
3771728.
FGD SYSTEM FOR 1000 MW/0 .£%-SULFUR/RETROF"fr MODEL PLANT
-------
D. REGENERATION
PUMPS + hOTOKS
EVAPORATORS + REBOILERS
HEAT EXCHANGERS
TANKS
STRIPPER
BLOWER
TOTAL D =
E. PARTICIPATE REMOVAL
VtNTURI SCKUbBtK
TANKS
PUMPS -t- MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
1
283310.
3204267.
418570.
53655.
11571H.
136160.
4211696.
0.
0.
u.
0.
»«HW067.
-------
INDIRECT COSTS
INTEREST DURING CONSTRUCTION
FIELD LABOR AND EXPENSES 4666671.
CONTRACTORS FEE AND EXPENSES 233H335.
ENGINEERING~~ "" <*'^92'*9^.
FREIGHT 550550.
-"OFFsftE 1321522."
SPARES 220220.
"TAXES ~" " 660661.
ALLOWANCE FOR SHAKEDOWN 2202203.
"A'CIIT PLANT'" ~"
TOTAL INDIRECT COST = 22553910.
CONTINGENCY 13319595.
GRAND TOTAL 79~9T7573T
"PRDTESS
STEAM-PROCESS (BlU/HR) 1547701701)^
"TTOOLING WATER rG~ATIS7YR)'377996"51"65."
COST-DOLLAHS PER KILOWATT 79T9I"
-------
WELLMAN-LORD ANNUALIZEO COSTS
A. RAW MATERIALS
SODA ASH
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHt-AT STEAK
PROCESS STEAM
c'. OKE.NATIN& LABOR
DIKLCT LABOK
SUPERVISION
0. MAINTENANCE.
LAHOR AND MATERIALS
SUPPLIES
0
1 e. OVERHEAD
.&.
1/1 PLANT
PAYROLL
F. FIXt-D COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
G. CREDITS
SULFuRIC ACID
NA2SQ4
UUANTITY UNII COS!
0.55 TON/H 55.00 S/TON
6899. KW 15.0 MILLS/KWH
3056.3 GAL/MIN ~ U.018 i/MUAL
1199.3 MGAL/MIN 0.004 S/MGAL
147.3 MM BTU/H U.fb4 */nn UIU
154,7 MM BTU/H 0.764 S/MM BTU
4 MEN/DAT B.UO */l"l«UnK
15K OF DIRECT LABOR
4% OP FIXLU ilMVt-S 1 MtlM 1
15B OF LABOK AND MATERIALS
50% OP OPERATION ANU PIAlNTt-NANCL
2058 OF OPERATING LABOR
5.00%
0.35%
4.00%
0.3 %
9. DOS
16.65%
TOTAL COST
7.69 TON/H 20.00 S/TON
0.55 TON/H 40.00 S/TON
TOTAL CREOI-TS
- NLT ANNUAL COST
MILLS PLK KILOWA1 1 -HOUK
ANNUAL COS 1 1 * >
lbll.30.
543983.
io^ib.
17576.
DyiiU'+b.
621919,
cou 3^0 .
4204S, "
3i^b ^U«i ,
479505.
ivy^iiaB.
64473.
14904627.
22921ttbU.
808849.
11 ^Ud. -
926049.
-~ - - 21995810". - -
4. 10
-------
0. REGENERATION
PUMPS * MOTORS
LVAPORATORS * REBOIUERS
HtAT EXCHANGERS
TANKS
STRIPPER
BLOWER
TOTAL D .=
E. PARTICIPATE REMOVAL
VENTURI SCRUbBLR
TANKS
PUMPS + MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
(•}
1
*>.
716100.
10638067.
1<*30590.
117917.
200011.
<+6b<»36.
13766953.
u.
0.
0.
0.
46273606.
-------
~PLANT~N"AME>
STD 1000 HS NEW
DIRECT COSTS-
A.~~~~TJA2C03~ PREPARATION"
STORAGE SILO
STORAGE TANK
AGITATORS
TOTAL A =
150506.
~ «*557."
81307.
16126.
253955.
S02 SCRUBBING
n
"ABSORBTRS"
FANS -f MOTORS
PUMPS" "T'fioiroRS
REHEATERS
"S 0 0 T " BL'O SIR'S
DUCTING
VALVES
~fOTAL~B~^~
1791765U.
Ibbl33.
3131510.
2099911.
"23219567
28336069;
PURGE TREATMEN1
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUPiPS + MOTOR
CENTRIFUGE
CRYSTALLIZER
STORAGE SILO
FEEDER
TOTAL C =
509851.
76177.
67056.
12140.'
776756. . ... .
1019703.
182715!
5532.
3914620.
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 1000 MW/3.5% SULFUR/NEW MODETj-PLANT
-------
INDIRECT COSTS
INTEREST DURING CONSTHUCTION
FIELD LABOR AND EXPENSES
CONTRACTORS FEE AND EXPENSES
"ENGINEERING— ""'
FREIGHT
•OFFSITE
SPARES
"TAXES"
ALLOWANCE FOR SHAKEDOWN
ACTO PLANT
4627360.
4627360.
2313fa80.
4627360.
576420.
"'1388208;'"
231368.
69110"+.
2313680.
3740331*.
TOTAL INDIRECT COST =
25141877.
******************** ******~* *
.. ^925.
9305.
COST-DOLLARS PER
65~.~69~ "
-------
WELLMAN-LOKU
COSTS
QUANTITY"
JTT~C~05T
TINMUAL COSriS)
A. RAW MATERIALS
SODA ASH
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHEAT STEAM
PROCESS STEAM
C. OPERATING LABOR
DIRECT LABOR
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
o
1 E, OVERHEAD
^ PLANT
PAYROLL
F. FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
6. CREDITS
SULFuRIC ACID
NA2SQ4
2.09 TON/H 55.00 S/TUN
9595. KW 15.0 MILLS/KWH
93o5.9 GAL/MIN o.oie WMOAL
3730.1 MGAL/MIN 0.001 t/MGAL
112.5 MH BTU/H 0.761 »/MM 8TU
581.6 MM BTU/H 0.761 $/M» BTU
1 MEN/DAY 8.00 5/MANHK
15* OF DIRECT LABOR
1% OF FIXED INVt.5 1 MLNI
15S> OF LABOR AND MATERIALS
50ft OF OPERATION AMU MAINTENANCE
20% OF OPERATING LABOR
5.00%
0.35%
1.00%
0.3 8
9.00%
18.65S
TOTAL COST
28.91 TON/H 20.00 */TON
2.09 TON/H 10.00 S/TON
TOTAL CREDITS
NET ANNUAL COST
fcUDbfb.
756500.
bb1b&.
51671.
572821.
2337159.
12018.
511191.
2132251 .
61173.
15982785.
-2GS26612.
3010025.
110193.
"3180518.
23316091.
-------
PLANT NAME-
STO 1000 HS RETROFIT
- --- DIRECT' COSTS-
NA2C03 PREPARATION
STORAGE SILO
VIBRATING FEEDER '
STORAGE TANK
AGITATORS
PUMPS + MOTOR
170717.
5012.
95253.
18703. ------
1762.
TOTAL A =
29l<+«*9.
8.
S02 SCRUBBING
AbSORBERS
FANS + MOTORS
PUMPS + MOTORS
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL 6 =
1
Ul
VJ C. PURGE TRLATMtNT
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUMPS + MOTOR
CENTRIFUGE
CKYSTALLIZER
STORAGE SILO
FEEDER
25Hl9<*Oy.
197070.
596UHU.
3559187.
2392320.
3122356.
2639070.
35925H3H.
579H83.
86922.
75171.
13i50.
883270.
1156966.
1390760.
227908.
6691.
TOTALC =
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 1000 MW/3.5% SULFUR/RETROFIT-MODEL PLANT
-------
0. REGENERATION
PUMPS + MOTlJRS
EVAPORATORS + REBOILE8S 12i27b92.
~HL AT~rxEH AGGERS ' 1627125.
TANKS 132668.
"STRYPFTR ~
BLOWER
0
Ul
TOTAL 0 = 15650115.
E. PARTICIPATE REMOVAL
VtNTURI SCKUbBEK
TANKS
PUMPS + MOTORS
0.
0.
0.
TOTAL E =
TOTAL INSTALLED DIRECT COST = 56335885.
-------
----1NUIKLC1 tUSIS—--
INTEREST DURING CONSTRUCTION 5fa33b88.
FIELD LABOrt A\D EXPENSES 5971603.
CONTRACTORS FEE AND EXPENSES 2985601.
"ENGINEERING " """' 5746.>60.
FREIGHT 704196.
~OFFSITE~ "" ~" "" """1690076.
SPARES 281679.
"TAXES "~ " ' " " 8<»503fi.
ALLOWANCE FOR SHAKEDOWN 281b79t.
"ACID PLANT " 3816678.
TOTAL INDIRECT COST = 30491719.
CONTINGENCY 17365520,
"BRAND TOTAT
I
Ol
10252T
9626T"
STEAM-PROCESS (BTU/HR)601755000.
12161839060."
KILOWATT
-------
WLLLMAN-LUKU ANNUALI2EU CUliTb
n
i
(Jl
(0
A. RAW MATERIALS
SOOA ASH
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHt-AT STEAM
PROCESS STEAM
C. OPEKATING LABOR
DIRtCT LABOR
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
E. OVERHEAD
PLANT
PAYROLL
F. FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FTXED CHARGES
6. CREDITS
SULFuRIC ACIO
NA2S04
HUANTITY UNI I CUbl
2.16 TON/H bS.OO */TON
9911. KW 15.0 MIULS/KWH
9626.1 GAL/MIN "O.Olfl S/MGAL
3B58.8 MGAL/MIN 0.00^ $/MGAL
147,3 MM BTU/H Q.tbH S/Hfl b 1 U
601.7 MM BTU/h 0.764 S/MM BTU
4 MEIM/OAT 8. 00 S/MANHK
15* OF DIRECT LABOR
48 OF FIXED INVt-blMLNI
15X OF LABOR AND MATERIALS
50K OF OPERATION ANU HAINTLNAIMCL
20% OF OPERATING LABOR
5.00%
0.35%
4.00S5
0.3 %
9. DOS
18.65K
TOTAL COST
29.91 TON/H 20.00 S/TON
2.16 TON/H 40.00 */1UN
TOTAL CREDITS
Nt-T ANNUAL COST
MILLS PLK KILOWAI I-HOUK
ANNUAL COSI ( S)
b26bb3.
731673.
57374.
56552.
d^^UHb.
2416061.
2uuo<:u .
42048. .
4167 f 23.
625158.
2bb/b^>b.
64473.
19432017.
31701641.
3144853.
4!3Dbtt2.
"" " 3600536.
23101104.
i>.34
-------
PLANT
STD bOO LS NLW
DIRECT COSTS-
A. NA2C03 PREPARATION
STORAGE SILO
VIBRATING FEEOE.K
STORAGE TANK
AGITATORS
PUMPS «• MOTOR
TOTAL A =
B. S02 SCRUBBING
ABSORBERS
FANS + MOTORS
PUMPS + MOTORS
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL B =
o
1
- C. PURGE TRLAICItNF
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUMPS + MOTOK
CENTRIFUGE
CRYSTALLIZER
STORAGE SILO
FEEDER
TOTAL C =
COSTS FOR WFT,T.MAN-T.ORn FfJD '
31389.
36450.
16126.
89976.
170675.
271008.
1616297.
1006379.
999947.
14413509.
263460.
39522.
32779.
12140.
526960.
3610ft!
5b27.
1714863.
^VQTFM Pop ^QO MW/Q 6^ SULFUR /NEW MODFT PT ANT
-------
D.
EVAPORATORS + REBOILEKS
HEAT EXCHANGERS "'
TANKS
STRIPPER
BLOWER
T795TTT'
190316.
30737.
75650.
61918.
TOTAL 0 =
2006275.
E. PARTICIPATE REMOVAL
VEWTURI SCKUbbER
TANKS
PUMPS + MOTORS
U.
0.
0.
TOTAL E =
TOTAL INSTALLED DIRECT COST =
182516'+'+.
O
~~
-tn-
-------
IfvDIRECT COSTS
INTEREST DURING CONSTRUCTION 1825461.
FIELD LABOR AND EXPENSES 16254&1*.
CONTRACTORS FEE AND EXPENSES 912732.
"ENGINEERING" ........ ~ ----------------- ' " 1825464.
FREIGHT _ _ 22al83.
547639.
SPAKES 91273.
"TAXES ........... 273619.
ALLOWANCE FOR SHAKEDOWN 912732.
"ACItrpL'A'NT --------------------- ...... ------- ....... ~ ----- 1124063.
TOTAL INDIRECT COST = 9566836.
****** *fi ******** *-*•*-*-*-****•**•***•*•*-* *"
CONTINGENCY 5564296.
GRAfJTJ" TOTAL 53"3"85777.
Q ***********************************
ui
4955.'
"STEAM-PROCESS (BTU/HR)773850TnrT
CGALS/YK)
C05T-DOLLAKS PtK KILOWATT65T7T"
-------
HELLMAN-LOKU ANNUAL1/LU
A, RAW MATERIALS
SODA ASH
B. UTILITIES
ELECTRICITY
PROCESS kATER
COOLING WATER
REHEAT STEAM
PROCESS STEAM
C. OPEKAT ING LABOR
DIRECT LABOR
SUPERVISION
0. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
O
t^, E. OVEKHEAD
-J
PLANT
PAYROLL
F, FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
G. CREDITS
SULFuRIC ACID
NA2SQ4
QUANTIIT UNIT COSI
0.27 TON/H 55.00 S/TON
3988. KW 15.0 MILLS/KMH
1528.1 GAL/MIN o.oio S/MGAL
599.6 MGAL/MIN 0.004 S/MGAL
73.6 MM 6TU/H U.7b4 S/i"ll"l UTU
77.3 MM BTU/H 0.764 S/P.M BTU
2 MEN/DAY 8.UO S/MAIMHK
15S5 OF DIRECT LABOR
ttf OF FIXED INVLSIMbNT
15S5 OF LABOR AND MATERIALS
50fc OF OPERATION ANU MAINTENANCE
20S OF OPERATING LABOR
5.00%
0.35X
4.00»
0.3 %
9.005S
16.658)
TOTAL COST '
3.64 TON/H 20.00 S/TON
0.27 TON/H 40.00 S/TON
TOTAL CREDITS
NET ANNUAL" 'COST
ANNUAL CUi> 11%)
80575.
314422.
9108.
6768.
310959.
IHUlbU .
21024.
200314.
3223b!
b22fa447.
»o*aSa7.
404424.
bUbOO .
' 463024.
" 93609'.42.
MILLS PS.R KILOWAI T-HOU
-------
PLftNT NAHT-
STIJ *it)0 L S KI.THOF IT
DIRECT COSTS---
A. NA2C03 PREPARATION
STORAGE SILO
VIBRATING FEEDER
STORAGE TANK
AGITATORS
PUMPS * MOTOR
TOTAL A =
B. soa SCRUBBING
ABSORBERS
FANS + MOTORS
PUMPS + MOTORS
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL B =
o
1
Ul
w C. PURGE TREATMENT
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUMPS + MOTOR
CENTRIFUGE
CRYSTALLIZED
STORAGE SILO
FEEDER
TOTAL C =
- - .
34968.
5007.
42520.
18703.
1602.
102800.
200909.
1814261.
1196161).
3212564.
1121033.
19786570.
295386.
44307.
36555.
22242.
13350.
195061.
590772.
708926.
6664.
1959966,
COSTS FOR WELLMAN-LORD_F.QD _SYSTEM_EQR_500 MW/Q.6% SJILEUB/EETBQPJLT..MQDEL^PLANT_.
-------
D. KLGLME.KATION
"PUMPS "V MOTORS" ~ " 199650.
EVAPORATORS + KLBOILEKS 1649861.
HEAT EXCHANGERS 213973.
TANKS 34303,
STRIPPER " "' ~ """ ~ ""84065.
BLOWER 69615.
TOTAL D = 2251468.
PARTICIPATE REMOVAL
•'VENTURT'SCROBBER— • 0.
TANKS 0.
' "PUMPS > MOTORS " ~"~o.
TOTAL E = Oi"
TOTAL INSTALLED DIRECT COST = 24100808.
I
01
vo
-------
INDIRECT COSTS
IMERtST DURING CONSTRUCTION
FIL.LU LABOR AND EXPENSES
CONTRACTORS FEE AND EXPENSES
ENGINEERING
FREIGHT
OFFSITE
SPARES
TAXES
ALLOWANCE FOR SHAKEDOWN
ACID PLANT
TOTAL INDIRECT COST =
CONTINGENCY
GRAND TOTAL
ft**************************!
1
85.
1277442.
