EPA-R2-73-244
May 1973 Environmental Protection Technology Series
Conceptual Design and Cost Study
SULFUR OXIDE REMOVAL
FROM POWER PLANT
STACK GAS
Magnesia Scrubbing - Regeneration:
Production of Concentrated
Sulfuric Acid
Office of Research and Monitoring
U.S. Environmental Protection Agency
Washington, D.C. 20460
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ERRATA
p. 5 - The first entry in table S-2 should read "Base
case-coal-fired units"
p. 24 • The photograph on p. 24 should be on p. 25, and
vice versa
p. 37 • The equation referred to near the bottom of the
first column and at the top of the second column
should be number 27 (not 28)
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EPA-R2-73-244
Conceptual Design and Cost Study
SULFUR OXIDE REMOVAL
FROM POWER PLANT
STACK GAS
Magnesia Scrubbing - Regeneration:
Production of Concentrated
Sulfuric Acid
by
G.G. McGlamery, R.L. Torstrick,
J.P. Simpson, and J.F. Phillips, Jr,
Tennessee Valley Authority
Muscle Shoals, Alabama 35660
(TVA Bulletin Y-61)
Interagency Agreement TV-29233A
Program Element No. 1A2013
EPA Project Officer: M.A.Maxwell
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND MONITORING
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, B.C. 20460
May 1973
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This report has been reviewed by the Environmental Protection Agency and
approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the Agency, nor does
mention of trade names or commercial products constitute endorsement
or recommendation for use .
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PERSPECTIVE VIEW OF A MAGNESIA
SCRUBBING SYSTEM FOR SO2 REMOVAL
ON A COAL-FIRED 500-MW POWER UNIT-
TWO-STAGE VENTURI CONCEPT
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PREFACE
On February 16, 1967, the National Center for Air
Pollution Control, Public Health Service, U. S. Department
of Health, Education, and Welfare [now the Office of
Research and Monitoring (ORM), Environmental Protection
Agency (EPA)] entered into a contract with the Tennessee
Valley Authority (TVA) for a series of conceptual design
and economic studies to be carried out by TVA on
processes for reduction of sulfur oxide and nitrogen oxide
emissions from power generation. The purpose is to
evaluate objectively and realistically the merits of different
methods under consideration for stack gas control, with a
common and uniform basis for comparison.
Various types of activities enter into the studies,
including:
1. Analysis of the published literature bearing on the
processes.
2. Direct contacts to obtain information from
organizations currently working on the processes.
3. Bench- and pilot-scale tests to fill in gaps in the
information.
4. Specific studies by specialists in power plant design,
power plant operation, and air and water pollution to
supplement the main study.
5. Preparation of conceptual flowsheets and equipment
arrangement drawings for each process.
6. Market appraisals for processes involving recovery of
a salable product.
7. Quotations from vendors and fabricators of major
pieces of equipment.
8. Examinations of raw material and shipping costs.
9. Order of magnitude cost estimates to cover a wide
range of the parameters involved.
Detailed evaluations of the first three studies have been
published and can be obtained from:
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22151
The reports are identified and priced as shown in the
following table:
Title
Number
Year of
Price issue
Sulfur oxide removal
from power plant stack gas-
sorption by limestone
or lime (dry process)
Sulfur oxide removal
from power plant stack gas-
use of limestone in
wet-scrubbing process
Sulfur oxide removal
from power plant stack gas-
ammonia scrubbing:
production of ammonium
sulfate and use as
intermediate in phosphate
fertilizer manufacture
PB 178-972 $3.00 1968
PB 183-908 3.00 1969
PB 196-804 6.00 1970
The present report on magnesia scrubbing-regeneration is
concerned primarily with aqueous magnesia scrubbing of
power plant stack gas to form magnesium sulfite, drying of
sulfite crystals and regeneration of absorbent magnesium
oxide for recycle, and production of concentrated sulfuric
acid. Also given cursory examination are NOX removal and
production of sulfur.
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A CKNO WLEDGEMENTS
Project supervision, process investigation, design, cost
estimating, and report preparation were carried out by the
Design Branch of TVA's Division of Chemical Development
in Muscle Shoals, Alabama. Assistance on process chemistry
and bench-scale work was given by the Fundamental
Research and Applied Research Branches and corrosion
investigation was provided by the Process Engineering
Branch, all under the Division of Chemical Development.
Shipping costs were evaluated by the Navigation Economics
Branch, Division of Navigation Development and Regional
Studies, Knoxville, Tennessee. Background information on
power plant design, operation and economics along with air
and water pollution considerations were provided by several
TVA organizations currently involved in related activities.
A major part of the evaluation has been the analysis of
findings by other organizations who have worked on
magnesia scrubbing-regeneration. These findings are, of
course, the basis for the conceptual design and are
referenced in the annotated bibliography. In addition to
referenced literature, several organizations have supplied
information directly for use in the study; the contributions
of the following are acknowledged:
Process Design
Babcock and Wilcox Company
Power Generation Division
Barberton, Ohio 44203
Chemico/Basic
Chemical Construction Corporation
320 Park Avenue
New York, New York 10022
Grillo-Werke Aktiengesellschaft
Weseler Strasse 1
41 Duisburg-Hamborn
GERMANY
Raw Materials-Magnesium Compounds
Basic Chemicals
845 Hanna Building
Cleveland, Ohio 44115
Diamond Shamrock Chemical Company
Chemetals Division
711 Pittman Road
Baltimore, Maryland 21226
Dow Chemical Company
Midland, Michigan 48640
Michigan Chemical Corporation
351 East Ohio Street
Chicago, Illinois 60611
Scrubbers
Air Correction Division
Universal Oil Products Company
Darion, Connecticut 06820
American Air Filter Company, Inc.
215 Central Avenue
Louisville, Kentucky 40208
Babcock and Wilcox Company
Power Generation Division
Barberton, Ohio 44203
Chemico
Chemical Construction Corporation
320 Park Avenue
New York, New York 10022
Heil Process Equipment Corporation
12901 Elmwood Avenue
Cleveland, Ohio 44111
MikroPul
Division of the Slick Corporation
10 Chatham Road
Summit, New Jersey 07901
Peabody Engineering
Environmental & Process Div.
39 Maple Tree Avenue
Stamford, Connecticut 06906
VI
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Poly Con Corporation
185 Arch Street
Ramsey, New Jersey 07446
Stebbins Linings, Inc.
Stebbins Engineering and Manufacturing Co.
P.O.Box 171
Watertown, New York 13601
Reheaters
Brown Fintube Co.-Therm-Mech. Inc.
P. O. Drawer 52599
Atlanta, Georgia 30305
North American Manufacturing Co.
4457 E. 71st
Cleveland, Ohio 44105
Peabody Engineering Corporation
39 Maple Tree Avenue
Stamford, Connecticut 06906
Sasakura Engineering Co., Ltd.
302 Park St.
Ridley Park, Pennsylvania 19078
Fans
American Standard
Industrial Products Division
165 W. Wieuca Road, N.E.
Atlanta, Georgia 30342
Dewatering Equipment
Ametek/Process Equipment
East Moline, Illinois 61244
Bird Machine Company
South Walpole, Massachusetts 02071
The De Laval Separator Company
Poughkeepsie, New York 12602
Dorr-Oliver, Incorporated
P.O.Box 1332
Bartow, Florida 33830
The Eimco Corporation
P.O. Box 20177
Vestavia Hills
Birmingham, Alabama 35216
Pennwalt Corporation
955 Mearns Road
Warminster, Pennsylvania 18974
Straight Line Filters, Inc.
P.O.Box 1911
Wilmington, Delaware 19899
Dryers and Calciners
Bartlett-Snow
6200 Harvard Avenue
Cleveland, Ohio 44105
Bethlehem Corporation
Foundry and Machine Division
225 W. Second St.
Bethlehem, Pennsylvania 18016
Dorr-Oliver, Incorporated
Stamford, Connecticut 06904
Fuller Company
General American Transportation Corporation
124 Bridge St.
Catasauqua, Pennsylvania 18032
Jeffrey Manufacturing Co.
Division of Jeffrey Gallon
P.O.Box 1879
Columbus, Ohio 43216
Nichols Engineering and Research
Corporation
150 William Street
New York, New York 10038
Dust Collectors
American Standard, Inc.
Industrial Products Division
Detroit, Michigan 48232
Dustex Division
American Precision Industries, Inc.
2777 Walden Avenue
Buffalo, New York 14225
Western Precipitation Division
Joy Manufacturing Company
3445 Peachtree Rd., N.E.
Suite 1090
Atlanta, Georgia 30326
vn
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Sulfuric Acid Plants
Chemico
Chemical Construction Corporation
320 Park Avenue
New York, New York 10022
Dorr-Oliver, Incorporated
77 Havemeyer Lane
Stamford, Connecticut 06904
Monsanto Enviro-Chem Systems, Inc.
10 South Riverside Plaza
Chicago, Illinois 60606
Newton Chambers Engineering Limited
Thorncliffe, Sheffield S30 4YP
ENGLAND
The Ralph M. Parsons Company
617 West Seventh Street
Los Angeles, California 90017
E. I. du Pont De Nemours & Co., Inc.
Heat Transfer Products Division
Dupont Building
Wilmington, Delaware 19898 (Acid coolers)
Vlll
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CONTENTS
SUMMARY . . .
Study Assumptions
Process Equipment . .
Investment Requirements
Evaluation Considerations
Comparison and Profitability
Conclusions . .
INTRODUCTION .
HISTORY AND STATUS
PROCESS VARIATIONS . .
The Magnesia Slurry Process
The Grille Variation . . .
The Clear Liquor Process
The Showa Denko Process .
NOX Removal Process . . .
Direct Sulfur Production in
the Calciner
PROCESS CHEMISTRY, PROPERTIES
AND KINETICS
Physcial Properties of Process
Compounds and Solutions ....
Solubility of Magnesium Sulfate and
Magnesium Sulfite .
Optical Properties and Specific
Gravity of Solid Materials
Density and Viscosity of Magnesium
Sulfite-Magnesium Bisulfite-
Magnesium Sulfate Solutions
Vapor Pressure of Sulfur Dioxide Over
MgS03 -Mg(HSO 3 )2 -MgS04
Chemistry . ...
Kinetics and Mass Transfer
Formation of Crystalline Deposits (Scaling)
Process Contaminants
Nitrogen Oxide Emission Control . .
Recovery As Sulfur ... ...
STUDY ASSUMPTIONS AND DESIGN
CRITERIA
Fuels
Flue Gas Composition
Emission Standards ... . . . .
. 1
2
.2
.3
.3
.4
7
10
15
15
15
16
17
17
18
20
20
20
22
26
26
26
37
39
40
43
46
50
50
51
51
Plant Location . .
Plant Size and Status . . .
Plant Life, Operating Time, and
Capacity Factor . . .
Flue Gas and Sulfur Dioxide Rates
Degree of Sulfur Dioxide Removal
Stack Gas Reheat
Dust Removal . ...
Amount of Storage . . .
Base Case
Process Flowsheets
Solid Waste Disposal . .
Miscellaneous ....
EQUIPMENT SELECTION AND
DESCRIPTION
Scrubbing Alternatives . . .
Slurry or Solution Processing
Sulfite Drying—Calcining
Sulfuric Acid Production
Materials of Construction
Equipment Description
INVESTMENT AND OPERATING COST
Fixed Investment
Working Capital
Operating Costs
Results
PROFITABILITY AND ECONOMIC
POTENTIAL
Marketing
Regulated Economic Evaluation .
Nonregulated Economic Evaluation
Cooperative Economics—Central
Processing Concept . .
RESEARCH AND DEVELOPMENT NEEDED
CONCLUSIONS AND RECOMMENDATIONS
REFERENCES AND ABSTRACTS ....
APPENDIX A .
APPENDIX B
51
51
52
53
53
53
54
55
55
55
55
55
57
57
64
67
72
73
74
79
79
81
82
86
100
100
106
110
112
131
133
138
147
352
IX
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TABLES
Page
S-l Capital requirements for magnesia Scheme A
and limestone-wet scrubbing . . .3
S-2 Cost of magnesia Scheme A vs limestone-wet
scrubbing under regulated economics . . .5
S-3 Profitability of Scheme A with supplementary
income as payment for pollution abatement . 6
S-4 Profitability of central regeneration-acid
manufacturing unit under cooperative economics.a
Magnesium sulfite supplied from combinations of
new 200-, 500-, or 1,000-mw units burning coal
with 3.5% sulfur. Regulated magnesia scrubbing
cost equalized to high and low projected limestone-
wet scrubbing process costs . . .6
1 Viscosity and density of magnesium sulfite-
bisulfite-sulfate solutions 27
2 Variation of slurry/solution viscosity ratio
with solid/liquid ratio 26
3 Logi0 equilibrium constants vs temperature 34
4 Typical limits of ash analysis of United
States bituminous coals . 41
5 Makeup water analysis . 41
6 Analysis of ash pond water . . . 41
7 Impurities of magnesium oxide . 42
8 Concentration and impurity input of
makeup water . . .42
9 Equilibrium concentration of NOX in air and
in a typical flue gas at 1 atm . 45
10 Effect of total pressure on gas phase composition . 49
11 Estimated flue gas compositions for coal-fired
boilers at various nitrogen oxide and sulfur
levels, percent by volume 52
12 Estimated flue gas compositions for oil-fired
boilers at various nitrogen oxide and sulfur
levels, percent by volume . . ... .52
13 Emission standards for new steam
generating facilities . . .53
14 Power unit input heat requirements 53
15 Assumed power plant capacity schedule . . 53
16 Flue gas and sulfur dioxide emission rates 54
17 Required S02 removal efficiencies . ... 54
18 Typical ash composition of a western
Kentucky coal . 57
19 Particle size distribution of fly ash . 57
20 Absorption efficiencies attainable with clear
liquor scrubbing scheme
21 Flue gas temperature . . .
22 Assumed pressure drop through gas system
inH20
23 Introduction rate of soluble contaminants
into sulfur dioxide absorber
24 Introduction rate of fly ash into sulfur
dioxide absorber
25 Heat requirements of alternative dewatering-
drying processes
26 Solid-liquid separation alternatives
27 Approximate equipment investment
requirements for thickening, $
28 Comparison of various MgS03-6H20
dewatering alternatives
29 Comparison of MgSO3 -6E20 and
MgS03 -3H20 dewatering processes
30 Dryer-calciner equipment alternatives
31 Estimated investment and operating costs for
rotary and fluid bed dryers and calciners
for base case installation
32 Estimated investment and operating costs
for control of dust emissions from the
dryer for base case installation
33 Estimated composition of feed gas to
sulfuric acid unit
34 Estimated fixed investment and operating
costs for "wet" and "dry" sulfuric
acid units for base case installation
35 Environmental Protection Agency emission
standards for sulfuric acid plants
36 Gas flow rates through each scrubbing train,
new 500-mw coal-fired units . .
37 Scrubber design conditions
38 Design temperature profile for indirect
steam reheater system
39 Approximate dimensions of rotary dryers
and calciners
40 Case combinations for coal- and oil-fired units
41 Indirect cost factors . . .
42 Costs for various magnesium oxide-containing
raw materials . . .
43 Rail shipping costs for magnesium sulfate
44 Rail shipping costs for magnesium oxide .
Page
61
. 63
. 64
. 65
65
65
65
66
67
67
68
71
71
72
73
73
75
75
. 76
76
. 80
82
. 82
83
83
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45 Trucking costs for magnesium sulfate or
magnesium oxide 84
46 Estimated overall maintenance costs 85
47 Annual capital charges for power industry
financing (new power unit with 30-yr life) . . 86
48 Total fixed investment requirements—magnesia
scrubbing and limestone-wet scrubbing
processes3 88
49 Process equipment and installation analysis-direct
cost for Scheme Aa (thousands of dollars) . . 89
50 Process equipment and installation analysis3
direct cost for limestone-wet scrubbing
process (thousands of dollars) ... 90
51 Possible reduction in investment requirements
for magnesia Scheme A-special design
provisions 91
52 Comparison of investment requirements for
a magnesia system including a new sulfuric
acid unit with a system using an existing
acid unit 91
53 Total fixed investment requirements Scheme D—
central process concept . 92
54 Scheme D unit combinations: rated acid
production capacity . . 92
55 Comparison of Scheme A total investment with
Scheme D total investment for similar capacity
installations . ... 92
56 Average operating costs for magnesia scrubbing
processes compared to limestone-wet scrubbing
process under regulated economics3 93
57 Annual operating costs for magnesia scrubbing
processes under nonregulated economics3 97
58 Lifetime operating costs3 for magnesia
scrubbing processes (new plants) . 98
59 Total operating costs for Scheme Da . 99
60 Total annual operating cost: combinations of
power unit systems in Scheme D 99
61 Summary of U.S. sulfuric acid
production-1972 100
62 Sulfuric acid plant capacity-short tons per day 101
63 Sulfuric acid end-use pattern-1970 101
64 Typical sulfuric acid strengths and major
end uses 105
65 Consumption of phosphate fertilizers in the
midwestern states 105
66 Sulfuric acid shipping costs 106
67 Actual and discounted cumulative total and unit
increase (decrease) in the cost of power for
magnesia schemes and limestone-wet scrubbing
process under regulated economics 108
68 Comparison of present worth of cumulative
total and unit increase (decrease) in cost of
power for case variations of magnesia Scheme
A and limestone-wet scrubbing processes
under regulated economics . . . 110
69 Required unit sales revenue for sulfuric acid
to equalize magnesia and limestone scrubbing
process costs . . . . . Ill
70 Economic potential of magnesia scrubbing-
regeneration schemes under nonregulated
economics . . . 115
71 Profitability of central regeneration-acid
manufacturing unit under cooperative economics.
Magnesium sulfite supplied from combinations
of new 200-, 500-, and 1,000-mw units burning
coal with 3.5% sulfur. Regulated stack gas
scrubbing costs equivalent to limestone-wet
scrubbing process with low limestone cost, on-
site solids, disposal . . . 123
72 Profitability of central regeneration-acid manu-
facturing unit under cooperative economics. Mag-
nesium sulfite supplied from combinations of new
200-, 5.00-, and 1,000-mw units burning coal with
3.5% su.lfur. Regulated stack gas scrubbing costs
equivalent to limestone-wet scrubbing process with
high limestone cost, off-site solids disposal . 123
XI
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FIGURES
Page
1 Magnesium bisulfite pulping process
with chemical recovery ..10
2 Magnesia slurry scrubbing-regenerating process
as developed by NIIOGAZ (Russian) . .11
3 Magnesia-manganese dioxide slurry scurbbing-
regeneration process as developed by
Grillo-Werke AG 12
4 150-mw prototype MgO-S02, recovery scrubbing
system at Boston Edison Co.—Mystic No.
6, Boston, Mass . . .14
5 Magnesia slurry scrubbing-regeneration
process as developed by Chemico-Basic . 16
6 Clear liquor variation of magnesia
scrubbing-regeneration process 17
7 Showa Denko dry MgO process for
SO 2 removal . 18
8 Magnesia process for removal of both sulfur
and nitrogen oxides from stack gas ... ... 19
9 Effect of temperature on magnesium
sulfate solubility 21
10 Effect of temperature on magnesium
sulfite solubility ..... 21
11 Effect of magnesium sulfate on magnesium
sulfite solubility 22
12 Photomicrograph of magnesium sulfite
hexahydrate-200 X . . . 23
13 Photomicrograph of magnesium sulfite
trihydrate-2000 X 24
14 Photomicrograph of magnesium sulfite
trihydrate-200 X 25
15 Effect of MgSO4 and pH on sulfur dioxide
vapor pressure over magnesium sulfite
slurry 28
16 Effect of dissolved MgSO3 on S02
vapor pressure over MgS03-Mg(HS03)2
solutions total S02 4.44% 28
17 Effect of dissolved MgS03 on S02
vapor pressure over MgS03-Mg(HSO3)2
solutions total S02 6.16% 28
18 Effect of MgS04 content and Mg(HS03)2/
MgS03 ratio on solution pH 29
19 Effect of salt concentration on oxygen
absorption 31
20 Effect of pH on air oxidation rate in
magnesium sulfite-bisulfite solution 31
Page
21 Effect of pH on calcium sulfite
oxidation rate . . .32
22 Effect of p-phenylenediamine and time on
oxidation of magnesium sulfite crystals
exposed to atmosphere . ... 32
23 Effect of temperature and slurry concentration
on conversion rate of MgS03-6H20
toMgS03-3H20 .32
24 Differential thermogram of MgS03-6H20
and MgS03-3H20 samples ... .33
25 Effects of temperature on nature of MgSO3
decomposition products—one hour
heating period . ... . . 33
26 Effect of temperature on nature of MgSO3
decomposition products—15 minutes
heating period . . 35
27 Effect of time and temperature on
decomposition of MgS03 . . .35
28 Equilibrium constants for combustion
reactions .... . 36
29 Equilibrium constants for reactions
of magnesium compounds . . 36
30 Effect of calcination temperature and
atmosphere on formation of product
materials . 36
31 Effect of calcination temperature and
atmosphere on formation of product
materials (expanded vertical scale) . . . 37
32 Effect of manganese on the rate of
magnesium sulfate decomposition . 38
33 Effect of gas velocity on mass
transfer coefficient . . .38
34 Effect of liquid mass rate on mass
transfer coefficient . . 39
35 Effect of gas mass flow rate on mass
transfer coefficient . .... 39
36 Effect of temperature on mass transfer
coefficient in absorption of S02 by
various solutions 39
37 Effect of time on increase of salt
concentration in sulfur dioxide
scrubbing system at pH 5.5-6.0 42
38 Effect of temperature on equilibrium
concentrations of NO and NO2 in
combustion gases .... . . 43
xn
-------
39 Effect of temperature on equilibrium
concentrations of NO for combustion
of methane . ... 44
40 Effects of air concentration on NOY
A
equilibrium in methane-air flames 44
41 Mg(OH)2 scrubbing process . 45
42 Effect of C/0 atom ratio on gas composition
for the system C-O-S at 600° K and
one atmosphere total pressure . . 47
43 Effect of temperature on elemental sulfur
recovery in the system C-O-S at P = 1
atm, S/0 = 0.5 and C/0 = 0.5 (composition
for optimum production of sulfur) 47
44 Effect of pressure drop on particulate
collection efficiency for a venturi
scrubber ... . . 58
45 Effect of liquid to gas irrigation
ratio on sulfur dioxide absorption
efficiency for a mobile bed absorber . 59
46 Effect of liquid to gas irrigation ratio
on sulfur dioxide absorption efficiency
for a venturi absorber .... 59
47 Effect of liquid to gas irrigation ratio
on sulfur dioxide absorption efficiency
for a spray absorber . . . ... 60
48 Effect of liquid to gas irrigation ratio
on pressure drop for a mobile bed
absorber . . 60
49 Effect of pressure drop on sulfur dioxide
absorption efficiency for a venturi
absorber . . . 60
50 Effect of slurry pH on sulfur dioxide
absorption efficiency for a mobile bed
absorber ... . . . ... 60
51 Effect of slurry pH on sulfur dioxide
absorption efficiency for a venturi
absorber 61
52 Effect of slurry pH on sulfur dioxide
absorption efficiency for a spray
absorber .... ... . . . . 61
53 Effect of time on solution-slurry interface
position for crystalline MgS03'-6H20 se.ftling
through saturated MgS03 -6H20 solutions
containing soluble MgS04 ... 66
54 Effect of moisture content of feed to calciner
on composition of calciner offgas 69
55 Effect of moisture content of feed to calciner
on concentration of H2S04 69
56 Effect of inlet solids temperature to calciner
on composition of S02 in calciner offgas . . .70
57 Effect of feed temperature of solids to calciner
on H2O requirement at H2S04 unit . ... 70
58 Effect of variation in solids disposal cost on
annual limestone-wet scrubbing
operating cost .
59 Effect of raw materials limestone cost on
annual limestone-wet scrubbing operating
cost . . . ...
60 Effect of power unit size on magnesia
process investment: new coal-fired units
61 Effect of power unit size on magnesia
process investment: new oil-fired units
62 Effect of plant status (new vs existing)
on investment for magnesia Scheme A: coal-
fired power units . ...
63 Effect of power unit fuel type
on investment
64 Effect of plant status (new vs existing)
on investment for magnesia Scheme A: oil-
fired power units
65 Effect of sulfur content of coal on
investment: 500-mwunits
66 Effect of sulfur content of oil on
investment: 500-mw units
67 Effect of plant size and sulfur content
of oil on investment
68 Effect of power unit size on total
fixed investment for Scheme D vs
Scheme A
69 Effect of total system size on fixed
investment: central regeneration
concept .
70 Effect of power unit size on annual
operating cost: new coal-fired units
under nonregulated economics
71 Effect of plant status (new vs existing)
on annual operating cost: coal-fired units
under regulated economics . .
72 Effect of plant status (new vs existing)
on annual operating cost: oil-fired units
under regulated economics . ...
73 Effect of power unit size on annual
operating costs: regulated economics . . .
74 Effect of power unit size on unit
operating cost: coal-fired units under
regulated economics ...
75 Effect of power unit size on unit
operating cost: oil-fired units under
regulated economics
76 Effect of power unit size on unit
operating cost of acid: coal-fired
units under nonregulated economics
77 Effect of sulfur content of coal on
annual operating cost under regulated
economics .... ....
78 Effect of sulfur content of coal on unit
operating cost of acid under nonregulated
81
84
87
87
87
87
87
87
. 90
90
94
. 94
94
94
. 94
economics
94
95
95
95
Xlll
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79 Effect of sulfur content of oil on total
annual operating costs under regulated
economics . . . .95
80 Effect of annual operating time on
annual operating cost under regulated
economics .... .95
81 Effect of annual operating time on annual
operating cost under nonregulated
economics . . ... ... .95
82 Effect of annual operating time on unit
operating cost of acid under nonregulated
economics ... . . 96
83 Central regeneration system: effect of total
system size on annual operating cost under
cooperative economics . . 96
84 Central regeneration system: effect of total
system size on unit operating cost under
cooperative economics ... . 96
85 Effect of shipping distance on total annual
operating cost for Scheme D under
cooperative economics . . 96
86 Effect of shipping distance on unit cost of
acid for combinations of Scheme D scrubbing
and regeneration plants under
cooperative economics . . 97
87 Sulfuric acid manufacturing capacity . . . 102
88 Location of major coal-and oil-
fired power units—1971 . . 104
89 Effect of power unit size on cumulative
present worth of total net increase or
decrease in the cost of power to
consumers for coal-fired power units
using magnesia schemes 109
90 Effect of power unit size on cumulative
present worth of unit increase or decrease
in the cost of power to consumers for coal-
fired power units using magnesia schemes . .109
91 The effect of power unit size on cumulative
present worth of total net increase or
decrease in the cost of power to consumers
for oil-fired power units using magnesia
schemes .112
92 Effect of sulfur content of coal on cumulative
present worth of total net increase or decrease
in the cost of power to consumers for magnesia
Scheme A .... . . 113
93 Effect of sulfur content of oil on cumulative
present worth of total net increase or decrease
in cost of power to consumers for magnesia
Scheme A .... 113
94 Effect of constant onstream time of 7,000 hr/yr
on cumulative present worth of total net increase
or decrease in cost of power to consumers for
coal-fired units using magnesia Scheme A . 114
95 Effect of constant onstream time of 7,000 hr/yr
on cumulative present worth of unit increase
or decrease in cost of power to consumers for
coal-fired units using magnesia Scheme A ... 114
96 Effect of plant age or status on cumulative
present worth of unit increase or decrease
in the cost of power to consumers for coal-
fired plants using magnesia Scheme A . 116
97 Effect of fixed investment on cumulative
present worth of total net increase or decrease
in the cost of power to consumers for coal-
fired units using magnesia Scheme A . . 117
98 Effect of fixed investment on cumulative
present worth of total net increase or
decrease in cost of power to consumers for
oil-fired units using magnesia Scheme A 117
99 The effect of variation in net sales revenue on
cumulative present worth of total net increase
or decrease in the cost of power to consumers
for coal-fired units using magnesia Scheme A . 118
100 Effect of variation in net sales revenue on
cumulative present worth of unit increase or
decrease in cost of power to consumers for
coal-fired plants using magnesia
Scheme A .118
101 Effect of annual labor cost variation on cumulative
present worth of total increase or decrease in
cost of power to consumers for coal-fired units
using magnesia Scheme A . . ... 119
102 The effect of power unit size on payout
period for magnesia Scheme A on coal-
fired units 120
103 The effect of power unit size on payout
period for magnesia Scheme B on coal-
fired units . 120
104 The effect of power unit size on payout
period for magnesia Scheme C on coal-
fired units . .120
105 The effect of power unit size on interest
rate of return for magnesia Scheme A on
coal-fired units . . .120
106 The effect of power unit size on interest
rate of return for magnesia Scheme B on
coal-fired units . . 120
107 The effect of power unit size on interest
rate of return for magnesia Scheme C
on coal-fired units . . 120
108 The effect of power unit size on payout
period for magnesia Scheme A on
oil-fired units . . . ... 121
109 The effect of power unit size on payout
period for magnesia Scheme B on
oil-fired units . . 121
110 The effect of power unit size on interest
xiv
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rate of return for magnesia Scheme A
on oil-fired units ... . . 121
111 The effect of power unit size on interest
rate of return on magnesia Scheme B
on oil-fired units . . ... 121
112 The effect of sulfur content of coal on
payout period for magnesia Scheme A
on coal-fired units . 121
113 The effect of sulfur content of coal on
interest rate of return for magnesia
Scheme A on coal-fired units . . .121
114 The effect of sulfur content of oil on
payout period for magnesia Scheme A on
oil-fired units . . . ... .122
115 The effect of sulfur content of oil on
interest rate of return for magnesia Scheme
A on oil-fired units 122
116 The effect of variation in net sales revenue
on interest rate of return for magnesia Scheme
A on coal-fired units—low payment . . . 124
117 The effect of variation in net sales revenue on
interest rate of return for magnesia Scheme
A on coal-fired units—high payment 124
118 The effect of variation in net sales revenue
on payout period for magnesia Scheme A on
coal-fired units—low payment 124
119 The effect of variation in net sales revenue
on payout period for magnesia Scheme A
on coal-fired units—high payment . 124
120 The effect of variation in fixed investment on
interest rate of return for magnesia Scheme
A on coal-fired units—low payment ... 124
121 The effect of variation in fixed investment on
interest rate of return for magnesia Scheme
A on coal-fired units—high payment 124
122 The effect of constant onstream time on
payout period for magnesia Scheme A on
coal-fired units . .... .125
123 The effect of power unit age or status on
interest rate for magnesia Scheme A on
coal-fired units .... .... . 125
124 The effect of annual labor cost escalation
on interest rate of return for magnesia
Scheme A on coal-fired units 125
125 The effect of annual labor escalation on
payout period for magnesia Scheme A
on coal-fired units 125
126 The effect of recycle magnesium oxide cost on
cumulative present worth of increase or decrease
in cost of power to consumers for regulated
portion of magnesia Scheme D under
cooperative economics . . . . . . . 126
127 The relationship of recycle MgO cost on increase
in the cost of power to consumers for 200-,
500-, and 1,000-mw scrubbing systems of
Scheme D . 126
128 The effect of shipping distance for recycle magnesium
oxide on cumulative present worth of the increase or
decrease in unit cost of power to consumers in the
regulated portion of magnesia Scheme D under
cooperative economics 127
129 The effect of power unit size on interest rate
of return of centralized regeneration-acid
plants supplied by combinations of 200-,
500-, and 1,000-mw scrubbing systems
under cooperative economics . . 128
130 The effect of shipping distance on interest rate
of return for centralized regeneration-acid
units—combinations of 500-mw scrubbing systems,
recycle MgO cost-$15/ton . .128
131 The effect of shipping distance on interest rate
of return for centralized regeneration-acid
units—combinations of 500-mw scrubbing systems,
recycle MgO cost-$55/ton 128
132 The effect of variation in sales revenue for recycle
MgO on interest rate of return of centralized
regeneration-acid units—combinations of
200-mw scrubbing systems . .128
133 The effect of variation in sales revenue for recycle
MgO on interest rate of return of centralized
regeneration-acid units—combinations of
500-mw scrubbing systems 129
134 The effect of variation in sales revenue for recycle
MgO on interest rate of return for centralized
regeneration-acid plants—combination of
1,000-mw scrubbing systems . 129
135 The effect of variation in net sales revenue for
sulfuric acid on interest rate of return for
centralized regeneration-acid units—combinations of
200-mw scrubbing systems—recycle MgO cost—
$25/ton . . .129
136 The. effect of variation in net sales revenue for
sulfuric acid on interest rate of return for
centralized regeneration-acid units-
combinations of 200-mw scrubbing systems-
recycle MgO cost-$55/ton . 129
137 The effect of variation in net sales revenue
for sulfuric acid on interest rate of return for
centralized regeneration-acid units—combinations
of 500-mw scrubbing systems—recycle MgO cost—
$15/ton .130
138 The effect of variation in net sales revenue for
sulfuric acid on interest rate of return for
centralized regeneration-acid units—combinations
of 500-mw scrubbing systems-recycle M'gO cost-
$55/ton . . . .- 130
139 The effect of variation in net sales revenue for
sulfuric acid on interest rate of return for
centralized regeneration-acid units—combinations
of 1,000-mw scrubbing systems—recycle MgO cost—
$10/ton . . . . . 130
140 The effect of variation in net sales revenue for
sulfuric acid on interest rate of return for
centralized regeneration-acid units-combinations
of 1,000-mw scrubbing systems-recycle MgO cost-
$55/ton . ... 130
xv
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SUMMARY
The decline in air quality over the past decade has
prompted increased efforts by government and industry to
reduce objectionable emission from fossil-fueled power
plants. With the recently instituted Federal ambient and
emission standards plus state and local requirements as
guides, several routes to pollution abatement are being
investigated. One of the more actively pursued alternatives
for reduction of particulate matter, sulfur oxides, and in
some cases nitrogen oxides, is stack gas scrubbing processes.
The present report on sulfur oxide removal with aqueous
magnesia slurries or solutions is the fourth in a series of
conceptual design and cost studies being carried out by the
Tennessee Valley Authority (TVA) for the Environmental
Protection Agency (EPA). The first two studies were
concerned with the use of lime or limestone as absorbents,
which convert the gaseous sulfur oxides to solid compounds
(calcium sulfite and calcium sulfate) that are discarded.
These were called "throwaway" processes. The third study
included processes using aqueous ammonia solutions as the
scrubbing medium and recovering the sulfur oxides as
ammonium sulfites which were converted to sulfate and
used as an intermediate in the production of fertilizer
products. This was the first recovery system examined in
which materials could be produced for sale to offset, at
least partially, the cost of operation.
Processes recovering the sulfur oxides in a useful form
are potentially superior to the throwaway type because
they do not generate solid waste disposal problems and also
offer the possibility that sales revenue will reduce the cost
of sulfur oxide removal. It should be kept in mind,
however, that recovery processes are generally more com-
plex, may be more expensive to install, and require a
definite commitment to sell the products produced.
In recent years, numerous processes have been proposed
for sulfur oxide recovery and some of these are currently
being developed extensively. The purpose of the EPA-TVA
conceptual design series is to select the more promising of
these and subject each to a detailed study in which the best
design is developed from available data; capital and oper-
ating costs are estimated on a uniform basis; a market
survey is made to estimate sales revenue; total cash flow is
related to economic promise; and needed research and
development are identified.
Scrubbing with magnesium oxide slurry to form
magnesium sulfite, followed by decomposition to produce
concentrated S02 (MgO is recycled), is one of the more
promising processes for sulfur dioxide removal. Slurries of
magnesia are good absorbents; however, the most
outstanding assets of the concept are:
1. The ease of separation of the sulfite salts formed
from the scrubber liquor.
2. The ability to regenerate and recycle the absorbent,
magnesium oxide.
3. The avoidance of a solids disposal problem.
4. The capability of separating, both financially and
operationally, the power unit scrubbing system from the
chemical manufacturing and marketing function.
At the same time, the process does require extra expense
for drying and calcining the intermediate MgS03 and
MgS04 formed, and the apparent need for two scrubbing
stages on coal-fired units to avoid mixing fly ash with the
undissolved absorbent. As with all aqueous scrubbing
processes, stack gas reheating, if required, would also add
expense. The potential of the process, however, is out-
standing enough to merit demonstration on a 155-mw,
oil-fired power unit of Boston Edison. This system,jointly
funded by EPA and a large group of chemical companies
and utilities, started up in early 1972.
In the regeneration of the absorbent, sulfur dioxide is
released at concentrations practical for conversion to
sulfuric acid, liquified sulfur dioxide, or elemental sulfur.
With the limited market for liquified sulfur dioxide and the
higher cost of conversion to sulfur, the product receiving
primary attention in this report is sulfuric acid. Commercial
grades of acid including 98% concentration and oleum are
easily produced in the process.
Around the world, development work on magnesia
scrubbing for power plant stack gas has followed at least
three major technological routes. The Russians, Japanese,
and Americans have concentrated on the use of magnesium
sulfite-magnesium oxide slurries having a basic pH; whereas
a German company has researched the use of an absorbent
activator, manganese dioxide, with the scrubbing slurry. In
addition, using technology associated with sulfite pulping
practice, at least one American company has also investi-
gated the use of magnesium sulfites in acidic solution so
that simultaneous particulate and S02 removal can be
accomplished with a single scrubber in coal-fired unit
applications.
1
-------
Each of these three scrubbing schemes is given detailed
review in the present study and is described as follows:
1. Scheme A—magnesia slurry variation--Wet scrubbing
with magnesium oxide-magnesium sulfite-water slurry to
absorb S02 and form undissolved MgSO3-6H20 plus some
MgS03-3H20. The MgS03-6H20 is thermally converted to
trihydrate and dried to form anhydrous MgS03. This
material, along with any sulfate formed by oxidation, is
calcined with coke to generate MgO for recycle and S02 for
production of H2S04 by the contact process.
2. Scheme B-MgO-MnO2 slurry variation-Wet
scrubbing with magnesium oxide-magnesium sulfite slurry
containing a scrubbing reaction activator, manganese
dioxide. The sulfites, sulfates, and unreacted manganese
dioxide are dried and calcined to regenerate the absorbent
and activator with the S02 rich gas being processed to
H2S04.
3. Scheme C—clear liquor variation—Wet scrubbing of
stack gas to remove particulates and absorb S02 simul-
taneously with an acidic solution of magnesium sulfites,
followed by separation of insoluble fly ash and liquor and
addition of MgO to the liquor to precipitate MgS03-6H2O.
The crystals of sulfite are then converted to trihydrate,
dried, and calcined. MgO is recycled and S02 processed to
acid.
The above variations can be applied to multiple power
units more economically than with individual power plants
by taking advantage of a concept called "central pro-
cessing." By processing (calcining and acid production) the
dried sulfite material from several scrubbing operations in a
single, large plant, a more efficient operation (higher annual
operating time) can be derived and economy of scale can be
achieved. This concept is not a technological variation, but
deserves separate consideration (Scheme D) to evaluate the
economic merit of the idea which, of course, can be used in
other type absorbent processes as well.
Some earlier preliminary investigations (1970) indicate
the possible use of a variation in magnesia scrubbing for
NOX control. Recent work (1972), however, indicates that
no more than 10% removal can be expected; therefore,
magnesia scrubbing should not be counted as a means of
meeting new Federal NOX emission standards.
Study Assumptions
Recovery process economics depend on several factors
including power plant size, type of fuel burned, sulfur
content of fuel, operating factor, plant location, unit
efficiency, and unit status (new vs existing). For detailed
design and cost estimating purposes, it is necessary to
assume a combination of conditions as a base case for both
oil- and coal-fired units. In the economic evaluation, the
effect of variations in the major parameters is determined.
The basic conditions assumed are as follows:
Power unit size, mw
Sulfur content of coal, %
Sulfur content of oil, %
Ash content of coal, %
Heating value of coal, Btu/lb
Heating value of oil, Btu/lb
Boiler excess air and leakage,
Coal-fired unit
Oil-fired unit
Degree of dust removal, %
Degree of S02 removal, %
Slurry Schemes A, B, D
Solution Scheme C
Boiler type
Plant location
Capacity factor, % of
nameplate rating
first to 10th year
11 th to 15th year
16th to 20th year
21st to 30th year
Avg over life of unit
Air preheater exhaust temp, °
Stack gas reheat temp, °F
Unit heat rate, Btu/kwh
Product storage, days
500
3.5
2.5
12
12,000
18,500
33
15
99
90
77
Horizontal, frontal-fired
Midwest
80
57
40
17
48.5
310
175
9,000
30
Process Equipment
The scrubbers, ductwork, and fans are the most expensive
items in a recovery process because they must handle the
full flow of gas (over 1,000,000 tons/day for a 1000-mw
boiler). The slurry processing, drying, calcining and sulfuric
acid units handle a lower throughput of material depending
on S content of fuel. Stage wise scrubbing will be necessary
when using slurry scrubbing on coal-fired units to keep the
majority of the fly ash from entering the drying and
calcining operations. For particulate removal, a venturi type
device using clarified, circulated water is chosen although
electrostatic precipitators and bag filters could be used.
Electrostatic precipitators have shown variations in outlet
loading due to operating characteristics and time, and bag
filters are more expensive.
In scrubbing sulfur oxides, slurry systems can utilize
venturi, mobile bed (plastic sphere type) or spray units.
For solution scrubbing service (Scheme C), plate and
packed scrubbers might be added to the list of acceptable
devices, but consideration must be given to residual fly ash
carryover causing plugging. In any case, corrosion and
erosion protection should be provided by linings such as
rubber or polyester-fiberglass.
At this time, mist eliminator performance in slurry
scrubbing service is of concern with a variety of designs and
materials of construction currently in use or under study.
-------
In this study, chevron vane type devices constructed of or
coated with corrosion-erosion resistant materials are used.
Reheating can be accomplished by indirect steam heat
exchange on new units for which design provisions have
been made in- the steam cycle; however, since existing units
are not likely to have excess steam available, direct fuel oil
reheat is preferred. Neither of these methods is the most
economical choice available, but the reliability of the
indirect liquid-gas heat exchange method considered in
previous studies has become suspect.
Solids separation in the slurry processing area probably
can be accomplished best by first thickening the 10% solids
slurry to 40% and then centrifuging to a cake containing
less than 15% free water. Since good test data are not
available, separation by filtration can not be ruled out;
however, cakes containing less than 15% water may be
more difficult to obtain.
Although rotary type devices are being utilized for
drying and calcining in the Boston Edison demonstration
project, discussions with vendors and some process
developers have indicated that possibly greater efficiency
and lower cost could be obtained with fluid bed units. In
the absence of test data, some doubt remains; however,
fluid bed systems appear to be the best choice.
The "dry" gas cleanup system for calciner off-gas and
the sulfuric acid plant utilize relatively well established
technology; therefore, few unforeseen problems should
arise in these areas. If desirable, the magnesia process could
easily be added to existing acid units which currently burn
elemental sulfur.
Investment Requirements
Investment under various combinations of conditions are
given for Scheme A and limestone-wet scrubbing in table
S-l. Although Scheme C has the lowest investment require-
ment ($36.2/kw for base case) for coal-fired power unit
scrubbing systems, S02 removal for Scheme C may not be
sufficient in all cases to meet Federal emission standards for
new units. In addition, the data supporting clear liquor
scrubbing are limited; therefore, the scheme should not be
considered as the leading process. Depending on type and
sulfur content of fuel and power unit size and age, the
magnesia Scheme A investment ranges from 1 -28% higher
than the investment for limestone-wet scrubbing.
Evaluation Considerations
Evaluation of recovery processes brings in factors such as
product marketability and price, profit margin and taxes
and project financial promise, all of which make the
analysis more difficult than for throwaway processes. It
would be desirable, of course, that recovery methods show
promise of a net profit, but this is not essential because
recovery should be preferable to throwaway, even at a net
loss, as long as the loss is lower than for throwaway
systems. The cost of limestone-wet scrubbing was used as
the criterion for comparison. Both high cost ($6/ton
limestone, $6/ton solids disposal) and low cost ($2.05/ton
limestone, variable on-site solids disposal) limestone
Table S-1. Capital requirements for magnesia Scheme A and limestone-wet scrubbing.
Capital, $/kw of power generating capacity
Conditions
Magnesia Scheme A
wet scrubbing
Limestone-wet
scrubbing
Base case—coal-fired units
(500-mw, new power unit, 3.5%
S in coal, reheat to 175°F)
Exceptions to base case (coal fired)
Existing power unit
2.0% sulfur
5.0% sulfur
200-mw
1,000-mw
Base case—oil-fired units
(500-mw, new power unit, 2.5%
S in oil, reheat to 175°F)
Exceptions to base case (oil fired)
Existing unit
1.0% sulfur
4.0% sulfur
200-mw
1,000-mw
43.5
49.3
37.6
48.5
58.4
33.1
24.9
27.8
19.8
29.1
33.4
18.8
35.2
39.9
32.3
37.8
46.0
27.4
21.4
24.8
19.0
23.4
28.5
16.6
-------
systems were estimated using the same variables as used for
the magnesia schemes.
The basis on which the recovery process is financed is a
major consideration in evaluating economic promise- and
acceptability. If a power company finances the entire
project, it can be assumed that the investment would
become part of the rate base on which the company is
allowed to earn what the regulatory authority regards as a
reasonable return on investment. If sulfur oxide removal,
either by throwaway or recovery method, were to increase
operating cost, then the price of power to consumers
presumably could be raised to offset the extra cost. Under
such basis, sulfur oxide removal (even by recovery) could
be considered as necessary for production of power just as
is the boiler operation, dust removal, or cooling water
system, and the costs; therefore, passed on to the con-
sumer. It is true that rate increases are often strongly
contested and delayed, and that the full adjustment may
not always be allowed, so that the power company has the
incentive to avoid extra investment and expense. In general,
however, the power company has a more or less assured
profit. For this reason, there is little risk and capital can be
attracted at regulated rates of return.
As a practical matter (but within limits), loss from
operation of a sulfur dioxide recovery system could be
passed on to the power consumer. The main trouble is the
considerable time and effort usually associated with
obtaining a rate increase. Another consideration is that
neither power producer nor regulatory authority has any
reason to favor recovery if it losses more money than
alternates such as limestone-wet scrubbing. Since both
alternatives have the same rate of return on investment
under the regulated financing basis, the present worth of
expenditures over the life of the plant must be compared
for both the recovery process and the limestone-wet
scrubbing process to determine which results in the least
cost to the power consumer.
Since power companies generally are not familiar with
chemical production and marketing, there would be some
advantage if a chemical company built and operated the
recovery process for a fee and marketed the products. For a
private, nonregulated company to enter into such an
activity, however, the project would have to be promising
enough to attract the necessary capital from investors. It is
difficult to say how much promise is needed because this
varies with the situation. It generally is considered that the
project cash flow (depreciation plus profit after taxes)
should pay out the original investment in about 5 years or,
on another basis which takes into account the time value of
money, the interest rate of return should be about 15%.
For the relatively high investment required by sulfur oxide
recovery processes, this is a major hurdle.
A characteristic of the central process concept is that
features of both regulated and nonregulated economics can
be utilized to advantage. If by cooperative arrangement,
magnesia scrubbing and drying operations are placed under
power industry (regulated) economics and regeneration and
acid manufacture are covered under nonregulated
economics, the power company can avoid any respon-
sibility for acid production and marketing and the chemical
company can reduce its capital responsibility to levels more
likely to achieve successful profitability. By charging the
power company for regenerated MgO and also by selling
sulfuric acid, enough revenue might be obtained for a
chemical company to justify manufacturing acid from
magnesium sulfite rather than by the more conventional
purchase of elemental sulfur. The revenue obtained for
regenerated MgO would, of course, depend on the resultant
cost to the power company for magnesia scrubbing as
opposed to limestone-wet scrubbing or other feasible
alternatives.
Comparison and Profitability
An important consideration for comparison under regulated
economics, and in profitability analysis under nonregulated
economics, is net sales revenue for the sulfuric acid. A
market review for the acid resulted in the following
conclusions:
1. The growth rate of sulfuric acid production is about
4-6%/year generally paralleling that of the phosphate
fertilizer industry.
2. The best end-use market appears to be the phosphate
fertilizer industry as an acidulant for phosphate rock. The
product is used in many other applications, however, any of
which merit consideration.
3. The most promising locations for magnesia scrubbing
regeneration systems appear to be on waterways serving the
areas where sulfuric acid is now heavily marketed. Areas on
the Ohio and Mississippi Rivers, and along the Gulf and
East Coasts are prime spots.
4. Sales price will be based on competition in each
individual area plus flexibility of demand. In those areas
where byproduct acid or low cost sulfur are available
competition will be greatest.
5. Expected net sales revenue after shipping and sales
expense are deducted could average about $8.00/ton of
100% acid for single site systems and $12.00/ton for large
central processing units. In the best locations these net
backs and maybe more should be attainable through the
1970's.
6. Long-term marketing contracts appear to be practical
since the likelihood of escalating sales revenue due to
prolonged product shortages is not in sight.
Comparison under regulated economics—A comparison
of Scheme A with both high and low cost limestone
scrubbing is given in table S-2. The values shown are the
cumulative present worth of the net annual costs over the
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Table S-2. Cost of magnesia Scheme A vs limestone-wet scrubbing under regulated economics.
Cumulative present worth of
net annual costs, $ millions
Conditions
Scheme Aa
Limestone-wet scrubbing
Low limestone
process cost"
High limestone
process costc
Base case-oil-fired units
(500-mw, new unit, 3.5% S
in coal, 48.5% average capacity
factor over 30 yr, reheat to 175° F)
Exceptions to base case (coal fired)
Existing unit (27 yr life)
2.0% sulfur
5.0% sulfur
200-mw
1,000-mw
64.7
68.7
56.4
71.8
36.3
94.9
aNet sales revenue assumed at $8/ton of acid.
^Limestone cost-$2.05/ton; cm-site pond disposal of solids.
cLimestone cost-$6/ton; off-site solids disposal cost, $6/ton.
55.0
57.7
49.4
60.0
29.3
84.3
70.3
71.9
59.9
80.4
33.9
117.3
Base case-oil-fired units
(500-mw, new unit, 2.5% S
in oil, 48.5% average capacity
factor over 30 yr, reheat to 175° F)
Exceptions to base case (oil fired)
Existing unit (27 yr life)
1 .0% sulfur
4.0% sulfur
200-mw
1 ,000-mw
38.3
40.2
31.1
44.2
21.7
56.6
34.0
36.4
29.7
37.9
18.6
52.5
38.6
40.6
30.9
46.2
19.4
63.6
life of the power unit; this base is used because under the
variety of conditions one system may be better at some
yearly levels of operation and vice versa at other levels.
Thus, the values represent the total bill in current dollars
including return on investment and income taxes for
particulate and S02 control over the power plant life.
Except for the small 200-mw units, the costs of
magnesia Scheme A examples lie between the high and low
limestone scrubbing costs. The only magnesia case with
costs lower than the low cost limestone system is a
1000-mw, coal-fired unit using Scheme C, the least
developed variation. Units smaller than 300-mw would
most likely use limestone scrubbing if funding were under
regulated economics. Because the incremental cost of
producing additional acid exceeds $8/ton (net sales revenue
for acid), increasing onstream time and higher sulfur
content of fuel does not improve the magnesia process
economics.
Profitability under nonregulated economics-Eased on
projected $8/ton revenue from acid sales alone, all magnesia
cases examined have negative interest rates of return and no
payout. If additional revenue in the form of a fee
equivalent to the cost of limestone-wet scrubbing or other
competitive S02 control method is charged by the chemical
company for sulfur oxide abatement, profitability can be
derived. Shown in table S-3 are payout periods in years and
interest rates of return in % for Scheme A assuming revenue
from both a fee and acid sales.
As would be expected, the results depend on the size of
the fee charged; for a fee equivalent to a high-cost
limestone scrubbing process, desirable profitability could be
achieved in some cases and for a smaller fee equivalent to a
low-cost limestone process, low profitability would result in
all cases. Funding under this concept will probably be
limited.
Profitability of cooperative central process ventures—
With the separation of investment and operating respon-
sibility and the advantage of economy of scale for large
central acid complexes, cooperative ventures (Scheme D)
between power companies and chemical companies are the
best route to financial funding of magnesia systems. Given
in table S-4 are the payouts and interest rates of return
after income taxes for Scheme D systems assuming revenue
from both acid and recycle MgO sales. The price of recycle
MgO must be such that magnesia scrubbing cost does not
exceed that of competitive limestone scrubbing for the
same power unit. For a 500-mw, coal-fired unit, only about
$15-20/ton could be paid for recycle MgO before exceeding
5
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Table S-3. Profitability of Scheme A with supplementary income as payment for pollution abatement.
Low equivalent payment13 High equivalent payment0
Conditions3
Payout, yi
Interest rate
of return, %
Payout, yr
Interest rate
of return,%
Base case—coal-fired units
(500-mw, new unit, 3.5% S in coal,
48.5% average capacity factor over
30 yr, reheat to 175°F)
Exceptions to base case (coal fired)
Existing unit (27 yr life)
2.0% sulfur
5.0% sulfur
200-mw
1,000-mw
7.6
7.7
7.4
7.7
8.3
7.1
8.4
9.5
8.5
7.4
10.0
5.6
5.7
5.7
5.4
6.7
4.8
^Net sales revenue assumed at $8/ton of acid.
Equivalent to limestone-wet scrubbing cost assuming low limestone price, on-site pond disposal of solids.
cEquivalent to limestone-wet scrubbing cost assuming high limestone price, off-site disposal of solids.
14.9
13.6
14.3
15.7
11.0
18.1
Base case— oil-fired units
(500-mw, new unit, 2.5% S in oil,
48.5% average capacity factor over
30 yr, reheat to 175°F)
Exceptions to base case (oil fired)
Existing unit (27 yr life)
1 .0% sulfur
4.0% sulfur
200-mw
1 ,000-mw
7.2
7.0
6.6
7.5
7.6
6.8
9.8
10.0
11.5
9.0
8.8
10.9
6.1
6.0
6.2
5.8
7.1
5.3
13.0
12.7
12.6
14.0
9.9
15.8
Table S-4. Profitability of central regeneration-acid manufacturing unit under cooperative economics.3 Magnesium
sulfite supplied from combinations of new 200-, 500-, or 1,000-mw units burning coal with 3.5% sulfur.
Regulated magnesia scrubbing costs equalized to high and low projected limestone-wet scrubbing process costs.
Case
units and size
200-mw equivalent
5 x 200-mw equivalent
10 x 200-mw equivalent
15 x 200-mw equivalent
500-mw equivalent
2 x 500-mw equivalent
4 x 500-mw equivalent
6 x 500-mw equivalent
1 ,000-mw equivalent
2x 1 ,000-mw equivalent
3x 1 ,000-mw equivalent
Payout,
Recycle MgOb
at $25/ton
None
6.6
5.2
4.6
Recycle MgOb
at $15/ton
None
9.9
7.7
6.5
Recycle MgOb
at $10/ton
None
9.9
8.3
years
Recycle MgO°
at $55/ton
8.4
3.4
2.7
2.4
Recycle MgOc
at$55/ton
5.1
3.5
2.8
2.4
Recycle MgOc
at $55/ton
3.6
2.9
2.5
Interest
Recycle MgOb
at $25/ton
Neg.
8.2
14.0
17.2
Recycle MgOb
at $15/ton
Neg.
0.3
5.1
8.7
Recycle MgOb
at$10/ton
Neg.
0.1
3.5
rate of return, %
Recycle MgOc
at $55/ton
3.3
26.6
35.5
40.6
Recycle MgOc
at $55/ton
14.4
25.3
34.1
39.7
Recycle MgOc
at $55/ton
24.4
33.0
38.5
aNonregulated portion of system with 10 yr life; acid revenue—$12/ton.
"Equivalent to limestone-wet scrubbing costs assuming low limestone price, on-site pond disposal of solids
cEquivalent to limestone-wet scurbbing costs assuming high limestone price, off-site disposal of solids.
-------
the low-cost limestone system; however, approximately
$55/ton could be paid if competition came from a high-cost
limestone system.
The results in table S-4 indicate that the smaller the
power unit supplying MgS03 and the larger the acid
complex, the better the profitability which could be
achieved. A 3000-mw equivalent acid plant supplied by
fifteen 200-mw units would show excellent profit making
potential-17.2% interest rate of return with $25/ton for
recycle MgO and $12/ton for sulfuric acid or 40.6% return
for $55/ton recycle MgO and $12/ton acid.
Conclusions
The more important conclusions derived from this study
can be summarized as follows:
1. Sulfur dioxide absorption by magnesia slurry
scrubbing is effective and the major portions of the process
as conceptualized utilize proven technology.
2. Magnesia scrubbing, like limestone scrubbing, is not
an effective means of NOX removal from power plant stack
gas.
3. Magnesia slurry scrubbing-regeneration has been
tested in laboratory and pilot plant stages and at least one
large scale demonstration is underway.
4. Although limited experience is available to guarantee
performance, equipment for commercial systems can be
obtained at this time from vendors and fabricators.
Depending on fuel type, sulfur content, plant size and age,
the magnesia slurry process investment requirements vary
from 1 to 28% greater than for limestone-wet scrubbing,
another approach to sulfur dioxide removal which does not
produce a salable product, but requires disposal of large
amounts of waste sludge.
5. For most U. S. fossil-fueled power plants, achievable
net sales revenue for recovered 98% sulfuric acid would
probably average only $8-12/ton over the next decade or
so; however, there will be applications where better net
backs are obtainable. Competition will continue from other
sources and grades of byproduct sulfuric acid and virgin
acid made from low cost sulfur.
6. Primary economic factors are investment, product
volume (depending on power unit size and sulfur content of
fuel), net sales revenue (from all sources), competitive cost
of alternatives, and basis of financing. Raw material, labor,
shipping costs, onstream time, and plant age are significant,
but not nearly as important as the primary factors.
7. Under total regulated financing, magnesia systems
can compete with limestone scrubbing on larger (400-mw
or greater) power units. The limestone process would be
favored in rural areas (low cost limestone and space for
solids disposal) whereas the magnesia scrubbing-
regeneration process would appear desirable in crowded
metropolitan areas.
8. Total nonregulated industry financing and operation
appear unlikely; however, with a large fee for pollution
abatement and large size units, such funding can be
considered.
9. A cooperative venture between several power com-
panies and a chemical company, with each supplying capital
for and operating their portion of the process, appears to be
a good way to fund a magnesia system. It will be necessary
for the regeneration-acid plant to charge a service fee for
MgO processed from MgS03 in order to obtain sufficient
revenue for desirable profitability.
10. Thus far, interest in the magnesia scrubbing-
regeneration process has centered more on replacement of
sulfur as raw material in existing sulfuric acid plants with
existing markets rather than for added capacity to meet
increasing acid markets.
11. There are a limited number of locations that can
support a central process installation. The Midwest, along
the Ohio and Mississippi Rivers, and the Gulf and East
Coasts are prime targets.
12. For short-range shipping distances (0-50 miles), the
cost of shipping MgS03 and MgO between sites is a small
part of the total process cost and will not greatly influence
process application; however, as distances exceed 100 miles,
shipping cost becomes much more significant.
Additional research and development of the process should
be performed primarily on the demonstration level to
determine effects of process factors such as contamination
build-up over long periods of MgO recycle, corrosion-
erosion of construction materials, scaling difficulties, and
adaptability to power plant operation. Some work on
oxidation, crystal growth, effectiveness of additives such as
manganese dioxide and the manufacture of sulfur in the
calciner should be performed on the bench or pilot levels.
-------
INTRODUCTION
The total emission of sulfur dioxide (S02) in the United
States during 1970 is estimated to have been about 37
million tons (21) and is expected to increase about 65%
during the decade of the 70's. Approximately 55% of the
1970 emissions resulted from combustion of coal and oil at
power generating plants, and by 1980 two-thirds of the
total emissions are expected to originate from this source as
a result of the rapid increase in electrical power demand.
The contribution of power plant emissions to the overall
condition of air quality has prompted considerable effort
toward reducing the S02 and particulate concentrations of
stack gases.
During the past few years, many Federal, state, and local
governments have established both ambient and emission
standards in an effort to improve air quality. The need for
particulate control generally has been accepted by the
utility industry and fly ash control devices have become
almost standard equipment on most new power plants;
many existing plants are currently being upgraded or
retrofitted with improved equipment. Sulfur dioxide is now
getting the same attention as particulate matter; however,
systems for its control are still undergoing continuing
development in demonstration size plants.
There appears to be several promising alternative routes
to SO2 emission control in power generation, including the
use of naturally occurring low sulfur fuel, coal and fuel oil
desulfurization, alteration of combustion processes, nuclear
power,, and stack gas removal processes, either recovery or
nonrecovery. Each alternative has advantages and disadvan-
tages, and only thorough evaluation by each potential user
can indicate which is best. However, there probably will not
be one single route which will satisfy all of industry's needs.
With funding provided by the Air Quality Act of 1967
and more recently the Clean Air Act of 1970, the Office of
Research and Monitoring of the Environmental Protection
Agency (formerly National Air Pollution Control
Administration—NAPCA) has become increasingly active in
promoting research and development on the various ideas
for reducing power plant emissions. In the case of stack gas
cleaning processes, literally dozens of concepts have been
proposed during recent years. The field became so com-
plicated that several years ago ORM contracted for a series
of area surveys to sort out the methods, organize them into
manageable classifications, and evaluate them on a
screening basis. The processes were classified as follows:
1. Scrubbing with aqueous salts.
2. Sorption by metal oxides.
3. Catalytic oxidation of sulfur dioxide to sulfur
trioxide.
4. Sorption by inorganic solids other than oxides.
5. Reduction of sulfur dioxide to sulfur.
6. Sorption by inorganic liquids.
7. Sorption by organic solids.
8. Sorption by organic liquids.
9. Separation by physcial methods.
Of these, the first three have received major attention, and
pilot plants and large demonstration scale units funded by
EPA and others are under construction or have been built
for processes falling within each of the three classes. It is
not appropriate here to review these processes; however, it
can be said that each has potential which can only be
evaluated by detailed analysis.
As part of the ORM-EPA program, the Tennessee Valley
Authority has over the last few years been preparing a series
of conceptual design and cost studies on several methods of
removing sulfur oxides and nitrogen oxides from power
plant stack gases. This report on the aqueous magnesia
scrubbing-regeneration process is the fourth in the series of
EPA-TVA conceptual design and cost studies. The first two
reports covered the use of limestone or lime in dry
absorption (88) and wet scrubbing processes (89). These
processes are considered to be the nonrecovery or "throw-
away" type in that the reaction products are waste
materials and are discarded. The third study, ammonia
scrubbing (production of ammonium sulfate and its use as
an intermediate in phosphate fertilizer manufacture) (87),
was the first recovery process evaluated and, of course,
required a more thorough economic appraisal since a salable
product was derived.
The present report on aqueous magnesia scrubbing-
regeneration is concerned with the use of magnesium
compounds as absorbents, primarily for S02 but con-
ceivably also for NOX. The magnesium salts formed can be
further processed so that the absorbent can be regenerated
and recycled. The primary product of the process is high
grade, concentrated (98%) sulfuric acid; however, liquified
S02 could be made if a market for large quantities existed.