21*58262.
301260.
723024.
12U501*.
36X512.
1205040.
1139002.
125b()735.
1
7330308.
"ti^aiaai.
r***«4t**
5050.
1561.
79116424.
193103695b.
87.96
-------
WELLMAN-LORO ANNUALIZED COSTS
"AT "RAH MATERIALS
--- SOOA~ASH ------
UTILITILS_
ELECTRICITY
PROCESS WATER
COOLING WATER
REHTAT"SrCAH
PROCESS STEAM
QUANTITY
0.28 TON/H
4065. KW
1561". 2" GAL/MIN ...........
612.6 MGAL/MIN
75".T~~MH "BTU/R
79.1 MM BTU/H
UNIT COST
55.00 S/TON
15.0 MILLS/KWH
0.018 $/MGAL
0.004 i/MGAL
"OV76* '$/«« BTU
0.76H S/KM BTU
ANNUAU'COSTm
82380
320521.
9305.
6.979.
101789.
L7925.
~CT. — 10PEKATING" LABOR
SUPERVISION
6 T
isss OF DIRECT LABOR
2102"*.
n
"MAINTENANC
pfB'OR AND MATERIALS
"E.
*8 ~OF FI XETJTTNVErSTT'iENT
15K OF LABOR AND MATERIALS
T759Z7TT
263691.
5TnrnCTF~CrPERST 1 0"N~~ATNfD~fl ATNTEWANCE
109217^7
32236*
DEPRECIATION
INTERIM REPLACEMENT
TAXES
C AP I t ffLTCOSf S
5.00'iS
0.35K
>r.6Q%
?*3 a
9TOOS
B2T52615.
T2552278;
TOTAL FIXED CHARGES
G. CREDITS
SULFuRIC ACID
18.6bS
TOTAL CO^T
3.93 TON/H
20.00 S/TON
40.00 - S/TON
413483.
NA2S04
TON/H
TOTAL "CREDITS
N£T-ANNUAC--COST
4T3396
T2T0788S2
MILLS PLR KILOWATT-HOUR
4.39
-------
PLANT NAME- STD 500 HS NEW
"MA2C03 PREPARATION"'
STORAGE SILO 84177.
•VlbR-ATTNtrFEEDTR
STORAGE TANK 62063.
"AGITATORS ~ 16126.
PUMPS + MOTOR
TOTAL A = 160379.
S02 SCRUBBING
ABSORBERS
FANS + MOTORS
PUMPS •»• MOTORS
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
- 9259457. -•• ' ....
17CI67b.
2/1U08.
1616297.
' 108 //44. .
1006379.
999947.
REATHEN1
REFRIGERATION UNIT 263480.
"HEAT' EXCHA"N~GO~ 39522.-
TANKS !*3.2.96 •
OR Y E~R 2 9 2 627"
ELEVATOR 12140.
"PUMP S~^fiOTO"R
CENTRIFUGE 526960.
TRYSTACLTZETJ 6323537"
STORAGE SILO 102191.
FEEDER 5529,
TOTAL C =
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 500 MW/3.5% SULFUR/NEW MODEL PLANT
-------
D. REGENERATION
' PUMPS + MOTORS
EVAPORATORS + REBOILERS
HEAT EXCHANGERS
TANKS
STKIPPER
BLOWER
TOTAL D =
E. PARTICULATE REMOVAL
VLNTURI SCRUBBER
TANKS
PUMPS + MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
n
— i
1+19132.
5632131.
739960.
76000.
210743!
7253007.
0.
0.
u.
u.
23693666.
U)
-------
INDIRECT COSTS
INTEREST DURING CONSTKUCTION
FIELD LABOR AND EXPENSES
CONTRACTORS FEE AND EXPENSES
ENGINEERING— "
FREIGHT
""6TFSITC
SPARES -
~TAXES ~~
ALLOWANCE FOR SHAKEDOWN
~AC ID "PLANT
TOTAL INDIRECT COST =
2389368.
2389368.
2389368.
296671.
71o810Y
358105.
119'r&e1».
2525059.
13575890.
-*-*-* ****** K
CONTINGENCY
7H93915.
O
I
GRAND TOTAL
***********************************
OTA"C~HORSCPOWER—FOR
4813T
STLAM-PROCt-SS (BTU/HRJ
"COOLIN& WATLK (
SU Q8775U0.
-UULLAKS> h-LK KIUOWATI
-------
WLLLMAN-LOKU ANNUALIZEU
o
1
CTi
A. RAW MATERIALS
SUUA ASH
8. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHLAT STEAtf
PROCESS STEAM
C. OPERATING LAbOK
DiKt-CT LAbOK
SUPERVISION
D. MAINTENANCE
LABOR AMD MATERIALS
SUPPLIES
E. OVEKHEAU
PLANT
PAYROLL
F. FIXED COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXEO CHARGES
G. CREDITS
SULFUKIC ACID
NA2S04
UUAN 1 I 1 T UINI I LUd 1 »IMNuAl_l,Ui>^(3>)
l.UB TON/H " 53.00 i/TON 313281.
5495. KW 15.0 MILLS/KWH 433238.
4813.0 GAL/MIN 0.018 i/MGAL 2BSU7.
1929.4 MGAL/MIN 0.004 S/MGAL 28276.
73.6 Ml"! bTU/h U./64 s/rtri mu iiybU2i.
300.8 MM BTU/H 0.764 S/HM BTU 1209030.
2 HLN/UAT tt.Ou i/ilAlMnR 1401bU.
15« OF DIRECT LABOR 21024.
HIS l^ (-IXEU INVESTMENT l/9t>5a9.
15iS OF LABOR AND MATERIALS 269780.
50fc OF OPERATION AND MAINTENANCE 1114/bii.
20* OF OPERATING LABOR 32236.
5.00%
0.35S
4.00SJ
0.3 %
9.00ft
10.65% aieab^i.
TOTAL COST 14u70723.
14.95 TON/H 20.00 S/TON 1572426.
1.06 TON/H HO.UO */TOI\i Z2IB1*!,
TOTAL CREDITS 1600268.
(JET ANNUAL COST ' "' "" " " 12270454.
M1LL6 HtK KILOWA 1 1 -HOUK H.Ob
-------
PLANT NAME-
SOO US KE.TKUHT
DIRECT"COSTS---
'NA2C03 PREPARATION
STORAGE SIUQ
VIBRATING FEEDER
_STORAGE: TANK
AGITATORS
PUMPS * MOTOR
TOTAL A =
94276.
—5W9T
7235"*.
18703.
1762.
192106.
B.
S02 SCRUBBING
ABSORBERS
FANS + MOTORS
PUKPS + MOTOKS
REhEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL B =
O
1
(Tv
11957613.
200909.
30402b.
1814261.
119&160.
321256H.
1121033.
1978btj/0.
PURGE THt-ATMENl
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DKYER
ELEVATOR
PUMPS + MOTOR
CENTRIFUGE
CHYSTALL1ZER
STORAGE SILO
FEEDER
295386.
14307.
46220.
32496.
13350.
4S3669.
590772.
706926.
125859.
bb87.
.
tOTAlT~C =
"23T9676T
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 500_ MW/3_._5% SULFUR/RETROFIT MODEL PLANT
-------
0. REGENERATION
"PUriPS" V MOTORS " H6B103.
EVAPORATORS + REBOILEKS 6327863.
HEAT EXCHANGERS -••-•• 831505.
TANKS 64769.
STRIPPER " 161179.
SLOWER 270526.
TOTAL__D_ = 81«HK>"»a.
E. PARTICIPATE REMOVAL
VENTURT^SCRUSBETR""" ~ " '' 0.
TAfJKS 0.
PUNrpS"";T"M"OTOR'S" " 0.
TO'TAL E = o~;"
TOTAL INSTALLED DIRECT COST = 3Cm2t01.
O
_!_
en
-j
-------
INDIRECT COSTS
UJTEPEST DURING CONSTRUCTION
CONTRACTORS FEE AND EXPENSES
"ElvGlNEE
FREIGHT
OFFSITE
SPARES
ALLOWANCE FOR SHAKEDOWN
~ACIU PLANT
304-+240.
"3226094.-
1613447.
"3105121*.-
360530.
152212.
1*56636."
1522120.
TOTAL INDIRECT COST =
16972300.
***********************************
CONTINGENCY
GRAND TOTAL
56897642.
**********************:
1
CM
00
TOTAL HORSEPOWER FOR PLANT
PROCESS WATER (GAL/MINI)
STEAM-PROCESS (faTU/HR)
COOLING WATER (GALS/YR)
COST-DOLLARS PER KILOWATT
*************
5960.
4917.
307456687.
6212841784.
113.79
-------
tJELLMAH-LORD ANNUALIZED COSTS
QUANTITY""
~A".~ R'AW MATERIALS
SODA ASH" '~
1.10 TON/H
UNIT COST
55.00 S/TON
"ANNUAL"
320132;
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHLAT STEAM
PROCESS STEAM
- - - ^9-17.3
1971.2
75.1
307.4
5604. Ktg
' GAL/MIN
MGAL/HIN
MM-BTU/fi —
MM 8TU/H
15.0 MlLLS/K'rfH
~ ' - 0.018 5/MGAL "
0.004 4/MGAL
"'" STfCf" '$XPIM"BTO
0.764 $/MM BTU
441&56.
------ -•- • 29309". '
23689.
1235468.
'IT. "OPERATTNG'OBOR"
T5TR E c"T~O B 0 ft~
SUPERVISION
2 HEN/DAY
STOTJ $/RA"NHR
15K OF DIRECT LABOR
rro-160—
21024.
~D7~"MArNTEWAWC'E~
LATJCR SNO MATrRTATTS"
SUPPLIES
4 ST~0"F"FIXETJ 'TlWrs TM E NT
158 OF LABOR AND MATERIALS
341385.
Q
1
(Ti
E. OVEKHEAO
PLANT
PAYROLL
F. FIXLD COSTS
DEPRECIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
G. CREDITS
50» Of OPERATION ANU MAINTENANCE 1^8^237.
20» OF OPERATING LABOR 32236.
5.00%
0.35%
4.00%
0.3 %
9.1)0%
18.65% 1061141U.
TOTAL COST 17ib6&05.
SULFURIC ACID
15.28 TON/H
20.00 S/TON
1606810.
NA2SQ4 1.10 TON/H 40.00 S/7UIM
"TOTAL CREDITS
NLT ANNUAL COST
.ii^ti^-.
- 1839634.
153291/1.
MILLS PE.K KILOWAn-HUUK
t>.
-------
PLANT NAME-
STD
250 LS NEW
-=•-"01R E C T C OSTS •
A. NA2C05 HKEHA «TlUN
STORAGE SILO
VltiR'ATING FttULK
STORAGE TANK
AblTATORS
PUMPS * MOTOR
TOTAL A =
B. S02 SCRUBBING
AttSOKBt-Hb
FANS + MOTORS
pu^ps +• MOT OKS
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL B =
0
-J
C. PUKbL 1 Rt-A ll"ltNl
REFRIGERATION UNIT
TANiKS
ORYER
ELEVATOR
PU'^PS •»• MOTOK
CENTRIFUGE
CRYSTALLIZE.K
STORAGE SILO
FEEDER
TOTAL C =
22155.
2630o!
ifaliifa.
1156.
72891.
HI?l55l!
I3bbo3.
827536.
1197871
Slliifa.
rdtiub^i.
131731.
2021U.
20999.
Idbll.
12110.
269168.
2726o!
bb27.
923570.
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 250 MW/0.5% SULFUR/NEW MODEL J?XANT
-------
D. REGENERATION
"PUMPS'"*" MOTORS "
EVAPORATORS * REBOILEKS 757m3.
HEAT EXCHANGERS 97289.
TANKS 19651.
STRIPPER "~ ~ 55299.
BLOWER 31652.
TOTAL D = 1095525.
E. PARTICULATE REMOVAL
" VENTURI'SCRUBBER ' — '- 0.
TANKS 0.
""PUMPS"* "MOTOR'S "" "" 0 ."
TOTAL E = 0V
TOTAL INSTALLED DIRECT COST = 9H72616.
Q
-------
---- INDIRECT COSTS ----
INTEREST DUftING CONSTRUCTION
"FIELD LABOfT'AND 'EXPENSES — "
CONTRACTORS FEE AND EXPENSES
FREIGHT
947261.'
116407.
OFFSITE
SPARES
TA-XTS
ALLOWANCE FOR SHAKEDOWN
'ACID PLANT
47363.
473630.
TOTAL INDIRECT COST =
5134633.
CONTINGENCY
2921450.
T5KAND TOTAL
I7b287DO.
"TOTAL HORSETPOWEK"F0«~PrAtJr
"PR0C Ess^irs TE:R~ r GTALV PTT R-J
3249T
78IV"
STEAM-PROCESS (BTU/HR)
~CUDnMC"lfffTLK (GW.S7YRT
T03T=I5'OrrAKS~TrE7n
-------
WELLMAN-LORD ANNUALIZEO COSTS
- COST-
-A NNU At"t 0 ST
"AT "RAW MATERIALS
SODA—
•TJ.lt TON/H
55.00 S/TON
-—41190.
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
RLHUT STEAM
PROCESS STEAM
C. OPt-RAI ING LABOR
DIKLCT UABOK
SUPERVISION
7fal.2
306.5
2572. KW
~ T3A'L/RIN " — '
MGAL/MIN
37.6 MM bTU/H
39.5 MM BTU/H
S/TON
S/TON
PLK KILOWAI I-HUUK
206741.
jjyyofa.
236698.
5079H27.
o.ob
-------
PLANT NAML- STU 2'jo us KLTKOFIT
DIRECT COSTS
NA2C03 PKEPARATION
STORAGE SILO
VI3RATING FLTTJLR
STORAGE TANK
AGITATORS
PUKPS •»• MOTOR
TOTAL A =
2b022.
5006.
33133.
- 18703.
1762.
63628.
soa SCRUBBING
ABSORBERS
FANS + MOTORS
PUMPS + KOTORS "
REHEATERS
SOOT BLOWERS
DUCTING
VALVES
TOTAL B =
-J
C. PUKbt TRt-AlflErJI
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
URYER
ELEVATOR
PUMPS + MOTOR
CENTRIFUGE
CRYSTALLIZE*
STORAGE SILO
FEEDER
bl/duuy.
207948.
"157234.
933909.
598060. •- ' - '
1733304.
SB01b2.
10393639.
152666.
22930. •
23553.
13350.
305733.
366600.
33405.
6683.
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 250 MW/0.6% SULFITR/RFTROFTT MnnP!Tj PLANT
-------
KLGEM-KA1 ION
PUMPS + MOTORS • "
EVAPOKATOhS + RtBOILERS
Ht-AT EXCHANGERS
TANKS
STRIPPER
BLOWER
TOTAL D =
E. PARTICIPATE REMOVAL
VENTURI 5CKUbbt.K
TANKS
PUMPS + MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
O
1
-J
1H92V6.
658917.
22069.
6170b.
3592t.
1230331.
0.
0.
0.
0.
1276t919.
-------
INDIRECT COSTS
IMTt.RE.ST DURING CONSTKUCTION 1276191.
"FIELD LABOR AND EXPENSES 1353081.
CONTRACTORS FEE AND EXPENSES 676510.
"'ENGINEERING -• - • 1302021.
FREIGHT 159561.
OFF'slTE "" " " 3B2917.'
SPARES 63821.
"TAXES •— "~ 191173.
ALLOWANCE FOR SHAKEDOWN 636245.
"A'CI'D" PLANT " 767861.
TOTAL INDIRECT COST = 6812053.
CONTINGENCY 3915391.
G^AND TOTAL
... I****************************:******
rOTSITTfORSEPOUIER-FOR-FCANT 3319 r
~PRtrCT5S~~W7Tr ER~T"G7ir7KTTn 8 0 6T"
STEAM-PROCETSS (BTU/HFTJ
997153669T'
"COST-DOLLARS PLR KILOVR
-------
WELLMAN-LORD ANNUALIZED COSTS
A. RAW MATERIALS
SODA ASH
B. UTILITIES
ELECTRICITY
PROCESS WATER
COOLING WATER
REHEAT STEAM
PROCESS STEAM
C. OPERATING LABOR
DIRt-CT LABOR
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
O
^ E. OVERHEAD
PLANT
PAYROLL
F. FIXED COSTS
DEPKE.CIATION
INTERIM REPLACEMENT
TAXES
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
G. CREDITS
SULFuRIC ACID
NA2SQ4
UUAN1 I 1 T UNI) CUS>I ANNUAL C 1 < * I
0.14 10N/H . bb.uo s/fuN 42bll.
2652. KW 15.0 MILLS/KWH 209134.
806.2 GAL/KIN 0.018 $7Ht,AL 4BUb.
316.3 MGAL/MIN 0.004 S/MGAL 4636.
38. fl MM BTU/H 0.764 S'/MH BTU 1561S1.
40.6 MM BTU/H 0.764 S/MM BTU 164062.
Z MLN/UAY 8.00 S/P1ANHK IHUlbU.
15So OF DIRECT LABOR 21024.'
15K OF LABOR AND MATERIALS 140954.
50)5 OF UPtKAlIUN AIMU MAIN 1 LNANCL biiU^lb.
20% OF OPERATING LABOR 32236.
6.66%
0.35K
o!3 %
9.00%
20.31J4 477iidbb.
TOTAL COST 7249183.
2.02 TON/H 20.00 */TON 213374.
0.14 TON/H 40.00 */TON 30917.
~ ~ " ' TOTAL CREDITS " 244291.
Nt.T ANNUAL COST " 7004892. '"
MILLS PtK KILOWAT I-HOUK
-------
PLANT
'^30 HS MLW
DIRECT COSTS-
A. NA2C03 PREPARATION " "
STORAGE SILO
VIBRATING FEEDER
STORAGE TANK
AGITATORS
PUMPS + MOTOR
TOTAL A =
B. so2 SCRUBBING
FANS + MOTORS
PUMPS -f MOTORS
REHEATERS
SOOT 6LOWEUS
DUCTING
VALVES
TOTAL B =
O
1
-J
C. PUKGE TRLAI MLNI
REFRIGERATION UNIT
HEAT EXCHANGER
TANKS
DRYER
ELEVATOR
PUMPS '+ MOTOR
CENTRIFUGE
CRYSTALLIZLR
STORAGE SILO
FEEDER
TOTAL C =
19132.
17531.
1156.
119101.
171551.
l3sb83.
827538.
119787.
SllS-ifa.
7,56ofo2i.
131731.
20210.
26991.
12110.
2&9168.
60011.
bb2H.
lUtibfaii.
COSTS FOR WELLMAN-LORD FGD SYSTEM_FOR _2.50._MW/_3_,_5%._SULFUR/_NEW _MODEL PLANT. .
-------
D. REGENERATION
O
-PUMPSTT-MOTORS—: 25663"*.
EVAPORATORS + REBOILERS 269b317.
HEAT EXCHANGERS 376108.
TANKS
-------
INUIKLCT COSTS
INTEREST DURING CONSTRUCTION
FIE.LD LAbOR AND EXPENSES
CONTRACTORS FEE AND EXPENSES
ENb INEERING
FREIGHT
OF-FSITE.
SPARES .
TAXES
ALLOWANCE FOR SHAKEDOWN
ACID PLANT
TOTAL INDIRECT COST =
CONTINGENCY
GKAND IUIAL
_. ft***********************
1
CO
TOTAL HORSEPOWER FOR PLANT
PROCESS WATER IGAL/MIMJ
SltAM-PROCLSS IbTU/HK)
COOLI^G WATER (GALS/YR)
COST-DOLLARS PEK KILOWATT
1239301.
1239301. ' ~ "
bl'JhSO.
123yiul.
151+912.
57179U.
61965.
103tt95.
619650.
1692ii5.
7H2H30H.
3963H6H.
zoTouT&^m
n***********
3701.
2*t60.
ISAf ^faHOH.
3108036049.
9b.l2
-------
WCLLMAN-LOKU ANNUALI^LU COSTb
•-QUATJTTTY-
A. 'RAW MATERIALS
SODA ASH
0.55 TON/H
UNIT COST
55.00 S/TON
160116.
B. UTILITIES .
ELECTRICITY
• "PROCESS wATER '
COOLING WATER
REHEAT STEAM
PROCESS STEAM
"2160.0
986.1
37.6
153.7
3342. KW
GAL/MIN "'
MGAL/MIN
- MM BTU/H ~
MM BTU/H
15.0 MILLS/KHH
0.018 S/MGAL " " " ' '
0.001 S/MGAL
U.7fc>1 S/MM B1U • '
0.761 t/MM BTU
263511.
11662. ' " - - -• -
11152.
151375.
617927.
SUPERVISION
" S7ITANHR"
15J5 OF DIRECT LABOR
T10T6TJV"
21021.
D. MAINTENANCE.
TTABOR~
SUPPLIES
fiATLRlALb
ISrOF'FIXEO'TNVESTME-NT
152 OF LABOR AND MATERIALS
112681.
1
00
I—1
E. OVERHEAD
PLANT
PAYROLL
bOS OF OPERATION AND MAINTENANCE b27550.
208 OF OPERATING LABOR 32236.
"FIXED—COSTS"
DLPKECIATIOIT
INTERIM REPLACEMENT
"TAXES
INSURANCE
"C API T AL~C1TST3
5.00%
0.35%
LOOS"
0.3 B
-?7WE"
TOTAL FIXED CHARGES
G. CREDITS
"TOTAL COST"-
~TOTAU CREDITS-
"NET"'ANNUWtrTCST
—920105T-
-^6-519177-
SULFURIC ACID
NA2SQ1
7.61 TON/H
O.bb TON/H
20.00
HU.UU
S/TON
*^ 1 Oi^J
803b56.
llblHU.
rlZLLb PLK KILOwAT T-HOUK
-------
PLANT NAME- STD 250 HS RETROFIT
----DIRECT 'COSTS-
A. " NA2C03 PREPARATION
STORAGE SILO
STORAGE TANK
AGITATORS
PUMPS + MOTOR
55661.
...... . 5007.
55653.
18703.
1762.
TOTAL A = 136791.
S02 SCRUBBING
ABSORBERS
FANS + MOTORS
"PUMPS + MOTORS
REHEATERS
SOOT BLOWEKS
DUCTING
VALVES
TOTAL B =
n
1
00
fj C. PUKGt lRt.AlWt.rj)
REFRIGERATION UNIT
HEAT EXCKANGLK
TANiKS
DRYER
ELEVATOR
PUMPS + MOTOR
CENTRIFUGE
CRYSTALLIZED
STORAGE SILO
FEEDER
61/43009.
207918.
157231.
938909.
173330l!
3SGlb2.
10393639.
152666.
32162,
25820.
13350.
237001.
305733.
366880.
71312.
6685.
TOTAL c =
COSTS FOR WELLMAN-LORD FGD SYSTEM FOR 250 MW/3.5% SULFUR/RETROFIT MODEL PLANT
-------
D, REGENERATION
EVAPORATORS + REBOILERS
Ht.AT EXCHANGERS
TANKS
STH1PPER
BLOWER
TOTAL. D =
E. PARTICIPATE REMOVAL
VLnlURI SCRUBbEK
TANKS
PUMPS •»• MOTORS
TOTAL E =
TOTAL INSTALLED DIRECT COST =
1
CO
~<>Bflt>B.
328b875.
429466.
54582.
11713U.
139725.
4315568.
0.
0.
u.
D.
16084042.
-------
IMF-REST DURING CONSTRUCTION
FIELD LABOR AND EXPENSES
CONTRACTORS FEE AND EXPENSES
ENGINEERING"' " ' —
FREIGHT
~OT f SIT £~
SPARES
'TAXES "
_ALLOWANCE FO_R SHAKEDOWN
~A~C1 D" PL" ANT
TOTAL INDIRECT COST =
1606404.
170490P.
1640b72.
201050.
30420.
1725269.
9341063.
CONTINGENCY
5005021
GKANO TOTAL
O
oo
TOTAIT"HORSEPOWER- FOrTTLANT
"3819,
-2540.
STLAM-PROCESSfBTU/HR)
"COOtlNG
^3209345187.
122.04
-------
RIMNO«l-l<:t.U two 10
A. RAW MATERIALS
bUUM ASH
B. UTILITIES
ELECTRICITY
COOLING WATER
PROCESS STEAM
C. OPERATING LABOR
DIRtCT LABCK
SUPERVISION
D. MAINTENANCE
LABOR AND MATERIALS
SUPPLIES
0
& E.. OVEKHEAD
Ul
PAYROLL
f. HXtD LUSTS
DEPKEC'IATlUR
INTERIM REPLACEMENT
INSURANCE
CAPITAL COSTS
TOTAL FIXED CHARGES
G. CREDITS
SULFuRIC ACID
NA2S04
UUANTITT UNI'I LOST
"'O'VbT TON/H " 55.00 S/TON
3447. KM 15-0 MILLS/KWH
2540.1 GAL/MIN 0.018 S/MGAL.
1018.2 MGAL/MIN 0.004 S/MGAL
38. fl MM BTU/H U./bH S/MM BTU
158.7 MM BTU/H 0.764 $/M« BTU
2 MtN/UAY 8.0U i/MANHK
15X OF DIRECT LABOR
4)5 O^ hlALCl IWVE&T|"IE!\|T
15» OF LABOR AND MATERIALS
3U% Oh UPt-KAl IUl»l Ai'^U NAlN 1 C.IMANLE.
20X OF OPERATING LABOR
0.35%
0.3 %
9.00S
20.31«
TOTAL COST
7.89 TON/H 20.00 S/TON
0.57 TON/H 40.00 S/TON
IOTAL CREDITS
" ' NET ANNUAL'COST"
HILLS PLK KILUWAI T-HUUR
ANNUAL COST15J
i65o^o.
271807.
1492s!
Ibbltil.
638110.
14016Q.
21024. .
lk!i!U4U5.
163060.
32236.
6196640.
9C3Vi6U.
829905.
12Q2S1.
" ' " 950157. " "
""• CS89203.
b. Ib
-------
PLANT NAME- STD 500 HS RETROFIT
PLANT ESCALATION FACTOR- 1.214
A... NA2C03 PREPARATION .._ _.'...
STORAGE SILO 85731.
0 VIBHATING- FEEUER 4555.
STORAGE TANK 62607.
AGITATORS- 16126..
r'' PUttPS + r-'OTOR 1456.
• • — — • — » — — — — — •• — ••
TOTAL A = 170477.
~:' B. so2 SCKU&BING
CO
""en . _ AbSOKBEKS _._ [ 9439636.
FANS + MOTORS 173999.
— - PUr.PS - •»- MOTuRS 27b287..
KEHEATtRS matSS.
SOOT—ULOWERS 1087-Z-'*-'W-
DUCTING 25H0337.
— — . VALVt-S 2036054..
TOTAU-B-=
X5969515.
C« PURGE- TREATMENT-
REFRIGERATION UNIT
TANKS
DhYER -----------------
ELF.VATOR
-PUMPS + MOTOR
CENTRIFUGE
STOKAGE SILO
-FtEOEB
-TOTAL C -=
266613.
.4029.1-^
43650.
. 2955U.
12140.
412550.
537226.
104078.
5530. .
. 209850.1. __
-------
REGENERATION
_*_MQIORS..
-OT
EVAPORATORS + REBOILERS
7bfal<40.
TANKS 7710«t.
cTB Tupro
BLOWER
TOTAL D = 7<»05698.
PARTICIPATE REMOVAL
R1_S£RUBBEJR 0 .•_
TAhKS 0,
.PUMPS <
JtOIAL-E-S 0_._
TOTAL INSTALLED DIRECT COST = 256Hi»395,
-------
INDIRECT COSTS
INTEREST CURING CONSTrtUCTION
P1ELO 1 ABOR "MJ FXPFN-SFS
CONTRACTORS FEE AND EXPENSES
FKEIGHT
QFFSITE
SPARES
TAXES
ALLOWANCE FOR SHAKEDOWN
ACID PLAMT
1 TOTAL INDIRECT COST =
00
2564439.
2564439.
1202219.
320554.
126221.
1262219.
1HH16356.
*»*»*»»*»«»*»«»*»»»»**»«*»*»**»*»»»
CONTINGENCY
6012550.
***********************************
5960.._
PRflrr«;g MATrK
_STEAM^PROCESS...(BIU/HR)
COOL ING-WATER—tGAtS/JfR)
__307H56667..
COST-POLtftftS PER KILOWATT
96
-------
WELLMAN-LORD ANNUALIZED COSTS
-.QUANTITY. _UNIJ_JCOST_
-ANNUAL_XOSTL*)_
A. RAW-MATERIAL S-
SODft ASH
S/TON
32Q132,
B. UTILITIES
ELECTRICITY
DBf\C r*Z*Z Ll A 1 r D
COOLING WATER
REHFAT RTE/\M
PROCtSS STEAM
C „ QP£R^TIWG LABnR
DIRECT LABOR
SUPERVISION
O D. MA1WTENANCE
^ LARD* ANQ MATERIALS
SUPPLIES
E OVERHEAD
PI AMT
PAYKoLL
f, FT^KU COSTS
DEPKLC1ATIOD
INTEKIM REPLACEMENT
INSURANCE
CApI^AL COSTS
... .. -TOTAu fJXED-CHARGES
G. CREDITS
SULFuRIC ACIO
5604. KW 15.0 MILLS/KWH
4q17 3 GAL/HIM n.018 $/MGAL
1971.2 MGAL/MIN 0.004 S/MGAL
19,7 MM BTU/H 0.7fc4 S/MM BTU
307.4 MM BTU/H 0.764 $/MM BTU
a. 00 S/MANHR
15S8 OF DIRECT LABOR
4K OF FIXED INVESTMENT
15% OF LABOR AND MATERIALS
50% OF OPERATION AND MAINTENANCE
20% OF OPERATING LABOR
s nuK
I*, 00%
0.3 %
Ifl.feSK
TOTAL COST
' 15.28 TON/H 20.00 S/TON
\t\Q TOM/H 40.00 $/TON
TUTAL CREDITS
NTT Af|fJUAL TOST
MILLS PER KILOWATT-HOUR
441856.
75447! ._ .• . .
1235468.
140160.
21024.
1923012.
288451.
1186323.
32236.
8966043.
14688355.
1606810.
232B23.
1839634.
12A48721.
4.88
-------
APPENDIX D
BASIS OF
LIME - LIMESTONE
PROCESS DESIGN
D-l
-------
BASIS OF LIME/LIMESTONE PROCESS DESIGN
A. Design Values
The process design basis for the wet limestone system
used in this study was determined after review of process
designs used or proposed for use at various installations
and discussions with control system manufacturers. Figure
D.I presents a typical process flow sheet for the wet lime-
stone process.
The plant evaluated for illustration of design basis is
similar to the 500 MW existing model plant evaluated in this
study. It is a single 500 MW, pulverized coal fired boiler
with a remaining life of 30 years. The coal burned has a
heating value of 12,000 BTU/lb and a 3.5 percent sulfur
content. The allowable sulfur dioxide emission rate is the
New Source Performance Standard Limitation of 1.2 Ib/MM BTU
of heat input. The average annual capacity factor is 60
percent. The plant is assumed to be meeting particulate
emission rate limitations and thus requires no additional
particulate control.
Values of the major overall design parameters are
tabulated below:
0 Flue gas rate: 1,500,000 ACFM
0 Flue gas temperature: 310°F
D-2
-------
D
I
U)
REHEATER
ENTRAINMENT SEPARATOR
(TRUCK
HOPPER 03 R.R.
1
-c— •>.
TO ASH ^
DISPOSAL
POND
\
\_
1
-t — i
mf
J 2S 1
CLEAN CAS TO STACK
PLENUM
FAN
ri ii r rue ,. — •
1
*=-<
»i
VENTUR
CE
FROM ISP
FROM TRAINS
•'VENTURI CIRC. TANKS
EFFLUENT SLURRY SURGE
TANK & PUMPS
DEAD STORAGE PILES (30 days)
VENTURI CIRC. ABSORBER CIRC.
TANK & PUMPS TANK & PUMPS
ClARIFIER
SLUDGE FIIATION TANK
FIICD SLUDGE
TO DISPOSAL -*J
Figure D.I Typical process flow sheet of wet limestone - SO_ scrubbing system.
-------
0 Flue gas pressure: atmospheric
0 Average inlet S02 concentration: 5.54 ib/MM BTU (3.5%
S coal)
0 Outlet S02 concentration: 1.2 Ib/MM BTU (allowable)
0 Reheat: 50°F above dew point (from 125 to 175°F)
0 Limestone consumption: 130% stoichiometric
Limestone System
Unloading hopper: 100 ton capacity
Dead storage pile: 17,280 tons (30 day storage)
Feeders, Conveyors: Capacity = 139.2 ton/hr (5.8 x
maximum limestone flow)
Live storage silos: 3 @ 576 tons capacity (3 days
storage)
Ball mills: 2-15 tons/hr capacity units
Limestone slurry storage tank: 2 tanks @ 35,535 ft
capacity (24 hours storage)
Limestone slurry feed pumps: 2 pumps/train with 1
spare for each 2 operating pumps
Raw water pumps: 2
Clarifier: 3 units
Sludge pond: 142 acre pond with 50 foot dike which
would cover the remaining plant life of 30 years
Scrubbing System (each train)
Fan: 1-100% unit
Type - Double inlet centrifugal
AP = 16.0" H20
Absorber: type - TCA with 2 beds
AP = 10" H20
L/G =65 GPM/MACFM (inlet gas to absorber scrub-
ber)
Slurry concentration =8% (wt.)