It is also possible that elemental sulfur could be produced,
either by reduction of concentrated S02 or by altered
conditions in the magnesium sulfite calcination step. In the
-------
case of the latter route, there are too few data available to
justify consideration as an alternative.
Regardless of which sulfur product is produced, the
overall market outlook is questionable since the expected
growth of byproduct sulfur and sulfuric acid from power
plants, smelters and sour gas processing plants may result in
an oversupply for many locations. With potential byprod-
uct recovery so large [in 1970 emission of S02 from all
domestic sources was equivalent to 50 million tons of 100%
sulfuric acid (98), nearly 70% greater than the 29 million
tons consumed], prices will remain under continuing
pressure for some time to come and overall competition
will be intense.
Obviously, not all S02 emissions will be recovered as
marketable sulfur related products. In many cases where
markets do not exist, other pollution control measures,
such as low sulfur fuel or nonrecovery processes, will be
utilized to reduce emission levels. For recovery processes
such as magnesia scrubbing-regeneration, the best applica-
tions will probably be found in areas of growing acid
consumption, in locations where solids waste disposal from
nonrecovery processes will not be economically or legally
acceptable, and in existing sulfuric acid plants where
byproduct S02 can economically replace purchased sulfur
as raw material.
Of particular interest with the magnesia scrubbing-
regeneration process is the concept of a central processing
plant for absorbent regeneration and product manufacture.
The idea of combining the sulfur dioxide laden absorbent
from several different emission sources, shipping to a
separate, large, centralized.plant for regeneration and final
processing, and recycling the regenerated absorbent to the
original location has considerable merit. Not only would
the benefit of economy of scale be realized, but also, as
compared to power plant operation, a more consistent,
higher onstream time could be maintained and power
companies could transfer the responsibility of chemical
manufacture and marketing to a more qualified organiza-
tion. Offsetting these advantages, however, is the cost of
shipping material from the emission source to a central
plant and back. Since the central processing concept can be
applied to other sulfur dioxide control processes, an
important part of this report will be to evaluate the
economics of the procedure.
In the last few years, the technology of S02 control by
stack gas scrubbing has progressed from the pilot plant to
the demonstration stage for several of the more promising
processes. The magnesia scrubbing-regeneration process is
one of those which has seen rapid development and for
which a demonstration unit has been built on a Boston
power plant. For a process to be successful, large-scale
operation over long periods will be required to prove
equipment performance and reliability. Removing the
relatively small quantity of sulfur dioxide (0.1-0.4%) from a
large quantity of gas (3 million actual cubic feet/minute for
a 1000-mw unit) is a difficult task, and it is desirable that it
be accomplished at a reasonable cost without interfering
unduly with the production of power.
-------
HISTORY AND STATUS
Perhaps the earliest use of the magnesium compounds
involved in this study was medicinal. In the period
1558-1603, magnesium sulfate or epsom salts were found
(91) by the Europeans to have value as a cathartic
medicine. Later in 1843, magnesium oxide was discovered
by A. Scacchi (66) near "Mount Vesuvius and since has been
widely used in firebricks or refractories.
The first industrial use of magnesium sulfite or bisulfite
occurred around 1874 (45) when C. D. Ekman, a Swedish
chemist, built the first sulfite paper pulp mill at Bergvik,
Sweden. Initially, magnesium bisulfite was used as a base
for the preparation of cooking liquor; however, as the
sulfite pulping process developed into widespread use,
limestone became the primary material because of
availability and low cost.
In the earlier pulp mills, disposal of the used cooking
liquor was directed into available watercourses, but as time
passed this became objectionable and ways were sought to
recycle or utilize the waste materials. About 1936, G. H.
Tomlinson of Howard Smith Paper Mills, Ltd., found that
when magnesia-base liquor is burned for heating value,
magnesium oxide is formed and sulfur dioxide is liberated
(92). In addition, he found that the magnesia-base liquors
could be evaporated to a high concentration with compara-
tive freedom from scale formation. These discoveries
became the basis for a new cyclic process for pulping wood.
A patent (U.S. 2,285,876) covering the process was issued
to G. H. Tomlinson in 1942.
The first pilot plant for the pulping process was installed
as a joint venture of the Howard Smith Paper Mills, Ltd.,
and The Babcock and Wilcox Company in 1937 at a
Canadian paper mill. About the same time, the Weyer-
haeuser Paper Company was independently developing the
same process. Inasmuch as the three companies had
common objectives, further duplication of effort was
eliminated by working out a cooperative arrangement. As a
result, the Longview, Washington, mill of Weyerhaeuser
became the first commercial system to utilize cyclic
magnesia-base pulping. Briefly, the modern process consists
of concentrating the cooking liquor in multi-effect evapo-
rators and burning it in a heat recovery furnace to form
MgO dust and S02 laden stack gas. The MgO dust is
collected, slurried in water, and routed to a series of venturi
scrubbers to form more cooking liquor by absorbing the
SO2 from the stack gas. The acid bisulfite is then fortified
in a separate tower to a pH of 4-5 with makeup S02 from
burning sulfur and recycled to the pulp mill. A generalized
flowsheet is given in figure 1. Approximately 15 such
systems are in use around the world.
In 1929, another use of magnesium sulfite-bisulfite
solution was patented (U.S. 1,865,224), based on produc-
tion of magnesium sulfate by air oxidation. A considerable
r
Steam
r
To stack
Waste liquor »
from pulping
Recovery
furnace
SO2,
MgO^
Dust
collector
MgO
*
SO2
Scrubber
rator
Mg(OH)2
9—
r.
-
Fortifier
S
1
, Mg(HS03)2
solution to
pulping
operation
sulfur burner
Figure 1. Magnesium bisulfite pulping process with chemical recovery.
10
-------
amount of technology relating to sulfite-bisulfite formation
was described in the patent (97).
The Russians were probably the earliest to consider the
use of magnesia liquor or slurries for sulfur dioxide removal
from smelters or power plant stack gases. Russian research
(66) on processes for stack gas control began in the early
thirties under the organizations of NIIOGAZ (Scientific
Research Institute for Industrial and Sanitary Purification
of Gases) and AUTI (Ail-Union Thermotechnical Institute).
Several processes were studied in the laboratory, including
the magnesia method. For verification on a large scale, a
magnesia scrubbing pilot plant was built in 1937 at the
Kashir power station. The plant was operated during 1938
and part of 1939 with reasonable success and, according to
references, an industrial size system similar to that shown in
figure 2 was built thereafter at one of the Russian power
stations.
Soviet investigators have continued to supply research
data on SO2 removal processes throughout the years,
including a great deal of information on the chemistry of
magnesia slurries. Some of this will be reported and
discussed in the section on Process Chemistry, Properties
and Kinetics. In recent years, they are reported to have
adapted the process to smelter waste gases from the
Magnitogorsk Metallurgic Works (15) to produce around
100,000 tons/yr of concentrated sulfuric acid.
The Japanese have also been active in investigating the
chemistry and application of the magnesia process. In the
early thirties, Hagisawa (38) produced considerable data on
magnesium sulfite solubility and hydrate formation. In later
years, Okabe and Hori (67) investigated mangesium sulfite
decomposition. Recently, it was reported that Showa
Denko (82) was working on a dry, fluid-bed absorption
process using magnesium oxide with subsequent regenera-
tion. A small test unit (100 cubic meters/hr) has been built
at Chiba City for demonstration. Another Japanese Com-
pany, Kawasaki Heavy Industries, Ltd., has been carrying
on basic research (Japanese patent 577,159) on the
magnesia scrubbing-regeneration process and is now mar-
keting a system very similar to those developed by the
Russians and Americans.
A German company, Grillo-Werke AG (61), .has also
developed a commercial magnesia process using naturally
occurring magnesium sulfate-monohydrate (kieserite) and
manganese dioxide (pyrolusite) as raw materials; however,
the process can also utilize calcined magnesite (magnesium
oxide) or magnesium hydroxide. The Grillo work was
started in 1964 with financial support from the Labor and
Social Ministry of the State of Nordrhein-Westfalen (West
Germany) and Firma Union Rheinische Braunkohlen
Kraftstoff AG, Wesseling. Almost all early development
covered oil-fired power plant installations; however, recent
Hydroclone
To stack
To stack
Figure 2. Magnesia slurry scrubbing-regenerating process as developed by NIIOGAZ (Russian).
11
-------
work indicates that with provision for fly ash removal, the
process can be adapted to coal-fired units.
Initial work on the Grillo process was on a laboratory
scale with later testing in a 25,000 cubic meters/hr pilot
plant at Duisburg-Hamborn. Since the Hamborn experi-
ments were made with simulated waste gas, it was decided
to test the process under actual conditions. The pilot plant
was moved to an oil-fired power station at Wesseling.
Overall, process development was considered a success, and
in 1969 the process technology was made available. A
flowsheet as proposed by Grillo is given in figure 3.
In the United States, development of the magnesia
scrubbing-regeneration process for S02 control has been
undertaken primarily by two companies—Chemico-Basic (a
joint company formed by Chemical Construction Corpora-
tion, New York, and Basic Chemicals, Cleveland, Ohio) and
Babcock and Wilcox Company, Barberton, Ohio. In addi-
tion, a contractor-constructor, United Engineers and
Constructors, Philadelphia, has recently become actively
involved in design technology.
Some basic research related to magnesium sulfite has
been carried out at TVA in recent years (1969-71), partly
under EPA contracts and partly under separate in-house
investigation. Hatfield, Jordan, et al have studied MgS03
calcination, solubility, and hydrate formation. Most of their
findings are presented in the Process Chemistry, Properties
and Kinetics section of this report.
Esso Research and Engineering Company in their EPA-
sponsored (3) study of NOX control from stationary
sources recognized the possibility of using a magnesia
scrubbing system for NOX control. Although the extent of
their research in this area is not known, it can be assumed
some investigation has been made. Babcock and Wilcox,
under a recent EPA-funded contract, has completed pilot
plant studies of NOX removal by magnesia scrubbing;
however, the preliminary results are not encouraging (26).
Chemico-Basic was the first U. S. company to market a
complete magnesia scrubbing-regeneration process for
sulfuric acid production using S02 from power plants,
smelters, or sulfuric acid plant waste gases. It has completed
pilot-plant test work at several locations, including par-
ticulate scrubbing at the Holtwood Station of Pennsylvania
Power and Light; Crane Station of Baltimore Gas and
Electric; and Dickerson Station of Potomac Electric Power;
Fluid
bed
calciner
Waste
heat
boiler
r
so.
Electrostatic
precipitator
Ash
Figure 3. Magnesia-manganese dioxide slurry scrubbing-regeneration process as developed by Grillo-Werke AG.
12
-------
and S02 scrubbing at Canal Electric Company, Sandwich,
Massachusetts; Olin Corp. (sulfuric acid plant) in Baltimore,
Maryland; and Cleveland Electrical Illuminating Company
in Cleveland, Ohio. Most of these pilot plants processed
about 1500 cfm of gas or 0.50-0.75 megawatt equivalent.
Chemico-Basic has made tests on both oil- and coal-fired
systems; on coal systems, fly ash is either removed before
S02 scrubbing or a special single scrubber technique is
used. Almost all of Chemico-Basic's work has been with
venturi type scrubbers; some of the results will be presented
in the Equipment Selection and Description section.
Patents issued to I. S. Shah (79) generally cover the
Chemico-Basic process and technology.
Recently, the Babcock and Wilcox Company entered the
market for complete power plant systems for S02 removal,
based on their extensive background in magnesium sulfite
pulping and chemical recovery. For many years B and W
scientists and engineers have been involved with research
and development in this area and have published consider-
able chemical and physical data on magnesium sulfite,
bisulfite, and sulfate solutions, including vapor pressure and
solubility relationships as a function of temperature and
solution composition.
One of the more important contributions of the
Babcock and Wilcox Company in this field is the magnesia
slurry scrubbing study (27) completed in 1970 for the
Office of Research and Monitoring of the Environmental
Protection Agency (formerly the National Air Pollution
Control Administration). In a study carried out in a pilot
plant (2000 acfm) at the Alliance, Ohio, Research Center,
data were obtained on both particulate and S02 scrubbing
in a venturi type scrubber and S02 removal in a mobile bed
scrubber (termed Floating Bed Absorber). Tests were made
of the effect of S02 removal on liquid-gas ratio, pressure
drop, slurry composition (including pH and sulfate con-
centration), stoichiometry, fly ash, preslaking of MgO, and
scrubber liquid residence time. In addition, evaluations
were made of the scaling problem, S03 formation in the
coal burners, and NOX removal. Although the early 1970
results for NOX removal were inconclusive for the most
part, the particulate and S02 removal data can be used for
the design of power plant scrubber systems; a considerable
part of this will be presented in the Equipment Selection
and Description section of this report. As stated earlier, a
new research project has recently (1972) been completed
on NOX removal and the preliminary results (26) will be
discussed in a later section.
Because of the advanced development of the magnesia
process, it has been selected by the EPA as one of the more
promising S02 control processes ready for demonstration
in a commercial size installation. In July 1970, EPA, an
electric utility company (Boston Edison), a design engi-
neering firm (Chemico-Basic), and one chemical company
(Essex Chemicals) combined as a group to fund, design,
build, and operate a magnesia scrubbing system at Boston
Edison's Mystic Station No. 6, a 155-mw steam generating
unit located in Everett, Massachusetts. The station, an
oil-fired facility, will be equipped with a venturi scrubber
system to remove S02 from the stack gases. An artist's
concept of the installation is shown in figure 4. The
magnesium sulfite slurry formed will be dewatered and
dried and the crystals will be shipped to an existing sulfuric
acid plant owned by Essex Chemical Corporation
located at Rumford, Rhode Island. There the material will
be calcined to release S02 for the 98% acid unit and the
resultant magnesium oxide will be shipped back to the
power plant.
Funding for the project will be approximately $5
million, with Boston Edison paying about half and EPA the
remainder. Financial support will also be provided by the
Eastern Utilities Associates, the New England Gas and
Electric Association, and Montaup Electric.
According to Chemico-Basic, the project will take 15
months to build, with operation planned for 1 or 2 years.
The system started up in early 1972.
During the 2-year period, a program will be undertaken
to test various operating parameters, optimize emission
control under a power plant operating cycle, demonstrate
reliability, and accurately define system operating cost. At
the end of the test and evaluation program, a report will be
prepared presenting the results.
A second system utilizing magnesia slurry scrubbing was
recently announced by Potomac Electric Power Company
for their Dickerson, Maryland station. Unit No. 3. Half of a
195-mw coal-fired unit will be equipped with a 2-stage
venturi scrubber system to remove both particulates and
S02 . Particulate removal is expected to exceed 99%, and
SO2 removal will be 90% plus.
Approximately 250,000 actual cubic ft/minute of stack
gas (at 259 °F) will be scrubbed in a single train with the
other half of the gas being passed through an existing
precipitator for dust removal prior to remixing with the
scrubbed gas.
The magnesium sulfite from the SO2 scrubber will be
dewatered, dried, and then shipped to the Essex Chemical's
sulfuric acid plant in Rhode Island for processing in the
EPA unit associated with the Boston Edison project.
Potomac Electric Power Company will fund the scrubbing
portion of the system and Chemico will design and build it.
At this time, there are several potential applications of
magnesia scrubbing in the offing, however, most have not
been announced publicly. Perhaps final decisions are
pending further on-site plant development test results. It
can be stated that Grillo is currently evaluating a system for
a process heat boiler at a German oil refinery. The
installation is reportedly sized at about 100,000 NM3/hr
(59,000 cfm).
13
-------
Figure 4. 150-mw prototype MgO-SO2, recovery scrubbing system at Boston Edison Co.-Mystic No. 6, Boston, Mass.
14
-------
PROCESS VARIATIONS
In the development of the magnesia scrubbing-regeneration
concept both process and equipment variations have been
pursued. Such process variations as raw material used or
process chemistry utilized; slurry, solution or solids
scrubbing of gases; and the choice of sulfur dioxide removal
with or without nitrogen oxide control are considered in
this section. Differences attributable to equipment alterna-
tives such as scrubber selection, slurry dewatering devices,
dryer and calciner design and type of sulfuric acid plant
(wet gas or dry gas) are considered separately in a later
section. Other variations possible with the magnesia
scrubbing-regeneration process are the choice of product-
sulfuric acid, liquid sulfur dioxide, elemental sulfur, or a
related fertilizer—and physical location of facilities (on-site
production vs off-site, centralized regeneration-acid manu-
facture); however, for most of the process schemes studied,
these will be considered as economic choices rather than
technological variations. Sulfur dioxide (relatively
concentrated at 14-16%) is evolved from the loaded
absorbent in almost all the schemes and can be further
processed to any of these products at the same or different
sites as the scrubbing operation. An exception, which will
be covered in this section, is the possible direct reduction of
magnesium sulfite-sulfate to produce elemental sulfur in the
calcination step.
The Magnesia Slurry Process
The magnesia scrubbing-regeneration process on which
most attention is being focused provides for aqueous slurry
scrubbing of sulfur dioxide with a mixture of reacted,
undissolved magnesium sulfite, dissolved sulfite-sulfate, and
unreacted magnesium hydroxide. The process is shown in
figure 5 as used by Chemico-Basic in the first commercial
demonstration unit at Boston Edison's Mystic Station. With
the exception of equipment choices, the Russian process
(see figure 2, History and Status section) and the Japanese
(Kawasaki) process appear to be very similar.
In the slurry process, fly ash from coal-fired systems is
first removed in a particulate scrubber along with some of
the SO3 in the stack gas. The ash-water mixture is
thickened, with the underflow sent to a pond for neutrali-
zation, if required, and settling; the clarified pond water is
returned to the particulate scrubber for reuse. For oil-fired
systems, the particulate scrubber is not required, since the
amount of ash in the stack gas is less than the proposed
emission standard.
To remove S02, the humidified and relatively dust-free
gas is scrubbed in a second device with circulating MgS03-
MgO base slurry having a pH between 6.5-8.5, capable of
S02 removal of better than 90%. Crystals of hydrated
MgSO3, plus MgS04 formed by oxidation, are withdrawn
in a side stream (10-15% solids) to a dewatering system
consisting of one or more items of equipment such as a
hydroclone, screen, thickener, or filter; clarified liquor is
returned to the scrubber. At this point in the process, any
contaminants accumulated over a period of continuous
MgO recycle can be removed. After further dewatering in a
centrifuge, the crystals are fed to a dryer for dehydration.
Dryer off gas can be used to partially reheat the main stack
gas stream.
Dried MgS03-MgS04 is next fed to a calciner, where
coke/carbon is introduced to reduce the sulfates and the
mixture calcined at 1400-1600° F to evolve S02 and
regenerate MgO for recycle to the scrubber system. The
calciner exit gas usually contains 10-16% S02 by volume
depending on heat losses, the amount of coke added for
MgSO4 reduction, and the provision for exhaust heat
utilization (feed preheat). Dust in the SO2 offgas is
removed by precipitator, bag filter, or wet scrubber and
returned to the system; the cleaned S02 laden gas is then
processed into sulfuric acid, liquified S02, or elemental
sulfur.
The Grillo Variation
In a variation of the basic magnesia slurry process,
Grillo-Werke AG, a German company, has developed a
slurry scrubbing system that utilizes manganese oxides in
magnesia scrubbing slurry. Although the process was
developed on an oil-fired system, the addition of a
particulate scrubber should permit adaptation to coal-fired
stack gas. Grillo also utilizes two- naturally occurring
minerals, kieserite (magnesium sulfate monohydrate) and
pyrolusite (87% manganese dioxide); however, magnesium
oxide could be substituted for the kieserite.
A generalized flow diagram as originally pjoposed by
Grillo. is shown in figure 3, History and Status section.
Absorption of S02 is carried out in a cocurrent or
countercurrent spray scrubber having a gas velocity of
15
-------
To stack
Water
Stack _
gas
I
Particulate
removal
system
Thickener
Ash to pond
Recycled pond water
Sulfur dioxide
absorber
Slurry ^
i;
Dewatering
system
Liquor
Dryer
MgSO3
Water MgO
LL
Makeup system
Coke-
Recycle MgO
Sulfuric acid
plant and/or
liquified SO2
and/or sulfur
SO,
Calciner
Air
Fuel
Figure 5. Magnesia slurry scrubbing-regeneration process as developed by Chemico-Basic.
about 10-18 meters/second (33-60 ft/sec) with a residence
time of 0.5-1.0 second. A circulated slurry composition of
3-6 moles of MgO/mole of Mn02 with a pH of 6.0-7.5 is
used. The manganese dioxide is said to allow use of smaller
scrubbers with a low L/G (approximately 6 gals/Macf) and
a high slurry solids concentration (30-70%). Furthermore,
the manganese compounds are reported to promote calcina-
tion of MgS04 without carbon addition at a temperature of
1800°F. The manganese oxides have been known, however,
to promote oxidation in some scrubbing systems and,
therefore, might increase MgSO4 formation. Another pro-
blem arises from the large amount of inert material that
enters the process from the pyrolusite and kieserite makeup
and must be removed from the system to prevent buildup
to intolerable levels. This problem would be reduced if
refined MgO and Mn02 were used as raw materials.
In general, most of the process equipment for a system
similar to that developed by Grillo could be the same as for
the basic slurry process. The only apparent differences
occur in the scrubber-mist eliminator design, the calcination
operation, and possibly in a decontamination system which
might need to be larger.
The Clear Liquor Process
Another process alteration, one investigated by Chemico-
Basic and possibly others, is the "clear liquor process" in
which an acidic solution of soluble magnesium bisulfite,
sulfite, and sulfate is used to scrub SO2 from the stack gas.
A possible use of such a process would be in coal-fired
systems where only one scrubber removes both the par-
ticulate and S02 removal. A flow sheet of the process is
shown in figure 6.
A clear solution is used so that the ash can be filtered
out; however, a lower pH (less than 6.0) is required in order
to get high enough solubility to keep the sulfite formed in
solution. It should be mentioned that the low pH will result
in greater bisulfite formation thereby increasing the vapor
pressure of the scrubbing solution and restricting efficiency
to less than that possible with the slurry process.
A "clear liquor process" also requires a separate step
for sulfite precipitation which, after ash removal, is
accomplished in a reaction tank by the addition of
MgO or Mg(OH)2. A pH change occurs in which the
bisulfite is converted to sulfite, causing MgSO3-6H2O
to crystallize from the liquor. The liquor is returned
to the scrubber system and the MgS03-6H20 crystals
are processed as in the basic slurry system-that is,
dewatered, dried, and calcined to evolve S02 and re-
generate MgO for recycle. In addition to the lower SO2
removal efficiency, the greater likelihood of fly ash
solubilization could increase process contamination.
Despite these drawbacks, the process may have
application on power units having limited space and,
16
-------
To stack
1
Stack
gas
Particulate and
SO2 scrubber
Water
MgO
Thickener
Water
i
Slurry
Fly ash filter
and wash
T
i :
Makeup system
Liquor
MgO
Sulfuric acid
plant and/or
liquified SO,
and/or sulfur
SO,
Calciner
Coke
4
Air
Fuel
MgO
Reactor
I
Slurry
Dewater
Liquor
To pond
Air
Fuel
Dryer
MgS03
Figure 6. Clear liquor variation of magnesia scrubbing-regeneration process.
therefore, will be given full economic evaluation later
in this report.
The Showa Denko Process
As mentioned earlier, sorption of S02 by finely divided
MgO (dry system) has been tested in Japan by Showa
Denko. A flowsheet is shown in figure 7. MgO is circulated
through an adsorption tower until a portion is converted to
MgSOs and MgSO4. A side stream is withdrawn and
calcined with the resultant S02, MgO, and undecomposed
sulfites and sulfates flowing to a dust collector where the
solids are separated and recycled to the absorber; the S02 is
then processed as desired. In bench scale tests sulfur
dioxide removal has been reported as near 80%.
This process has several advantages, including:
1. No need for stack gas reheat.
2. No energy required for drying free or hydration
water from MgSO3.
3. Reduced corrosion and erosion.
Offsetting problems include:
1. Difficulty in getting complete dust removal from the
absorber exhaust precipitator because of the high resistivity
of the magnesium solids.
2. High internal recycle required.
3. Loss of absorbent efficiency over extended cycles of
sorption and regeneration.
4. A need for an impurities purge to prevent intolerable
buildup of inerts and contaminants.
The process is in such a preliminary stage of develop-
ment, as compared to the aqueous scrubbing techniques
already described, that it is not given serious consideration
in this report. If progress is continued on the development
of a dry process, it may be worthwhile to study such a
concept separately.
NOX Removal Process
Use of magnesia scrubbing for NOX control has been
described in the Esso Research and Engineering Study for
EPA, "Systems Study of Nitrogen Oxide Control Methods
for Stationary Sources" (3), and the Babcock and Wilcox-
EPA study of scrubbers for S02 removal by the magnesia
process (27). This process utilizes magnesium sulfite slurry
scrubbing for S02 removal and magnesium hydroxide for
NOX absorption. A generalized flow diagram is shown in
figure 8.
17
-------
•*• To stack
Stack.
gas
Electrostatic
precipitator
Dust
Figure 7. Showa Denko dry MgO process for SO2 removal.
The sulfur oxides removal system must precede the NOX
removal section for the process to function. For best
results, the NOX system requires the recycle of nitrogen
dioxide to obtain an equimolar mixture of N02 and NO,
forming N203 which can be absorbed more effectively than
either NO or N02 alone. The recycle of N02, however,
would oxidize S02 in the gas to S03 as in equation 1
resulting in sulfate formation and little NOX removal.
N02 + S02 -» S03 + NO
(1)
When most of the S02 is removed prior to addition of
N02, however, the process might work as outlined in
equations 2 and 3.
Mg(OH)2 + N203 -» Mg(N02)2 + H20
3Mg(N02)2 + heat + 2H20 + pressure ->
Mg(N03)2 + 2Mg(OH)2 + 4NO
(2)
(3)
The NO would be oxidized and recycled to the absorber
and the magnesium nitrate ammonia ted to yield ammonium
nitrate.
Mg(N03)2 + 2NH3 + 2H
2NH4N03 + Mg(OH)2
(4)
The ammonium nitrate is a salable fertilizer product, and
the insoluble magnesium hydroxide could be recycled to
the scrubber system.
So far, this procedure can not be considered seriously
since preliminary test results from the 1972 EPA-Babcock
and Wilcox program (26) were discouraging; however, the
chemistry of this procedure will be given further treatment
in the Process Chemistry, Properties and Kinetics section of
this report.
Direct Sulfur Production in the Calciner
It is known that several investigators are currently working
on a magnesium sulfite calcination step which would yield
sulfur directly instead of S02. As will be shown in the
section on Process Chemistry, Properties and Kinetics,
Sillen and Andersson (81), two Swedish researchers, pre-
dicted that it is possible to get H2S and MgO in a cal'ciner
by operating under strongly reducing conditions at lower
temperatures. It is conceivable that elemental sulfur could
be made in the calciner under some condition; however, in
view of the relatively low concentration of SO2 (10-15%)
produced with direct calcination, the procedure could be
difficult. A possible process might be developed using an
indirectly heated calciner, an inert gas sweep, and operating
at a temperature in which sulfate, thiosulfate, and MgO
could be produced. The thiosulfate might be decomposed
to magnesium sulfate and elemental sulfur and the two
products separated.
18
-------
To stack
Stack _
gas
Recycle
water
from
pond
Water
i
Participate
removal
system
Thickener
I
Ash to pond
1
i
Sulfuric acid
and/or
liquified SO2
and/or sulfur
1
NOX absorption
system
Makeup
Mg(OH)2
MgS04
Mg(N02 )2
i r
Slaked
lime
Sulfate removal
system
Mg(OH)2
CaS04
Mg(N02)
Nitration reactor
SO
Mg(N03)2
Mg(OH)2
i r
NH3
Ammoniator
I
Mg(OH)2
Figure 8. Magnesia process for removal of both sulfur and nitrogen oxides from stack gas.
As is apparent, the scheme is in need of a great deal of
research and, hopefully, additional work will be done;
however, it is much too early to attempt process definition
and the idea does not merit complete evaluation at this
time.
A more practical scheme for sulfur manufacture has
been developed by Allied Chemical (99) in which low
concentration SO2 from calcination can be reduced to
elemental sulfur. This process should not be considered as a
technological variation of magnesia scrubbing but, as stated
earlier, an economic variation since many processes
producing S02 could utilize the development. Chemistry of
the Allied Chemical S02 reduction process will be discussed
further in the section to follow.
19
-------
PROCESS CHEMISTRY, PROPERTIES AND KINETICS
Some of the first chemical and physical data applicable to
the magnesia process comes from the pulp and paper
industry, which has long used sulfite pulping with subse-
quent S02 recovery. Because of the nature of the pulping
operation, much of this information applies to magnesium
sulfite-bisulfite solutions and is, therefore, more related to
the clear liquor process than the slurry process.
Soviet workers, represented principally by B. A.
Chertkov and V. A. Pinaev, have made large contributions
to ammonia, limestone, and magnesia scrubbing of S02 at
smelter and power plants. As early as 1940 (68), Peisakhov
and Chertkov considered the use of magnesia scrubbing at
the Moscow and Leningrad power plants. Japanese workers
have studied the physcial properties of MgS03 and are now
showing interest in the magnesia process. Johnstone at the
University of Illinois worked on all phases of S02 scrubbing
with ammonia and some of his results are applicable to the
magnesia system. More recently, Shah (79), Markant (63,
64), Downs, and Kubasco (26, 27) have made substantial
contributions to our understanding of the magnesia process.
There are three series of reactions which occur in the
magnesia scrubbing-regeneration process. In the first series,
the scrubbing step,the following reactions predominate:
Sulfur dioxide absorption, represented by the reactions:
5H20 + Mg(OH)2+S02 -> MgS03-6H20 4- (5)
SO2 + MgSO3-6H2O -> Mg(HS03)2 + 5H20 (6)
Bisulfite neutralization, represented by the reaction:
Mg(HS03)2 +MgO+ 11H20 -+2MgS03-6H20 4. (7)
Magnesium sulfite oxidation, represented by the
reaction:
MgS03-3H20 -» MgS03 + 3H20 t
or
MgS03-6H20-» MgS03 + 6H2Ot
A and
MgS04-7H20-+ MgS04 + 7H2Ot
(9)
(10)
(11)
The dry crystals are calcined at 800 to 1100° C in the
presence of coke to regenerate MgO and S02 . The reactions
occurring in the calciner are:
C + i/202 -> CO
CO + MgS04 -> C02 + MgO + S02 t
MgS03 -> MgO + S02 t
(12)
(13)
(14)
The magnesium oxide is cycled back to the scrubber system
and the sulfur dioxide is sent to a sulfuric acid plant.
The physcial properties of process compounds, chemical
equilibria, kinetics, and mass transfer involved in the
magnesia process have been studied and are covered in the
following discussion. It will be evident that there are areas
of disagreement and incomplete understanding. Of par-
ticular need for further research are impurity buildup and
fly ash leaching, sulfite oxidation, and crystal growth or
scaling in the scrubber systems.
Physical Properties of Process Compounds and Solutions
The nature of the process under consideration will, in part,
depend on the physcial and chemical properties of process
compounds and solutions. For that reason, some of the
physcial properties, optical properties, solubility data and,
where important, information on chemical reactivity are
given below.
2MgS03 + 02 -> 2MgS04
(8)
Magnesium sulfite hexahydrate crystals are removed
from the scrubbing system and either sent directly to a
dryer or thermally converted to MgS03-3H20 and then
dried. It is possible that some MgS04-7H20 and perhaps
MgS04-6H20 will also be occluded in the MgS03-6H20.