D-4
-------
S02 removal = 85%+
Gas velocity =10 FPS, absorber
Circulating tank - 10 minutes retention, absorber
Pumps = 4/train plus 1 spare pump for each train
Entrainment Separator: Chevron vane type
Number passes - 2
AP = 2" H20
Gas velocity = 7 FPS
Reheater: type - indirect tubular
AT = 50°F (inlet temperature = 125°F; outlet
temperature = 175°F)
Heating medium - low pressure steam
B. Design Rationale
The design rationale used in the study are listed
below:
0 The unloading hopper was sized to hold 100 tons in
order to accommodate unloading of railroad cars as well
as trucks.
0 The limestone dead storage pile was sized for 30 days
storage to allow the plant to continue operating in the
event of an interruption in the supply of limestone.
0 The live storage silos were sized for 3 days storage.
0 The feeders and conveyors were sized at 5.8 times the
maximum limestone flow to allow the unloading of lime-
stone to take place during a 40 hour week while the
plant operates continuously.
0 2-15 tons/hr capacity ball mills were provided and
sized to allow the power plant to generate at maximum
capacity while burning high sulfur content coal. In
the event 1 mill was out of service, the other mill
could keep the plant operating for 64 hours.
0 The limestone slurry storage tanks were sized for 24
hours storage to allow the scrubbing trains to continue
operating for 59 hours with 1 mill out of service or
for 24 hours if maintenance required complete shutdown
of the 2 ball mills.
D-5
-------
0 In general, all pumps in the process are provided with
spares.
0 3 thickeners and a new pond (142 acres) were used with
diking to provide sufficient pond space for the life of
the plant. The thickener concentrates the effluent
slurry from 15% solids to 30% solids and then dis-
charges the 30% effluent slurry to the vacuum fil-
tration units. The effluent leaves the filtration unit
with a slurry 60% by weight and then enters a mixing
tank where the fixation additives are stirred in with
the 60% slurry and then pumped to the sludge pond.
0 A UOP* Turbulent Contact Absorber (TCA) was selected
for removal of the bulk of the SO?. This unit has 2
beds of hollow plastic spheres which move randomly
between support grids and provide the contact area
necessary for mass transfer of SO- from the gas to the
liquid phase. The absorber is designed for an L/G of
65 GPM/MACFM (inlet gas to the absorber) and a pressure
drop of 7" H20. Slurry concentration will be 8%; gas
velocity in the unit will be 10 FPS; and S02 removal is
specified to be about 85% plus. The size or the
turbulent contact absorbers will be 15' x 35' approxi-
mately in cross-section and will treat 375,000 ACFM,
respectively of saturated gas. Four absorbers will be
required for this unit.
0 Each absorber has a circulating tank sized to provide a
10-minute retention time based on the slurry circulat-
ing rate. This retention time is essentially the same
as that reported by others and should provide suffi-
cient time for desupersaturation and thus reduce
scaling potential.
However, if long retention times are required, the
incremental cost would be small since the circulating
tanks do not represent large cost items, but space
limitations may require locating a secondary tank some
distance away and require additional piping.
0 The Chevron vane-type entrainment separator was se-
lected to remove mist which is carried over in the gas
from the absorber. This unit contains two stages of
Chevron vanes which are washed continuously with water.
Superficial gas velocity through the unit is 7 FPS and
the pressure drop is expected to be about 2" H^O.
Design of the unit is based on information from C-E,
Chemico and UOP.
* Universal Oil Products Company
(Air Correction Division)
D-6
-------
0 The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for it
for adequate atmospheric dispersion. The number of
degrees of reheat necessary is variable and dependent
on a number of factors such as stack height, local
weather conditions, population density, terrain of the
area, maximum allowable SO? ground-level concentration,
etc. For this study, a reheat AT of 50°F was used;
this is believed to be about the minimum acceptable
value. Obviously, the lowest acceptable reheat AT
should be chosen since each increase of 50°F of the
flue gas temperature requires about 1.5% of the gross
heat input to the plant.
An indirect finned tubular heat exchanger was selected
for the reheater. The first 33% of the rows of tubes
are constructed of Alloy 20 for corrosion resistance to
the gas which enters at it's dew point. The remaining
67% of the rows are constructed of carbon steel.
Heating medium for the unit is low pressure saturated
steam. Pressure drop through the reheater is calculated
to be about 4" H20.
0 Based on experience at an existing installation, a
retractable soot blower is used for each 25 ft^ of
scrubber exit duct cross-section for the heat exchanger.
Half of the soot blowers will be on the entry side, the
remainder on the exit side of the heat exchanger.
0 Cost of reheat was based purely on a coal conversion
cost in BTU's.
D-7
-------
APPENDIX E
BASIS OF
WELLMAN - LORD
PROCESS DESIGN
E-l
-------
BASIS OF WELLMAN-LORD PROCESS DESIGN
A. Design Values
The process design basis for the Wellman-Lord system
used in this study was determined after review of process
designs used or proposed for use at various installations
and discussions with Davy Power Gas. Figure E.I presents a
typical process flow sheet for this process.
The plant evaluated for illustration of design basis is
similar to the 500 MW existing model plant evaluated in this
study. It is a single 500 MW, pulverized-coal-fired boiler.
The coal burned has a heating value of 12,000 BTU/lb, and a
3.5 percent sulfur content. The allowable sulfur dioxide
emission rate is the New Source Performance Standard Limi-
tation of 1.2 Ib/MM BTU of heat input. The average annual
capacity factor is 60 percent. The plant is assumed to be
meeting particulate emission rate limitations and thus
requires no additional particulate control.
Values of the major overall design parameters are
tabulated below:
0 Flue gas rate: 1,500,000 ACFM
0 Flue gas temperature: 310°F
0 Flue gas pressure: atmospheric
0 Average inlet S02 concentration: 5.54 Ib/MM BTU (3.5% S
coal)
E-2
-------
w
I
OJ
Figure E.I Typical process flow sheet of Wellman-Lord SO2 Scrubbing System.
-------
0 Outlet S02 concentration: 1.2 lb/MM BTU (allowable)
0 Reheat: 50°F above dew point (from 125 to 175°F)
0 Soda ash consumption: 5% stoichiometric
Soda Ash System
Unloading Hopper: 100 ton capacity
Storage Silo: 893 tons (30 day storage)
Feeders: Capacity = 3.72 tons (3.0 x maximum soda ash
flow)
3
Na2C03 Slurry Storage Tank: 570 ft (4 hours)
Na2CO_ Slurry Feed Pump: 1 pump
Raw Water Pumps: 2
Scrubbing System (Each Train)
Fan: 1-100% unit
Type - Double inlet centrifugal
AP = 16.0" H20
Absorber: Type - Seive tray with 2 stage (4 required)
AP = 8" H20
L/G = 3 GPM/MACFM/stage (inlet gas to absorber
scrubber)
Slurry Concentration = 25% (wt.)
SO - Removal = 90%+
Gas Velocity = 8 FPS
Solution Storage Tanks - 24 hour storage
Pumps = 2/stage plus 1 spare pump for each unit
Entrainment Separator: Chevron vane type (2/absorber)
Number passes = 2
AP = 2" H^O
E-4
-------
Gas Velocity = 7 FPS
Purge Treatment:
Refrigeration: Temperature 40°F; Flow - 5% of
recirculation rate
Centrifuge: Solids - 5% of stoichiometric Na2C03
Acid Plant:
Size: 415 tons/day (125% of average S02 flow)
S0~ Regeneration:
Evaporators: 30% slurry of Na HSC>3 based on SO,,
absorbed. Evaporators are sized for one hour
retention and 50% free space.
Reboilers: 7.5°F temperature rise; 8 Ibs of steam
per Ib of S02
Stripper: Overhead is 1 Ib SO- and 1 Ib H20
for every 1 Ib of S02
Reheater: type - indirect tubular
AT = 50°F (inlet temperature = 125°F;
outlet temperature = 175°F)
Heating Median - low pressure steam
B. Design Rationals
The design rationale used in the study are listed below:
0 The soda ash storage silo was sized for 30 days storage
to allow the plant to continue operating in the event
of an interruption in the supply of soda ash.
0 The feeders were sized at 3.0 times the maximum soda
ash flow.
0 The soda ash slurry storage tank was sized for 4 hours
storage.
0 In general, all critical pumps in the process are
provided with spares.
0 A sieve tray was selected for removal of the bulk of
the SO2« This unit has 2 stages of sieve trays to
provide the contact area necessary for mass transfer to
E-5
-------
S0~ from the gas to the liquid phase. The absorber is
designed for an L/G of 3 GPM/MACFM/stage (inlet gas to
the absorber) and a pressure drop of 8" H20. Slurry
concentration will be 25%; gas velocity in the unit
will be 8 FPS; and S02 removal is specified to be about
90%. Four units will be required and each will treat
375,000 ACFM of saturated gas.
The absorbers have common solution storage tanks sized
to provide a 24 hour storage of the slurry. This .
storage time allows the absorbers to operate for
approximately 24 hours in the event the acid plant
should breakdown.
The Chevron vane-type entrainment separator was se-
lected to remove mist which is carried over in the gas
from the absorber. This unit contains two stages of
Chevron vanes which are washed continuously with water.
Superficial gas velocity through the unit is 7 FPS and
the pressure drop is expected to be about 2" H20.
The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for it
for adequate atmospheric dispersion. The number of
degrees of reheat necessary is variable and dependent
on a number of factors such as stack height, local
weather conditions, population density, terrain of the
area, maximum allowable S02 ground-level concentration,
etc. For this study, a reneat AT of 50°F was used;
this is believed to be about the minimum acceptable
value. Obviously, the lowest acceptable reheat AT
should be chosen since each increase of 50°F of the
flue gas temperature requires about 1.5% of the gross
heat input to the plant.
An indirect finned tubular heat exchanger was selected
for the reheater. The first 33% of the rows of tubes
are constructed of Alloy 20 for corrosion resistance to
the gas which enters at it's dew point. The remaining
67% of the rows are constructed of carbon steel.
Heating medium for the unit is low pressure saturated
steam. Pressure drop through the reheater is calculated
to be about 4" H20.
Based on experience at an existing facility,«a re-
tractable soot blower is used for each 25 ft of
scrubber exit duct cross-section for the heat exchanger.
Half of the soot blowers will be on the entry side, the
remainder on the exit side of the heat exchanger.
E-6
-------
0 Cost of reheat was based purely on a coal conversion
cost in BTU's.
0 Purge treatment equipment was based for the most part
on TVA cost estimates.
0 The acid plant cost was based on costs furnished by
Wellman-Lord.
E-7
-------
APPENDIX F
NATIONWIDE FGD COST ASSESSMENT METHODOLOGY
F-l
-------
NATIONWIDE FGD COST ASSESSMENT METHODOLOGY
Data used in estimating the capital and annualized
costs of FGD systems for the selected plants were obtained
from:
(1) Steam Electric Power Plant Factors/1973 Edition,
National Coal Association.
(2) The L.S.U. data file (Strategies and Air Standards
Division, U.S. EPA).
(3) Directory of Electric Utilities, 1974-1975 (83rd
edition).
In several cases, more accurate information, obtained
through plant inspections and contacts, was available from
PEDCo files. Where discrepancies existed between data
sources, a "most reasonable" value was selected.
It is emphasized that because of site-specific factors
which could not be determined and evaluated due to time and
budget limitations, the costs reported for individual plants
are not accurate. Individual plant costs were determined
solely to generate national and regional estimates. These
estimates, however, are considered to be reasonable since
the errors in individual plant estimates should cancel.
In many cases, only a portion of total plants flue gas
required control to meet an emission limitation. The re-
P-2
-------
quired degree of control was computed by assuming a 90% S0_
removal efficiency for the flue gas treated. For example,
if S0~ control requirements at a 1000 megawatt plant amounted
to 40 percent overall control, cost estimates were prepared
40%
on the basis of controlling 445 megawatts (r x 1000 MW) .
The individual boilers selected for control were chosen on
the basis of remaining lives, with the newer boilers con-
trolled first.
Individual plant data necessary for FGD cost estimates
which were not available (without direct plant contact) ,
were estimated using applicable regional averages as itemized
in Table F.I and delineated below.
Table F.I ASSUMED VALUES FOR REGIONAL VARIABLES
THAT AFFECT FGD SYSTEM COST
Region
East West East
New Middle North North South South
Regional characteristic England Atlantic Central Central Atlantic Central Mountain
Operating labor rate, $/man-hr 8.0 9.0 8.0 7.0 7.0 6.50 7.25
Power cost, mills/KWH 25.00 20.00 15.00 13.00 13.00 12.00 19.00
Limestone cost, $/ton 9.00 5.00 4.50 4.25 5.00 4.00 8.00
Sludge Disposal (Limestone system) - Sludge disposal
was determined to be either on-site or off-site accord-
ing to each plant's location. Plants located in rural
areas were assumed to have adequate land for on-site
disposal, whereas plants in urban areas were assumed to
require offsite disposal.
Capacity Factor - Assumed to be 0.6 if data not avail-
able.
Capital Cost - Assumed to be 9% (after taxes) for all
plants.
F-3
-------
Soda-Ash Cost (Wellman-Lord) - Assumed to be $55/ton
for all plants.
Acid Credit (Wellman-Lord) - Assumed to be $20/ton for
all plants.
Salt Cake Credit (Wellman-Lord) - Assumed to be $40/ton
for all plants.
Table F.2 presents a summary of the estimated plant FGD
system costs.
F-4
-------
Table F.2 FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
NEW ENGLAND
Massachusetts
Bray ton Pt.f
New England
Power Company
MIDDLE ATLANTIC
New York
Charles Huntleyf
Niagara Mohawk
Power Corp.
Dunkirk
Niagara Mohawk
Power Corp.
Goudey
N.Y. State E. &
G. Corp.
Scrubbed
units
Rem.
lifeb
25
23
25
20
Cap.
(MW)
695
233
103
16
Total
plant
cap.
(MW)
965
828
628
146
Sulfur
content
of
coal, %
1.00
2.53
2.9
2.3
Cap.
factor
(1973)
0.79
0.56
0.69
0.53
Sludge
disposal
Off-
site
X
X
On-
Site
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
57 (82)
22 (96)
11 (109)
3 (179)
Limestone
$ MM ($/KW)
41 (58)
15 (63)
9 (87)
4 (255)
Annualized costs
Wellman-Lord
Total •
fuel and , power
O&M
$ MM/yr
(mills/KWH)
17 (3.6)
4.2 (0.9)
2.26 (0.5)
6.5 (5.7)
0.9 (0.8)
1.4 (1.2)
3.5 (5.7)
0.70 (1.1)
0.82 (1.3)
1.1 (14.7)
0.08 (1.1)
0.4 (5.9)
Limestone
Total
fuel and power
O&M
$ MM/yr
(mills/KWH)
14.7 (3.1)
2.2 (0.5)
4.9 (1.1)
4.5 (3.9)
0.4 (0.3)
1.4 (1.2)
3.1 (5.0)
0.3 (0.5)
1.1 (1.8)
1.4 (19.3)
0.05 (0.7)
0.6 (8.3)
I
tn
Costs presented in this table are based on S0? removal efficiencies required to meet projected emission
limitations. All $/KW costs are based on KW's of plant capacity scrubbed.
Weighted by unit capacity.
Fuel and electricity costs.
Operation and maintenance costs, excluding fuel and electricity costs and fixed costs.
Net operation and maintenance costs (Includes byproduct credits), excluding fuel and electricity costs and
fixed costs.
Requires 25% or more S02 control.
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
New York (cont. )
Green idge
M.Y G « E Co.
Mi 111 ken
N.Y. State E &
Gas Co.
Rochester 3
Rochester Gas &
Electric Corp.
Rochester 7
Rochester Gas &
Electric Corp.
Pennsylvania
Cheswickf
Duquesne Light
Co.
Croniby
Phil. Elec. Co.
Eddystone
PM1. Elec. Co.
Scrubbed
units
Rem.,
lifeb
18
23
24
22
35
20
25
Cap.
(MW)
12
30
7
21
525
361
608
Total
plant
cap.
(MW)
167
270
196
253
525
418
707
Sulfur
content
of
coal , %
2.4
2.3
2.6
2.47
2.3
2.4
2.5
Cap.
factor
(1973)
0.71
0.68
0.38
0.62
0.77
0.75
0.6
Sludge
disposal
Off-
site
X
X
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM (S/KW)
3 (209)
4 (144)
2 (259)
3 (156)
55 (104)
35 (97)
52 (86)
Limestone
$ MM ($/KW)
4 (320)
5 (165)
4 (487)
4 (206)
39 (75)
24 (67)
36 (59)
Annualized costs
Wcllman-Lord
Total c
fuel and^power
O&M
$ MM/yr
(mills/KWH)
1.0 (13.5)
0.08 (1.1)
0.44 (5.0)
1.5 (8.5)
0.20 (1.1)
0.50 (2.9)
0.82 (33.1)
0.03 (1.2)
0.44 (17.8)
1.2 (10.6)
0.12 (1.1)
0.47 (4.2)
15 (4.4)
3.2 (1.0)
1.7 (0.5)
10 (4.4)
2.2 (1.0)
1.6 (0.7)
15 (4.7)
2.2 (0.7)
3.0 (0.9)
Limestone
Total c
fuel andepower
O&M
$ MM/yr
(mills/KWH)
1.4 (18.8)
0.06 (0.8)
0.6 (8.0)
1.7 (9.7)
0.10 (0.57)
0.70 (3.8)
1.3 <52.1
0.03 (1.2
0.60 (23.9
1.5 (13.3)
0.07 (0.6
0.63 (5.6
13 (3.7)
1.33 (0.4)
4.54 (1.3)
8.3 (3.5)
0.92 (0.4)
2.88 (1.2)
13 (4.1
1.1 (0.4
5.2 (1.6
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS
REGION
State
Plant name
Power Co.
Pennsylvania
(cont.)
Holtwood
Penn. P 8 L Co.
Mitchellf
Allegheny Power
Service Corp.
Newcastle f
Penn Power Co.
Phillipsf
Duquesne Light
Co.
Seward
Penn. Elec. Co.
Springdale-^
W. Penn Power
Co.
Scrubbed
units
Rem.
lifeb
20
23
29
20
22
17
Cap.
(MW)
41
444
133
298
55
179
Total
plant
cap.
(MW)
75
449
426
411
268
416
Sulfur
content
of
coal, %
2.2
2.4
3.2
2.3
2.95
1.6
Cap.
factor
(1973)
0.51
0.6
0.64
0.6
0.6
0.66
Sludge
disposal
Off-
site
X
X
On-
Site
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
5 (135)
43 (97)
16 (117)
36 (121)
5 (83)
16 (92)
Limestone
$ MM ($/KW)
5 (135)
29 " (66)
11 (84)
22 (72)
6 (102)
13 (70)
Annualized costs
Wellman-Lord
Total
fuel and, power
O&M
$ MM/yr
(mills/KWH)
1.8 (10.02)
0.21 (1.2)
0.57 (3.2)
12 (5.3
2.3 (1.0
2.1 (0.9
4.8 (6.4)
1.0 (1.3)
0.89 (1.2)
11 (6.7)
2.3 (1.5)
1.5 (1.0)
1.6 (5.5)
0.15 (0.5)
0.61 (2.1)
5.2 (5.0)
0.85 (0.8)
1.1 (1.1)
Limestone
Total
fuel and power0
OSMe
$ MM/yr
(mills/KWH)
1.9 (10.3)
0.09 (0.5)
0.79 (4.3)
9.6 (4.1)
0.86 (0.4)
3.3 (1.4)
4.5 (6.0)
0.31 (0.4)
2.11 (2.8)
8.9 (5.7)
0.62 (0.4)
4.26 (2.7)
1.9 (6.5)
0.13 (0.5)
0.73 (2.5)
4.3 (4.1)
0.42 (0.4)
1.44 (1.4)
I
-J
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
EAST NORTH
CENTRAL
Illinois
Baldwin
111. Power Co.
Coffeen
Central 111. Pub.
Service
Da 11 man
Springfield Water
Light & Power
Dept.
Dixon
Com. Edison Co.
Jolietf '
Com. Edison Co.
Kincaidf
Com. Edison Co.
Scrubbed
units
Rem.
lifeb
38
36
37
18
30
33
Cap.
(MW)
891
216
26
22
1407
397
Total
plant
cap.
(MW)
1246
1006
160
119
1862
1320
Sulfur
content
of
coal, %
2.8
3.63
3.75
4.4
3.03
4.2
Cap.
factor
(1973)
0.66
0.36
0.60
0.67
0.60
0.45
Sludqc
disposal
Off-
site
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
93 (104)
26 (122)
5 (179)
4 (192)
130 (98)
50 (127)
Limestone
$ MM ($/KW)
54 (60)
15 (70)
5 (194)
4 (204)
77 (58)
30 (75)
Annualized costs
Wellman-Lord
Total
fuel and, power
O&M
$ MM/yr
(mills/KWH)
25 (4.8)
4.0 (0.8)
3.3 (0.6)
7.1 (10.4)
0.78 (1.1)
1.4 (2.1)
1.5 (11.0)
0.17 (1.3)
0.46 (3.4)
1.4 (11.0)
0.17 (1.3)
0.42 (3.3)
35 (5.0)
5.2 (0.7)
5.6 (0.8)
13 (8.5)
1.9 (1.2)
2.0 (1.3)
Limestone
Total
fuel and power
O&M6
$ MM/yr
(mills/KWH)
18 (3.5)
1.46 (0.3)
6.54 (1.3)
f
4.8 (7.1)
0.20 '(0.3)
1.8 (2.7)
1.7 (12.5)
0.06 (0.4)
0.71 (5.2)
1.6 (12.4)
0.05 (0.4)
0.69 (5.3)
25 (3.6)
1.93 (0.3)
8.79 (1.3)
9.6 (6.1
0.5 (0.3
3.6 (2.3
I
00
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Illinois (cont.)
Lakeside
Springfield
Water L & P Dept.
Marion
S. 111. Power
Cooperate
Venice
Union Elec. Co.
Waukegan
Com. Edison Co.
Will County f
Com. Edison Co.
Wood River
111 . Power Co.
Indiana
f
Baily
No. Ind. Public
Serv. Co.
Scrubbed
units
Rem.
lifeb
30
37
15
26
28
27
32
Cap.
(MW)
21
19
61
451
612
486
486
Total
plant
cap.
(MW)
146
114
500
1042
1269
657
616
Sulfur
content
of
coal, %
3.8
3.95
1.2
1.83
0.92
3.1
3.6
Cap.
factor
(1973)
0.21
0.52
0.25
0.45
0.44
0.47
0.49
Sludge
disoosal
Off-
site
X
X
X
On-
Site
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
4 (182)
4 (202)
6 (95)
40 (89)
47 (77)
51 (104)
45 (93)
Limestone
$ MM ($/KW)
4 (202)
5 -(237)
6 (95)
27 (61)
34 (56)
33 (68)
27 (55)
Annualized costs
Wellman-Lord
Total
fuel and, power0
0&Ma
$ MM/yr
(mills/KWH)
1.3 (32.7)
0.05 (1.3)
0.5 (13.5)
1.3 (14.8)
0.1 (1.1)
0.5 (5.4)
1.9 (14.2)
0.08 (0.6)
0.64 (4.8)
11 (6.1)
1.0 (0.6)
2.5 (1.4)
13 (5.3)
1.0 (0.4)
2.8 (1.2)
14 (6.6)
1.7 (0.8)
2.4 (1.2)
12 (5.5)
1.7 (0.8)
1.9 (0.9)
Limestone
Total
fuel and power
O&M
$ MM/yr
(mills/KWH)
1.5 (37.9)
0.02 (0.4
0.69 (17.3)
1.5 (17.7)
0.04 (0.5)
0.62 (7.32)
2.0 (14.4)
0.05 . (0.4)
0.75 (5.4)
10.8 (6.1)
0.51 (0.3)
5.19 (2.9)
10.2 (4.3)
0.60 (0.3)
3.16 (1.3)
10.3 (5.0)
0.60 (0.3)
3.49 (1.7)
14 (6.4)
0.50 (0.2)
8.48 (3.9)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Indiana (cont.)
Clifty Creek
Ind.-Ky. Elec.
Corp.
Culley
S. Ind. G & E
Co.
Dresser
Pub. Service Co.
Edwardsport
Pub. Service Co.
Elmer Stout
Ind. P & L Co.
Logansport
Logansport Mun.
Utilities
Michigan Cityf
No. Ind. Pub.
Service
Scrubbed
units
Rem.,
lifeb
21
31
15
15
38
37
15
Cap.
(MW)
135
92
24
138
260
29
118
Total
plant
cap.
(MW)
1304
397
150
144
752
39
236
Sulfur
content
of
coal, %
3.6
3.5
4.1
2.8
2.7
2.1
2.9
Cap.
factor
(1973)
0.83
0.49
0.3
0.24
0.36
0.27
0.45
Sludge
disposal
Off-
site
X
On-
Site
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
15 (113)
11 (124)
4 (172)
16 (114)
25 (97)
5 (158)
14 (118)
Limestone
$ MM ($/KW)
10 (78)
9 . (93)
4 (182)
11 (81)
18 (70)
5 (176)
10 (85)
Annualized costs
Wollmnn-Lord
Total
fuel and^power0
O&M
$ MM/yr
(mills /KWH)
4.4 (4.52)
1.0 (1.0)
0.6 (0.6)
3.3 (8.3)
0.40 (1.0)
0.75 (1.9)
1.4 (22.5)
0.07 (1.1)
0.5 ' (8.2)
4.7 (16.0)
0.27 (1.0)
4.2 (4.1)
6.9 (8.3)
0.6 (0.7)
1.6 (1.9)
1.5 (21.4)
0.06 (0.8)
0.60 (8.3)
4.2 (9.1)
0.46 (1.0)
0.90 (2.0)
Limestone
Total
fuel and power0
O&M
$ MM/yr
(mills/KWH)
3.8 (3.8)
0.29 (0.3)
1.56 (1.6)
2.8 (7.2)
0.13 (0.3)
1.07 (2.7)
1.5 (24.4)
0.03 (0.5)
0.57 (9.2)
3.6 (12.2)
0.09 (0.3)
1.24 (4.2)
6.2 (7.6)
0.24 (0.3)
2.57 (3.1)
1.6 (23.8)
0.03 (0.4)
0.62 (9.2)
3.4 (7.3)
0.15 (0.3)
1.23 (2.6)
i
M
O
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS
REGION
State
Plant name
Power Co.
Indiana (cont.)
Mitchell*
No. Ind. Pub.
Serv.
Petersburg
Ind.
State Linef
Com. Edison
Tanners Creek
Ind. & Mi. Elec.
Twin Branch
Ind. & Mi. Elec.
Wabash Riverf
Pub. Service
Co. of Ind.
Warrick #4f
S. Ind. G & E
Scrubbed
units
Rem.
lifeb
26
34
24
25
1
28
32
Cap.
(MW)
456
28
622
927
102
700
650
Total
plant
cap.
(MW)
529
650
964
1098
394
962
732
Sulfur
content
of
coal, %
3.0
3.0
1.5
3.5
4.4
2.6
3.4
Cap.
factor
(1973)
0.71
0.68
0.63
0.74
0.25
0.59
0.36
Sludge
disposal
Off-
site
X.
On-
Site
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
46 (101)
a (154)
53 (85)
99 (107)
14 (133)
69 ' (99)
79 (122)
Limestone
$ MM ($/KW)
28 (62)
5 .(175)
39 (63)
58 (63)
8 (83)
45 (64)
45 (70)
Annualized costs
Wellman-Lord
Total c
fuel and,power
O&M
$ MM/yr
(mills/KWH)
13 (4.5)
2.7 (0.9)
1.6 (0.6)
1.4 (8.5)
0.16 (1.0)
0.43 (2.6)
14 (4.2)
1.7 (0.5)
2.4 (0.7)
27 (4.4)
5.0 (0.8)
3.2 (0.5)
4.5 (20.1)
9.3 (1.3)
1.0 (4.3)
19 (4.7)
3.0 (0.7)
3.12 (0.8)
21 (10.2)
2.5 (1.2)
3.7 (1.8)
Limestone
Total
@
fuel and-power
O&M
$ MM/yr
(mills/KWH)
9.7 (3.4)
0.8 (0.3)
3.6 (1.3)
1.7 (10.0)
0.07 (0.4)
0.72 (4.2)
15 (4.5)
1.00 (0.3)
6.78 (2.0)
20 (3.3)
1.6 (0.3)
7.36 (1.2)
3.! (13.9)
0.08 (0.4)
1.03 (4.6)
15 (3.7)
1.20 (0.3)
5.11 (1.3)
14 (6.8)
0.6 (0.3)
4.94 (2.4)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Michigan
Cobbf
Consumers Power
Co.
Conners Creek
Det. Edison Co.
Eckert #5, #6 f
Lansing Board
of W and L
Erickson
Lansing Board
of W & L
Karn
Consumer Power
Co.
Marysville
Det. Edison Co.
Pennsalt
Det. Edison Co.
Scrubbed
units
Rem.
lifeb
21
5
35
38
26
12
14
Cap.
(MW)
354
118
77
74
156
76
15
Total
plant
cap.
(MW)
510
460
160
160
530
200
37
Sulfur
content
of
coal, %
2.8
1.6
2.8
2.7
3.0
2.5
2.13
Cap.
factor
(1973)
0.82
0.63
0.60
0.60
0.79
0.54
0.23
Sludge
disposal
Off-
site
X
X
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
34 (96)
11 (91)
9 (116)
9 (119)
15 (99)
8 (110)
3 (200)
Limestone
$ MM (S/KW)
22 (62)
8 . (71)
8 (100)
8 (104)
11 (73)
70 (92)
4 (269)
Annualized costs
Wellman-Lord
Total
fuel and^power
O&M
$ MM/yr
(mills/KWH)
9.7 (3.8)
2.0 (0.8)
1.3 (0.5)
4.8 (7.4)
0.4 (0.6)
0.8 (1.2)
2.7 (6.6)
0.36 (0.9)
0.66 (1.6)
2.6 (6.8)
0.37 (1.0)
0.60 (1.6)
4.5 (4.2)
0.89 (0.8)
0.73 (0.7)
2.8 (7.7)
0.29 (0.8)
0.68 (1.9)
1.1 (36.8)
0.02 (0.7)
0.44 (14.7)
Limestone
Total
(^
fuel and power
O&M
$ MM/yr
(mills/KWH)
8.5 (3.4)
0.8 (0.3)
3.62 (1.4)
4.0 (6.2)
0.2 (0.3)
1.03 (1.6)
2.6 (6.3)
0.14 (0.3)
1.02 (2.5)
2.5 (6.5)
0.13 (0.3)
0.95 (2.5)
3.9 (3.6)
0.3 (0.3)
1.46 (1.4)
2.5 (7.1)
0.10 (0.3)
0.85 (2.4)
1.4 (46.7)
0.01 (0.5)
0.54 (17.9)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Michigan (cont.)
River Rouge
Oet. Edison Co.
St. Clairf
Det. Edison Co.
Trenton Channel
Oet. Edison Co.
James De Young
Holland Board
of Pub. Works
Ohio
Avon Lake
Clev. Elec.
Illumination Co.
Beckjord
C.G. & E. Co.
Burger
Ohio Edison Co.
Scrubbed
units
Rem.
lifeb
23
30
5
37
24
28
20
Cap.
(MW)
495
1054
421
60
81
1174
471
Total
plant
cap.
(MW)
842
1905
800
77
1275
1221
544
Sulfur
content
of
coal, %
2.8
3.1
2.5
3.5
2.9
3.6
2.8
Cap.
factor
(1973)
0.65
0.74
0.71
0.60
0.53
0.37
0.60
Sludge
disposal
Off-
site
X
X
X
On-
Site
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
47 (94)
104 (99)
43 (101)
9 (158)
9 (113)
123 (105)
40 (84)
Limestone
$ MM ($/KW)
30 (60)
66 . (62)
27 (65)
8 (136)
7 (92)
70 (59)
•
25 (54)
Annualized costs
Wellman-Lord
Total
«
fuel and ..power
0&Md
$ MM/yr
(mills/KWH)
13 (4.5)
1.9 (0.7)
2.1 (0.7)
28
5.3
3.3
4-1)
0.8)
0.3)
18 (6.8)
1.6 (0.6)
2.0 (0.8)
2.8 (8.8)
0.35 (1.1)
0.70 (2.2)
2.7 (7.2)
0.33
0.67
0.9)
1.8)
33 (8.6)
3.8 (1.0)
6.3 (1.6)
11 (4.1)
2.0 (0.7)
1.7 (0.6)
Limestone
Total
fuel and power
O&M
$ MM/yr
(mills/KWH)
14 (5.0)
0.80 (0.3)
7.66 (2.7)
34 (4.9)
1.9 (0.3)
19 (2.9)
13 (5.0)
0.75 (0.3)
3.08 (1.2)
2.6 (8.4)
0.12 (0.4)
0.9£ (3.2)
2.5 (6.6)
0.12 (0.3)
0.98 (2.6)
22 (5.7)
1.0 (0.3)
7.5 (2.0)
9.8 (3.6)
0.70 (0.3)
4.4 (1.6)
I
M
U)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Ohio (cont.)