The chemical reactions which occur in the dryer are:
Solubility of Magnesium Sulfate and Magnesium Sulfite
Solubility of magnesium sulfate in water—At least four
hydrates-of magnesium sulfate exist between 0 and 100° C:
MgS04-7H20, MgS04-6H20, MgS04-5(or 4)H20, and
MgS04-H20 (59). The solubility relationships are further
complicated by the great range of metastability of
MgS04-6H2O and MgS04-5(4?)H20.
20
-------
The ^compilation of solubility information, between 0
and 60° C, found in Link's book (59) is shown in figure 9.
The transition temperature between MgS04-7H20 and
MgS04-6H20 occurs at 48° C (118° F) and; therefore, it is
possible that both phases may be present in process slurries.
Solubility of magnesium sulflte in water-At least three
sources of magnesium sulfite solubility data exist (59, 64,
69), but all three data sets are in fair agreement. These are
presented in figure 10. It is generally agreed that at least
two hydrates exist, MgSO3-6H20 and MgS03-3H2O. In
addition, Markant et al (64) claim evidence for two other
unstable hydrates of unknown composition.
The temperature of transition between MgS03-6H2O
and MgS03-3H20 is variously quoted as being 40° C.
However, the slow rate of conversion at this temperature
could make true equilibrium difficult to attain. For this
reason the quoted value of 40° C may be questionable.
Hatfield (42), on the basis of solubility product calcula-
tions, also questions the value of the transition temperature
as well as the composition of the solid which Hagisawa (38)
claimed to be MgS03-3H20. By using published thermo-
dynamic stability constants (60) for H2S03, HS03;
MgOH+, and MgS03, Hatfield is able to show that the
solubility product of Mg(OH)2 is exceeded when
Hagisawa's MgS03-3H20 solubility data is used. Between
42 and 50° C, Hagisawa's solutions are supersaturated with
Mg(OH)2 by about 15%. With increasing temperature the
apparent degree of supersaturation increases until the
solution is 100% supersaturated at 85° C; i.e., the calcu-
lated Mg(OH)2 solubility product is half the observed value.
Such supersaturation is perhaps unreasonable, and a more
reasonable explanation for these disparate results is that
Hagisawa's MgS03-3H2O is, in fact, a mixed hydroxisulfite
of some type.
It is known that MgS03-6H2O precipitates in the sulfur
dioxide scrubber section even when the solution tempera-
ture exceeds 50° C. There are at least two possible
explanations for this:
1. Because there is a solid phase of MgO-Mg(OH)2 in the
scrubber, the stable phase on the surface of a MgO particle
maybeMgS03-6H2O.
2. The stable phase at operating temperature is
MgS03-6H2O and the temperature of transition exceeds
50° C.
Solubility ofMgSO3 inMgSO4 solution-Because oxida-
tion of sulfite can occur in the scrubber, substantial
amounts of MgS04 might be present in process solutions;
therefore, the influence of magnesium sulfate on mag-
nesium sulfite solubility, vapor pressure, and other solution
characteristics should be considered.
Pinaev (69) has shown that MgSG4 alters the solubility
of magnesium sulfite in a somewhat unusual manner. His
solubility data between 0 g/1. and 200 g/1. MgS04 are
shown in figure 11.
If only the common ion effect were predominant,
increased MgS04 concentration would be expected to
depress the MgS03 solubility; but up to 200 g/1. MgS04,
MgS03 solubility actually increases. To explain the
increased MgS03 solubility, Pinaev suggests the formation
40
8
^
30
20
I
20
30
40
Temperature, °C
50
60
Figure 9. Effect of temperature on magnesium
sulfate solubility (59).
1.75
1.50
fr
2
I >-25
*2
G
1
£
1 1.0
.75
.50
O Link
A Pinaev
D Markant, et al
MgSO3 -6H2 O (Metastable)
MgSO3-3H2O(Metas table)
MgSO3-6HjO (Stable)
20
30
40 50
Temperature, °C
60
70
Figure 10. Effect of temperature on magnesium
sulfite solubility (59) (64) (69).
21
-------
of one or more complex ions. The known
decrease in the activity coefficient of
Mg++ with increased ionic strength will
also account for the increased MgS03
solubility.
In pilot plant work (12), MgS04 con-
centration ranged from 17 g/1. to about
120 g/1. in the MgS03 slurry. Thus,
actual MgS03 solubility at 50° C, for
example, could be as much as 75% higher
than the solubility of MgSO3 in water,
which is about 13 g/1.
Optical Properties and Specific
Gravity of Solid Materials
Given below are the specific gravity,
crystal lattice, crystal habit, and refrac-
tive indices of solid compounds
encountered in the process. Unless noted,
refractive indices refer to those measured
in visible light.
Magnesium sulfate heptahydmte,
MgSO4-7H2O fP<5y-Magnesium sulfate
heptahydrate is described as ortho-
rhombic with a = 11.94, b = 12.03, and c
= 6.87. The crystals are usually prismatic
and often fibrous. Refractive indices in
sodium light are nx = 1.432, ny = 1.455,
and nz = 1.461. Specific gravity is 1.677.
Magnesium sulfate hexahydrate,
MgSO4-6H^O (96)-ThJs compound is
monoclinic with a = 10.04, b = 7.15, and
c = 24.34 kX. The crystals are described
as thick, basal, tablets, or prismatic. nx =
1.426, ny = 1.453, and nz = 1.456.
Specific gravity is 1.75.
Magnesium oxide, MgO (96)- u
Magnesium oxide is isometric with the
sodium chloride space lattice a = 4.203
kX. The crystals are either cubic or
octahedral. The refractive index in
sodium D light is 1.7366. Specific gravity
is 3.56.
Magnesium hydroxide, Mg(OH)2 (96)-Magnesium
hydroxide is hexagonal with a = 3.12 and c = 4.75 kX.
Crystals are described as basal plates with perfect cleavage.
Specific gravity = 2.39 n0 = 1.566 and ne = 1.585.
Magnesium sulflte hexahydrate, MgS03-6H20 (96)-
Magnesium sulfite hexahydrate is hexagonal with a = 8.82
and c = 9.04 kX n0 = 1.524 and ne = 1.474 in blue mercury
light. The specific gravity is 1.73. As shown in figure 12 at
200X, the crystals appear as hemimorphic trigional
pyramids. This photomicrograph and the subsequent
50 100 150 200
Magnesium sulfate concentration, g/1
Figure 11. Effect of magnesium sulfate on
magnesium sulfite solubility (69).
photographs were made with a scanning electron
microscope.
Magnesium sulfite trihydrate, MgSO3-3H2O-As shown
in figure 13, at 2000X, magnesium sulfite trihydrate
apparently occurs as platy prismatic pyramids. The cal-
culated specific gravity is 2.13, somewhat higher than the
density of the hexahydrate (43). nx = 1.552, ny = 1.555,
and nz = 1.595. In general, MgS03 -6H20 crystals are much
larger and better formed than MgS03-3H20 crystals. A
comparison between figure 12 and figure 14, both at 200X,
22
-------
Figure 12. Photomicrograph of magnesium sulfite hexahydrate-200 X.
-------
* I t
Figure 1 3. Photomicrograph of magnesium sulfite trihydrate—2000 X.
24
-------
Figure 14. Photomicrograph of magnesium sulfite trihydrate—200 X.
25
-------
emphasizes the great size difference between MgS04-6H20
and MgS04-3H20, about 10:1.
viscosity is 1.23, thus, slurry viscosities could be expected
to exceed solution viscosities by about 23%.
Density and Viscosity of Magnesium Sulfite-
Magnesium Bisulfite-Magnesium Sulfate Solutions
Pinaev (70) has measured the viscosity and density of
magnesium sulfite-bisulfite-sulfate solutions between 30
and 60° C. The data were fitted to the equations shown
below by linear regression analysis.
P =A0 +A1[MgS04J +A2[Mg(HS03)2] +A3T +
A12[MgS04] [Mg(HS03)2] +A13[MgS04]T +
A23[Mg(HS03)2]T + A4[MgS03] (15)
f =B0 +B1[MgS04] +B2[Mg(HS03)2] +B3T +
B12[MgS04] [Mg(HS03)2] +B13[MgS04]T +
B23[Mg(HS03)2]T + B4[MgS03] +
B44[MgS03P
(16)
Where A0, A1; A2, A3, A12, A13, A23, A4, B0, B1; B2,
B3, B12, Bi3, B23, B4, and B44 are constants; MgS03,
Mg(HS03)2, MgS04, and T represent molar concentrations
and temperature in °C; and p and f are density in g/ml
and viscosity in cp. The correlation coefficients and
standard errors for equations 15 and 16 are, respectively,
0.9981 and 0.0016 g/ml and 0.9898 and 0.049 cp.
These equations were used to calculate the viscosity and
density information found in table 1. The MgS03 con-
centration was held constant in the scrubber solution since
it does not vary appreciably.
It has long been known that the viscosity of a disperse
system, consisting of a suspension of solid particles in a
dispersing liquid, has a higher viscosity than the dispersing
liquid alone. Kurgaev (56) has expanded the work of A.
Einstein and others to develop the equation, shown below,
which relates suspension viscosity, juc to solution viscosity,
Mo-
= Mr
2C
1 +
(1-1.2C2/3)
(17)
In this equation, C is the volume ratio of dispersed phase
particles to dispersing phase volume. In table 2, values of
H c/n 0 are shown at several values of C.
The S02 scrubber system will have about 10 weight %
solids, tprimarily MgS03-6H20, which is equivalent to a
volume ratio of about 0.07. The ratio of slurry to solution
Table 2. Variation of slurry/solution
viscosity ratio with solid/liquid ratio.
MC/MO
C = 0.05
1.14
C = 0.10 C = 0.15
1.36 1.68
C = 0.20
2.12
C = 0.25
2.85
26
Vapor Pressure of Sulfur Dioxide Over
MgS03-Mg(HS03)2-MgS04
Because scrubbing efficiency is directly related to the
difference between the partial pressure of S02 in the stack
gas and the sulfur dioxide vapor pressure over the scrubbing
solution, the dependence of vapor pressure on scrubber
solution composition is quite important. Kuzminykh and
Babushkina (57) determined vapor pressures over MgS04-
MgS03-Mg(HS03)2 slurries of various compositions
between 10 and 70° C. Their results are in good agreement
with Hagisawa (39) 'and Yakimets (100), but differ
considerably from Conrad and Brice (23).
Pinaev (71) has also measured S02 vapor pressure over
MgS03-MgS04 slurries, but because his vapor pressure
measurements are much lower than other workers, they are
considered questionable.
Since pH and solution composition can be related easily
Chertkov (15) reworked the data of Kuzminykh and
Babushkina to point out the relationship between vapor
pressure and pH. Results of these calculations, shown in
figure 15, show the increase in S02 vapor pressure that
occurs with decreased pH and increased MgSO4. Similar
results were found in the ammonia system (16). The effect
of MgSO4 on S02 vapor pressure is most important at
lower pH.
Markant et al (63) measured S02 vapor pressure over
magnesium sulfite-bisulfite solutions (not slurries) at two
levels of total dissolved S02 , 4.44% and 6.16%, and three
temperatures, 100, 120, and 140° F. Results are given in
figures 16 and 17.
Because of the high bisulfite to sulfite ratio, the pH of
these solutions will be rather low; therefore, the data would
be more applicable to a clear liquor process than a slurry
process.
At constant total dissolved S02 , vapor pressure increases
with decreasing MgS03 concentration or increasing bisulfite
concentration. There is a substantial increase in S02 vapor
pressure with temperature, and as pointed out in a later
section, this could adversely affect the mass transfer
coefficient.
Chemistry
Slaking o/Afg-0-Smithson and Bakhshi (85), who studied
the slaking characteristics of MgO, believe two surface
chemical reactions occur when MgO reacts with water
and goes into solution.
MgO + H20 -> Mg(OH)2
Mg(OH)2 -» Mg++ + 20H-
(18)
(19)
-------
Table 1. Viscosity and density of magnesium sulfite-bisulfite-sulfate solutions
Temperature C
40
40
40
40
40
40
40
40
40
40
40
40
40
40
40
50
50
50
50
50
50
50
50
50
50
50
50
50
50
50
60
60
60
60
60
60
60
60
60
60
60
60
60
60
60
MgS04,g/l
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
24.9960
49.9920
74.9880
99.9840
124.9800
Mg(HS03)2,g/l
5.0034
5.0034
5.0034
5.0034
5.0034
24.9984
24.9984
24.9984
24.9984
24.9984
44.9934
44.9934
44.9934
44.9934
44.9934
5.0034
5.0034
5.0034
5.0034
5.0034
24.9984
24.9984
24.9984
24.9984
24.9984
44.9934
44.9934
44.9934
44.9934
44.9934
5.0034
5.0034
5.0034
5.0034
5.0034
24.9984
24.9984
24.9984
24.9984
24.9984
44.9934
44.9934
44.9934
44.9934
44.9934
MgS03,g/l
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
5.0024
Density, g/ml
1.0072
1.0361
1.0650
1.0939
1.1227
1.0164
1.0467
1.0771
1.1074
1.1378
1.0255
1.0574
1.0892
1.1210
1.1529
1.0008
1.0300
1.0592
1.0884
1.1176
1.0099
1 .0406
1.0712
1.1019
1.1325
1.0190
1.0511
1.0832
1.1154
1.1475
0.9945
1.0239
1.0534
1.0829
1.1124
1.0034
1.0344
1.0653
1.0963
1.1272
1.0124
1.0448
1.0773
1.1097
1.1421
Viscosity, cp
1 .0405
1.2543
1.4681
1.6819
1.8958
1.0710
1.3050
1.5389
1.7729
2.0069
1.1015
1.3556
1.6098
1.8639
2.1180
0.8597
1.0305
1.2013
1.3721
1.5429
0.8838
•1 .0747
1.2657
1.4566
1 .6476
0.9078
1.1189
1.3301
1.5412
1.7523
0.6789
0.8066
0.9344
1 .0622
1.1899
0.6965
0.8445
0.9924
1.1403
1.2882
0.7142
0.8823
1.0504
1.2184
1.3865
27
-------
28
o ~2-15%MgSO4
o without MgS04
= 48°C-500C(118°F 122" F)
Figure 15. Effect of MgSO4 and pH on sulfur dioxide vapor pressure over magnesium sulfite slurry (15).
20
10
8.0
^6.0
6
E
£4.0
3.0
o
CL,
> 2.0
-------
Because of the high concentration of MgO and water at the
participate surface, formation of Mg(OH)2 should be much
more rapid than its subsequent dissolution; therefore,
Smithson and Bakhshi believe the second reaction is rate
controlling.
The dissolution rate of Mg(OH)2 and, hence, reactivity
will be proportional to surface area which in turn depends
on time and temperature of calcination of MgO. Calcination
temperatures for optimum reactivity and surface area may
vary from 400 to 1000° C, depending on the magnesium
compound being decomposed. MgO calcined at 1200° C is
called "hard burned" while that calcined above 1600° C is
called "dead burned." Both "hard burned" and "dead
burned" magnesium oxide may be quite unreactive.
As a result of pilot plant work, Downs and Kubasco (27)
and Grillo researchers feel that preslaking MgO is not
necessary. This could, however, depend on the properties or
source of the raw material. Pilot plant tests carried out by
Chemico-Basic at Cleveland Electrical Illuminating Com-
pany show that recycle MgO was as reactive as virgin MgO
(80). From this limited information, it appears that the
reactivity of recycled MgO is sufficiently high so that no
preslaking is necessary. This could change if MgO were
calcined for prolonged periods above 1200° C.
pH-Botti Pinaev (71) and Semishin et al (78) have
measured the pH of magnesium bisulfite solutions saturated
with magnesium sulfite in the presence of magnesium
sulfate. The data of Semishin et al was chosen for detailed
mathematical treatment because it covers solution pH
above 7.0, which is desirable in the magnesia slurry process.
However, with the exception of one datum point, the
agreement between the two data sets is good.
Semishin's data cover the pH range 3.82 to 8.70 between
25 and 70° C with 0 and 10% magnesium sulfate. The data
were fitted to the equation:
pH = b0 + b, (S/C) + b2 (S/C)2 + b3 (S/C)3
(20)
where S/C is the molar ratio of sulfur dioxide to active
magnesia and b0, bl5 b2, and b3 are constants. When the
data are represented in this form, temperature is not
statistically significant and does not explicitly appear in the
equation. It is important to understand that magnesium
concentration (C in equation 20) will vary with tempera-
ture for MgS03-Mg(HS03)2 slurries; therefore, temperature
dependence is indirectly included in the equation. The
equation does not reflect temperature variation in MgS03-
Mg(HS03)2 solutions where magnesium concentration is
not fixed; e.g., clear liquor solutions which are unsaturated
with respect to MgS03.
The standard error of equation 20 at 0%MgS04 was 0.1
pH unit and 0.4 pH unit at 10% MgS04. When plotted in
figure 18, the data clearly show the effect of dissolved
MgS04 on pH. The effect is particularly significant at the
== 6
1.4 1.6
S/C ratio
Figure 18. Effect of MgSO4 content and Mg(HSO3)2/
MgSO3 ratio on solution pH (78).
higher S/C ratios (lower pH) which will occur in the clear
liquor process.
Chertkov reports 8.3 as the pH of a saturated solution of
pure magnesium sulfite at 50° C, while Jordan (50) reports
8.8 as the pH of saturated MgS03 solution at 25° C.
Oxidation of magnesium sulfite to magnesium sulfate—
Because thermal decomposition of magnesium sulfate
requires higher temperature and more energy than decom-
position of magnesium sulfite, it is advantageous to retard
sulfite oxidation throughout the process. Johnstone (47)
showed that little sulfur dioxide is oxidized in the gas phase
by flue gas. Therefore, sulfite oxidation will be primarily
dependent on scrubbing solution characteristics such as
temperature, sulfite and bisulfite concentration, pH, and
oxygen mass transfer rate.
Downs and Kubasco (27) indicate that most of the
magnesium sulfate formed in mobile bed or venturi
scrubbers results from sulfite oxidation by oxygen absorbed
from flue gas rather than NOX, S03, or oxygen in makeup
water. The rate controlling step may be either oxygen
diffusion rate across the liquid film, or catalytic oxidation
of sulfite to sulfate. Downs and Kubasco, as well as Linek
and Mayrhoferova (58), feel that catalytic oxidation is rate
limiting.
As shown in figure 19, Chertkov (17), using packed
tower scrubbers with MgS03 as the absorbent, found that
29
-------
increasing salt concentration, primarily magnesium sulfate,
drastically reduced oxygen mass transfer coefficients and
presumably sulfite oxidation rates. He attributes this
decrease to increased solution desnity and viscosity. Opera-
tion at higher pH also reduced oxygen mass transfer
coefficients from 46 g/m2-hr atm at pH 5.5-5.7 to 19.5
g/m2—hr atm at pH 6.9. Figure 20 shows that magnesium
sulfite oxidation is more rapid at low pH (5.5-5.7) than at
high pH (6.9).
Chertkov (18) has developed the following empirical
equation to relate oxygen uptake to solution and process
parameters.
= 0.8 Q9-7 a (S/C)6
o2 = Tp
(21)
Q represents the liquid rate in M3/M2-hr, S/C is the
molar ratio of dissolved sulfur dioxide to magnesium, a is a
dimensionless temperature coefficient equal to t/50 where t
is the average centigrade solution temperature, and j and
p are, respectively, slurry viscosity and density. Go is in
g/M2-hr atm. Although strictly applicable to the pH range
4.0-6.2, the equation gives a general idea of trends in sulfite
oxidation above pH 6.2.
The equation predicts moderate increases in oxidation
rate with increasing temperature and decreasing slurry
viscosity and density; but variations in composition of the
sulfite-bisulfite solution, represented by S/C, will have a
decisive influence on oxidation rate, particularly in
moderately acid solutions. With decreasing acidity, the S/C
ratio approaches 1.0 and the influence of S/C becomes less
pronounced.
Chertkov points out that laboratory studies of oxidation
kinetics of sulfite-bisulfite are, in general, not confirmed
under pilot plant conditions. Ample evidence of this exists
in the magnesia system. For example, Winston et al (97)
claim that, in the presence of iron catalysts, maximum
oxidation rate occurs at pH 7, which corresponds to a S/C
ratio of 1.23. Winston also claims that in the absence of
catalyst the oxidation rate is almost independent of sulfite
or bisulfite concentration (S/C ratio). It is known that iron
will promote oxidation (47) but the claim that oxidation
rate is independent of solution composition is not
substantiated.
Kim (55), working with the analogous calcium system at
constant total sulfur, finds that oxidation rate decreases
with decreasing pH and, thus, would appear to disagree
with Chertkov. Kim's data are found in figure 21.
As shown in Schroeter's (76) monograph, Able, on the
basis of a plausible free radical reaction mechanism,
developed the following rate equation.
-d[S03
g[HSOa
= VH+
(22)
Oxidation rate will then depend on the ratio [HS03"] //H .
Results of a detailed study by Potts et al (73) have
resolved some of the apparent discrepancies between
laboratory and pilot plant studies. Using extended Debey-
Huckel equations to calculate hydrogen and bisulfite ion
activities in the system CaO-S02-H20, Potts et al show that
the ratio [HS03']// H+, and hence oxidation rate, may
either decrease or increase with pH changes depending on
whether the system is saturated or unsaturated with respect
to CaS03 -%H20. Decreasing pH strongly inhibits oxidation
rate in unsaturated solutions, but in saturated slurries,
oxidation rate increases with declining pH. Similar results
might be expected for the analogous MgO-SO2-H20
system.
Thus, the apparent disagreement between Chertkov and
Kim may be due to the use of different experimental
conditions. Oxidation rate should increase with decreasing
pH in MgO slurries as Chertkov found. But in the clear
liquor process with unsaturated solutions, decreasing pH
should inhibit the oxidation rate.
Air oxidation of sulfite is a light-sensitive chain reaction
(62) involving free radicals and, like many such reactions, is
accelerated by heavy metal cations and inhibited by free
radical scavengers. Inhibitors include phenols, hydro-
quinone, numerous alphatic alcohols, ketones, and esters.
As Johnstone (48) pointed out, flue gases contain such
inhibitors and, thus, will retard sulfite oxidation. Chertkov
(17) shows that as little as 0.001% p-aminophenol in the
scrubber solution can reduce the sulfite oxidation rate by
one-half.
Manvelyan et al (62) note that traces of nitrogen oxides
reduce the inhibitory action of p-phenylenediamine and
p-aminophenol. But, because Manvelyan does not state the
nitrogen oxide concentration used, it is difficult to estimate
the significance of NOX.
As early as 1931, Johnstone (48) pointed out that iron
and manganese catalyzed sulfite oxidation In the same
publication, he reported that copper ions inhibited sulfite
oxidation, but this has not been substantiated. Data by
Bottomley and Cullen (7) show the high catalytic activity
of manganese and copper ions. Linek and Mayrhoferova
(58) report that cobalt also shows strong catalytic activity.
Because of corrosion, these transition metal cations might
be expected to be present at trace concentration in process
solutions. Another source of iron is the presence of fly ash.
Downs and Kubasco reported that fly ash accelerated the
oxidation of magnesium sulfite in mobile bed and venturi
scrubbers. They tentatively attribute the increased
oxidation to iron in the fly ash.
Developers of the Grillo process cl,aim that manganese
ions significantly increase the efficiency and capacity of
magnesium sulfite scrubber solution to absorb S02. But in
view of the known catalytic activity of manganese,
additional sulfite oxidation might be expected.
30
-------
200
150
e
o
100
8
I 50
o
u
Packed tower scrubber
pH'5.7-6.2
Temperature 48° - 52° C
O
I
I
5 10 15 20
Salt concentration, weight %
Figure 19. Effect of salt concentration on oxygen absorption (17).
25
1.5
I
Packed tower scrubber
Temperature 48° C - 52°
MgSO4 18 weight %
0 Initial pH 5.5-5.7
A Initial pH 6.9
Time, hours
Figure 20. Effect of pH on air oxidation rate in magnesium sulfite-bisulfite solution (17).
31
-------
100
90!
80
70
60
50
40
^ 30
s
"3
20
c
|c
'3
Jlf
6-
4-
-i
Temperature - 50 C
0 pH-6~7
A pH-4
D pH-3
1.0
2.0 3.0 4.0
Time, hours
5.0
Figure 21. Effect of pH on calcium
sulfite oxidation rate (55).
Pinaev (72), in figure 22, shows that surface oxidation of
magnesium sulfite crystals is greatly reduced by intro-
duction of 0.001-0.005% p-phenylenediamine into the
crystal lattice. This could be an effective means of retarding
oxidation when magnesium sulfite crystals are stored or
shipped off-site for calcination and regeneration of MgO.
Especially during transit, surface oxidation of the crystals
could become excessive.
Slurry conversion of MgS03-6H2O to MgSO3-
3H2O—Prior to calcination, magnesium sulfite hydrate
should be dehydrated so that the minimum amount of
water will be driven off with S02 from the calciner.
Because less energy is required to dehydrate MgS03-3H20
than MgS03-6H20, the observation (33) that MgSO3'6H20
slurry converts to MgS03-3H20 at a reasonably low
temperature is quite significant.1 Because of the difference
in crystal size, MgS03-3H20 should be somewhat more
difficult to dewater; however, the difference in dewatering
probably will not negate the advantage of converting
MgS03-6H20 toMgS03-3H20 prior to drying.
Figure 23 shows the effect of temperature and slurry
concentration on the conversion rate. The percent degraded
material was estimated by petrographic analysis; therefore,
the results are somewhat imprecise. Nevertheless, two
trends are clearly evident:
1. The rate is temperature sensitive.
2. The conversion rate is significantly increased by
increasing the slurry concentration from 10 to 60% MgS03.
l Through private communication it is known that the Babcock
and Wilcox Company has done research on this conversion pro-
cedure, but their results are yet to be published. Peisakhov and
Chertkov (68) have also noted this phase transition.
10
•a
o
on
55
No inhibitor
0.005% p-phenylenediamine
10
Time, days
15
20
Figure 22. Effect of p-phenylenediamine and time
on oxidation of magnesium sulfite crystals
exposed to atmosphere (72).
O 70" C, 10% slurry
A 80° C, 60% slurry
P 80° C, 10% slurry
20 30
Time, minutes
Figure 23. Effect of temperature and slurry concentration
on conversion rate of MgSO3-6H2O to MgSO3-3H2O (33).
32
-------
For rapid conversion, a temperature near 80° C is desirable.
The dehydration product is quoted as degraded material
rather than MgS03-3H20 because a small amount of
unidentified material (<10%), possibly penta or
tetrahydrate, is always present with the trihydrate.
Thermal dehydration and calcination of magnesium
sulfite-In the proposed magnesia process, magnesium
sulfite hydrate crystals are first dewatered by mechanical
means and then thermally dehydrated before feeding to a
calciner. The dehydration characteristics of magnesium
sulfite hydrates were studied by Okabe and Hori (67) using
differential thermal analysis, X-ray analysis, and infrared
analysis. Although experimental conditions are not clearly
described, their results were obtained by heating the
samples in a closed tube. The authors claim that the first 3
water molecules of MgS03-6H2O are lost in two steps at 60
and 100° C. At 200° C, the last three water molecules are
lost to yield amorphous anhydrous MgS03 .
Results of recent dehydration experiments at TVA differ
from those of Okabe and Hori, but because the heated
samples were not sealed, the differences may be more
apparent than real. Using differential thermal analysis,
Jordan (51), see figure 24, shows that when laboratory
prepared MgSO3-6H20 is exposed to air and heated,
dehydration starts at about 100° C. Commercially available
MgS03-6H20, containing impurities believed by Jordan to
Commercial MgSO3-6H2O
with impurities
100
200 300
Temperature, °C
400
500
Figure 24. Differential thermogram of MgSO3-6H2O
and MgSO3-3H2O samples (51).
be lower hydrates, also begins dehydration at 100° C, but a
second endothermic decomposition begins at 270° C. When
laboratory prepared MgS03-3H20 was heated in air,
dehydration started at 160° C. It is interesting that an
exothermic decomposition or phase change occurs between
430 and 470° C, but no such exotherm was observed when
MgS03-6H20 was heated.
Results of other TVA work (43) tend to give similar
results. After heating MgS03-6H20 in a stream of argon for
18 hours at 104° C, Hatfield et al showed that 5.67 of the
6 moles of water were lost (95%). The same results were
obtained by heating MgS03-6H20 in air. X-ray analyses
showed only amorphous MgS03 and a small amount of
MgSO3-6H2O in the dehydration product. There was no
evidence for the formation of intermediate lower hydrates.
When MgS03-3H2O was heated in air for 16 hours at 140°
C, 2.3 moles (77%) of the 3 moles of water were lost.
The available evidence suggests that MgS03-6H20 is
almost completely dehydrated to amorphous MgSO3 in air
at 100° C. There is no evidence of partial dehydration to
MgS03-3H20. In all likelihood, the differences between
Okabe-Hori and TVA are due to different experimental
conditions used. Partial dehydration of MgS03-3H2O can
occur at 140° C, but complete, rapid dehydration would
require a much higher temperature.
Results of two separate investigations (32, 54) of MgS03
thermal decomposition between 300 and 600° C are
presented in figures 25 and 26. Data from the two sources
show reasonable agreement. Although each group of
workers proposes different decomposition mechanisms to
explain the decomposition products, both groups agree on
two points:
80
I
O Sulfur dioxide
A Magnesium sulfate
V Magnesium thiosulfate
— Q Sulfur
300
350
400
Temperature, °C
500
550
Figure 25. Effects of temperature on nature of MgSO3
decomposition products-one hour heating period (32).
33
-------
1. The primary sulfur-bearing decomposition products
above 500° C are S02, MgS04, and sulfur in decreasing
order of occurrence.
2. Even as low as 300° C some decomposition of
MgS03 occurs.
The latter is important because dryer offgas will be sent
directly to the stack with no provision for SO2 recovery.
Accidental overheating of the MgSO3 could result in some
S02 loss and sulfate formation.
Hatfield et al (44) have made a rather complete kinetic
study of MgS03 decomposition between 504 and 602° C,
and show the order of the decomposition as 3/2. The 3/2
order shows that the decomposition rate per unit volume is
higher initially than in the latter stages of decomposition,
which suggests that decomposition products interfere with
the decomposition reaction. The effects of time and
temperature on decomposition are found in figure 27.
Extrapolating to higher temperature shows that about eight
seconds are required for 99.9% decomposition at 1000° C.
This rapid decomposition suggests that thermodynamic
equilibrium will be approached at calciner operating condi-
tions and Gibbs Free Energy values may be used to
compute the composition of the reaction mass in the
calciner.
From standard enthalpy, entropy, and heat capacity
data, Whitney, Elias, and May (95) have compiled the
necessary thermodynamic information for the calculations.
Their data came primarily from the U. S. Bureau of
Standards. Logarithms of equilibrium constants for primary
reactions are presented in table 3 and figures 28 and 29.
Because free energy is an exact differential, it can be
added and subtracted to obtain free energy values for
supplementary reactions. Whitney used this technique to
calculate the equilibrium constants for the supplementary
reactions found in figures 28 and 29.
The formation of magnesium oxide and sulfur dioxide
appears to be favorable above 1000° C, but without
detailed calculations it is not possible to precisely
determine the composition of the solid and gas phases.