Clev. Div. of.
Pwr. & Light T
Same
Cardinal
Ohio Power Co.
Conesville
Col. and S. Ohio
Elec. Co.
East Lakef
Clev. Elec.
Illumination Co.
Gavin
Ohio Power Co.
George
Ohio Edison Co.
Kyger Creek
Ohio Valley Elec.
Co.
Scrubbed
units
Rem.
lifeb
20
32
27
37
40
12
20
Cap.
(MW)
144
286
143
460
2340
80
337
Total
plant
cap.
(MW)
160
1180
434
1275
2600
87.5
1086
Sulfur
content
of
coal, %
3.15
3.5
4.8
3.3
3.7
3.23
3.8
Cap.
factor
(1973)
0.60
0.75
0.70
0.76
0.60
0.58
0.75
Sludge
disposal
Off-
site
X
X
On-
Site
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
17 (115)
30 (104)
20 (137)
48 (104)
261 (112)
11 (137)
40 (119)
Limestone
$ MM ($/KW)
12 (84)
20 . (71)
12 (85)
32 (69)
160 (68)
8 (97)
21 (64)
Annualized costs
Wellrnan-Lord
Total
fuel and oowerc
0&Md
$ MM/yr
(mills/KWH)
4.7 (6.3)
0.67 (0.9)
0.94 (1.2)
8.2 (4.4)
1.6 (0.8)
1.1 (0.6)
5.6 (6.3)
1.2 (1.4)
0.69 (0.8)
13 (4.2)
2.2 (0.7)
1.9 (0.6)
69 (5.5)
11 (0.9)
9.1 (0.7)
3.6 (8.8)
0.47 (1.2)
0.69 (1.7)
11 (4.9)
2.5 (1.1)
1.0 (0.4)
Limestone
Total
fuel and powerc
0&Me
$ MM/yr
(mills/KWH)
4.4 (5.8)
0.20 (0.3)
1.9 (2.6)
7.0 (3.7)
0.55 (0.3
2.64 (1.4
4.4 '(5.0)
0.30 (0.3)
1.83 (2.1)
12 (3.9)
0.9 (0.3)
5.2 (1.7)
53 (4.3)
3.5 (0.3)
19.7 (1.6)
3.0 (7.2)
0.12 (0.3)
1.2 (2.8)
8.0 (3.6
0.6 (0.3
3.4 (1.5
I
M
*>
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Ohio (cont.)
Lake Road
Clev. Div. of
L & W
Lake Shore
Clev. Elec.
Illumination Co.
tfiami Fortf
C. G. & E. Co.
Muskingum River
Ohio Power Co.
Philof
Ohio Power Co.
Piquaf •
Piqua Municipal
Power System
Poston
Col. & S. Ohio
Elec. Co.
Scrubbed
units
Rem.
lifeb
35
26
20
28
8
14
18
Cap.
(MW)
129
283
249
1036
382
46
132
Total
plant
cap.
(MW)
160
541
387
1466
500
53
232
Sulfur
content
of
coal, %
2.2
2.5
3.5
5.0
3.7
2.86
3.1
Cap.
factor
(1973)
0.19
0.52
0.57
.
0.71
0.33
0.35
0.57
Sludge
disposal
Off-
site
X
X
X
On-
Site
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
12 (90)
27 (96)
27 (109)
133 (128)
48 (125)
5 (117)
16 (121)
Limestone
$ MM ($/KW)
10 (79)
19 (68)
17 (68)
73 (71)
25 (65)
5 (117)
11 (84)
Annualized costs
Wellman-Lord
Total
fuel and,powerc
0&Md
S MM/yr
(mills/KWH)
3.3 (15.5)
0.11 (0.5)
1.0 (4.8)
7.4 (5.8)
0.88 (0.7)
1.5 (1.1)
7.6 (6.1)
1.3 (1.0)
1.3 (1.0)
35 (5.4)
7.9 (1.2)
2.4 (0.4)
14 (13.0)
1.5 (1.2)
2.0 (1.8)
1.8 (12.8)
0.09 (0.6
0.60 (4.3)
4.7 (7.1)
0.70 (1.0)
0.90 (1.4)
Limestone
Total
c
fuel and power
O&M
$ MM/yr
(mills/KWH)
3.0 (14.1)
0.07 (0.3)
1.0 (4.9)
6.7 (5.2)
0.40 (0.3)
2.76 (2.2)
5.7 -(4.6)
0.38 (0.3)
2.2 (1.8)
26 (4.1)
1.9 (0.3)
12.4 (1.9)
8.7 (7.8)
0.34 (0.3)
3.0 (2.7)
1.9 (13.3)
0.04 (0.3)
0.72 (5.1)
3.7 (5.6)
0.22 (0.3)
1.37 (2.1)
I
M
Ul
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co .
Ohio (cent.)
Sammis
Ohio Edison Co.
Stuartf
Dayton Power &
Light Co.
Tiddf
Ohio Power Co.
Toronto
Ohio Edison Co.
Vine Street
Orrville Mun.
Utilities
WEST NORTH
CENTRAL
Iowa
Ames #2f
Ames Elec. Oept.
Scrubbed
units
Rem.
life13
34
37
12
14
37
37
Cap.
(MW)
1255
342
201
51
35
42
Total
plant
cap.
(MW)
1980
1830
222
176
64
68
Sulfur
content
of
coal, %
2.7
1.9
3.4
3.0
3.5
3.56
Cap.
factor
(1973)
0.71
0.71
0.57
0.49
0.37
0.40
Sludge
disposal
Off-
site
X
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
122 (97)
31 (90)
22 (107)
5 (147)
5 (138)
5 (111)
Limestone
$ MM ($/KW)
78 (62)
22 (65)
14 (69)
5 (152)
5 (145)
5 (127)
Annualized costs
Wcllman-Lord
Total
fuel and power
0&Md
$ MM/yr
(mills/KWH)
33 (4.2)
4.9 (0.6)
5.4 (0.7)
8.4 (4.0)
1.0 (0.5)
1.6 (0.8)
6.8 (6.8)
0.90 (0.9)
1.1 (1.0)
1.6 (11.9)
0.13 (1.0)
0.53 (3.9)
1.5 (13.6)
0.10 (0.9)
0.49 (4.4)
1.5 (10.0)
0.07 (0.5)
0.57 (3.8)
Limestone
Total
fuel and powerc
O&M6
$ MM/yr
(mills/JCWH)
26 (3.3)
2.2 (0.3)
9.4 (1.2)
7.1 (3.3
0.60 (0.3
2.4 (1.1
5.0 (5.1)
0.3 (0.3)
1.6 (1.6)
1.7 (12.8)
0.06 (0.4)
0.65 (4.9)
1.7 (14.8)
0.04 (0.3)
0.72 (6.2)
1.7 (11.5)
0.04 (0.3)
0.68 (4.6)
-------
Table P.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS*
REGION
State
Plant name
Power Co.
Minnesota
Blackdogf
N. States Power
Co.
High Bridge
N. States Power
Co.
Kingf
N. States Power
Co.
Missouri
Meramec
Union Elec. Co.
Rush Island
1, 2 Union Elec.
Co.
Sioux
Union Elec. Co.
Scrubbed
units
Rem.,
life*1
25
5
33
26
40
33
Cap.
(MW)
25
20
301
433
102
619
Total
plant
cap.
(MW)
487
438
574
923
1184
1100
Sulfur
content
of
coal, %
1.6
1.6
3.0
1.47.
2.4
2.74
Cap.
factor
(1973)
0.77
0.61
0.60
0.62
0.60
0.39
Sludge
disnosal
Off-
site
X
X
X
X
On-
Site
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
3 (139)
3 (149)
32 (108)
36 (82)
9 (88)
53 (85)
Limestone
$ MM ($/KW)
4 (173)
4 -(186)
20 (67)
27 (61)
8 (75)
38 (61)
'
Annualized costs
Wellman-Lord
Total
fuel and power0
O&Md
$ MM/yr
(mills/KWH)
1.2 (6.9)
0.10 (0.6)
0.44 (2.6)
1.5 (13.8)
0.07 (0.7)
0.43 (3.9)
8.5 (5.4)
1.2 (0.8)
1.3 (0.8)
9.5 (4.0)
l.'l (0.5)
1.8 (0.7)
2.6 (4.9)
0.34 (0.6)
0.59 (1.1)
14 (6.5)
0.84 (0.4)
3.3 (1.6)
Limestone
Total
fuel and power0
OSMe
$ MM/yr
(mills/KWH)
1.5 (9.1)
0.06 (0.4)
0.63 (3.8)
1.8 (17.1)
0.04 (0.4)
0.59 (5.6)
7.5 "(4.8)
0.40 (0.3)
3.3 (2.1)
9.7 (4.1)
0 55 (0.2)
4.2 (1.8)
2.5 (4.7)
0.14 (0.3)
2.0 (1.8)
12 (5.7)
0.5 (0.2)
4.5 (2.1)
I
I-1
^J
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS*
REGION
State
Plant name
Power Co.
SOUTH ATLANTIC
Delaware
Delaware City
Delmarva Power
& Light Co.
Florida
Big Bendf
Tampa Elec. Co.
Cristf
Gulf Power Co.
Gannon
Tampa Elec. Co.
Lansing Smith
Gulf Power Co.
Georgia
Hammond
Georgia Power
Co.
Scrubbed
units
Rem.,
lifeb
24
35
37
30
31
35
Cap.
(MW)
130
742
810
970
244
365
Total
plant
cap.
(MW)
130
900
1128
1270
305
953
Sulfur
content
of
coal, %
7.03
3.0
3.4
3.1
3.0
3.5
Cap.
factor
(1973)
0.60
0.54
0.62
0.48
0.83
0.64
Sludge
disposal
Off-
site
X
X
X
On-
Site
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
13 (96)
67 (90)
80 (99)
84 (87)
27 (111)
44 (120)
Limestone
$ MM ($/KW)
10 (75)
43 (58)
49 (61)
50 (52)
17 (69)
30 (81)
Annualized costs
Wellman-Lord
Total
fuel and,power
O&M
$ MM/yr
(mills/KWH)
3.6 (5.2)
0.45 (0.7)
0.8 (1.2)
17 (4.8)
1.9 (0.5)
2.6 (0.7) .
20 (4.6)
2.4 (0.6)
2.7 (0.6) .
22 (5.3)
2.2 (0.5)
4.2 (1.0)
7.3 (4.1)
1.4 (0.8)
0.8 (0.5)
13 (6.1)
2.4 (1.2)
2.4 (1.2)
Limestone
Total c
fuel and power
O&M
$ MM/yr
(mills/KWH)
3.8 (5.5)
0.20 (0.3)
1.8 (2.7)
20 '(5.6)
0.50 (0.1)
11.5 (3.2)
16 (3.6)
0.70 (0.2)
6.1 (1.4)
22 (5.4)
0.62 (0.2)
12.0 (3.0)
6.0 (3.4)
0.50 (0.3)
1.38 (1.3)
9.5 (4.6)
0.60 (0.3)
3.4 (1.6)
I
M
00
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Maryland
Chalk Pointf
Pot. Elec. Pw.
Co.
Dickerson
Potomac Elec.
Power Co.
Morgantown
Potomac Elec.
Power Co.
South Carolina
Urquhart
S. Carolina Elec.
& Gas Co.
VI rg i n i a
Potomac River
Potomac Elec.
Power Co.
West Virginia
Albrightf
Allegheny Power
Service Corp.
Scrubbed
units
Rem.
life*5
30
27
36
32
22
19
Cap.
(MW)
571
227
424
20
158
66
Total
plant
cap.
(MW)
710
570
1451
250
486
200
Sulfur
content
of
coal, %
1.9
1.9
1.7
1.6
1.0
2.8
Cap.
factor
(1973)
0.43
0.73
0.67
0.72
0.56
0.85
Sludge
disposal
Off-
site
X
X
X
X
On-
Site
X
X
Capital costs
We 1 Ima n- Lo rd
$ MM ($/KW)
47 (82)
19 (84)
33 (77)
4 (125)
11 (71)
8 (116.)
Limestone
$ MM ($/KW)
31 (54)
13 - (58)
26 (61)
5 (143)
10 (64)
7 (99)
Annualized costs
Wellman-Lord
Total
fuel and,powerc
O&M
$ MM/yr
(mills/KWH)
12 (5.8)
1.0 (0.5)
2.3 (1.1)
5.2 (3.6)
0.67 (0.5)
1.0 (0.7)
8.8 (3.5)
0.9 (0.4)
1.8 (0.7)
1.3 (6.5)
0.10 (0.5)
0.50 (2.3)
3.3 (4.3)
0.26 (0.3)
0.93 (1.2)
2.3 (4.7)
0.40 (0.8)
0.50 (1.0)
Limestone
Total
fuel and power
O&M-
$ MM/yr
(mills/KWH)
9.5 (4.4)
0.8 (0.4)
3.0 (1.4)
4.8 (3.3)
0.40 (0.3)
2.0 (1.4)
8.0 "(3.2)
0.57 . (0.2)
2.58 (1.0)
1.5 (7.6)
0.0,' (0.4)
0.58 (2.9)
3.2 (4.1)
0.20 (0.3)
1.1 (1.4)
2.3 (4.7)
0.15 (0.3)
0.91 (1.8)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
West Virginia
Amos
Appalachian
Power Co.
Cabin Creek
Appalachian
Power Co.
Ft. Martinf
Allegheny Power
Service Corp.
Harrison
Monongahela
Power Co.
Kammer
Ohio Power Co.
Mitchellf
Ohio Power Co.
Mt. Storm f
Va. Electric &
Power Co.
Scrubbed
units
Rem.
life6
36
5
33
40
23
36
38
Cap.
(MW)
276
12
535
691
601
1049
470
Total
plant
cap.
(MW)
2900
273
1107
1280
675
1633
1662
Sulfur
content
of
coal, %
1.13
1.0
3.7
4.1
4.1
3.9
1.0
Cap.
factor
(1973)
0.64
0.42
0.73
0.60
0.60
0.48
0.40
Sludge
disposal
Off-
site
X
On-
Site
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
16 (57)
2 (199)
51 (95)
78 (112)
49 (81)
•
122 (116)
43 (91)
Limestone
$ MM ($/KW)
17 (62)
4 -(325)
36 (68)
50 (72)
25 (42)
78 (74)
29 (62)
Annualized costs
Wellman-Lord
Total
fuel and ,power
O&M
$ MM/yr
(mills/KWH)
4.5 (2.9)
0.25 (0.2)
1.3 (0.9)
1.2 (27.9)
0.03 (0.7)
0.38 (8.9)
13 (3.9)
2.0 (0.6)
1.5 (0.5)
20 (5.5)
2.7 (0.7)
2.8 (0.8) .
13 (3.7)
2.9 (0.8)
1.0 (0.3)
31 (7.1)
3.1 (0.7)
5.2 (1.2)
11 (6.8)
0.80 (0.5)
2.2 (1.3)
Limestone
Total
J. V UU .*.
fuel and power
O&M
$ MM/yr
(raills/KWH)
5.0 (3.3)
0.4 (0.3)
1.4 (0.9)
1.8 (42.4)
0.04 (1.0)
0.46 (10.9)
12 "(3.5)
0.8 (0.2)
4.5 (1.3)
16 (4.4)
0.9 (0.2)
5.8 (1.6)
9.4 2.7)
0.6 0.2)
4.1 1.2)
24 . (5.4)
1.0 (0.2)
8.5 (1.9)
8.7 (5.3)
0.40 (0.2)
2.9 (1.7)
I
10
o
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS
REGION
State
Plant name
Power Co.
West Virginia
(cent.)
Rivesville
Allegheny Power
Service Corp.
Willow Islandf
Allegheny Power
Service Corp.
Washington D.C.
Benning
Potomac Elec.
Power Co.
EAST SOUTH
CENTRAL
Alabama
Barry
AT. Power Co.
Chickasaw
Al . Power Co.
Scrubbed
units
Rem..
lifeb
5
25
5
35
14
Cap.
(MW)
55
116
45
1058
55
Total
plant
cap.