To circumvent this problem, Sillen and Andersson (81)
have reworked Whitney and May's data into what they call
logarithmic equilibria diagrams.2 These diagrams are in the
form of a plot of log PQ2 called rO, vs -log P where P
represents the partial pressure of any gas of interest over
the solid phase. Construction of these diagrams depends on
the following assumptions:
pH20+pH2 =
PH2S
PS02 + PS03
atm
Equations 23 and 24 approximate conditions at the
discharge point of the calciner. Since the partial pressure of
S02 at the discharge point is expected to be about 0.16
atm, equation 25 does not hold; therefore, Sillen and
Andersson's treatment should be applied to MgS03 calcina-
tion with caution. While the equilibrium diagrams are of
interest in themselves, Sillen and Andersson used them to
generate graphs showing conditions under which all sulfur is
in the gas phase; i.e., the only solid phase is MgO. In figures
30 and 31, temperature is plotted against the quantity A
where
A =
= 100(P0 -
(26)
Figure 31 is a vertical expansion of figure 30.
At positive values, A is practically the percent 02 in the
gas phase. When A is negative, the atmosphere is deficient
in oxygen and is reducing. Referring to figures 30 and 31,
in the area marked MgS04, 99% or more of the sulfur is in
the form of MgS04. In the region H2S-MgO, > 99% of the
sulfur is in the form of H2S, while in the S02-MgO area,
2More precise thermodynamic data is now available (46) but this
should not significantly affect Sillen and Andersson's conclusions
about the gas phase composition in an oxidizing atmosphere.
Table 3. Log10 equilibrium constants vs temperature.
Reaction
C(s) + H02(g) = C0(g)
C(s) + 02(g) = C02(g)
H2(g) + V£02(g) = H20(g)
H2(g) + ^S2(g) = H2S(g)
V4S2(g) + 02(g) = S02(g)
S02(g) + %02(g) = S03(g)
MgC03(s) = MgO(s) + C02(g)
MgS04(s) = MgO(s) + S02(g) + &02(g)
MgS(s) + 202(g) = MgS04(s)
MgS(s) + H20(g) = MgO(s) + H2S(g)
500°K
16.3
41.3
22.9
6.6
33.8
5.3
-3.5
-25.1
78.3
3.0
800°K
11.9
25.8
13.3
3.2
19.8
1.5
1.1
-10.3
41.9
1.8
1200°K
9.5
17.2
7.9
1.3
11.8
-0.5
3.4
-2.3
21.9
1.2
1500°K
8.5
13.8
5.7
0.5
8.8
—
—
0.8
14.1
0.9
34
-------
100
I
80
O Sulfur dioxide
A Magnesium sulfate
V Magnesium thiosulfate
D Sulfur
300
350
400
450
Temperature, °C
Figure 26. Effect of temperature on nature of MgSO3
decomposition products-15 minutes heating period (54).
1000
_ 1800
900
E 800 -
700 -
Numbers on curves denote
decomposition of MgSO
Figure 27. Effect of time and temperature on
decomposition of MgSO3 (44).
35
-------
:so
Temperature. °C
500 750
1000
:o -
15
10
-10
250
500
750 1000
Temperature, DK
1250
1500
Figure 28. Equilibrium constants for
combustion reactions (95).
99% of the sulfur is in the form of S02. The intermediate
region represents conditions' where appreciable amounts of
both SO2 and MgS04 occur. Under conditions covered in
figure 30, magnesium sulfide is not a stable phase.
At 1000° C, MgO and S02 are the primary reaction
products over a wide variation of gas phase compositions.
With decreasing temperature, high yields of S02 and MgO
require a more restricted gas phase composition. Thus,
when operating at 900° C, high yields of MgO and S02 are
possible only when -0:5
-------
Temperature, °C
-,n 600 700 800 900 1000 11QQ 1200 1300 1400 1500
i i n n 1 1 1 1 1 r
15 . MgS04
1.0
0.5
A 0.0
-0.5
-1.0
-1.5
-2.0
SOj, MgO
H3 S, MgO
\
\
800 900 1000 1100 1200 1300 1400 1500 1600 1700
Temperature, °K
Figure 31. Effect of calcination temperature and-
atmosphere on formation of product materials
(expanded vertical scale) (81).
Kinetics and Mass Transfer
Information on reaction kinetics for the magnesia scrubbing
system is limited, but for reasons stated below, information
from other systems may be of some help in understanding
the magnesia system. Chertkov (15), using an aqueous
alkaline absorbent, proposes the following sequence of
reactions for scrubbing sulfur dioxide.
SO2 (g) = S02 (solution)
H20 + SO2 (solution) = HSS03=+H2O
(27)
(28)
(29)
(30)
The reaction mechanism is considered to be independent
of the source of hydroxide ions; therefore, information
from similar alkaline systems may be directly applicable to
the magnesium system.
Chertkov assumes that the hydration step, equation 28 is
the slowest step, and at elevated S02 concentrations, it will
become rate limiting. However, if ammonia, sodium
hydroxide, or sodium carbonate are the absorbents, equation
28 becomes rate limiting only when the S02 concentration
in the gas phase exceeds 3.5% (19).
Reported mass transfer coefficients vary widely and are
difficult to compare because of different experimental
conditions, scrubber type, gas velocity, liquid intensity,
temperature, and solution composition. Based on data
obtained from a packed absorber and magnesium sulfite-
bisulfite slurry (50° C, pH 6.2) as the absorbent, Chertkov
reports that sulfur dioxide mass transfer coefficients are
directly proportional to gas flow rates up to at least 5.9
ft/sec. The relationship between mass transfer coefficient
and gas velocity is found in figure 33.
As shown in figure 34, changes in liquid mass rate also
have a noticeable effect upon the mass transfer process.
With constant gas flow rate, Chertkov reports the mass
transfer coefficient, K, to be proportional to liquid
intensity raised to the 0.4 power.
In the pH range tested, 6.1 to 6.4, liquid film resistance
was not important, but Chertkov states that, with lower
pH, liquid film resistance will be more significant because
of reduced S02 solubility and increased viscosity. The
increased liquid film resistance leads to a decrease in mass
transfer rate and, thus, would tend to favor the slurry
process (high pH) over a clear liquor process.
Using clear liquor solutions, Markant et al (63) have
measured mass transfer coefficients in venturi scrubbers at
rather high gas velocities and under a wide variety of
conditions. Their data covered much higher gas velocities
than did Chertkov's, 30-100 ft/sec vs 1-6 ft/sec. The results
(figure 35) show the increased mass transfer that occurs
with higher gas mass flow rate.
While no information on the effect of temperature on
S02 transfer rates into MgS03 slurries is available, results
from ammonia, sodium carbonate, and sodium hydroxide
scrubbing shed light on the magnesia system (20). As shown
in figure 36, the mass transfer coefficient, K, falls only
slightly with increasing temperature when using NaOH or
Na2C03 scrubbing solution, but the decrease in K is quite
pronounced in the ammonium sulfite-bisulfite system.
Chertkov attributes the behavior difference to the rapid
increase in S02 vapor pressure with temperature in the
ammonium bisulfite system.
Thus, if the pH of a magnesia scrubbing slurry remains
above 7.0 where S02 vapor pressure is very low, the adverse
influence of increased temperature on K will be slight. But,
in an acid-sulfite solution (lower pH), S02 vapor pressure
increases rapidly with temperature (63); therefore,
significant reduction in K will occur.
Using venturi scrubbers and magnesium sulfite-bisulfite
solution (not slurry), Markant et al (63) find that S02
absorption efficiency decreases by about 10% between
110° F (44° C) and 170° F (77° C) at 0.812% MgS03-
5.09% Mg(HS03)2. They also show that the decreased
scrubbing efficiency can be offset by increasing the MgS03
37
-------
100
1100
1000
Temperature, °C
Figure 32. Effect of manganese on the rate of
magnesium sulfate decomposition (40).
1200
2.0
I I I
Packed column
Liquid intensity - 13.5 to 19.0 gallons/min-ft2
Solution temperature - 50° C
Scrubbing solution pH - 6.2
Gas velocity, ft/sec
Figure 33. Effect of gas velocity on mass transfer coefficient (15).
38
-------
20.0
«j
% 15.0
,c
1
-„ 10.0
g 9.0
S 8.0
1 7.0
£ 6.0
4.0
3000
2000
5 1000
I 900
=2 800
1 700
S oOO
8
S 500
1
a 400
300
200
Packed column
Solution temperature 50° C
Scrubbing solution pH 6.1 -6.3
« 4.6 ft/sec gas flow rate
O 5.Oft/sec gas flow rate
.05
5 6 7 8 9 10 15 20
Liquid mass rate - gallon/min - ft2
Figure 34. Effect of liquid mass rate
on mass transfer coefficient (15).
I
I
I
I I I
Venturi scrubber
pH 4.5 - 5.5 (clear liquor)
Liquor temperature 45° C ~ 75° C (114° F-168° F)
I I
I
I
4 6 8 10 15 20 30 40
Gas mass flow rate, Ib (wet)/hr - ft2 x 10-3
Figure 35. Effect of gas mass flow rate on
mass transfer coefficient (63).
concentration to 1.16%. Because MgSO3 concentration
increases with temperature in a slurry system, it is doubtful
if any significant decrease in S02 absorption will occur
with moderate temperature changes.
Formation of Crystalline Deposits (Scaling)
Because crystalline deposits of hydrated magnesium sulfites
might form when saturated solutions or slurries are used to
scrub SO2, there is naturally some concern about potential
scaling problems. While several theories are advanced to
o
00
.04
.03
.02
3 .01
.00
Packed column
o Na2C03
A NaOH
n Ammonium sulfite S/C = .81
v Ammonium sulfite S/C = .936
I
I
0
10
20
40
50
60
30
Temperature, "C
Figure 36. Effect of temperature on mass transfer
coefficient in absorption of SO2 by various solutions (20).
explain crystal growth, there is general agreement that, for
a crystal to grow, it must overcome two resistances:
diffusion of solute molecules or ions to the crystal face and
incorporation of the solute into the crystal. Diffusional
resistance depends on solution properties and movement of
solution through the crystal. Incorporation of solute into
the crystal depends on the properties of the crystal and
crystal temperature.
Studies made with KA1S04-12H2O (6), CuS04-5H20
(65), and MgSO4-7H20 (22) show that crystal growth rate
initially increases rapidly with solution velocity past the
crystal face, but levels off at higher solution velocities. The
KA1S04-12H20 growth rate becomes independent of
solution velocity above 1-3 in./sec. Magnesium sulfate
heptahydrate growth rate levels off at about 9 in./sec. For
CuS04'5H2O, the increase in growth rate becomes
negligible above a solution velocity of 2 in./sec.
Clontz et al (22) show that the rate at which
MgS04'7H20 was incorporated into the crystal increased
with degree of supersaturation and temperature. Botsaris
and Denk (6) also show that growth rate increases with
degree of supersaturation.
In general, at low solution velocity, crystal growth rate
depends on solution velocity, but at higher velocity, crystal
growth rate is independent of solution velocity. This
"breakpoint" occurs below 1 ft/sec. Crystal growth rate,
particularly at higher solution velocities such as will occur
in pipes, increases with crystal temperature and degree of
supersaturation.
For the process under consideration, MgS03-6H20
crystal growth may be expected at points of high solution
velocity and turbulence where solutions are supersaturated
with MgS03 or at wet-dry interfaces of scrubbers. In a pilot
39
-------
plant study, Downs and Kubasco (27) found magnesium
sulfite deposits most prevalent at points of extreme
turbulence such as sump suction and discharge, and along
threaded sections of plastic pipe. The deposit appeared as a
"hard, resilient, plate-like deposit" tightly bonded to the
metal surfaces. Similar deposits of CaS04-2H20 and
CaS03-1/iH20 occur in the limestone system.
Downs and Kubasco note several factors which influence
deposit formation:
1. Systematic shifting of sulfite slurry concentration.
2. Availability of precipitation surface area.
3. Nature of the surface material.
4. Fluid flow environment.
Systematic shifting of MgS03 slurry concentration may
occur by chemical reaction or temperature changes and, in
either case, probably changes the degree of supersaturation.
They propose the following reactions for the gas-liquid
scrubber:
SO 2 +OH' -> HSO3 (31)
S03= + H20 -> HS03- + OH- (32)
MgS03 -6H20 -» Mg++ + S03= + 6H20 (33)
The net equation is
MgS03-6H20 + SO2 -* Mg+++2HS03 + 5H20 (34)
thus, relatively insoluble MgS03 actually dissolves to the
more soluble Mg(HS03)2 in the gas-liquid scrubber. In the
sump, where bisulfite is partially neutralized with MgO,
these reactions occur:
HS03 + OH' -> S03
+ H20
MgS03-6H20
(35)
(36)
The last reaction is the mechanism by which crystal
growth proceeds. They support this mechanism with the
following observations:
1. No deposits form in the gas-liquid contact zone
where MgS03 is actively dissolving.
2. Deposition is most severe in the sump and piping
when the system is acid and MgO is directly added to the
sump.
3. Deposition was substantially reduced by changing the
MgO makeup point from the sump to the gas-liquid contact
zone.
To insure rapid reaction, they preslaked the MgO;but, in
view of its reactivity, preslaking does not appear to be
necessary.
Temperature cycling may occur when there is a
temperature drop between the inside pipe wall and bulk
liquid or in the bulk slurry due to heating by flue gas and
cooling by makeup slurry and water. In either case,
solutions may become supersaturated and crystal growth
occur.
Downs and Kubasco find fly ash very effectively reduces
the tendency to form solids. They attribute this to
additional suspended surface created by the finely divided
fly ash and the abrasive or scouring action of fly ash.
The ability of a solid to adhere to a solid surface
depends on the attractive force between the surface and the
deposit. Downs and Kubasco relate the attractive force to
the wetability of the surface by sulfite solutions. Surfaces
not wet by liquids have little affinity for the liquid;
therefore, the contact angle between liquid and surface is
high; i.e., the liquid forms beads on the solid surface. When
the affinity between liquid and solid surface is high,
wetability is high and contact angles are lower.
The polyvinylidene chloride pipe material used in their
tests has a surface with a large contact angle; therefore, in
zones where deposit formation is a problem, it is a better
material of construction than steel or brass which has a
lower contact angle.
In summary, the following action should be taken to
reduce deposit formation.
1. Reduce the degree of MgS03 supersaturation and
precipitation by adding MgO as close as possible to the S02
scrubber and where possible maintain constant
temperature. Avoid dramatic pH changes which result in a
shift from acid to base or base to acid.
2. Allow some fly ash into the system.
3. Choose the proper material of construction where
supersaturation and high solution flow rate or turbulence
are unavoidable.
In addition, the use of a high solids concentration in the
scrubbing slurry will provide additional deposition sites;
therefore, reduce scale formation. The solids concentration,
of course, is limited by pumping and erosion difficulties.
Process Contaminants
Soluble impurity buildup in particulate scrubber—For
those particulate removal systems which must operate with
closed loop scrubbing liquor, consideration should be given
to contaminant buildup. Usually recycle water from the ash
pond is used to scrub fly ash from the flue gas with the
resulting slurry pumped back to the pond. Makeup water is
added only to compensate for humidification losses.
Two sources of soluble impurities should be considered:
1. Makeup water.
2. Soluble impurities leached from the fly ash.
Both will be highly variable and little is known of the
leaching characteristics of fly ash. Presented in table 4 are
typical limits of fly ash analysis of United States
bituminous coals (77). The sulfur trioxide reported in the
40
-------
Table 4. Typical limits of ash analysis of
United States bituminous coals (77).
Constituent %
Silica, Si02
Alumina, A1203
Ferric oxide, Fe203
Calcium oxide, CaO
Magnesium oxide, MgO
Titanium dioxide, Ti02
Alkalies, Na20 + K20
Sulfur trioxide, S03
20-60
10-35
5-35
1-20
0.3-4
0.5-2.5
1-4
0.1-12
Table 5. Makeup water analysis.
coal ash analysis represents sulfur retained in the ash and
consists principally of CaS04.
Because of the paucity of laboratory data on fly ash
leaching, the relative importance of leaching vs makeup
water to the impurity buildup problem was estimated using
data from a TVA power plant. Recognizing variability in fly
ash leaching and makeup water composition, the
information below is not universally applicable.
Table 5 presents average Cl", S04=, andCaC03 analysis
of makeup water. The calculated impurity input is based on
0.266 1. of makeup water per pound of coal burned.
Table 6 shows analysis of ash pond water. It can be
assumed that the dissolved minerals in the water are derived
from both ash leaching and makeup water. The impurity
input in g/lb coal burned is estimated from analysis of
water leaving the pond and the quantity of pond water per
pound of coal burned which is about 3.69 1.
A comparison of table 5 with table 6 shows that the fly
ash supplies most of the soluble impurities in the ash pond
water.
Based on the pond water analysis and a pond volume of
150,000,000 gallons, the level of impurity buildup during 1
year can be calculated for a 500-mw unit burning 375,000
pounds of coal per hour. Results are found in column 4 of
table 6.
The increase of CaC03 and S04= over an operating time
of 1 year is enough to precipitate CaS04 and perhaps
CaC03. Not considered in the calculation is the influence
of SO2 and S03 in the flue gas. The pH of the pond water
at the power plant from which the data were taken is 10.1.
In such case, some S02 and S03 will also be scrubbed out
in the particulate scrubber. The S03, on the order of 0.001
volume %, will immediately be converted to sulfate. In the
absence of laboratory or pilot plant data, the effect of the
SO2 on impurity buildup is conjectural. The S02 will lower
the pH of the pond water and probably increase the rate of
leaching. At the same time, the decreased pH may be
enough to prevent precipitation of CaC03. Because there is
excess 02 in the flue gas, some of the absorbed S02 may be
oxidized either in the scrubber or in the ash pond, causing
the sulfate concentration to increase. The presence of
Impurity
Concentration,
g/1
Impurity input,
g/lb coal burned
CaCOs
S04 =
ci-
0.072
0.015
0.010
0.019
0.0040
0.0027
Table 6. Analysis of ash pond water.
Impurity input, Impurity input
Concentration, g/lb coal level in 500-mw
Impurity g/1 burned plant, g/l-year
CaC03
S04 =
cr
Ca++
Mg++
Fe+++
Mn++
Total
dissolved
solids
0.098
0.090
0.015
0.035
0.0025
0.0028
0.0003
0.280
0.36
0.32
0.054
0.13
0.0090
0.010
0.001
1.03
1.7
1.5
0.26
0.60
.042
.046
.0046
4.6
dissolved iron and manganese will accelerate the oxidation
rate both in the scrubber and in the pond.
The decreased pH and increased S04~ will tend to favor
CaS04 precipitation and prevent CaC03 precipitation.
Unless steps are taken to control the calcium and sulfate
level, CaS04 scaling could occur in the recycle line and the
scrubber system. Increased chloride ion buildup, particularly
at low pH, could also increase corrosion rates.
Impurity buildup could be controlled by bleeding off a
small stream from the pond recycle at a rate .which
compensates for impurity input. At least three methods of
treating the bleed stream are available: ion exchange,
storage in a deadend pond with reliance on solar evapora-
tion to maintain pond volume, or crystallization by steam
evaporation with solid disposal. Ion exchange is perhaps the
most expensive treatment method. In dry climates with
high solar evaporation rates, storage in deadend ponds
should be possible. In portions of eastern United States
with high rainfall, the bleed stream would have to be
concentrated by evaporation before being sent to a deadend
storage pond.
Soluble impurity buildup in the S01 scrubbing system-
With regeneration and recycle of MgO, the sulfur dioxide
scrubbing system also will operate closed loop, and
therefore, will be subject to buildup of impurities which
would result in scaling and corrosion problems. The
estimated system losses of water and magnesium oxide are
0.075 Ib water/lb coal burned and 8.11 x 10'4 Ib MgO/lb
coal burned. These losses will be replaced by fresh makeup
water and virgin MgO which are both sources of
contaminants.
41
-------
In addition sulfite ion oxidation to soluble MgSO4 will
occur, but there is little information currently available to
predict the effect of long-term buildup of MgSO4 in
continuously operated, closed cycle S02 scrubbers.
Chertkov (17) has measured magnesium sulfate increase
in a packed tower scrubber system. His results, given in
figure 37, show that magnesium sulfate concentration
rapidly increased to about 13%. Beyond this, the rate of
increase fell to a very low level. However, the duration of
the run was only 2.5 days; hence, it is not known if the
oxidation rate will be reduced to zero or what the terminal
magnesium sulfate concentration will be. If the steady state
oxidation rate is not zero, provision must be made for
magnesium sulfate removal. Of course when the MgS04
solubility limit is reached, MgSO4-7H20 will be removed
with MgS03 -6H2O crystals, but this will not occur until the
MgS04 concentration exceeds 33 weight %. It is possible
that enough MgS04 will be occluded in the MgS03 crystals
to prevent this high MgSO4 concentration, but a minimum
steady state concentration of at least 10 to 15 weight %
should be expected. If the temperature of the
MgS03-6H20 slurry is raised to convert the crystals to
MgSO3-3H20, which requires reduced dryer heat, the
occluded MgS04 will be solubilized and returned with
mother liquor to the scrubber system.
The concentration range and input rates of some
expected impurities in commercially available magnesium
oxide are presented in table 7. Impurity input is based on a
500-mw plant using 8.11 x 10'4 Ib of MgO/lb coal burned.
The impurity concentration and input rate from one
source of makeup water is found in table 8. Input rates are
Table 7. Impurities of magnesium oxide
48
60
0
0 12 24 36
Time, hours
Figure 37. Effect of time on increase of salt concentration
Impurity
Silica, Si02
Ferric oxide, Fe203
Alumina, A1203
Chloride ion, Cl"
Sulfate ion, SO4 =
Calcium oxide, CaO
Concentration,
wt/%
0.2-7.0
0.005-1.25
0.04-1.25
0.00-1.0
0.00-1.2
0.5-6.0
Impurity input x
10s g/lb coal burned
0.16-5.6
0.004-1.0
0.03-1.02
0.00-0.81
0.00-0.97
0.4-4.9
Table 8. Concentration and impurity
input of makeup water.
Concentration, Impurity input x
Impurity g/1 10s g/lb coal burned
Calcium oxide, CaO
Sulfate ion, S04~
Chloride ion, Cl"
0.040
0.015
0.010
140
51
34
in sulfur dioxide scrubbing system at pH 5.5-6.0 (1 7).
based on a makeup water addition of 0.075 Ib of water/lb
coal burned.
Comparison of table 8 with table 7 shows that, in this
case, makeup water will contribute almost all of the
nonsulfate impurities to the scrubbing system. Because of
this, careful attention should be given to the source and
purity of the makeup water.
If the prevalent impurity input rate to a 500-mw plant is
assumed to be 0.002 g/lb coal burned and impurity
concentration in the scrubbing liquor is not allowed to
exceed, say, 3.0 g/1., scrubbing solution must be removed
and purged at a rate of 4.2 l./min (1.1 gal/min). Some of
these impurities will be lost from the scrubber by entrain-
ment in the offgas, but these losses will be quite small;
therefore, a purge treatment will be necessary. An
important point to consider is that sending a side stream
directly to a deadend pond would be the simplest and
probably least expensive purge treatment. Assuming a
clarified solution with a soluble MgS03 concentration of
1.2% and a MgS04 concentration of 15%, the losses would
be 33.6 Ib of MgO/hr-30.8 Ib as soluble MgS04 and 2.8 Ib
as soluble MgS03.
Magnesium losses could be reduced by concentrating the
mother liquor until MgS04 precipitates. Evaporation
should not be allowed to proceed beyond the point where
undesirable impurities such as NaCl precipitate with the
MgS04. This procedure alone would not remove insoluble
impurities such as silica, ferric oxide, aluminum oxide, and
fly ash. A possible complete treatment would involve
dissolving MgS03-6H20 slurry with a minimum amount of
sulfur dioxide, filtering the insoluble impurities, then
reprecipitating sulfite with makeup MgO. The resultant
crystals would be filtered and returned to the system; the
mother liquor would be evaporated to recovery MgS04 and
the supernatant of soluble impurities discarded.
42
-------
Since almost no data exists at this time on the buildup
of impurities in aqueous scrubbing processes for S02
control, it is difficult to quantify the magnitude of the
problem. Only extended operation of a system will yield
enough information to define a complete impurity control
method.
Nitrogen Oxide Emission Control
The fixation of nitrogen during high temperature
combustion may be represented by the following reaction:
N,+O,
2NO
(37)
Other nitrogen oxides can be formed from NO; however, as
shown in figure 38, at combustion temperatures exceeding
1000° K, only NO is present in significant amounts.
Following ejection of the combustion products to the
atmosphere, however, the formation of other nitrogen
oxides is more likely although the rate of formation may be
rather low. The equilibrium constant for reaction 37 may
be represented by the following expression:
(38)
100,
50
30
20
10
5.0
3.0
BO
O 2'°
z
12 1.0
CD
r*
O
^ 0.5
0.3
0.2
0.1
0.05
0.03
0.02
0.01
Methane combustion
with 10% excess air;
atmospheric pressure
_L
J_
_L
400
500
900
600 700 o 800
Temperature, K
Figure 38. Effect of temperature on equilibrium
concentrations of NO and NO2 in combustion gases (3)
1000
where R is the gas constant and T the absolute temperature.
This expression shows that NO is thermodynamically stable
only at high temperature; figure 39 illustrates the variation
in equilibrium NO concentration with temperature and air
stoichiometry. Figure 40 further emphasizes the sensitivity
of NO concentration to air stoichiometry. Highest NO
concentration occurs at 10-15% excess air even though the
peak flame temperature occurs at only 95% stoichiometric
air, indicating that the availability of oxygen limits the
equilibrium concentration of NO. Typical equilibrium
concentrations of NO and N02 in air and flue gas are found
in table 9 (24).
Residence time at peak flame temperature is usually
insufficient for NO to reach equilibrium concentration;
therefore, the kinetics of NO formation have important
bearing on final NOX concentration in the flue gas. The
reaction mechanism of NO formation is now thought to be
a chain reaction involving oxygen and nitrogen free radicals
(35). The high activation energy for the fixation reaction,
about 135 Kcal/mole (3, 35), is responsible for the extreme
temperature dependence of this reaction.
From the standpoint of NOX emission control the
decomposition rate of NO to nitrogen and oxygen is also
quite important (3). Although NO becomes thermo-
dynamically unstable as the flame temperature decreases,
the decomposition rate becomes so low that below
1260-1320° C the NO concentration becomes fixed (3). As
the flue gas is diffused into the atmosphere the NO may
combine with oxygen to yield NO2.
The type of fuel used in power plants may have a
pronounced effect on NOX emission levels. Based on
adiabatic flame temperature, one may expect that NOX
emission rates will be highest for coal-fired boilers, followed
in descending order by oil and gas. The actual situation is
more complex, of course, because NOX formation will also
depend on heat transfer rates in the boiler and the
chemically bound nitrogen content of the fuel.
Coal and oil are prone to burn with luminous flames
which increase heat transfer and flame quench rates. Gas
usually burns with a blue flame, the emissivity of which is
much lower than the luminous oil and coal flames. Because
the heat transfer rate of such flames is low, the flame is
quenched more slowly. Thus, in large boilers where almost
all heat transfer is by radiation, natural gas fired boilers
may actually produce more NOX than coal or oil fired
boilers. The Southern California Edison Company (1), for
example, reports that, in general, NOX emissions have
increased with unit size, and for units of 480-mw or larger,
NOX emissions are greater for gas fuel than for residual oil.
A second reason that fuel type is important lies in the
fact that coal and oil contain chemically bound nitrogen.
One may expect that oxygen would more easily attack the
more reactive N-N or N-C bonds in fuel molecules than the
N = N bond of molecular nitrogen. Convincing
43
-------
4800
1400
1500
1600
1900
2000
2100
1700 1800
Temperature, °K
Figure 39. Effect of temperature on equilibrium concentrations of NO
for combustion of methane (3).
2200
5000
4000
3000
2000
1000
Temperature
4000
3000
S
I
SL
£
2000
1000
50
100 150
% Stoichiometiic air
200
Figure 40. Effects of air concentration on NOX
equilibrium in methane—air flames (3).
44
-------
JTable 9. Equilibrium concentration of NOX in air and in a typical flue gas at 1 atm (24).
Temperature, °C
527
1600
NO (ppm)
2.3
6,100
Air
NO 2 (ppm)
0.71
12
Flue gas3
NO (ppm)
0.77
2,000
N02 (ppm)
0.11
1.8
a3.3%O2, 76% N2.
experimental evidence of this comes from the Argonne
National Laboratory (49). Fluidized bed combustion of
coal occurs at about 900° C, too low for nitrogen fixation
to occur. Yet, workers at Argonne found that in one set of
fluidized bed experiments using air, NO concentration in
the offgas was about 500 ppm. Substitution of inert argon
for nitrogen produced essentially no change in the offgas
NO concentration, thus showing that the source of the NO
was nitrogen chemically bound in the coal.
Crynes and Maddox (24) have divided nitrogen oxide
emission control into three broad categories: fuel treat-
ment, combustion control, and flue gas cleanup. Fuel
treatment to remove chemically bound nitrogen does not,
at present, appear technologically possible.
Because nitrogen oxide concentration is sensitive to
flame temperature and length of time reactants are exposed
to peak flame temperature, some NOX control is possible
through modification of the time temperature profile by
means of boiler and combustion changes. In practice,
modification of existing boilers may be both difficult and
expensive.
Nitrogen oxide production is significantly decreased by
lowering the excess oxygen concentration (1) but,
unfortunately, combustion efficiency is lowered also. This
problem can be circumvented by adding slightly less than
stoichiometric air through the primary air ports with
additional air being added "downstream" to complete
combustion (1, 41). It is claimed that significant reductions
in NO concentration are possible with only moderate
increase in operating costs (1, 2, 41). Decreasing the
enthalpy per unit volume of reactants can lower the peak
combustion temperature and thus the NO formation rate
(2). This may be accomplished by simply reducing com-
bustion air preheat or recirculating product gases and
mixing these with the combustion air. The inert product
gases absorb a fraction of heat of combustion and, in effect,
reduce the peak flame temperature.
A third method of NOX control involves stack gas
cleanup. So far, catalytic decomposition, selective reduc-
tion of NO with ammonia, hydrogen sulfide, or hydrogen,
adsorption on solid supports, and aqueous scrubbing with
alkaline solutions such as Mg(OH)2 or concentrated sulfuric
acid have been considered.
Schmidt et al (74) have described the use of Mg(OH)2
and MgC03 for scrubbing NOX from nitric acid plant
offgas. As was discussed in the previous section, an
adaption of this process has since been suggested for NOX
removal from power plant offgas (27). Figure 41 shows a
flow diagram of the NOX control system.
In the scrubber, magnesium hydroxide or carbonate
slurry absorbs the nitrogen oxides to yield magnesium
nitrite, some magnesium nitrate, and, if sulfur dioxide
removal is not complete, magnesium sulfate. The mag-
nesium nitrite solution is sent to a decomposition tank
where nearly pure NO is liberated at elevated temperature
and pressure, via the reaction:
3Mg(N02)2 + 2.H20
2Mg(OH)2 + 4NO t
Mg(N03)2
(39)
The resulting suspension is treated with ammonia and
carbon dioxide to yield Mg(OH)2 and MgCOs for recycle to
Mg(OH)2
Air
NH,N03
(NH,)2SO,
solution
Figure 41. Mg(OH)2 scrubbing process (74).
45
-------
either the NOX or S02 scrubbers and a solution of
'NH4N03 which may be sent to an ammonium nitrate
manufacturing plant.
(NH4)2C03+Mg(N03)2
2NH4N03 + MgC03 ;
(40)
The NO from reaction is air oxidized to N02 and
injected into the flue gas in an amount sufficient to
maximize the N203 concentration.
Any sulfate formed in the scrubber would be removed
from the system as soluble ammonium sulfate in the
ammonium nitrate stream.
Alternately, Downs and Kubasco (27), see figure 8, have
suggested the addition of sufficient slaked lime to the
stream leaving the NOX scrubber to precipitate the sulfate
asCaSO4.
Ca(OH)2+MgS04 ->• CaS04 I + Mg(OH)2 4- (41)
Unless provision is made for recovery, this process
alternate will lead to some magnesium losses, but because
of the paucity of engineering data, no choice can be made
between the alternates at this time.
Because of the unreactivity of NO (relative to N02 or
N203), efficient scrubbing with H2S04 or aqueous alkaline
solutions hinges on the idea of injecting N02 into the flue
gas prior to the absorption step.
In the presence of water vapor, Downs and Kubasco
assume the following gas phase reaction:
NO, ^2HNO,
(42)
Although the equilibria is shifted well toward the left,
favorable kinetics with continuous HN02 removal will drive
the reaction to completion.
In a more recent study (26), using a 1500 cfm spray
type scrubber, Downs evaluated NOX scrubbing efficiency
with MgO as a function of liquid to gas ratio, NO2 to NO
ratio, MgO slurry concentration, stoichiometry, and gas
flow rate. Under all conditions tested, scrubbing efficiency
was less than 10%.
Assuming liquid film resistance to HNO2 transfer is
negligible, the expected HN02 mass transfer rate, Kg3,
should be near 23.0 Ib moles/hr-ft3 and the NOX absorp-
tion efficiency about 33%. Since the observed absorption
efficiency and corresponding Kg3 are much lower, Downs
concludes that liquid film resistance to HN02 absorption is
significant.
The minimum NOX absorption efficiency necessary to
produce a self-sustained supply of NOX is 75%. To achieve
even this modest efficiency, the Kg3 must exceed 72
moles/hr-ft3 Because this mass transfer rate is nearly 1 00
times the observed Kga, Downs concludes that it is not
&
physically possible to design a spray type scrubber which
will increase the nitrous acid mass transfer coefficient this
much. Thus, a system such as MgO that is liquid-film
mass-transfer or chemical-reaction-rate limiting will not
perform.
If MgO dissolution is the rate limiting step, then it is
possible that the nitrous acid mass transfer coefficient
might be increased to the necessary 72 Ib moles/hr-ft3 by
using a soluble basic absorbent such as Na2C03 instead.
Downs feels that for soluble salts such as sodium carbonate,
a packed tower has the best chance of success.
Recovery As Sulfur
Although process schemes evaluated in this study call for
the conversion of flue gas sulfur oxides to sulfuric acid,
there are advantages in recovering the sulfur values as
elemental sulfur. These advantages include lower shipping
costs (per mole of sulfur) and fewer storage problems.
There are at least two possible routes to elemental sulfur:
1. Catalytic reduction of a stream rich in sulfur dioxide
to elemental sulfur by addition of carbon, natural gas, or
carbon monoxide.
2. Production of hydrogen sulfide in the calciner with
subsequent conversion of the H2S to elemental sulfur.
The first route, reduction of sulfur dioxide to elemental
sulfur, is now in operation in at least two plants (36, 99).
One process (36) uses the hot reducing gases from partial
combustion of Bunker C fuel oil to reduce S02 to
elemental sulfur. In a process developed by Allied Chemical
(99), methane gas is used to reduce SO2 to elemental
sulfur. The Allied Chemical process is described in more
detail below. These systems are quaternary, containing
carbon, oxygen, sulfur, and hydrogen. Alternately, it is
possible to reduce S02 with carbon or carbon monoxide, in
which case the system would be ternary.
Kellogg (52), who has developed the principal features
of both systems from thermochemical calculations, demon-
strates that critical control problems occur in attaining the
maximum sulfur recovery in any process which reduces
S02 with carbon, hydrocarbons, or carbon monoxide.
For example, in the ternary oxygen-carbon-sulfur
system, starting with a pure S02 stream and carbon as
reducing agent, the elemental sulfur concentration reaches a
maximum at a carbon to oxygen atom ratio of 0.5, but as
shown in figure 42, potential sulfur recovery sharply
decreases at either side of this optimum ratio. Thus, below
C/0 ratio 0.5, both S02 and S20 partial pressures rapidly
increase with decreasing C/0 ratio while above a ratio 0.5,
COS and CS2 increase. A possible method of achieving the
optimum ratio, Kellogg suggests, would be to add excess
carbon at elevated temperature, then bleed in the required
amount of S02 to achieve C/0 ratio 0.5 for maximum
sulfur recovery.
46
-------
0.2
0.3 0.4
Atom ratio C/0
0.5
Figure 42. Effect of C/O atom ratio on gas composition
for the system C-O-S at 600° K
and one atmosphere total pressure (52).
Potential sulfur recovery also increases with decreasing
temperature. Again starting with carbon and a pure S02
stream, figure 43 shows that about 99.8% of the sulfur is
elemental (.02% combined) at 625° K, the remainder being
predominantly COS and S02. Achieving practical reaction
rates at this low temperature requires an activated alumina
catalyst. The dew point of sulfur under optimum experi-
mental conditions is 597° K and, therefore, the reaction
temperature must remain above this temperature to prevent
condensing sulfur from fouling the catalyst.
At 625° K, the reaction between carbon and SO2 is far
too slow to be practical; thus, elevated temperature,
perhaps as high as 1200° K, may be necessary for rapid
reaction. At higher temperature, the undesirable products,
COS, CS2, and H2S predominate, and the reaction mixture
700 800
Temperature, °K
Figure 43. Effect of temperature on elemental sulfur recovery
in the system C-O-S at P = 1 atm, S/O = 0.5 and C/O = 0.5
(composition for optimum production of sulfur) (52).
must be cooled to optimum temperature of 625° K and
allowed to equilibrate before condensing the sulfur.
Using carbon monoxide as the reductant, optimum
sulfur recovery also occurs at a C/O ratio of 0.5, but
because the product gas is leaner in sulfur, condensation
may be more difficult. This problem may be offset by the
fact that carbon monoxide reacts with sulfur dioxide much
faster than does solid carbon and, thus, a lower initial
reaction temperature can be used.
Methane is an alternate but less effective reductant than
carbon or carbon monoxide. Kellogg shows that, at 600° K,
88.5% of the sulfur, at most, can be recovered as elemental
sulfur in one pass through the reaction chamber. Recovery
as high as 95% is possible by taking the offgas from the first
condensation through a second condensation at lower
temperature. The lower temperature of the second con-
densation will not condense liquid sulfur because the dew
point has been sharply altered by the first condensation. To
47
-------
achieve optimum sulfur recovery, the [C + H] /O atom ratio
must be 1.25. As before, small departures from this ratio
sharply reduce the yield of elemental sulfur.
Finally, any inert gas in the system, such as nitrogen, in
effect lowers the partial pressure of gaseous sulfur and
makes condensation less efficient. For maximum sulfur
recovery, inert gas should be avoided.
A possible alternate sulfur recovery process might
include hydrogen sulfide production directly in the calciner
followed by conversion of the H2S to elemental sulfur.
Based on thermochemical calculations, Sillen and
Andersson (81) have shown that H2S production in the
calciner should be possible under reducing conditions.
However, their calculations did not include the possible gas
phase species COS and CS2. In an oxidizing atmosphere,
such omissions should not be critical since these species
would not be present. In a reducing atmosphere, one can
envision significant amounts of COS, CS2, or elemental
sulfur, and for this reason, the equilibrium gas phase
composition of the quaternary system, C-O-S-H, was
reexaminedat 1200°K.
The gas phase constituents considered in the calculation
were S2, S02, S03, 02, H2S, H20, H2, C02, CO, COS,
and CS2. Because the partial pressure of the sulfur
polymers S3 through S8 is thought to be negligible (34),
these were not considered in the analysis. The following
seven equilibria were used to express the relationship
between the eleven gas phase species.
C02 +^S2 =CS2 + S02
3S2 + 2C02 =2COS + S02
2
SO2
= S03
=H20
= H2S
+ CO = CO,
(43)
(44)
(45)
(46)
(47)
(48)
(49)
The eleven partial pressures which appear in the equilibria
are determined by simultaneous solution of eleven
equations: seven equilibrium constant equations, three equa-
tions which specify the system composition, and a final
equation relating the total pressure to the sum of the partial
pressures. The latter four equations.are shown below; Pj,
C/S, H/S, and 0/S are, respectively, total pressure and mole
ratio of carbon to sulfur, hydrogen to sulfur, and oxygen to
sulfur:
PT = PCO + PC02=P]
PCO + PCO2 + PCOS +
5 -
PS02 + PS03+PH2SH
2PH2 + 2PH2S + 2PH2
=> -
H20+PH2+PS2+P
pCS2
h2PCS2+pCOS + 2PS2
o
PS02 + PS03 + PH2S + 2PCS2 + PCOS + 2PS2
2P02+PH20
(50)
(51)
(52)
5
-(53)
2PS.
_ _ ^2
All thermochemical data required in the calculation were
taken from the JANAF tables (46). Ideal gas behavior was
assumed at one atmosphere, but if an inert gas such as
nitrogen were present, the total pressure of the system
would be correspondingly lower.
A box central composite design was used to cover the
region of interest, which was C/S ratio 1.0 to 3.0, H/S ratio
1.0 to 3.0, and S/0 ratio 4.0 to 6.0-fifteen data points in
all.
An iterative method similar to Kellogg's was used with a
digital computer to solve the eleven simultaneous equations
at each of the fifteen points. The method consists of
substituting starting value partial pressures of four repre-
sentative species containing carbon, hydrogen, oxygen, and
sulfur into the equilibria expressions to give values of the
remaining seven partial pressures. The set of eleven partial
pressures is substituted into the total pressure and ratio
equations to yield interim values of P-j and the three mole
ratios. The differences between the interim values and the
desired values are computed and compared with the
convergence criteria (0.02% of the desired value). If any
one of the differences is greater than the convergence
criteria, four new starting values of C02, H2, H20, and
H2S are computed and the process repeated. The iteration
procedure continues until either the convergence criteria is
satisfied or to a preset number of iterations if the partial
pressure values do not converge. New starting values are
computed from the following equations:
(r.in ]T (54)
1
new
old
new
new
new
old
old 1P*
: = logH2S+log[^]
old r
(55)
(56)
(57)
where the asterisk indicates interim values. The components
T, U, V, and W are integers used to manipulate the rate of
48
-------
convergence. The fifteen calculated equilibrium hydrogen
sulfide partial pressures were used to generate by regression
analysis the polynomial shown below-, which represents
hydrogen sulfide partial pressure as a function of system
composition.
(58)
where X l = C/S, X2 = H/S, and X3 = 0/S. The correlation
coefficient was 0.9845, indicating that the data were well
represented by the equation.
In a complicated system such as this, there is sometimes
difficulty in analyzing and simplifying the large amount of
partial pressure data. By using a method of constrained
nonlinear programming (37), it was possible to determine
that the gas phase composition which maximized the H2S
partial pressure within the region of experimentation was
C/S = 3.0, H/S = 3.0, and 0/S = 4.0. The gas composition
under these conditions at total pressures of 1.0 or 0.5
atmospheres is shown in table 10.
With a total pressure of combustion products of either
0.5 or 1.0 atm, approximately 80 mole % of the sulfur is
present as H2S with carbonyl sulfide and elemental sulfur
comprising the remainder. The gas composition of 0.5 atm
would correspond to a sweep gas of half inert nitrogen, half
combustion products.
As presently conceived, the magnesium sulfite calciner
will be swept at about 1200° K with the hot gases from
combustion of a number 6 fuel oil with air. The sweep gas
will contain almost 60% nitrogen and have C/S, H/S, and
0/S ratios of 0.73, 1.50, and 4.31, respectively.
By modification of the combustion conditions and
addition of enough coke to the calciner to approach
optimum conditions, a gas stream containing about 80 mole
% of the sulfur as H2S will be obtained. Cooling this stream
and blending S02 into it to yield the optimum (C + H)/0
ratio will maximize the sulfur content of the stream.
With the multiple condensation suggested by Kellogg,
95% sulfur recovery is possible when no inert gases are
present in the gas stream. The presence of nearly 60%
nitrogen in the stream presents an obstacle to efficient
sulfur recovery, but if the fuel oil were burned with pure
oxygen, this difficulty would be removed.
Alternately, a series of sulfur condensations at
successively lower temperature will make it possible to
efficiently recover elemental sulfur. Allied Chemical (99)
has developed such a system at its Falconbridge facility in
Ontario, Canada. The plant is designed to treat 500 tons per
day sulfur contained in a roaster gas of composition (dry
basis) 12-13% sulfur and 1-1.5% oxygen and remove 90% or
more of the inlet sulfur.
The system consists of three sections: a gas purification
system and a high temperature reactor followed by a low
temperature Claus reactor system.
Particulate matter and catalyst poisons are wet scrubbed
from the roaster offgas and the sulfur dioxide is catalyti-
cally reduced with methane in the high temperature reactor
to elementary sulfur, hydrogen sulfide, and lesser amounts
of other sulfur compounds. The elemental sulfur is con-
densed out of the gas and the remaining sulfur compounds
sent to a two-stage Claus converted for further sulfur
recovery. Additional sulfur condensation occurs after the
Claus system.
Methane gas was chosen as reducing agent because of
availability and economics, but other reductants such as
carbon monoxide or hydrogen could also be used.
Table 10. Effect of total pressure on
Component
Partial pressure (atm)
at one atmosphere
total pressure
gas phase composition.
Partial pressure (atm)
at 0.5 atmosphere
total pressure
CO
CO 2
COS
CS2
H2
H20
H2S
02
S2
S02
S03
0.46
0.17
0.27 x 10'1
0.98 x 10-3
0.10
0.5 Ix lO'1
0.18
0.40 x 10-16
0.62 xlO-2
0.28 x ID'5
0.53 x ID'14
0.23
0.84 x ID'1
0.13x JO'1
0.42 x lO'3
0.53 xlO'1
0.26 x ID'1
0.86 x 10-1
0.39 x ID'16
0.53xlO-2
0.25 x ID'5
0.46 xlO-14
49
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STUDY ASSUMPTIONS AND DESIGN CRITERIA
The magnesia slurry process and three proposed variations
are given detailed consideration in the present study.
Although other products are possible, each scheme is
designed to produce 98% sulfuric acid.
Scheme A, magnesia slurry process—Wet scrubbing of
stack gas with an aqueous magnesium oxide-sulfite slurry to
absorb S02 and form additional crystalline MgS03-6H20.
The MgS03-6H20 is thermally converted to MgS03-3H20
which is dried to form anhydrous MgS03. This material,
along with 5-10% MgS04 formed by oxidation, is calcined
to generate MgO for recycle to the scrubbers andS02-rich
gas for production of sulfuric acid by the contact process.
Coke is used to reduce the sulfate to SO2 and MgO. This
scheme follows closely the development work of
Chemico-Basic, B & W, the Russians, and the Japanese.
Scheme B, MgO-MnO2 slurry variation— Wet scrubbing
of stack gas in a cocurrent spray device to absorb S02 with
an aqueous magnesium oxide-sulfite slurry containing an
activator, manganese oxide. The crystalline MgS03-6H20
formed is thermally converted to MgS03-3H20; the
resulting crystals are dried to anhydrous MgS03, MgSO4,
and compounds of manganese. These materials are calcined
to generate Mg6Mn08 for recycle to the scrubbers and
SO2-rich gas for production of sulfuric acid by the contact
process. This scheme is an adaptation of the Grillo-Werke
development with modifications.
Scheme C, clear liquor variation— Wet scrubbing of stack
gas to remove particulates and absorb S02 with an acidic
solution of magnesium bisulfite and magnesium sulfite,
followed by separation of insoluble fly ash and liquor, and
addition of MgO to the liquor to precipitate crystalline
MgS03-6H20. The MgS03-6H20 is thermally converted to
MgS03-3H2O which is dried to form anhydrous MgS03.
The drier product including MgS03 and 5-10% MgS04 is
calcined with coke to yield MgO for recycle to the reactor
and scrubbers and generate S02 rich gas for production of
sulfuric acid by the contact process. This scheme follows
closely the development work of Chemico-Basic. Although
available design data were based on a venturi type scrubber,
other designs using slightly different operating conditions
should be feasible.
Scheme D, central processing concept—On-site wet
scrubbing of stack gas with magnesia slurry to absorb S02
and form crystalline MgS03-6H20 followed by thermal
conversion to MgS03 -3H20 as in Scheme A. The trihydrate
crystals are dried on site to produce anhydrous MgSO3 ,
which is shipped to an off-site central processing unit
capable of calcining MgS03 from several source locations.
Recycle MgO is shipped back to each scrubber location and
the S02-rich calciner offgas is converted to sulfuric acid in
a more economically sized contact plant. By avoiding
dependency on a single source of magnesium sulfite, this
process variation of Scheme A permits more efficient design
and operation of the calcination and acid manufacturing
steps as compared to an on-site system subject to the cyclic
nature of power plant operation to meet electrical demand.
Schemes A, B, and D can be applied to either coal- or
oil-fired units, however, coal-fired units require particulate
removal in a separate step prior to absorption of S02 .
Scheme C, an alternative in which sulfites are kept in
solution to permit removal of particulates and SO2 simul-
taneously in a single scrubber, is applicable only to
coal-fired; since little fly ash is emitted from oil-fired units,
the more effective slurry schemes can be used.
Fuels
In the previous conceptual design studies, primary attention
was given to control of S02 from coal-fired power units,
coal being the predominant fossil fuel utilized in U. S.
plants and producing the largest quantity of emitted S02.
With only minor differences, the earlier conceptual designs
were applicable to both coal- and oil fired units. However,
in the present study, there are more distinct and important
differences between control systems for power units
burning coal or oil; therefore, coverage will be expanded to
give both fuels complete attention.
Previous conceptual design reports considered the
burning of coal with sulfur contents of 2.0, 3.5, and 5.0%.
These sulfur levels were selected to evaluate the economics
of sulfur dioxide removal from power plant stack gas over
the range of sulfur levels of coal reported in the literature
(94), and will be used again in the current report. As
before, the coal is assumed to contain 12% ash and have a
total heating value of 12,000 Btu/lb. Although coals having
higher ash content and lower heating value are becoming
more predominant, these values are still representative of
coal mined in the midwestern U. S.
A survey to obtain representative fuel oil characteristics
indicated that compositions of fuel oil, like coal, vary
50
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considerably. Since sulfur content
less than for coal, concentrations
sulfur were assumed. These are
reported in the literature. A No. 6
gravity and an ash content of 0.
representative fuel and a typical
18,500 Btu/lb or 149,000 Btu/gal
levels (75).
of fuel oil generally is
of 1.0, 2.5, and 4.0%
fairly typical of values
fuel oil with a 15° API
1% is assumed to be a
total heating value of
is assumed for all sulfur
Flue Gas Composition
To serve as a basis for flowsheet calculations, it is desirable
to define distinct flue gas compositions for both coal- and
oil-fired systems. Although NOX removal by the magnesia
process is not well enough defined to justify detailed
treatment in this report, flue gas compositions will include
an NOX concentration. In doing so, it is necessary to give
NOX special consideration since its concentration, unlike
S02, depends primarily on boiler design, excess air, and
flame temperature, rather than fuel characteristics.
Available literature sources indicate that for various
types of coal-fired boilers NOX concentrations range from
about 200 to 1200 ppm by volume (5, 25), whereas,
concentrations for similar type oil-fired boilers range from
about 100 to 900 ppm (3, 4). Since the concentrations vary
over a wide range, compositions of flue gas are estimated
for two of the more common boiler types for both coal-
and oil-fired units. Pulverized coal (horizontal, frontal-
fired) and cyclone-fired boilers were considered for the
coal-fired units, whereas, tangential-fired, and horizontal,
frontal-fired boilers were considered for the oil-fired units.
The concentrations of NOX in the flue gas from these type
boilers are included in the estimated flue gas compositions
presented later.
As in the previous conceptual design reports, flue gas
compositions for coal firing are based on combustion with
20% excess air to the boiler, and 13% additional air
inleakage at the air preheater. These values reflect operating
experience with TVA frontal-fired, coal-burning units. For
oil-fired units, flue gas compositions were estimated
assuming 5% excess air to the boiler with an estimated 10%
air inleakage at the air preheater. Reflecting coal-fired
boiler operating experience, it was assumed that 75% of the
ash present in coal is emitted as fly ash from pulverized coal
(horizontal, frontal-fired) boilers, whereas only 25% of the
ash is emitted from cyclone-fired boilers. For the oil-fired
units, it was assumed that all of the ash in the fuel oil is
emitted. The complete flue gas analyses covering both fuels
are given in tables 11 and 12.
Emission Standards
The EPA has established emission standards for new steam
generating facilities as shown in table 13 (29).
In this report, process and equipment designs will meet
the standards for particulate and S02 emission. As
indicated earlier, the magnesia process does not appear to
be capable of reducing NOX emission more than 10% at
best and should not be relied upon for meeting NOX
emission standards. A more successful approach might be
accomplished by modifying the boiler firing system.
Furthermore, some commercial boilers currently available
are capable of meeting NOX emission standards.
Plant Location
Sulfuric acid is one of the world's most widely used
industrial chemicals. Although it is consumed in large
quantities in many industrial applications, the largest end
use is for the production of phosphate fertilizers. In the U.
S., the Midwest is the area of greatest fertilizer usage and
for purposes of this study, it has been assumed that the
power unit is located in this section of the country. In
addition, location on a navigable river is desirable since it
may be possible to ship large quantities of sulfuric acid by
barge to fertilizer plants not located in the immediate
vicinity of the power plant.
For evaluation of the central processing concept
(Scheme D), metropolitan areas of Chicago, Illinois, and
Philadelphia, Pennsylvania, are arbitrarily chosen as loca-
tions for recovery systems since this concept appears
practical only for locations having many sources of sulfur
dioxide emissions. Shipping costs in these areas will be used
in the economic evaluation of Scheme D.
Plant Size and Status
The size of fossil-fueled power plants currently being built
ranges up to 1300-mw. At this time, the largest operating
unit is a 1130-mw TVA boiler; however, several other units
as large as 1300-mw are expected onstream in the next few
years (30). Although a considerable portion of the future
generating capacity will be from power units 500-mw or
larger, 200-mw and smaller units will continue to be
utilized. It is expected that the majority of the older and
smaller units will be operated as peaking stations; however,
some new 200-300-mw units may be used for base loads.
To determine the effect of power plant size on the
economics of sulfur dioxide recovery, three unit sizes, 200,
500, and 1000-mw, are given detailed attention in the
conceptual design. In addition, both new and existing units
are studied since they usually have differences in input heat
requirements, remaining years of operating, and installation
expense (new vs retrofit) for particulate and S02 removal
devices. Representative heat rates used in this study are
shown in table 14. These rates are assumed to be applicable
for either coal- or oil-fired units.
51
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Table 11. Estimated flue gas compositions for-coa)-fired boilers at
various nitrogen oxide and sulfur levels, percent by volume.
Boiler type
Nitrogen oxides in
flue gas, ppm by vol.
Sulfur content of
coal, % by wt
Flue gas composition,
% by volume
Nitrogen
Carbon dioxide
Oxygen
Water
Sulfur dioxide
Sulfur tioxide
Nitrogen oxides
Fly ash loading
Grains/SCF dry
Grains/SCF wet
Boiler type
Nitrogen oxides in
flue gas, ppm by vol.
Sulfur content of
oil, % by wt
Flue gas composition,
% by volume
Nitrogen
Carbon dioxide
Oxygen
Water
Sulfur dioxide
Sulfur trioxide
Nitrogen oxides
Fly ash loading
Grains/SCF dry
Grains/SCF wet
Pulverized coal
(horizontal, frontal-fired)
2.0
74.62
12.57
4.86
7.77
0.12
0.001
0.06
4.11
3.79
Table 1 2.
various
1.0
73.83
12.52
2.55
11.03
0.05
0.001
0.02
600
3.5
74.55
12.55
4.86
7.76
0.22
0.001
0.06
4.11
3.79
5.0
74.49
12.54
4.85
7.75
0.31
0.001
0.06
4.11
3.79
Estimated flue gas compositions for
nitrogen oxide and sulfur
Tangential-fired
200
2.5
73.73
12.37
2.55
11.19
0.14
0.001
0.02
0.035 0.036
0.031
0.032
2.0
74.59
12.57
4.83
7.77
0.12
0.001
0.12
1.37
1.26
oil-fired boilers
Cyclone-fired
1,200
3.5
74.52
12.55
4.83
7.76
0.22
0.001
0.12
1.37
1.26
at
5.0
74.46
12.54
4.82
7.75
0.31
0.001
0.12
1.37
1.26
levels, percent by volume.
4.0
73.64
12.21
2.54
11.37
0.22
0.001
0.02
0.037
0.033
1.0
73.81
12.52
2.53
11.03
0.05
0.001
0.06
0.035
0.031
Horizontal, frontal-fired
600
2.5
73.71
12.37
2.53
11.19
0.14
0.001
0.06
0.036
0.032
4.0
73.62
12.21
2.52
11.37
0.22
0.001
0.06
0.037
0.033
Plant Life, Operating Time, and Capacity Factor
Based on power plant evaluation guidelines suggested by
the Federal Power Commission (31), the expected
operating life of a new fossil-fueled power unit is about 30
years. Historically, the highest operating rates (onstream
time) occur during the first 10 years of operation and
decline thereafter. Reflecting TVA experience (83), table
15 shows the power plant operating schedule assumed in
this study. This schedule is equivalent to a chemical plant
operating at 8000 hr/yr for 16 years.
Since existing power units can be expected to have less
remaining years of operation at high capacity factors,
power plant age is also an important parameter. In this
study, existing 200-mw units are assumed to have
22 years remaining life (8 years old) and 500-mw
and 1000-mw units are assumed to have 27 years
remaining life (3 years old). In each case, the first
52
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Table 13. Emission standards for
new steam generating facilities.
Allowable emission,
pounds per million
Btu heat input
Boiler type
Participates
Sulfur dioxide
Nitrogen oxide, expressed as N02
Coal fired Oil fired
0.1 0.1
1.2 0.8
0.7 0.3
Table 14. Power unit input heat requirements
Unit size, mw
1,000 new
1,000 existing
500 new
500 existing
200 new
200 existing
Btu/kwh
8,700
9,000
9,000
9,200
9,200
9,500
Table 15. Assumed power plant capacity schedule.
Capacity factor, % Annual kwh/kw
Year of life (nameplate rating) capacity
1-10
11-15
16-20
21-30
80
57
40
17
7,000
5,000
3,500
1,500
few years of operation at a high capacity factor are
assumed lost.
When considering sulfur dioxide control processes for
power plants, both the tendency of units to decline in
utilization over their operating life and the intermittent
operation on a daily basis due to electrical demand
variation should be recognized. For recovery processes in
particular, the associated large investment requirements and
market commitments usually make it desirable to operate
the recovery system at a high capacity factor to minimize
the effect of the continuing fixed capital charges on unit
production costs.
Maintaining a high capacity factor may not be possible
where a single facility is involved (as in Schemes A, B, and
C); however, by utilizing the central processing concept
(Scheme D), the effect of fluctuations in power plant load
and operation can be minimized for the regeneration and
sulfuric acid systems. Using feed material from several
independent sources, this unit can operate on a more
uniform schedule similar to that of most chemical plants,
say, 8,000 hr/yr. For purposes of this report, it is assumed
that the operating life of the central processing unit is 10
years. If shipping costs are not excessive, such a system
should be more economical than units tied to a single
power plant boiler.
Flue Gas and Sulfur Dioxide Rates
The parameters which determine the amounts of flue gas
and sulfur oxides emitted from coal- and oil-fired power
units have been discussed. Since design of sulfur dioxide
recovery units is dependent upon actual quantities of gas
and S02 as well as gas compositions indicated earlier,
calculated flue gas and equivalent sulfur dioxide emission
rates as both S02 and sulfuric acid are tabulated in table
16. Volumetric flue gas rates to the scrubbing system are
based on a gas temperature of 310° F at the exit of the air
preheater.
Degree of Sulfur Dioxide Removal
From the analyses of fuels and Federal emission standards
presented earlier, it can be seen that required S02 removal
efficiencies vary depending on the sulfur content and type
of fuel. The required removal efficiencies are tabulated in
table 17 for the various fuels and sulfur levels considered in
this study.
Before emission standards were defined, previous con-
ceptual designs arbitrarily provided for 90% removal of
sulfur dioxide from the stack gas. Since test data show that
three of the four magnesia scrubbing schemes are capable of
achieving this degree of sulfur dioxide removal, a 90%
removal efficiency also is provided for these systems so that
comparisons with previously studied processes can be made.
Indications are that the fourth scheme, the clear liquor
process, may be capable of only 70-85% S02 removal;
therefore, only design provisions necessary to meet the
emission standard will be provided.
Stack Gas Reheat
The need for stack gas reheat for plume buoyancy has been
recognized, but the degree of reheat required has not been
well established. The effect of temperature on plume
buoyancy and ground-level concentration of stack gas
constituents was studied in detail for the limestone-wet
scrubbing conceptual design (89). The results indicated that
with a high degree of sulfur dioxide removal (80% or
above), the stack gas temperature is not critical. However,
to prevent high ground-level concentrations during adverse
atmospheric conditions, reheat from 125 to 175° F is
provided in this conceptual design.
In the magnesia process, some reheat is obtained from
dryer offgas and exhaust fan compression, but additional
heat is needed to reach 175° F at the stack exit. For new
coal-fired power units, indirect steam reheat is provided
since new units can be designed to supply steam to the
53
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Table 16. Flue gas and sulfur dioxide emission rates
Power plant Type
size, mw plant
Coal-fired units
200 New
200 Existing
500 New
500 New
500 New
500 Existing
1,000 New
1,000 Existing
Oil-fired units
200 New
200 New
200 New
200 Existing
500 New
500 New
500 New
500 Existing
1 ,000 New
1 ,000 New
1 ,000 New
1 ,000 Existing
Sulfur content
of fuel, %
3.5
3.5
2.0
3.5
5.0
3.5
3.5
3.5
1.0
2.5
4.0
2.5
1.0
2.5
4.0
2.5
1.0
2.5
4.0
2.5
scrubbing area. In cases of existing coal-fired and both new
and existing oil-fired power units,
provided from combustion of fuel oil
limestone-wet scrubbing conceptual
direct gas reheat is
. As discussed in the
design study, other
reheat methods can be utilized; however, these two are
probably the simplest to install and most reliable for their
respective applications. They are probably in the mid-cost
range as compared to other choices such as cyclic liquid-gas
heat exchange and gas to gas heat exchanger.
Dust Removal
Gas flow
to scrubbers,
acfm(310°F)
630 M
650 M
1.540M
1,540M
1,540M
1,570M
2,980 M
3,080M
530 M
530 M
530 M
550 M
1,300M
1,300M
1 ,300 M
1 ,320 M
2,510M
2,510M
2,510M
2,590 M
Table 17.
Fuel
Coal
2.0% S
3.5%S
5.0% S
Oil
1.0% S
2.5% S
4.0% S
Equivalent
sulfur dioxide
emission rates
Lbs SOJhr
9,310
9,610
13,010
22,760
32,510
23,270
44,000
45,520
1,990
4,960
7,940
5,130
4,850
12,140
19,420
12,410
9,390
23,470
37,540
24,280
Required SO2 removal
Tons 100%
H2S04/hr
7.1
7.4
10.0
17.4
24.9
17.8
33.7
34.9
1.5
3.8
6.1
3.9
3.7
9.3
14.9
9.5
7.2
18.0
28.7
18.6
efficiencies.