(MW)
175
215
134
1771
120
Sulfur
content
of
coal, %
3.8
3.2
0.8
2.4
1.9
Cap.
factor
(1973)
0.55
0.81
0.44
0.65
0.53
Sludge
disposal
Off-
site
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
7 (136)
13 (113)
4 (92)
97 (92)
6 (115)
Limestone
$ MM ($/KW)
6 (104)
10 (82)
5 (106)
65 (61)
6 (105)
Annualized costs
Wellman-Lord
Total
fuel andjpower-
O&M
$ MM/yr
(mills/KWH)
3.3 (7.0)
0.40 (0.9)
0.38 (0.8)
3.7 (4.5)
0.73 (0.9)
0.53 (0.6)
2.0 (11.3)
0.07 (0.4
0.54 (3.0)
25 (4.2)
2.7 (0.5)
4.2 (0.7)
2.0 (7.9)
0.15 (0.6)
0.56 (2.2)
Limestone
Total
fuel andg power0
O&M
$ MM/yr
(mills/KWH)
3.0 (6.3)
0.15 (0.3)
0.95 (2.0)
3.4 (4.1)
0.23 (0.3)
1.4 .(1.6)
2.3 (13.0)
0.06 (0.3)
0.64 (3.6)
20 (3.3)
1.3 (0.2)
6.6 (1.0)
2.0 (7.7)
0.07 (0.3)
0.73 (2.8)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Alabama
Colbertf
Tenn. Valley
Auth.
Widows Creek
Tenn. Valley
Auth.
Kentucky
Cane Run
Louisville Gas
& Elec. Co.
Dalexf
Rural Elec. Co.
Ghentf
Ken. Utilities
Co.
Green River
Ken. Utilities
Co.
Mill Creek f
Louis. Gas &
Elec. Co.
Scrubbed
units
Rem.
lifeb
24
26
29
-
39
22 .
37
Cap.
(MW)
1043
1180
890
-
391
176
100
Total
plant
cap.
(MW)
1220
1675
992
194
525
263
330
Sulfur
content
of
coal, %
4.0
3.4
3.7
1.4
3.2
3.0
3.8
Cap.
factor
(1973)
0.59
0.60
0.59
0.60
0.60
0.61
0.50
Sludge
disposal
Off-
site
. X
On-
Site
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
109 (104)
109 (92)
91 (102)
Allowable emiss
40 (103)
20 (115)
11 (115)
Limestone
$ MM ($/KW)
61 (58)
70 - (59)
50 (57)
ons greater th<
27 (69)
14 (79)
9 (86)
Annualized costs
Wellman-Lord
Total
fuel and power0
O&Md
$ MM/yr
(mills/KWH)
28 ' (5.2)
4.1 (0.8)
3.6. (0.7)
28 (4.6)
3.4 (0.6)
4.4 (0.7)
•
24 (5.1)
3.7 (0.8)
3.3 (0.7)
n actual emissions'
10 (5.0)
1.4 (0.7)
1.1 (0.5)
5.6 (6.0)
0.80 (0.9)
1.0 (1.1)
3.2 (7.3)
0.38 (0.9)
0.68 (1.5)
Limestone
Total
fuel and powerc
O&M
$ MM/yr
(mills/KWH)
20 (3.7
1.3 (0.2
7.4 (1.4
22 (3.6)
1.4 (0.2)
7.6 (1.2)
'17 (3.7)
1.1 (0.2)
6.5 (1.4)
8.6 (4.2)
•tt.50 (0.20)
3.1 (1.5)
4.5 (4.7)
0.27 (0.3)
1.7 (1.7)
2.8 (6.3)
0.10 (0.2)
1.1 (2.5)
I
M
N)
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co.
Kentucky (cont.)
Paddy's Run
Louisville Gas
& Electric Co.
Paradise
Tenn. Valley
Auth.
Shawnee
Tenn. Valley
Auth.
Tennessee
Cumberland
Tenn. Valley
Auth.
Gallatinf
Tenn. Valley
Auth.
Johnsonville
Tenn. Valley
Auth.
Kingston
Tenn. Valley
Auth.
Scrubbed
units
Rem.
lifeb
15
32
19
38
24
18
20
Cap.
(MW)
219
2064
1332
1486
573
1365
1270
Total
plant
cap.
(MW)
338
2504
1750
2600
1245
1485
1700
Sulfur
content
of
coal, %
3.0
4.2
3.5
4.4
4.1
4.1
2.1
Cap.
factor
(1973)
0.17
0.68
0.69
0.45
0.61
0.53
0.64
Sludge
disposal
Off-
site
On-
Site
X
X
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
20 -• (91)
189 (91)
134 (101)
197 (133)
66 (114)
135 (99)
107 (84)
Limestone
$ MM ($/KW)
13 (61)
103 - (50)
71 (53)
122 (82)
37 (65)
73 (54) .
62 (49)
Annualized costs
Wellman-Lord
Total
fuel and power
o&yfl
$ MM/yr
(mills/KWH)
5.7 (17.4)
0.20 (0.6)
1.5 (4.5)
47 (3.9)
8.9 (0.7)
34.5 (2.8)
33 (4.1)
3.0 (0.4)
4.3 (0.5)
49 (8.4) .
3.4 (0.6)
8.9 (1.5)
17 (5.5)
2.5 (0.9)
2.3 (0.8)
32 (4.9)
2.9 (0.4)
3.9 (0.6)
28 (4.4)
3.5 (0.5)
4.6 (0.7)
Limestone
Total
fuel and power
O&M6
$ MM/yr
(mills/KWH)
4.0 (12.3)
0.08 (0.2)
1.22 (3.8)
38 (3.1)
2.7 (0.2)
16.0 (1.3)
24 '(3.0)
1.0 (0.1)
9.4 (1.2)
36 (6.2)
C.9 (0.2)
12.3 . (2.1)
12 (4.0)
0.8 (0.3)
4.3 (1.4)
24 (3.6)
0.85 (0.1)
9.5 (1.4)
20 (2.8)
1.6 (0.2)
6.8 (1.0)
I
M
CO
-------
Table F.2 (continued). FLUE GAS DESULFURIZATION SUMMARY FOR SELECTED U.S. POWER PLANTS'
REGION
State
Plant name
Power Co .
Tennessee (cont.)
T.H. Allenf
Tenn. Valley
Auth.
Watts Barf
Tenn. Valley
Auth.
MOUNTAIN
Arizona
Navajo
Salt River Dis.
Proj.
Nevada
Mo have
S. Cal. Edison
Co.
New Mexico
Four Corners
Arizona Pub.
Service Co.
Scrubbed
units
Rein.
life0
24
9
40
35
30
Cap.
(MW)
330
116
1671
705
595
Total
plant
cap.
(MW)
990
240
2250
1510
802
Sulfur
content
of
coal, %
3.1
4.1
1.0 .
0.4
1.0
Cap.
factor
(1973)
0.61
0.47
0.60
0.40
0.39
Sludge
disposal
Off-
site
On-
Site
X
X
X
X
X
Capital costs
Wellman-Lord
$ MM ($/KW)
34 (102)
14 (123)
119 (71)
52 (74)
46 (78)
Limestone
$ MM ($/KW)
21 (63)
9 - (79)
89 (53)
44 (62)
33 (56)
Annualized costs
Wellman-Lord
Total
fuel and powerc
0&Md
$ MM/yr
(mills/KWH)
8.8 (5.0)
1.1 (0.6)
1.4 . (0.8)
4.7 (9.9)
0.40 (0.8)
0.76 (1.6)
33 (3.7)
3.5 (0.4)
7.3 (0.8) .
14 (5.7)
0.60 (0.2)
3.7 (1.5)
13 (6.3)
1.4 (0.7)
3.0 (1.4)
Limestone
Total
fuel and power0
O&M
$ MM/yr
(mills/KWH)
6.8 (3.8)
0.40 (0.2)
2.5 (1.4)
3.5 (7.4)
0.10 (0.2)
1.2 (2.5)
28 (3.2) .
2.8 (0.3)
8.6 (1.0)
12 (5.0)
0.80 (0.3)
3.0 (1.3)
10 (4.9)
0.7 (0.3
3.1 (1.5)
-------
APPENDIX G
DETAILS OF UTILITY INDUSTRY SURVEY COST ADJUSTMENTS
G-l
-------
Plant Alabama Electric Cooperative
Tombigbee Units 2 and 3
Jackson, Alabama
Boiler capacity, megawatts 2 @ 255 510
Boiler flue gas scrubbed, megawatts 357
FGD system Limestone
Installation status New Under consideration
Unit No. 2 3/78
Unit No. 3 1/79
Sulfur content of fuel, percent by weight 2.5% coal
Capital cost analysis
Reported capital cost for $ 40,463,880
Corrected capital cost for 1975 40,463,880
Particulate removal equipment adjustment -10,000,000a
Redundancy adjustment
Indirect cost adjustment - 1,417,000
Sludge disposal adjustment
Adjusted cost for 1975 29,047,000
Adjusted cost per rated kilowatt for 1975 81.36
Notes;
All cost corrections are in terms of 1975 dollars.
aSubtracted cost of electrostatic precipitators for control
of particulate emissions.
Subtracted indirect costs to reflect for precipitator removal.
G-2
-------
Plant Arizona Public Service Company
Cholla Unit 1
Joseph City, Arizona
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
119.8
59.9
Limestone
Operational 12/73
Sulfur content of fuel, percent by weight
Capital cost analysis
Reported capital cost for
Corrected capital cost for 1975
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
0.4-1.0% coal
$ 6,500,000
8,371,000*
-2,888,000C
588,000'
964,000
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
7,035,000
58.72J
Notes:
All cost corrections are in terms of 1975 dollars.
aBase year for cost reported not given. Construction started 2/72
and system became operational 12/73 (assumed 1973 cost basis).
bAdjusted reported costs (assumed 1973) to 1975 dollars.
cSubtracted adjusted cost of venturi scrubber system for particulate
controls.
Added cost of sludge pond for extended life from 2 years to
to 22 years.
f^
Added cost for dewatering sludge (clarifiers and vacuum filters)
and crushing limestone (plant is presently buying crushed lime).
Considered costs for system representative for treating full 119.8 MW;
only difference between the modules is that Module B is not packed.
G-3
-------
Plant Boston Edison Company
Mystic Station
Charlestown, Massachusetts
Boiler capacity, megawatts 150
Boiler flue gas scrubbed, megawatts 150
FGD system Magnesium-oxide
Installation status Retrofit Demonstration unit
(April '72 - June '74)
now shut down
Sulfur content of fuel, percent by weight 2.5% oil
Capital cost analysis
Reported capital cost for 1974 $ 5,010,000a
Corrected capital cost for 1975 6,430,000
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment - c
Sludge disposal adjustment ,
Acid plant, calcining system, reheat 10,575,000
and design changes
Adjusted cost for 1975 17,005,000
Q
Adjusted cost per rated kilowatt for 1975 113.37
Notes:
All cost corrections are in terms of 1975 dollars.
Reported cost does not include cost of calcination at the acid
plant or costs to regenerate and recycle MgO back to the power
plant; costs shown are actual; construction began 2/71 and was
completed 4/72.
Adjusted reported costs (1974) to 1975 dollars, assuming 90% of
costs generated by 4/72 and 10% by 12/73.
°No reheat to discharge flue gas.
Calcining costs from data sheets and added: acid plant, heat
exchanger and equipment design changes.
Costs are for totally intergrated plant.
G-4
-------
Plant " Cincinnati Gas & Electric Company
Miami Fort Station Unit No. 8
North Bend, Ohio
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
Lime (probably)
Planned
500
500
1/78
Sulfur content of fuel, percent by weight 2.72% coal
Capital cost analysis
Reported capital cost for 1978 (Jan. 1) $ 40,617,000'
Corrected capital cost for 1975 32,465,000
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
4,151, 000*
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
36,616,000
73.23
Notes:
All cost corrections are in terms of 1975 dollars.
aReported costs of January 1, 1978 made mid 1974.
Adjusted reported cost to 1975 dollars, after removing capability
loss capital costs and including operating personnel training and
start-up.
°Added costs for sludge disposal pond, sludge dewatering, and
sludge pumping.
G-5
-------
Plant
Columbus & Southern Ohio Electric Company
Conesville Generating Station, Units 5 and 6
Conesville, Ohio
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
2 @ 411
Lime
Planned
822
822
No. 5 - 3/76
No. 6 - 1/78 (?)
Sulfur content of fuel, percent by weight 4.67% coal
Capital cost analysis
Reported capital cost for 1975 $ 38,661,000
Corrected capital cost for 1975
38,661,000
Particulate removal equipment adjustment - 8,360,000
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
+26,289,000
+ 4,973,000C
Adjusted cost for 1975 61,563,000
Adjusted cost per rated kilowatt for 1975 74.89
Notes:
All cost corrections are in terms of 1975 dollars.
Reported 1975 costs are direct costs (indirect costs not
reported).
Subtracted cost of electrostatic precipitator for particulate
emission control.
Added indirect costs.
j
Added cost for enlarged pond to extend its life from 5 to 33
years. Also added cost for closed-loop piping system and
associated pumping facilities.
G-6
-------
Plant
Dallas Power & Light Company
Texas Electric Service Company
Texas Power & Light Company
Martin Lake Steam Electric Station Unit 1
Rusk County, Texas
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
750
750
Limestone
Under construction 2/77
Sulfur content of fuel, percent by weight 1.5% lignite
Capital cost analysis
Reported capital cost for 1974 $ 25,218,392
Corrected capital cost for 1975 28,641,000
Particulate removal equipment adjustment -11,990,000
Redundancy adjustment 11,439,000
Indirect cost adjustment
Sludge disposal adjustment
6,995,000
2,506,000*
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
37,591,000
50.12
Notes:
All cost corrections are in terms of 1975 dollars.
aAdjusted reported direct costs (1974) to 1975 dollars.
Subtracted cost of electrostatic precipitator for particulate
control.
°Added indirect and contingency costs to adjusted 1975 direct
costs.
Added cost of larger sludge pond for extended life to 35 years.
eAdded cost for disposal equipment (clarifiers and vacuum filters)
G-7
-------
Plant
Detroit Edison Company
Monroe Units 1, 2, 3, 4
Monroe County, Michigan
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
4 @ 750 3000
3000
Limestone
Under consideration - 1981
Sulfur content of fuel, percent by weight 2.8 - 3.5% coal
Capital cost analysis
Reported capital cost for 1981 $ 344,000,000
Corrected capital cost for 1975 262,600,000a
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975 262,600,000
Adjusted cost per rated kilowatt for 1975 87.53
Notes:
All cost corrections are in terms of 1975 dollars.
Adjusted reported 1981 costs to 1975 dollars, using reported
5% escalation.
G-8
-------
Plant
Detroit Edison Company
St. Clair Power Plant Unit 6
Belle River, Michigan
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
325
170
Limestone
Under construction - 5/75
Sulfur content of fuel, percent by weight
Capital cost analysis
Reported capital cost for
4% coal
$ 13,088,000
13,088,000
Corrected capital cost for 1975
Particulate removal equipment adjustment -2,612,000'
. Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
1,411,000"
665,000°
1,141,000
13,693,000
80.55
Notes:
All cost corrections are in terms of 1975 dollars.
Proportioned & removed cost of venturi for control of particulate
emissions.
Since test is for 1 year & ponding not a problem, added a pond for
19 years additional for system comparison.
°Added costs for ball mill to mill CaCCU (study plant plans include
CaCO-j purchased ready to use, whereas in operations for a commercial
operation a ball mill is used). Also added costs for sludge dewatering
equipment (clarifier and vacuum filter).
G-9
-------
Plant
Duquesne Light Company
Frank R. Phillips Station Units 1-6
Wireton, Pennsylvania
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
414.9
138.3
Lime
Operational since 1973
Sulfur content of fuel, percent by weight 2.3% coal
Capital cost analysis
Reported capital cost for 1974 $ 32,346,000
Corrected capital cost for 1975 35,715,000a
Particulate removal equipment adjustment -25,941,000
Redundancy adjustment - *°
Indirect cost adjustment
Sludge disposal adjustment
682, OOO1
Adjusted cost for 1975 10,456,000
Adjusted cost per rated kilowatt for 1975 75.60
Notes:
All cost corrections are in terms of 1975 dollars.
a Adjusted reported cost ('70-'74) to 1975 dollars.
Proportioned & subtracted cost of venturi scrubbers for particulate
control and redundant S02 control equipment (spare scrubber train) .
^
Added cost of enlarged pond for extension of life for an
additional 17 years. Cost only includes SC>2 sludge disposal,
i.e. does not include fly-ash disposal portion. Present pond
will be sufficient for 3 years more.
G-10
-------
Plant General Public Utilities Service Corporation
Pennsylvania Electric & N.Y. State Electric & Gas Co.