Required degree
of SO 2 removal, %
60.9
77.6
84.4
26.0
70.4
81.5
Combustion of pulverized coal containing 12% ash in a
frontal-fired boiler results in a dust emission of 7.5
Ib/million Btu (~4 grains/acf) at the boiler exhaust; with a
cyclone boiler, the fly ash content is about one third this
amount. Combustion of fuel oil containing 0.1% ash
produces a dust emission of 0.054 Ib/million Btu (0.04
grain/cu ft). A comparison of these dust loadings with the
emission standards given earlier indicates the need to
remove a minimum of 98.6% of the dust emitted frorn coal,
frontal-fired boilers to meet Federal emission standards,
whereas no additional facilities are required for oil-fired
units unless dictated by local law.
Because of the regenerative and cyclic nature of MgO
scrubbing processes, it is necessary to minimize the amount
of contaminants which are introduced into the sulfur
dioxide scrubbing loop. Since high dust removal efficiencies
are desirable to prevent possible contaminant buildup, the
processes are designed to attain at least 99% dust removal.
The most common types of equipment for controlling
particulate emissions are mechanical collectors, fabric
filters, eletrostatic precipitators, and wet scrubbers; how-
ever, mechanical collectors are not capable of attaining high
removal efficiencies, and fabric filters are generally too
expensive for use in handling large volumes of flue gas.
Presently, electrostatic precipitators are the most widely
54
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accepted type of equipment for control of fly ash in
modern power plants, but experience has shown these units
to be expensive to install and maintain and occasionally
unreliable for attaining high removal efficiencies over long
periods of time. Wet scrubbing of flue gas has the
disadvantage of lowering the temperature and buoyancy of
the gas by humidification. Since the MgO schemes control
SO 2 emission by wet scrubbing, provisions for reheat are
required regardless of the method used for dust removal;
thus, wet scrubbing is the logical method for removing dust
in these schemes.
Many existing coal-fired power units already have
electrostatic precipitators in operation, but some are not
capable of attaining the desired removal efficiency.
Arbitrarily, it will be assumed that these precipitators will
be kept in operation. However, due to the need for
maximum dust removal discussed above, existing coal-fired
units will also be equipped with particulate scrubbers
capable of attaining dust removal efficiencies of 99%.
Amount of Storage
The amount of storage which should be provided for a
product depends largely upon its consumption rate for each
end use. Since sulfuric acid is an intermediate product
which usually undergoes further processing, the largest
storage burden is often passed on to the industrial
consumer rather than the producer. However, to provide
for large consumer and cyclic markets such as the phos-
phate fertilizer industry, storage requirements of 30 days or
more are not uncommon. In this study, 30 days storage is
provided, with facilities included for up to three product
acid concentrations. In addition, 4 weeks storage is
included for fresh makeup MgO and coke. A minimum
period of 1 day is provided for in-process storage of MgSO3
and recycle MgO to give some flexibility of operation. For
the central processing concept (Scheme D), MgSO3 and
recycle MgO storage is increased to 3 days to cover possible
transportation delays.
Base Case
The base case chosen for Schemes A, C, and D of the
magnesia scrubbing conceptual design is a new 500-mw
power unit with a horizontal, frontal-fired boiler utilizing
coal containing 3.5% sulfur. The base case chosen for
Scheme B, the MgO-Mn02 variation, is a new 500-mw
power unit with a horizontal, frontal-fired boiler utilizing
fuel oil containing 2.5% sulfur. Although several cases for
both coal- and oil-fired units are evaluated in this report,
flowsheets are presented for the base cases only, since most
of the detailed design and cost data were obtained for these
systems, and a major effort would be required to present
separate flowsheets for each case.
Process Flowsheets
Process flowsheets and material balance tables representing
base case conditions for each scheme are shown in
Appendix B and are designated as follows:
Figure
Scheme A- B-l
B-2
Scheme B - B-3
B-4
Scheme C - B-5
B-6
Scheme D - B-7
B-8
Solid Waste Disposal
Fly ash collected in the particulate scrubbers of coal-fired
power plants is pumped as an 8 to 20% solids slurry to a fly
ash storage pond. In this study it is assumed that the ash is
allowed to settle and clarified water is recycled back to the
particulate scrubbers to minimize the consumption of fresh
water and to reduce contamination of nearby streams. A
power plant to pond distance of 1 mile is assumed for cost
estimates. Although not required in all cases, costs for ash
neutralization facilities are included in the investment, and
slaked lime is provided for neutralization of S03 absorbed
in the particulate scrubbers.
Insoluble contaminants removed from the S02 scrubber
system by purge treatment are disposed in the ash pond.
Concentrated soluble contaminants from the system are
pumped to an evaporative pond for direct disposal, with no
return of water.
Miscellaneous
The increased pressure drop of flue gas due to operation of
wet scrubbers requires that higher energy fans be provided.
For new power units, a single fan capable of overcoming
the pressure drop incurred in both the boiler and scrubbing
equipment is included for each duct. The investment cost
assigned to the scrubbing area is assumed to equal the
incremental cost between a new fan to handle the total
pressure drop and one to handle the pressure drop of the
power unit alone. For existing units, the investment cost of
new fans to handle the pressure drop of the scrubbing
system alone is provided. The operating cost for these fans
is divided between the power plant and the recovery unit
according to the pressure drop incurred in each area.
An optional bypass duct is provided for each scheme to
allow for continued operation of the power plant during
unscheduled shutdown of the scrubbing system. The
55
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investment for the bypass ducts is itemized separately in For Schemes A, B, and C representing on-site facilities,
the cost tables (Appendix A). Flue gas ducts are designed magnesium oxide losses due to handling and conveying are
for average gas velocities of 50 ft/sec. assumed to be 2.0%. Losses for Scheme D, which represents
Spare pumps are provided to prevent operational shut- off-site central processing and requires considerable
downs due to pump failure; however, no other spare additional materials handling, are assumed to be 3.0%, 50%
equipment is included in the estimates. greater than for on-site operations.
56
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EQUIPMENT SELECTION AND DESCRIPTION
The facilities required for scrubbing stack gas with magnesia
slurry and regeneration of the absorbent can be divided into
the following major equipment categories:
1. Particulate control
2. Sulfur dioxide absorption and stack gas reheat
3. Slurry or solution processing
4. Sulfite drying-calcining
5. Magnesia slurry preparation
6. Sulfuric acid production
7. Sulfuric acid storage
8. Fuel oil storage
9. Optional bypass duct
Prior to description of specific equipment items for each
category, several alternatives are considered with emphasis
on both performance and cost. A discussion of the major
alternatives for the magnesia schemes along with available
data, curves, and design information follows.
Scrubbing Alternatives
Particulate control— Combustion of pulverized coal con-
taining ash results in the release of much of the ash as fine
dust particles that escape, at least partially, with the
combustion gas. Although the composition of the ash varies
widely from source to source, a typical ash composition of
a western Kentucky coal is indicated in table 18 (84).
As discussed earlier, the portion of ash present in the
coal which eventually is emitted depends upon the type of
boiler: a pulverized coal (horizontal, frontal-fired) boiler
typically emits about 75% of the ash present in the coal as
fly ash, as compared to approximately 25% for cyclone-
fired boilers. Although the particle size distribution of fly
ash is likely to vary considerably, a sample distribution is
shown in table 19 (87).
As mentioned earlier, wet scrubbing was selected as the
method for controlling particulate emission in the magnesia
schemes. Of the various types of wet scrubbers available, a
venturi was chosen for control of particulates since it is
generally considered to be the least costly device capable of
attaining the high dust removal efficiencies desired. The
Babcock and Wilcox Company has reported specific data
for removal of fly ash from the combustion gases of a
pilot-size, coal-fired boiler using a venturi scrubber (27).
This data, presented in figure 44, shows a relationship
between pressure drop and fly ash collection efficiency at
an L/G of 15 gal/Macf and is used in this report.
Several methods of fly ash disposal, including trucking
to off-site locations and on-site ponding, are used in the
industry. For the magnesia cases studied, only the on-site
ponding technique is considered. Off-site disposal would be
more expensive for large power units; however, this may
not be true for small units.
In the on-site ash disposal system, effluent from the
particulate scrubbers is received in a surge tank designed for
partial clarification of the recycle stream. A thickened
underflow containing about 8-20% fly ash is pumped to an
on-site fly ash disposal pond, and a return line and pumps
are provided for recycle of clarified pond water to the
particulate scrubbers. The distance from the scrubbers to
the pond is assumed to be 1 mile.
Table 18. Typical ash composition
of a western Kentucky coal (84).
Constituent
Percent by weight
CaO
MgO
A10
23
SiO,
K20
Na20
Unknown
6.1
1.1
20.5
16.9
44.9
1.9
0.8
0.3
7.5
100.0
Table 39. Particle size distribution of fly ash (87).
Particle size, Percent of total Percent
microns number of particles by weight
0.5 and smaller
1
2
3
4
5 to 9
10 to 100
57.2
20.5
10.6
5.2
3.0
3.0
0.5
100.0
0.13
0.37
1.5
2.5
3.5
17.0
75.0
100.0
57
-------
99.8,
99.6
99.4
99.2
99.0
98.5
98.0
- ~15gal/Macf
G
4.0
5.0 6.0 7.0
Venturi pressure drop, inches HjO
8.0
Figure 44. Effect of pressure drop on particulate collection
efficiency for a venturi scrubber (27).
In many cases, the effluent from the fly ash scrubber is
acidic with initial pH determined partially by the amount
of sulfur dioxide or sulfur trioxide absorbed in the
particulate scrubber. The composition and amount of fly
ash collected in the particulate scrubber also affects the pH
of the scrubber effluent; however, slow response times are
normally encountered because fly ash is relatively insoluble
and the final pH is not quickly attained. Although the
composition of fly ash is likely to vary for different coal
sources, operating experience in the TVA system indicates
that a basic pond water is normally encountered when dry
collected fly ash is sluiced with water. Since little experi-
ence is available to indicate the final pH which would result
from prolonged contact of an acidic scrubber effluent with
a basic fly ash, slaked lime addition facilities can be
included in the fly ash disposal circuit for neutralizing all
sulfur oxides absorbed in the particulate scrubber. This
measure may not be necessary for all applications; however,
it provides insurance agairtst possible leakage of acidic pond
water into other streams.
Sulfur dioxide absorption and stack gas reheat—The
absorber types considered for stack gas magnesia scrubbing
processes include packed, tray, mobile bed, venturi, and
spray devices. Packed and tray scrubbers are the most
common absorbers used in the chemical industry; how ever,
they are not often used for slurry service due to their
tendency to plug. Based on discussions with vendors of
these devices, it is recommended that they not be used in
Schemes A, B, and D which utilize slurries and are expected
to have a tendency to form scale deposits. For the clear
liquor process which requires simultaneous particulate and
S02 removal, these scrubber types are suitable for the
sulfur dioxide absorption; however, they are generally not
effective for attaining high dust removal efficiencies, and
their use in magnesia scrubbing is questionable.
The mobile bed, venturi, and spray absorbers are capable
of operating with either clear liquor or slurry absorbents
and can be considered for all four magnesia process
schemes. Scaling is less a problem for mobile bed absorbers
because the turbulent action of the internal bouncing balls
minimizes accumulation. Also, scaling is usually not a
problem for venturi absorbers because high gas velocities
and simple internal design inhibit scale formation. Because
of the high gas velocities, however, venturi absorbers
generally consume more energy from the gas and result in
higher operating pressure drops than other type absorbers.
Spray absorbers usually operate with greater residence time
and lower pressure drop than venturi absorbers by utilizing
gas velocities similar to packed, tray, or mobile bed
absorbers. However, they do not contain internal packing,
and absorption efficiencies are generally lower than for the
above type absorbers. Scaling can be minimized in spray
scrubbers by designing for high liquid to gas ratio which
reduces the effect of solids formation; the flushing action
of high irrigation rates tends to prevent accumulation of
deposits. In the spray scrubber application developed by
Grillo for MgO-Mn02 scrubbing (Scheme B), a high gas
velocity is utilized (49 ft/sec), but the added manganese
dioxide is said to promote the rapid absorption necessary to
achieve good efficiency.
The absorption of sulfur dioxide from power plant stack
gas by magnesia scrubbing has been evaluated by the
Babcock and Wilcox Company for both mobile bed and
venturi absorbers and by Chemico Basic for the venturi
type. It is understood that the spray absorber is the only
device Grillo has tested using the MgO-Mn02 slurry
concept.
The conceptual designs of the magnesia schemes are
based on the relationships which follow.
The effect of liquid to gas irrigation ratio on sulfur
dioxide absorption efficiency for slurry scrubbing with a
mobile bed absorber is shown in figure 45 (27). A similar
relationship for slurry scrubbing using a venturi absorber
(12) is shown in figure 46. The data indicate that sulfur
dioxide removal efficiency increases with an increase in
L/G. Both absorber types are capable of attaining sulfur
dioxide absorption efficiencies of 90% or greater; however,
a venturi absorber requires a higher operating L/G to
58
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98
96
£-94
90
80
MgO Slurry scrubbing
pH ~ 5.0-7.8
^P ~ 4.0-6.6" H,0
Gas velocity ~ 13-14 ft/sec
10
20
L/G, gal/Macf
30
40
Figure 45. Effect of liquid to gas
irrigation ratio on sulfur dioxide absorption
efficiency for a mobile bed absorber (27).
98
96
94
92
90
80
I I
MgO slurry scrubbing
pH ~ 8.0
Gas velocity ~ 75 ft/sec
= 6.4"H20 —
10
20 30
L/G, gal/Macf
40
50
Figure 46. Effect of liquid to gas irrigation ratio on sulfur
dioxide absorption efficiency for a venturi absorber (12).
achieve the same absorption efficiency as that of a mobile
bed absorber.
The effect of liquid to gas irrigation ratio on sulfur
dioxide absorption efficiency for spray scrubbing using the
MgO-Mn02 slurry variation is shown in figure 47 (61).
These results indicate that the spray scrubber is capable of
achieving high sulfur dioxide absorption efficiencies at
relatively low values of L/G for this process.
A linear relationship exists between pressure drop and
L/G for slurry scrubbing with a mobile bed absorber as
indicated in figure 48 (27). The effect of pressure drop on
S02 absorption efficiency for slurry scrubbing with a
venturi (27) is indicated in figure 49. Although the
correlation is based on a minimum amount of data at
elevated pressure drops, it is in close agreement with similar
data obtained by Chemico-Basic during slurry scrubbing
tests at the Canal Electric Company (12).
Since pH is a function of the scrubbing liquor com-
position, the effect of pH on absorption efficiency is an
important parameter, as indicated in figure 50 (27), for
slurry scrubbing using a mobile bed absorber operating at
various pressure drops. The data indicate that increased
absorption efficiencies are obtained with either increased
pressure drop or higher pH. A similar relationship for a
venturi absorber is shown in figure 51 (27). The solid curve
represents actual data for a venturi absorber operating at a
pressure drop of 1.5 in. of water. Since data were not given
for absorption efficiencies at higher pressure drops, the
dashed curve is projected based on data for venturi
absorbers operating at higher pressure drops as indicated in
figures 46 and 49.
The effect of pH on sulfur dioxide absorption efficiency
for spray absorption using the MgO-Mn02 slurry scheme is
shown in figure 52 (40).
Best operation for this process variation is reported to be
at pH values ranging from 6.0 to 7.5.
Clear liquor scrubbing processes can be designed to
operate either at a low pH (5.0-6.0) with moderate
concentrations of soluble magnesium bisulfite-sulfite
absorbent in the liquor or a higher pH (6.5-7.5) with low
concentrations of soluble absorbent. The main disadvantage
of the low pH method is the high solution vapor pressures
of S02 which restrict achievable absorption efficiencies.
For higher pH values near 7.0, control is difficult, especially
in restricting scale deposition from solids formation. The
very low solubility of absorbent with basic pH values
requires extremely high liquor to gas irrigation to provide
for the desired amount of absorption. Although test work
59
-------
94
92
90
580
70
50
Gas velocity, ft/sec
~ O 49.0
0 37.0
A 24.5
MgO-Mn03 slurry scrubbing
8.0
02468
L/C, gal/Macf
Figure 47. Effect of liquid to gas irrigation ratio on sulfur
dioxide absorption efficiency for a spray absorber (61).
7.0
O
X
6.0
5.0
4.0
MgO slurry scrubbing
Two stage absorber
Gas velocity ~ 13-13.4 ft/sec
10
20 30
L/G, gal/Macf
40
50
Figure 48. Effect of liquid to gas irrigation ratio on
pressure drop for a mobile bed absorber (27).
98
96
94
.2 92
•§ 90
80
70
I
MgO slurry scrubbing
L/G = 30 gal/Macf
pH> 7.0
o
O/
0 /
/ o
J_
o/ H
/
/
/
/ o
/
J_
_L
246
Venturi pressure drop, inches H2O
Figure 49. Effect of pressure drop on sulfur dioxide
absorption efficiency for a venturi absorber (27).
10
99.6
99.4
MgO slurry scrubbing '
Gas velocity ~ 13-13.4 ft/sec
Liquid to gas ratio, gal/Macf
A 29-30
O 18-19
Q 9.6-13
7 2
70
6.0
8.0
7.0
Slurry pH
Figure 50. Effect of slurry pH on sulfur dioxide
absorption efficiency for a mobile bed absorber (27).
9.0
60
-------
96
MgO slurry scrubbing
L/G,gal/Macf
94 -
92
V
o
A
D
39
31 -36
26
21
90
-x
80
70
60
~ 1.5"H20
50
I
Projected from
previous data
I
5.0
6.0
8.0
7.0
Slurry pH
Figure 51. Effect of slurry pH on sulfur dioxide
absorption efficiency for a venturi absorber (27).
9.0
MgO - MnO2
slurry scrubbing
60
6.0
6.5
7.0
8.0
8.5
7.5
Slurry pH
Figure 52. Effect of slurry pH on sulfur dioxide
absorption efficiency for a spray absorber (40).
on the clear liquor scheme has been limited, unpublished
data provided by Chemico-Basic for absorption of S02
from pulverized coal combustion gas using a venturi
scrubber indicates the efficiency attainable. The data,
tabulated in table 20, were obtained for operation of the
venturi at pressure drops ranging from 12.5 to 15.0 in. of
water and at an L/G of approximately 20 gal/Macf.
The effect of other parameters on sulfur dioxide
absorption efficiencies by magnesia slurry scrubbing which
were determined in the EPA-Babcock and Wilcox pilot
program are discussed below.
1. Absorption increases with increasing MgO to S02
stoichiometric ratio to a molar ratio of 1.0. Above this
value absorption does not increase significantly.
2. The presence of fly ash in the gas to the sulfur
dioxide absorber does not affect sulfur dioxide absorption
levels.
3. The presence of high concentrations of dissolved
magnesium sulfate reduces sulfur dioxide absorption in the
low pH range. At higher pH, sulfur dioxide absorption is
not affected.
4. Conversion of magnesium oxide to the hydroxide
before injection into the absorber does not improve sulfur
dioxide absorption.
5. Increasing the total liquid holdup time including the
time in the sump does not improve sulfur dioxide
absorption.
Because of the lack of pilot plant data to verify
absorption capabilities, spray scrubbers were not selected
for Schemes A, C, or D. By the same reasoning, venturi and
mobile bed absorbers were not utilized as the scrubber type
for Scheme B. Before considering these alternate scrubber
choices, operation of a spray scrubber without Mn02
activator should be tested as well as operation of venturi or
mobile bed absorbers with MnO2 addition, since variations
are likely.
Mobile bed absorbers appear to be more effective than
venturi absorbers for absorption of S02 in magnesia
slurry, but both types appear capable of reducing S02 to an
acceptable level. Therefore, costs and actual performance
over extended periods become the primary considerations
for selection. In discussions with vendors, it was determined
that several different designs and materials of construction
Table 20. Absorption efficiencies attainable
with clear liquor scrubbing scheme.
Recirculating liquor, pH
6.0
5.8
5.7
5.5
5.5
5.2
Absorption efficiency, %
76
71
77
77
81
72
61
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are being considered, but that predicted total costs (invest-
ment and operating) for complete systems of either venturi
or mobile bed scrubbers are very close. Selection for an
actual installation should be based on the latest cost
quotations and performance results to determine which
absorber is more attractive. For purposes of this report, the
design parameters required for both types of scrubbers will
be given with the equipment descriptions to follow and the
flowsheets in Appendix B will reflect the ranges of liquid
irrigation necessary for both devices. Cost data given in the
text and the Appendix A tables on the sulfur dioxide
portion of the scrubbing system for Schemes A, C, and D
are probably closer to the venturi option.
Design provisions for operational turndown or tempo-
rary shutdown of any one magnesia scrubbing system will
depend primarily on how that unit operates in its total
system. Base load power units of large size will not require
as extensive flexibility as smaller units used in peaking
service. Generally, 200-mw systems with as many as six coal
feeders are not operated at less than 25-33% of load so that
in the event of failure in a feed system at least one
operating feeder is left. If other power generation facilities
are available, midrange base load units such as a 500-mw
facility are usually restricted to a turndown around 50-60%;.
operation at loads less than 50% justifies complete shut-
down and shift of load to a smaller peaking unit.
Several methods are available to provide turndown
capabilities including:
1. Multiple scrubbing trains
2. Variable flow control to individual scrubbers
3. Compartmentalized scrubbers
4. Individual scrubber bypasses
5. Connecting plenum ducts between trains
These different methods affect both duct and scrubber
design and, unfortunately, little experience is available to
indicate which method is best. In limited TVA pilot plant
tests of a Turbulent Contact Absorber (mobile bed type)
with limestone scrubbing, reasonable dust and S02 removal
efficiencies were maintained during operation at gas rates as
low as 50% of design capacity. In the large scale demonstra-
tion systems for S02 removal being constructed in 1972
around the country, a variety of these alternatives are being
utilized, in many cases, provision is made for more than one
alternative.
For this conceptual design study, a variable throat
control is provided for the particulate venturi to maintain
high gas velocities when operating at reduced gas rates.
Other than possible changes in liquid circulation rate, no
specific provisions are included for the S02 scrubbers. To
provide isolation for temporary shutdowns, each train of
scrubbers is equipped with sufficient shutoff dampers and a
bypass duct; however, when using these provisions, a
portion of the boiler gas is exhausted without particulate
and SO2 control.
The use of a mist eliminator in the SO2 scrubber exit gas
duct is desirable for the following purposes:
1. To reduce the load on the stack gas reheater.
2. To decrease the deposition of liquid and entrained
solids in ducts and equipment located downstream from the
scrubber.
3. To reduce the amount of solids emitted to the
atmosphere as entrained dust.
4. To minimize the amount of makeup MgO required to
compensate for losses out the stack.
For maximum efficiency and extended service, mist elimi-
nators should be designed for proper gas distribution and
include facilities for removing any accumulated solids.
In previous process studies (87, 89) several types of mist
eliminators were evaluated. The simplest and most common
are the impingement vane types in which the shape of the
vanes and their arrangement cause impaction and coales-
cence of the mist. Other types of entrainment separators
evaluated included centrifugal vane, wire mesh (York), fiber
bed (Brink), cyclonic, and packed bed (6-12 in. of
Tellerettes, Pall Rings, or other packing). Although it may
be possible to adequately reduce mist with these devices,
there is some uncertainty about the ability of some types to
operate in slurry service without plugging. Presently more
large-scale gas scrubber installations are utilizing chevron
vane type mist eliminators, or slight modifications, because
they are generally considered the type least likely to plug.
Although experience in power unit service is limited,
scrubber vendors are recommending the use of fiberglass
reinforced polyester chevron vane type mist eliminators for
the magnesia schemes; therefore, such devices will be used
in this study. Considerable doubt still exists as to their
effectiveness and reliability over long periods of time;
however, extended tests such as the Boston Edison demon-
stration should provide better information than currently
available.
Various methods for supplemental reheat of the stack
gas were discussed in previous conceptual design studies.
For this report the alternatives are repeated and updated
where additional information applies. Portions of the
required flue gas reheat are obtained from heat of compres-
sion of the gas in passing through the induced draft fans
and from direct addition of dryer exhaust to the main flue
gas stream; however, supplemental heat is required to
obtain a stack gas outlet temperature of 175° F. Table 21
shows the expected temperature rise or loss of the gas in
passing through the system.
Additional heat may be supplied by installing a combus-
tion system at the base of the power plant stack for burning
natural gas, oil, or coal and mixing the combustion
products with the scrubber exit gas. The main advantages
for this method are moderately low investment, flexibility
in degree of reheat, minimum added pressure drop, low
maintenance, and good reliability. Disadvantages are fuel
62
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Table 21. Flue gas temperature.
JZ
Exit temperature from mist eliminator 127
Expected temperature rise through induced draft fan 14
Expected temperature rise from dryer offgas 5
Expected temperature loss in stack -4
Reheat required 33
Net temperature out of stack 175
cost, introduction of objectionable components (S03, S02,
and ash) into the gas, and fuel supply problems. Natural gas
is the most desirable fuel; however, gas supplies are
extremely limited and probably restricted from many
power plants. Oil would be more expensive, but since
already required by the process, a practical alternative. Use
of coal could result in the lowest fuel cost, but would add
more sulfur dioxide and ash to the stack gas. The fly ash
emission could be minimized by firing the coal on a grate
stoker.
A second reheat choice is to bypass the scrubber with
part of the gas stream and mix this gas with the scrubber
exit gas. This procedure requires minimum investment and
has essentially no operating cost. However, it requires that
higher particulate and SO2 removal efficiencies be obtained
in the scrubber since a portion of the gas is emitted to the
atmosphere without being scrubbed. This is not a desirable
alternative.
A third reheat method uses heat exchangers for direct
transfer of heat from the scrubber inlet gas to the exhaust
gas. With this method, heat that would be wasted is
recovered. Further advantages are reduction in the amount
of water required for evaporative cooling, a corresponding
reduction in gas volume and, except for maintenance, no
labor requirement. Disadvantages are the large heat
exchanger required (because of low transfer coefficient and
temperature differential), high pressure drop, and possi-
bility of fouling-which would lead to low efficiency and
high maintenance cost. Corrosion by sulfur trioxide would
be a problem.
Using a cyclic-liquid heat exchange system with heat
transfer from the inlet gas to treated water and from the
water to the scrubber exhaust gas is another alternative.
The better heat transfer coefficient would permit use of
smaller exchangers than those required for gas-gas exchange
and the smaller surface would reduce pressure drop and
maintenance. Fouling, corrosion, and erosion problems are
major disadvantages.
Heating with steam from the turbine cycle in a heat
exchanger at the scrubber outlet is one of the more popular
reheat techniques. This method would require additional
fuel in the boiler to generate the extra steam and
modification of the turbine to allow higher than normal
extraction rates. Extensive modification of existing units
would be impractical, but in a new plant a system could be
included to provide the steam required.
Use of steam for reheat would require relatively small
heat exchangers installed only on the scrubber discharge
where if mist eliminators are effective, the gas should be
relatively clean. Corrosion, fouling, and pressure drop
would be minimized. The main disadvantage is the added
fuel requirement.
Finally, a sixth reheat system considered uses a cyclic
system comprised of heat exchange towers where liquid or
solid particles are sprayed into the gas stream ahead of the
scrubber and the sensible heat gained by the particles is
transferred to the scrubber exit gas in a similar chamber.
With this system, there would be no heat exchangers to foul
or corrode and the pressure drop would be low. With a
liquid, partial dust removal could be effected by filtering or
centrifuging the liquid from the "hot" tower. However, a
low vapor pressure over the liquid would be required to
prevent carryover to the scrubber and the liquid should be
nonflammable or have a high kindling temperature to
prevent fire hazard. Use of solid particles would require a
material with good abrasion resistance to withstand the
rough handling.
As discussed in the Study Assumptions and Design
Criteria section, at this time, simplicity and reliability are
more important considerations for selection of the method
for stack gas reheat than are costs. On a performance basis,
direct combustion and steam reheat are probably the most
desirable methods. Although other concepts may also prove
to be reliable, these two are chosen for use in the current
study. Because of lower cost and the ability to provide for
in the original design, the steam reheat method is incorpo-
rated in new coal-fired power units; all other cases utilize
the direct combustion method. Since fuel oil is used at each
plant to supply the heat for drying, it was selected as the
fuel for the combustion reheat systems.
There are three alternatives for location of the fan for
new coal-fired installations, including:
1. Upstream of the scrubbing system
2. Between particulate and sulfur dioxide scrubbers
3. Downstream from the scrubbing system
For new oil-fired installations the second location is not
applicable since particulate scrubbers are not utilized.
The selection of fan location largely dictates the choice
of fan. A wet fan is required for handling gases at saturated
conditions; whereas, a dry fan is applicable for handling
gases at temperatures above the dew point. Since the gas
temperature is about 310° F at the entrance to the
scrubbers, a dry fan is applicable for the first location.
Because of the higher gas temperature prior to gas
humidification and cooling this fan would handle the
largest volumetric flow. The gas at the second location is
saturated and a wet fan would be required. At the third
location, placement of the fan upstream of the reheater
63
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would require a wet fan, whereas downstream locations can
utilize the dry type. Use of a dry fan after reheat requires a
fan with a somewhat higher volumetric capacity, but this
location is generally considered to be the most desirable.
Although smaller quantities of particulates are present in
the gas to cause erosion at this location, deposition of
entrained solids may be a problem.
A dry fan installed downstream of the flue gas reheater
is assumed for this study. Use of a dry fan agrees with the
current TVA selection for the 550-mw Widows Creek
limestone scrubbing installation.
The type of installation (new or retrofit) and the type of
power plant, (coal- or oil-fired) largely dictates the design
specifications for the flue gas system. New power plant
installations can be designed to utilize one I.D. fan for each
duct to overcome the draft losses both in the boiler and in
the scrubbing system. However, for retrofit installations the
existing I.D. fan is not capable of overcoming the pressure
drop in the scrubbing system, and an additional fan is
required. The pressure drop encountered in oil-fired
installations is less than for coal-fired because oil-fired
systems do not include particulate scrubbers. The pressure
drop distribution shown in table 22 is assumed for
specification of the fans and determination of resulting
operating costs for Schemes A, C, and D installations on
coal- and oil-fired power units. Pressure drop in the Grillo
designed spray scrubber is understood to be only 2.2 in.;
therefore, for Scheme B cases, the applicable pressure drops
are adjusted downward by 2.3 in.
Slurry or Solution Processing
Each of the magnesia schemes is based on the formation of
magnesium sulfite with a minimum amount of oxidation to
sulfate and subsequent separation from the absorbent
liquor by further processing. In Schemes A, B, and D
crystalline magnesium-sulfur compounds are formed
directly in the circulating slurry and the precipitated solids
are recovered from the scrubber effluent for further
treatment. In Scheme C, the clear liquor variation, the
absorbed sulfur dioxide is present in the effluent as a
solution of magnesium compounds in a fly ash slurry, and
additional steps are required for separation of fly ash and
solution and reaction of clarified solution with magnesia to
increase the pH and precipitate the magnesium compounds.
The precipitated compounds can then be processed to
obtain a crystalline cake for feed to the dryer in the same
manner as used in the other three schemes.
Slurry or solution processing can be subdivided into the
following three functions:
1. Contamination control.
2. Hydrate conversion.
3. Solid-liquid separation.
Contamination control is required to reduce the amount
of impurities which will accumulate in the closed loop
sulfur dioxide absorber liquor. At this time little data are
available to define the magnitude and exact method for
control of the contaminants; however, this information
should become available after extended operation of the
Boston Edison demonstration system during 1972-73.
Both soluble and insoluble impurities are introduced
into the sulfur dioxide absorber. As indicated in the Process
Chemistry, Properties and Kinetics section of the report,
the majority of the soluble contaminants enter the system
in the makeup water. Additional soluble impurities from
makeup MgO are introduced in much smaller quantities
into the absorber. Based on the impurity data given, a new
500-mw power unit burning coal containing 3.5% S
introduces soluble contaminants into the sulfur dioxide
absorber liquor at the rates shown in table 23.