Homer City Station Unit 3
Homer City, Pennsylvania
Boiler capacity, megawatts 650
Boiler flue gas scrubbed, megawatts 650
FGD system Lime
Installation status New Planned 10/77
Sulfur content of fuel, percent by weight 2.3% Aver.,2.8% Max coal
Capital cost analysis
Reported capital cost for 1977 $ 60,192,000
Corrected capital cost for 1975 54,702,000a
Particulate removal equipment adjustment
Redundancy adjustment -8,608,000^
Indirect cost adjustment 4,426,000°
d
Sludge disposal adjustment
-2,770,000e
Adjusted cost for 1975 47,750,000
Adjusted cost per rated kilowatt for 1975 73.46
Notes;
All cost corrections are in terms of 1975 dollars.
a Adjusted reported cost (1977) to 1975 dollars.
Subtracted cost of the system's spare scrubber train
(five trains were installed and only four are required).
Added interest costs at 8% for 3 years with progressive payments
after removing the capitalized value of capability, escalation,
reported interest calculated, & redundancy. Also added costs
for allowance for start-up & modifications (based on 5% of the
above costs) and contingency.
Ponding costs appear high for 10 years service; consequently
nothing additional was allowed for remaining plant life.
G
Subtracted capitalized value of capability $2,770,000.
G-ll
-------
Plant
Illinois Power Company
Wood River, Unit 4
East Alton, Illinois
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
103
103
Catalytic oxidation
(?) Under construction 8-15-74
Sulfur content of fuel, percent by weight 3.1% coal
Capital cost analysis
Reported capital cost for 1974 $ 8,295,700a
Corrected capital cost for 1975 9,860,000b
Particulate removal equipment adjustment - c
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
789,000C
Adjusted cost for 1975 10,649,000
Adjusted cost per rated kilowatt for 1975 103.39
Notes;
All cost corrections are in terms of 1975 dollars.
Actual reported costs expended over 3.7 year construction
period to 8/74 and modifications to date.
Adjusted reported actual costs (1971rl974) to 1975 dollars,
Electrostatic precipitators required since system for SO7
removal tolerates only a small fraction of flyash. ^
Added interest for cost of capital.
G-12
-------
Plant
Indianapolis Power & Light Company
Petersburg Generating Station Unit 3
Petersburg, Indiana
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
532
532
Limestone
Planned 4/77
Sulfur content of fuel, percent by weight 4.5% coal
Capital cost analysis
Reported capital cost for 1974 (Oct.) $ 32,855,658
Corrected capital cost for 1975
33,400,000'
Particulate removal equipment adjustment -4,365,000
Redundancy adjustment
Indirect cost adjustment 5,501,000°
Sludge disposal adjustment
4,584,000C
Adjusted cost for 1975 39,120,000
Adjusted cost per rated kilowatt for 1975 73.53
Notes:
All cost corrections are in terms of 1975 dollars.
a Adjusted reported 10-74 cost to 1975 dollars.
r^
Subtracted direct and indirect costs for electrostatic
precipitators for control of particulate emissions.
c
Added interest for capital with progressive equipment payments
and increased contingency costs.
Added costs for a sludge disposal system, including sludge pond,
piping and pumping for a closed-loop system.
G-13
-------
Plant Kentucky Utilities Company
Green River Power Station Units 1, 2, 3
Central City, Kentucky
Boiler capacity, megawatts 3 @ 20 60
Boiler flue gas scrubbed, megawatts 60
FGD system Lime
Installation status Retrofit Under construction 4-75
Sulfur content of fuel, percent by weight 3.8% coal
Capital cost analysis
Reported capital cost for 1975 $ 3,966,156a
Corrected capital cost for 1975 3,966,156
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975 3,966,156
Adjusted cost per rated kilowatt for 1975 66.10
Notes;
All cost corrections are in terms of 1975 dollars.
Turnkey operation.
Costs for Green River's engineering, operator's training, etc
were not reported.
G-14
-------
Plant
The Montana Power Company
Colstrip Units 1 and 2
Colstrip, Montana
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
358
358
Flyash alkalinity w/Lime
Under construction
No. 1 7/75
No. 2 5/76
0.77 - 1.0% coal
$ 32,633,000
32,633,000
Sulfur content of fuel, percent by weight
Capital cost analysis
Reported capital cost for 1975/1976
Corrected capital cost for 1975
Particulate removal equipment adjustment -11, 258, 000a
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment 2,066,000
2,554,000C
Adjusted cost for 1975 25,995,000
Adjusted cost per rated kilowatt for 1975 72.61
Notes;
All cost corrections are in terms of 1975 dollars.
a Subtracted cost of venturi scrubbers for particulate
emissions control.
Added costs for enlarged sludge disposal pond to increase
its life to 30 years.
Added costs for sludge dewatering equipment/ including
clarifier and vacuum filter.
G-15
-------
Plant
New England Power Company
Brayton Point Unit I
Somerset, Massachusetts
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
250
75
Metal oxide regenerative
Under consideration
Sulfur content of fuel, percent by weight 2.5% coal
Capital cost analysis
Reported capital cost for 1975 $ 14,811,000
Corrected capital cost for 1975 14,811,000
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
530,000'
Adjusted cost for 1975 15,341,000
Adjusted cost per rated kilowatt for 1975 204.55
Notes:
All cost corrections are in terms of 1975 dollars.
Added allowance for start-up and modifications.
G-16
-------
Plant
New England Power Company
Brayton Point Station Unit 3
Somerset, Massachusetts
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
654
654
Metal oxide regenerative
Under consideration
Sulfur content of fuel, percent by weight 2.5% coal
Capital cost analysis
Reported capital cost for 1975 $ 95,000,000
Corrected capital cost for 1975 95,000,000
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
3,400,000'
Adjusted cost for 1975 98,400,000
Adjusted cost per rated kilowatt for 1975 150.46
Notes;
All cost corrections are in terms of 1975 dollars.
Added allowance for start-up and modifications
(5% of direct cost).
G-17
-------
Plant Northern Indiana Public Service Company
Dean H. Mitchell, Unit 11
Gary, Indiana
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system Wellman-Lord Allied Chemical
Installation status Retrofit Under construction - 12/75
Sulfur content of fuel, percent by weight 3.16% coal
Capital cost analysis
Reported capital cost for 1975 $ 13,441,000
Corrected capital cost for 1975 13,441,000
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975 13,441,000
Adjusted cost per rated kilowatt for 1975 116.88
Notes:
All cost corrections are in terms of 1975 dollars.
G-18
-------
Plant
Northern States Power Company
Sherburne County Generating Plant Units 1 and 2
Becker, Minnesota
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status New
2 @ 680
1360
1360
Limestone
1-5/76
Under construction 2-5/77
Sulfur content of fuel, percent by weight 0.8% coal
Capital cost analysis
Reported capital cost for 1975 $ 60,000,000a
Corrected capital cost for 1975 60,000,000a
Particulate removal equipment adjustment 0
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
-7,056,000'
+40,800,000C
+ 685,000C
-I- 1,260,000
Adjusted cost for 1975 95,689,000
Adjusted cost per rated kilowatt for 1975 70.36
Notes:
All cost corrections are in terms of 1975 dollars.
Reported 1975 costs are direct costs (indirect costs hot
included).
Subtracted the cost of one scrubber train (twelve provided,
one to serve as a spare).
° Added indirect costs.
Added costs for vacuum filter and clarifier for sludge
dewatering.
e Added cost for sludge pond for S02 sludge only.
G-19
-------
Plant
Ohio Edison Company
Pennsylvania Power Company; Cleveland Electric Illuminating
Co.; Bruce Mansfield Plant Units 1 and 2
Shippingport, Pennsylvania
Boiler rating, megawatts
Boiler flue gas scrubber, megawatts
Process description
Status New
Sulfur content of fuel, percent by weight
Sludge disposal shown as 42% of costs
Capital cost analysis
Reported capital cost for 19 77
Corrected capital cost for 1975
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975
Cost per rated kilowatt for 1975
2 @ 917
1834
1834
Lime
. Unit 1-12/75
Planned: Unit 2-4/77
4.75% coal
$ 213,200,000
173,400,000a
-25,617,000b
-8,393,000°
+28,354,000d
-25,045,000e
142,699,000
77.81
Notes:
All cost corrections are in terms of 1975 dollars.
a Removed contingency, escalation and interest before correcting to
1975 dollars.
Proportioned cost of venturi scrubbers for particulate emission
control and subtracted same.
c Adjusted cost for spare scrubbing train.
Added the interest and contingency in terms of 1975 dollars plus
increased contingency allowance to 20%. Proportioned engineering
and field expenses to account for reduced cost of SC>2 control
only (i.e., no particulate emission control).
6 Subtracted proportion of sludge transport and site costs in
proportion to the amount due to particulate emission control.
G-20
-------
Plant Philadelphia Electric Company
Eddystone Generating Station Unit 1
Chester, Pennsylvania
Boiler capacity, megawatts 325
Boiler flue gas scrubbed, megawatts 108.3
FGD system Magnesium-oxide
Installation status Retrofit Under construction
Sulfur content of fuel, percent by weight 2.5 - 3.0% coal
Capital cost analysis
Reported capital cost for 1972 $ 20,189,500
Corrected capital cost for 1975 22,887,000a
Particulate removal equipment adjustment-13,684,000
Redundancy adjustment
Indirect cost adjustment 650,000°
Sludge disposal adjustment ^
Acid plant, recovery & regeneration 4,984,000
facilities
Adjusted cost for 1975 14,837,000
Adjusted cost per rated kilowatt for 1975 137.00
Notes;
All cost corrections are in terms of 1975 dollars.
a Adjusted reported cost (mid '72) to 1975 dollars.
Proportioned cost of venturi scrubbers for particulate control
and subtracted same.
^
Added interest during construction.
G-21
-------
Plant Potomac Electric Power Company
Dickerson Unit 3
Dickerson, Maryland
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
Magnesium-oxide
Operational
184
95
9/73
Sulfur content of fuel, percent by weight 3%
Capital cost analysis
Reported capital cost for $ 6,500,000*
Corrected capital cost for 1975 8,242,000*
Particulate removal equipment adjustment
Redundancy adjustment
Coal
Indirect cost adjustment
363,000
Sludge disposal adjustment ,
Acid and regeneration, etc. facilities 5,075,000
Adjusted cost for 1975 13,680,000
Adjusted cost per rated kilowatt for 1975 144.00
Notes:
All cost corrections are in terms of 1975 dollars.
aAssumed reported costs on (mid-'72-'73) dollars.
Adjusted reported costs to 1975 dollars.
°Added cost of capital - interest of 8% for 16 months with
progressive payments.
This adjusted cost includes the cost of a recovery or regenerative
system and a by-product acid plant. This then becomes an
intergrated unit.
G-22
-------
Plant
Public Service Company of New Mexico
San Juan Station Unit 1
Waterflow, New Mexico
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
350
350
Wellman-Lord S02 Recovery
System
Planned 12/76
Sulfur content of fuel, percent by weight 1.3%
Capital cost analysis (for one Unit)
Reported capital cost for 1974 $44,755,000
Corrected capital cost for 1975 50,044,000a
Particulate removal equipment adjustment-6,756,000
Coal
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
-3,940,000
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
39,348,000
112.42V
Notes:
All cost corrections are in terms of 1975 dollars.
Adjusted reported cost (mid '74) to 1975 dollars.
Proportioned cost of venturi scrubbers for particulate control
CAdjusted cost of one spare scrubber train (four provided three
needed).
Unit 2's costs are identical.
G-23
-------
Plant Public Service Company of New Mexico
San Juan Station, Unit 3
Waterflow, New Mexico
Boiler capacity, megawatts 550
Boiler flue gas scrubbed, megawatts 550
FGD system Wellman-Lord SO- Recovery System
Installation status New Under Construction 5/78
Sulfur content of fuel, percent by weight 1.3% Coal
Capital cost analysis
Reported capital cost for 1974 59,199,000
Corrected capital cost for 1975 66,195,000a
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
b
Adjusted cost for 1975 52,431,000
Adjusted cost per rated kilowatt for 1975 95.33°
Notes;
All cost corrections are in terms of 1975 dollars.
a Adjusted mid-1974 costs to 1975 dollars.
i_
Proportioned costs similar to San Juan Unit 1 & adjusted for
redundancy differences.
Unit 4's cost are identical.
G-24
-------
Plant South Carolina Public Service Authority
Winyah Generating Station Unit 2
Georgetown, South Carolina
Boiler capacity, megawatts 280
Boiler flue gas scrubbed, megawatts 140
FGD system Limestone
Installation status New Planned 5/77
Sulfur content of fuel, percent by weight 1.0% Coal
Capital cost analysis
Reported capital cost for 1975 $ 6,818,613
Corrected capital cost for 1975 6,818,613
Particulate removal equipment adjustment -l,838,773a
Redundancy adjustment
Indirect cost adjustment 273,000
Sludge disposal adjustment 1,092,000°
Utilities & Service l,411,000d
Adjusted cost for 1975 7,756,000
Adjusted cost per rated kilowatt for 1975 55.40
Notes:
All cost corrections are in terms of 1975 dollars.
a Subtracted direct equipment cost for electrostatic precipitator
for particulate control and subtracted indirect costs for this
ESP by proportioning its relative contribution to total direct
costs.
Added interest during construction period. Also added indirect
costs for sludge pond, utilities and services.
c Added cost for a sludge pond to accommodate expected life of
plant (30 years).
" Added cost for utilities and services to serve FGD system.
G-25
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Plant Southern California Edison Company
Kaiparowits Generating Station Units I, 2, 3, 4
Page, Arizona (Vicinity of)
Boiler capacity, megawatts 4 @ 750 3000
Boiler flue gas scrubbed, megawatts 3000
FGD system Lime
Installation status New Under Consideration 1981 to 1984
Sulfur content of fuel, percent by weight 0.52% Aver Coal
Capital cost analysis
Reported capital cost for 1980 $ 300,000,000
Corrected capital cost for 1975 189,050,000a
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
Adjusted cost for 1975 189,050,000
Adjusted cost per rated kilowatt for 1975 63.02
Notes:
All cost corrections are in terms of 1975 dollars.
a Adjusted reported 1980 costs to 1975 dollars.
G-26
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Plant
Southern California Edison Company
Mohave Generating Station, Units 1 and 2
South Point, Nevada
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status retrofit
2 @ 790
Lime
Planned
1580
1580
6/77
Sulfur content of fuel, percent by weight
Capital cost analysis
Reported capital cost for 1977
Corrected capital cost for 1975
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment
0.6%max.
$ 129,000,000'
110,597,000*
-20,682,000
4,476,000
500,000
Coal
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
94,891,000
60.06
Notes;
All cost corrections are in terms of 1975 dollars.
Costs estimated by Southern California Edison Co.
Adjusted reported 1977 costs to 1975 dollars.
c
Subtracted cost for one spare scrubber train (five scrubber
trains were provided, only four needed).
Added costs for sludge disposal pond and pumping.
Q
Added costs for sludge dewatering.
G-27
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Plant Tennessee Valley Authority
Widows Creek Steam Plant Unit 8
Stevenson, Alabama
Boiler capacity, megawatts 550
Boiler flue gas scrubbed, megawatts 550
FGD system ' Limestone
Installation status Retrofit Under Construction 2/77
Sulfur content of fuel, percent by weight 4.3% Coal
Capital cost analysis
Reported capital cost for 1977 $ 55,636,000
Corrected capital cost for 1975 49,516,000a
Particulate removal equipment adjustment -17,083,000
Redundancy adjustment
Indirect cost adjustment
Sludge disposal adjustment 2,620,000°
2,628,000d
Adjusted cost for 1975 37,681,000
Adjusted cost per rated kilowatt for 1975 68.51
Notes:
All cost corrections are in terms of 1975 dollars.
a Adjusted reported 1977 cost to 1975 dollars.
Proportioned cost of a venturi scrubber for control of particulate
emissions and subtracted same.
Added costs for sludge pond to cover the life of the plant
(20 years) .
Added costs for sludge dewatering, including a clarifier and
a vacuum filter.
G-28
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Plant
Virginia Electric & Power Company
Mt. Storm
Mt. Storm, West Virginia
Boiler capacity, megawatts
Boiler flue gas scrubbed, megawatts
FGD system
Installation status Retrofit
2 @ 570.24
1 @ 522
Limestone
Under Consideration
1662.48
1147.11
6/78
Sulfur content of fuel, percent by weight 2.4-2.8% Coal
Capital cost analysis
Reported capital cost for 1978 $ 85,739,000
Corrected capital cost for 1975 69,209,000a
Particulate removal equipment adjustment
Redundancy adjustment
Indirect cost adjustment 7,716,000
Sludge disposal adjustment
Adjusted cost for 1975
Adjusted cost per rated kilowatt for 1975
5,544,000^
2,404,000d
84,873,000
73.99
Notes;
All cost corrections are in terms of 1975 dollars.
a Adjusted 1978 reported costs to 1975 dollars.
Increased indirect costs.
0 Added costs for sludge disposal pond.
Added costs for sludge pumping & piping.
G-29
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