Insoluble contaminants are introduced into the sulfur
dioxide absorber chiefly as fly ash. For the slurry schemes
(A, B, and D) applied to coal-fired power units, approxi-
mately 1% of the fly ash emitted from the boiler is in the
gas at the inlet to the sulfur dioxide absorber. Even though
particulate scrubbers are not provided for oil-fired units,
quantities of fly ash in the gas to the sulfur dioxide
absorber would be smaller than for coal firing. For the clear
liquor scheme, all of the fly ash emitted from the boiler is
introduced into the sulfur dioxide absorber. Table 24
indicates the rates of introduction for new 500-mw units.
Although not all of this fly ash will be collected in the
circulating liquor, the values indicate the potential
magnitude of contamination.
It can be seen that the rate of input for insoluble
impurities is much greater than for soluble contaminants.
Equipment requirements for removal of contaminants
can not be well defined until operating results are available.
Because of differences in input rate of insoluble impurities
and the form in which the sulfur compounds exist,
Table 22. Assumed pressure drop through gas system in H2O.
Type unit
Coal— new
Coal-existing
Oil— new
Oil -existing
Boiler
15
-
15
-
Particulate
scrubber
8.5
8.5
-
-
S02
scrubber
4.5
4.5
4.5
4.5
Reheater
2.0
2.0
2.0
2.0
Duct
8.0
8.0
4.0
4.0
Total
38.0
23.0
25.5
10.5
64
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Table 23. Introduction rate of soluble
contaminants into sulfur dioxide absorber.
Soluble contaminant
rate, Ibs/hr
Major soluble From makeup
contaminant MgO
Calcium oxide, CaO
Sulfate ion, S04 =
Chloride ion, Cl"
Total major soluble
contaminant
0.040
0.008
0.007
0.055
From makeup
H20 Total
1.156
0.421
0.281
1.858
1.196
0.429
0.288
1.913
Table 24. Introduction rate of fly
ash into sulfur dioxide absorber.
Slurry schemes, coal fired
Slurry schemes, oil fired
Clear liquor scheme, coal fired
Fly ash rate,
Ib/hr
337
243
33,700
different contaminant control procedures are required for
slurry and clear liquor schemes.
For the slurry schemes, equipment can be provided for
reacting a portion of the slurry with sulfur dioxide in a
solubilizing tank, followed with removal of the fly ash by
filtration and disposal of the cake. Fresh MgO can be added
to the filtrate in an agitated reactor to reprecipitate the
magnesium compounds. These solids can be recovered from
the slurry by filtration, and returned to the scrubbing loop,
with the filtrate containing soluble contaminants discarded
to an evaporative pond.
For the clear liquor scheme, a considerable amount of
fly ash is present in the scrubber effluent and a thickener is
necessary for sedimentation. Since the sulfur compounds in
the effluent are soluble, a solubilizing tank is not required
prior to removal of fly ash. Fly ash is filtered from the
thickener underflow, sluiced with water, and then disposed.
A bleed stream of the filtrate is treated to remove the
soluble impurities as described for the slurry schemes.
Pilot plant data for MgO slurry scrubbing indicate that
MgS03-6H20 may be the predominant sulfite species
present in the effluent from the sulfur dioxide absorber.
Further test work presented in the Process Chemistry,
Properties and Kinetics section indicates that MgS03-3H20
can be obtained from the hexahydrate by simple thermal
conversion. Since the heat required for drying the latter
species is less than that required for drying MgS03-6H20,
an economic evaluation is desirable to determine which
material should be fed to the dryer. Two process
alternatives were considered. The first alternative provides
for dewatering the scrubber effluent to obtain a cake
primarily composed of hexahydrate crystals, followed by
drying. The second alternative requires thermal conversion
of a thickened hexahydrate slurry to obtain the trihydrate
material, followed by dewatering as in the first method, and
drying.
Dewatering and drying of hexahydrate crystals can be
performed satisfactorily (12); however, no test results are
available for dewatering and drying of trihydrate crystals.
As discussed in the Process Chemistry, Properties and
Kinetics section, trihydrate crystals are likely to be much
smaller than the hexahydrate form and dewatering could be
more difficult. For purposes of evaluation, a trihydrate
cake was assumed to contain approximately 15% free
moisture as compared to 5% for a hexahydrate cake.
Although additional equipment and heat are required to
convert the hexahydrate crystals to the trihydrate form and
to evaporate the additional free moisture in the cake, a
considerable heat savings is obtained in the dryer. The total
heat requirements of the two alternatives are indicated in
table 25 for a new, 500-mw, 3.5% S, coal-fired unit. The
heat required for thermal conversion is based on a
concentrated slurry since data presented earlier show
thickened slurries to have the fastest conversion rates and
require less sensible heat. This net heat savings was applied
in the dewatering evaluation to follow.
The several solid-liquid separation alternatives were
considered for concentrating the slurry prior to drying as
indicated in table 26.
Chemico-Basic has tested direct centrifugation (alterna-
tive 1) of the scrubber effluent for the MgS03-6H20
process and found this to be a satisfactory operation. Their
work indicates that a centrifuge cake containing about 5%
Table 25. Heat requirements of
alternative dewatering-drying processes.
MgS03-6H20 MgS03-3H20
process process
Heat required for conversion,
million Btu/hr
Heat required for drying,
million Btu/hr
Total heat required,
million Btu/hr
-
70
70
10
48
58
Table 26, Solid-liquid separation alternatives.
MgS03 -6H20 process
concentrating methods
MgS03-3H20 process
concentrating methods
1. Centrifuge
2. Thicken, then centrifuge
3. Filter
4. Thicken, then filter
1. Thicken, convert, then
centrifuge
2. Thicken, convert, then
filter
65
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free moisture can be obtained. Since thickening of the
effluent slurry from the sulfur dioxide absorber can reduce
the volumetric feed rate of the slurry, a thickener and
centrifuge alternative was also considered (alternative 2).
A third alternative, filtration, was considered for con-
centrating the slurry. However, based on equipment costs,
filtration equipment vendors do not recommend filtration
of dilute slurries.
After prior thickening, filtration should be a practical
alternative (alternative 4). Test work on filtration of
MgS03-6H20 slurries has not been reported; however,
equipment vendors indicate that the filter cake would
contain between 10 and 20% free moisture. A somewhat
higher capacity dryer would be required for operation with
a filter compared to a centrifuge to compensate for the
additional free moisture content.
Gravity thickeners and wet screens were considered for
thickening the solids in the scrubber effluent. Experience in
the chemical industry has shown gravity thickening to be a
reliable and relatively inexpensive way to increase the solids
concentration of a slurry. The primary equipment required
for this operation includes a conical bottom settling tank, a
thickener rake with drive and supports, and slurry pumps
for pumping the thickened underflow. The size of the
equipment is dependent upon the settling rate of the solids.
Laboratory tests were made at TVA to determine the
concentration of solids to be expected in the underflow
from a gravity thickener and the parameters which affect
the settling rate of the crystals. The data indicate that the
crystals settle to form a slurry containing about 50-60%
solids. It was also found that the settling rate of the solids is
dependent upon the concentration of magnesium sulfate in
the solution phase, but relatively independent of the
temperature of the slurry. Figure 53 shows the relationship
between time and solution-slurry interface for
MgS03-6H20 settling through saturated solutions
containing soluble MgS04; the rate of settling of
MgS03-6H20 is more rapid for slurries with low
concentrations of soluble MgS04.
Wet screens are utilized in industry for dividing a slurry
into two streams:
1. A dilute slurry containing the smaller size crystals.
2. A concentrated slurry containing the larger size
crystals.
Since fine solids are recycled to the scrubbing loop,
satisfactory operation of these devices for the MgO schemes
depends upon crystal growth rather than new crystal
formation in the absorption loop. If crystalline growth is
satisfactory, these devices can be used in place of gravity
thickeners. Since they do not require the large tank
provided for the gravity thickener alternative, the
investment for these devices is less.
Chemico-Basic has recently tested the use of wet screens
for the 150-mw prototype installation at Boston Edison's
18
1 Slurry
temp,
""> Soluble'MgSU4
DF in slurry,% by wt
0
10
20 30
Time, minutes
40
50
60
Figure 53. Effect of time on solution-slurry interface
position for crystalline MgSO3-6H2O settling through
saturated MgSO3-6H2O solutions containing soluble MgSO4,
Mystic No. 6 power plant and found their performance to
be satisfactory. Table 27 below shows comparative equip-
ment costs for a gravity thickener and a wet screen. In
addition to having a favorable cost advantage, the wet
screen devices require less space than gravity thickeners,
which itself would be adequate basis for selection for some
power plant locations. Wet screens were selected for
thickening the effluent from the scrubbers. Underflow
pumps are not required for the wet screen type thickener
because the screens can be elevated to discharge directly
into the conversion tank.
Prior to obtaining final cost data, a preliminary eco-
nomic evaluation of MgS03-6H20 and MgS03-3H20
dewatering methods was made. Since the filtration alterna-
tives require more heat for drying than do the centrifuge
alternatives, both the concentrating and drying steps were
considered. Table 28 shows the estimated equipment
investment, operating horsepower, dryer heat requirements,
and annual operating costs for the MgS03-6H20 process
dewatering alternatives. Although alternative 4 requires the
Table 27. Approximate equipment investment
requirements for thickening, $.
Thickener and drive
Thickener tank including lining
Wet screens
Liquor tank
Liquor pumps
Underflow pumps
Subtotal-equipment
Gravity
thickener
25,000
85,000
—
10,000
4,000
2,000
126,000
Wet
screens
—
—
20,000
10,000
4,000
-
34,000
66
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Table 28. Comparison of various MgS03-6H2O dewatering alternatives.
Dewatering method
Estimated equipment investment, M$
Operating horsepower
Dryer heat requirement, million Btu/hr
Annual operating cost including
capital charges, M$/yr
1
Centrifuge
dry
1,320
1,590
70.1
812
2
Thicken
centriguge dry
1,150
1,410
70.1
772
3
Filter
dry
4
Thicken
filter dry
1,110
1,270
81.1
816
lowest investment and horsepower, a greater amount of
heat is required for this alternative. Based on the above
annual operating costs, thickening followed by centri-
fugation (alternative 2) appears to be the most economical
dewatering alternative and was selected for the
MgS03-6H20 process.
For concentrating MgS03-3H20 slurry, alternative 1,
indicated earlier (thicken, convert, and centrifuge), was
selected since the smaller trihydrate crystals would be
harder to filter than the hexahydrate crystals; therefore, the
centrifuge alternative should be more economical.
A comparison of the estimated total dewatering require-
ments for the MgS03-6H20 and MgS03-3H2O processes is
given in table 29.
Based on a fuel oil cost of $0.09/gal ($0.60/million Btu),
and an annual operating rate of 7,000 hrs/yr, the net heat
savings when using the MgS03-3H20 as opposed to the
MgSO3-6H20 process amounts to a fuel cost savings of
approximately $50,400/yr. The remaining operating cost
difference is the result of the lower equipment investment
and operating horsepower required for the MgS03-3H20
process.
Sulfite Drying-Calcining
Regeneration of magnesia from a wet cake feed involves
drying the feed to remove the free and combined moisture,
and calcination to regenerate magnesia and release gaseous
sulfur dioxide at concentrations necessary for production
of sulfuric acid. Drying and calcining can be performed
either separately or in a single combined device. Although a
combined dryer-calciner probably can be designed for more
efficient heat utilization, the greater amount of heat
required for the combination unit to provide for both
drying and calcining results in an offgas containing low
concentrations of sulfur dioxide. In addition, the high
moisture content of the feed cake to a combination unit
results in higher concentrations of moisture in the offgas.
The combined effects would make it more expensive to
produce 98% H2S04. By providing separate facilities for
drying and calcining, the amount of moisture in the feed to
the calciner and the amount of combustion gas in the
calciner can be reduced to more desirable levels for 98%
H2SO4 production; therefore, separate drying and calcining
units are incorporated in the process design. There is no
alternative when considering off-site magnesia regeneration
and H2S04 production.
To improve the heat utilization of a separate drying unit,
the offgas from the dryer, after dust removal, can be
exhausted to the stack to supply a portion of the required
stack gas reheat. The heat utilization of a separate calciner
unit can be improved by providing preheating stages for
countercurrent contact between offgas and incoming feed.
Operating requirements for drying, calcining, and sul-
furic acid manufacture are interrelated, since any moisture
contained in the solid discharge from the dryer is trans-
ferred to the calciner offgas, which is fed to the sulfuric
acid unit. Because of this relationship, the effect of
moisture content of the feed to the calciner on the sulfuric
acid process was studied. The results are discussed below
and are based on calcination by direct combustion of a No.
6 fuel oil with 5% excess air.
Table 29. Comparison of iyigSO3-6H2O and ly1gSO3-3H2O dewatering processes
Process
Estimated equipment investment, M$
Operating horsepower
Converter heat requirement, million Btu/hr
Dryer heat requirement, million Btu/hr
Annual operating cost including
capital charges, M$/yr .
MgS03-6H20
(thicken-centrifuge)
dry
MgS03-3H20
(thicken-convert-centrifuge)
dry
1,150
1,410
_
70
998
1,250
10
48
772
666
67
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Figure 54 shows the relationship between the moisture
content of the feed to the calciner and the composition of
S02 and H20 in the calciner off gas. The effect of moisture
content of the feed to the calciner on the concentration of
sulfuric acid, assuming no addition or removal of water at
the sulfuric acid unit, is shown in figure 55. The moisture
content of the feed to the calciner must be below 4.4%
H20 at an inlet feed temperature of 400° F to allow for
production of 98% H2SO4 without providing extra
facilities for removing water from the calciner offgas.
However, supplemental water must be added at the H2S04
unit to obtain 98% H2S04 if the moisture content of the
feed is below 4.4%. Since this appears to be the simplest
method for controlling the concentration of the product
acid, a calciner feed containing less than 4.4% moisture is
desirable.
The effect of the temperature of the feed to the calciner
on the composition of S02 in the offgas, and the amount
of water which must be added at the sulfuric acid unit is
shown in figures 56 and 57. The relationships are based on
a calciner feed containing about 2.1% water and a 98%
sulfuric acid rate of 16.1 tons/hr or 35.4 gal/min. These
correspond to the expected product rates assuming Scheme
A is applied to a new 500-mw unit utilizing coal containing
3.5% sulfur. For an off-site calcination unit with an inlet
feed temperature of approximately 60° F, the required rate
of addition of water for 98% H2S04 manufacture is
approximately 1.1 gal/min.
The equipment alternatives which were considered for
drying and calcining in the magnesia scheme are shown in
table 30.
In the test program performed by Grillo on the
MgO-Mn02 variation (Scheme B), spray dryers were
utilized for drying the effluent slurry containing absorbed
sulfur dioxide. Vendors of spray drying equipment were
contacted to provide general information and cost data to
aid in determining the applicability of these devices for full
scale installations. Operation of spray dryers requires that
the feed be pumpable; therefore, spray dryer installations
must be capable of evaporating a greater amount of
moisture than required for drying a centrifuge cake. The
additional moisture in the feed increases the dryer heat
requirement considerably. For base case conditions, the
heat requirement for a spray dryer installation is in the
range of 150-175 million Btu/hr. This compares with an
estimated heat requirement of about 70 million Btu/hr for
Table 30. Dryer-calciner equipment alternatives.
Dryer alternatives Calciner alternatives
1. Spray
2. Entrainment
3. Rotary
4. Fluid bed
1. Rotary
2. Fluid bed
drying a centrifuge cake composed primarily of
MgS03-6H2O and about 58 million Btu/hr for conversion
of MgS03-6H20 to MgS03-3H20 followed by drying.
From discussions with vendors of spray dryers, it appears
that these devices are generally used for drying heat
sensitive materials or for other special applications. Also, a
larger capital investment is required for these devices. For
the magnesia schemes, other types of dryers appear to be
more practical; therefore, spray dryers were not selected.
In entrainment dryers, the feed to the dryer is entrained
in the carrier gas and is dried in passing through the system.
Although this method of drying appears to be feasible,
vendors declined to estimate the costs of these systems
without first performing tests. They indicate that satis-
factory operation requires a relatively free-flowing feed,
which may necessitate recycle of dryer product to mix with
the centrifuge cake. Actual tests are required to determine
the amount of recycle to provide before design and costs
can be determined. In addition, a lower inlet gas tempera-
ture is required for entrainment dryers because of the high
gas requirements for conveying the solids. Since cost data
was not made available, these devices were not included in
the design.
Both rotary and fluid bed systems appear to be feasible
for drying and calcining. Chemico-Basic has tested a rotary
system for drying a MgS03 -6H20 centrifuge cake; products
containing about 3% moisture were obtained when the feed
was dried to temperatures of 600-800° F. Although
oxidation data is not available, Chemico-Basic recommends
drying with a minimum amount of excess oxygen in the gas
to prevent excessive conversion of MgS03 to MgS04.
Chemico-Basic has also tested a rotary calciner for
regeneration of magnesia. The tests showed that essentially
complete regeneration from magnesium sulfite was
obtained at calcination temperatures of 1600-2000° F with
the addition of coke to produce a reducing atmosphere in
the calciner.
Although very little data are available for either drying
or calcining in fluid bed equipment, these devices have
advantages over rotary systems, including lower investment
and operating costs, better temperature control, lower heat
losses, and less space requirements. Because of better
contact between the solid and gas phases, these devices
should be capable of obtaining high calcination efficiencies
at lower temperatures (1400-1800° F) than required for
rotary equipment. Tests performed in Japan with regenera-
tion of the MgO-Mn02 material indicates a fluid bed system
performed satisfactorily at 1800° F without reducing coke.
With reductant, lower temperatures should be feasible.
Based on vendor quotations, estimated investment and
operating costs for rotary and fluid bed dryers and calciners
are given in table 31 for a coal-fired, base case installation.
Rotary equipment was assumed to require about 10% more
-------
25.01
S.20.0
u
"o
E
o
S 15.0
C
C
O
r*
* 10.0
o
8"
•a 5.0
o
CL
I
Inlet solids temperature 400° F
5% excess combustion air to calciner
2.5 5.0 7.5 10.0
Moisture content of feed to calciner, weight percent
12.5
15.0
Figure 54. Effect of moisture content of feed to calciner on composition of calciner offgas.
100
95
c 90
o
o
8
X
85
80
Inlet solids temperature 400° F
5% excess combustion air to calciner
No addition or removal of H2 C t
H2SO4 unit
2.5 5.0 7.5 10.0
Moisture content of feed to calciner, weight percent
12.5
15.0
Figure 55. Effect of moisture content of feed to calciner on concentration of H2SO4.
69
-------
25
§20
'15
10
c*-.
o
c
o
o
O
2.2% H2O in calciner feed
5% excess combustion air to calciner
150
300 450 600
Inlet solids temperature, °F
750
900
Figure 56. Effect of inlet solids temperature to calciner on composition of SO2 in calciner offgas.
300
240
180
120
60
500-mw new coal-fired power plant
3.5% Sin coal
2.2% H2 O in calciner feed
5% excess combustion air to calciner
150
300 450 600
Inlet solids temperature, °F
750
900
Figure 57. Effect of feed temperature of solids to calciner on H 2O requirement at H 2SO4 unit.
70
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Table 31. Estimated investment and
operating costs for rotary and fluid bed
dryers and calciners for base case installation.
Rotary
Fluid bed
Total investment,
MS
Operating horse-
power
Heat required,
million Btu/yr
Annual operating
cost including
capital charges,
MS/yr
Dryer Calciner Dryer Calciner
740 1,475 635 845
600 750 450 400
420,000 459,000 381,000 417,000
571
792
510
593
heat to compensate for additional losses due to the
larger equipment size.
Fluid bed equipment was selected for drying and
calcining for the various magnesia schemes because of the
estimated lower overall operating costs.
The Boston Edison demonstration scale unit incorpo-
rates rotary dryers and calciners for regeneration of
magnesia, although Chemico-Basic and others generally
agree that fluid bed regeneration will be the most attractive
alternative for future installations. The rotary system was
selected for the 155-mw demonstration installation because
all test data were obtained for rotary equipment and timing
did not permit further testing on fluid bed devices.
Cyclone dust collectors are normally provided for
primary collection of dust from the offgases of fluid bed
dryers and calciners. Generally, these devices are not
capable of achieving removal efficiencies as high as required
for the magnesia applications; therefore, secondary dust
control is necessary to obtain overall removal efficiencies of
99.5%. The following acceptable alternatives for secondary
dust control were considered:
1. Wet scrubbers
2. Bag filters
3. Electrostatic precipitators
Wet scrubbers are capable of high dust removal effi-
ciencies with relatively low investment; however, these
devices result in humidification of the offgas preventing
effective heat utilization. Bag filters are capable of high
dust collection efficiencies without reducing heat utiliza-
tion, but the temperature of the gas is limited to 425-500°
F to prevent destruction of the fabric bags. Electrostatic
precipitators also are capable of high dust collection
efficiencies without loss in utilization of heat, but their
capital cost is higher. However, these devices can operate
over a wider range of temperatures than bag filters.
With a dryer offgas temperature of about 400° F, either
a bag filter or an electrostatic precipitator could be
effectively utilized. For the fluid bed calciner, the
temperature of the offgas is expected to be 1400-1800° F,
and gas cooling is necessary if a bag filter is to be used.
Since more efficient overall heat utilization can be
obtained in the calciner by providing a waste heat boiler in
the offgas stream, this provision, under proper design
conditions, permits use of either a bag filter or an
electrostatic precipitator for cleaning the calciner exhaust
gas.
The estimated investment and operating costs for wet
scrubbers, bag filters, and electrostatic precipitators for
cleaning the dryer exhaust are given in table 32 for a
coal-fired, base case installation. These costs are based on
an inlet gas rate to the dust collector of about 57,900 acfm
at 400° F. Based on these results, wet scrubbing is not
economically feasible for controlling dust emissions from
the offgas. Although the investment required for this
method is lower than for the other methods, the net
operating costs are higher due to the high utility require-
ments and loss of heat utilization. There is little difference
in the operating costs of either bag filters or electrostatic
precipitators. Bag filters require a somewhat smaller initial
investment, but have higher projected utility and main-
tenance costs. As mentioned previously, TVA operating
experience with electrostatic precipitators for fly ash
removal has shown that high collection efficiencies are
difficult to maintain over long periods of time. Since any
reduction in dust removal from the calciner offgas
introduces additional undesirable contaminants into the
sulfuric acid unit, bag filters appear to be the- more
satisfactory devices for maintaining high dust removal
efficiencies; therefore, these devices are chosen for all four
schemes. It might be mentioned that Chemico-Basic has
selected bag filters for the Rumford, Rhode Island, demon-
stration calcining plant. These devices appear to be more
practical for cleaning small volumes of gas as encountered
in drying and calcining; however, for larger volumes
electrostatic precipitators may be the better choice.
Table 32. Estimated investment and operating
costs for control of dust emissions from
the dryer for base case installation.
Wet
scrubber
Bag
filter
Electrostatic
precipitator
Total investment, MS
Utility requirements,
$/yr
Heat loss, $/yr
Maintenance, $/yr
Capital charges. $/yr
Annual operating
cost, $/yr
182
207
225
12,000
39,500
7,300
27,100
3,200
0
7,000
30,900
1,900
0
6,000
33,500
85,900 41,100 41,400
71
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Because of the potential for reaction of sulfur oxides,
air, and water in the calciner offgas, and possible condensa-
tion of H2S04 mist, the temperature of this gas must be
controlled carefully. Since some additional cooling occurs
with the addition of supplemental air required for conver-
sion of SO2 to SO3, the waste heat boiler is designed to
cool only to 700° F so that gas temperature remains above
the dew point of the acid after the supplemental air is
added. This air is added between the waste heat boiler and
the bag filter; at low concentrations of S03 in the gas, the
resulting 400° F final temperature should insure
satisfactory operation of the bag filter without
condensation of acid mist.
SulfuricAcid Production
Most of the sulfuric acid production facilities built in the
last decade utilize the contact process in which the
following steps, in order, take place (28):
1. The generation of a sulfur dioxide-containing gas
from an appropriate raw material.
2. The cooling (if necessary), purification, and drying of
the sulfur dioxide-containing gas.
3. Reheating of the sulfur dioxide-containing gas to the
proper temperature for conversion to sulfur trioxide.
4. Catalytic oxidation of the sulfur dioxide to sulfur
trioxide.
5. Cooling of the sulfur trioxide-containing gas.
6. Production of sulfuric acid by absorption of the
sulfur trioxide in concentrated sulfuric acid.
Many of these steps are independent of the source of
sulfur dioxide; however, others are dependent on the
composition of the carrier gas. Because of the water
content of the feed to the calciner and the water formed
during combustion of the fuel for calcination, the offgas
from a magnesia regeneration unit contains more moisture
than a conventional gas from a sulfur burner and must be
dried prior to S03 conversion. Table 33 shows the
estimated overall composition of feed gas to the sulfuric
acid unit for a MgS03 calciner offgas, and a sulfur burner
offgas. For comparison, each of these compositions
includes the required amount of bleed air to result in an
O2:S02 mole ratio of 1.4 as required for efficient
conversion of S02 to S03.
Table 33. Estimated composition of
feed gas to sulfuric acid unit.3
Overall composition, mole %
Type gas N2 C02 02 H20 S02 Totaf
MgSO3 calciner
offgasb 68.67 5.71
S burner offgas 77.33 -
10.92 6.90 7.80 100.00
11.99 2.11 8.57 100.00
aExcluding CO, SO3, and other compounds wich may be present.
Based on a calciner feed containing 2.2% H2O.
As mentioned in the previous section, several alternatives
are available for cleaning the feed gas to the sulfuric acid
unit. Generally, these are described either as "wet" or
"dry" dust removal systems, and the selection of the type
to be included is closely related to design of the acid unit.
Although more design and operating experience is available
for the wet type, certain advantages are inherent in both
systems.
The main advantage of "dry" gas cleanup systems over
"wet" is the ability of these systems to clean the gas without
lowering the temperature. Since the gas must be heated to
high temperatures (about 830° F) prior to entering the
converter, better heat utilization is obtained. However, dry
systems do not offer a practical way for removing moisture
from feed gases when required. Production of 98% H2S04
requires an overall mole ratio of H20:S02 in the feed of
about 1.11. At lower mole ratios, water must be added to
the system, whereas higher ratios require removal of
moisture for producing the high strength acid. Condensa-
tion of water from the gas by cooling below the saturation
temperature appears to be the most practical way to reduce
the water content of the gas. If this is required, a wet
scrubber would be the simplest device for cooling the gas
and, because of its dual role of both cleaning and cooling,
would become the most practical alternative.
Cooling the feed gas to a sulfuric acid unit to allow for
production of high strength acids is practical and done
routinely with metallurgical S02 offgas. The offgas of a
separate calciner unit can be controlled to adequate
moisture contents to allow for production of 98% H2S04 ;
however, the moisture content of the offgas of a combina-
tion dryer-calciner can not be reduced enough by wet
scrubbing alone to allow for production of a concentrated
acid. The larger quantity of gas contains more moisture
than required even at saturated conditions at the scrubber
operating temperature. Based on discussions with vendors,
it does not appear to be desirable to design an acid unit for
producing a dilute acid. This type unit would introduce
special problems including:
1. More difficult acid mist control because it is harder
to collect H2S04 mist than to absorb S03, especially in
lower strength acids.
2. More expensive materials of construction due to the
higher corrosiveness of weaker acids.
3. Larger facilities for storing a dilute acid.
4. More expensive heat exchangers.
5. Additional expense in shipping the more dilute acid.
6. Lower sales price for dilute acid.
Because of the above production of dilute acids was not
considered to be an economical alternative, and further
evaluation of combination dryer-calciner units was not
pursued.
Since the separate unit selected for drying the centrifuge
cake is designed to obtain a high water removal efficiency,
72
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either a "wet" or a "dry" sulfuric acid process is feasible.
Estimated investment and operating cost for both acid
processes are shown in table 34. Although investment data
were obtained from several vendors, for uniform
comparison of wet and dry system costs, only one set of
data is shown.
Based on the estimated lower costs, a dry sulfuric acid
system was selected for incorporation in the various
magnesia schemes. Although this type system requires
higher drying efficiencies for producing 98% H2S04 than
the wet system, as discussed previously, the higher
efficiencies appear to be attainable.
High degrees of contamination control are desirable in
the sulfuric acid unit to prevent fouling of converter
catalyst. It appears that a dry sulfuric acid process utilizing
a bag filter for dust removal will provide sufficient control
for maintaining activity of the catalyst over long periods.
In addition to defining the emission standards for power
generating plants, the EPA has also defined emission
standards for various chemical processes including those
shown in table 35 for sulfuric acid plants (29).
Based on, these standards, sulfuric acid plants are
required to convert a minimum of 99.7% of the inlet sulfur
dioxide to sulfuric acid. A typical single absorption contact
plant is capable of attaining an S02 recovery efficiency of
about 97%. Since this does not meet the EPA standards for
emission control, additional facilities are required for
reducing the sulfur dioxide content of the tail gas. A tail gas
system capable of a recovery efficiency of 90% in conjunc-
tion with a 97% efficient contact plant will provide an
overall sulfur dioxide recovery efficiency of 99.7% which
meets the emission standards. In the design of on-site
sulfuric acid units, the tail gas is cycled back to the stack
gas absorber to increase overall recovery efficiencies.
For off-site sulfuric acid units, this can not be done;
therefore, the following alternatives were considered:
Table 34. Estimated fixed investment and
operating costs for "wet" and "dry" sulfuric
acid units for base case installation.
Type of gas cleanup system
Wet Dry
Total fixed investment for acid plant
including calciner gas cleanup system, M$
Annual operating cost including
capital charges, M$/yr
4,364 3,650
1,267 1,107
Table 35. Environmental Protection Agency
emission standards for sulfuric acid plants.
Allowable emission,
lb/tonofH2S04
4.0
0.15
Sulfur dioxide
Sulfuric acid mist
1. Utilize a double absorption sulfuric acid process
which achieves higher S02 conversion and absorption
efficiencies.
2. Utilize a wet scrubbing process for absorbing S02
from the sulfuric acid unit tail gas.
It is not certain that the first alternative can achieve an
overall absorption efficiency of 99.7%; therefore, this
alternative was not selected. There are several tail gas
scrubbing processes which appear to be capable of meeting
emission requirements including limestone scrubbing,
sodium salt scrubbing, and magnesium oxide scrubbing.
Although the merits and costs of these processes were not
compared, an MgO tail gas scrubbing system was selected
and incorporated into the design of the tail gas cleanup
system. This alternative requires that a centrifuge and dryer
system be provided at the off-site calcination unit to
dewater and dry the scrubber effluent prior to its introduc-
tion into the calciner; however, it is the most compatible
alternative with magnesia scrubbing of power plant stack
gas.
During the procurement of cost and design data for
sulfuric acid units, some vendors recommended the use of
fluorocarbon heat exchangers and acid pump tanks in the
sulfuric acid plant. Although the costs of these systems
were said to be less than the costs of more conventional
cast iron units, the only acid plant prices received were
based on conventional heat exchange systems. For purpose
of this report, the flow diagrams, equipment costs, and
layout drawings presented will reflect only the cast iron
type exchangers. It should be recognized that fluorocarbon
heat exchange systems are potential money savers if
conditions permit their utilization.
Materials of Construction
One of the most important design considerations for the
magnesia scrubbing-regeneration process is the specification
of appropriate materials of construction for the equipment,
piping, and ductwork to minimize operational failures and
maintenance costs due to corrosion and erosion. Materials
of construction are particularly important for stack gas
slurry scrubbing applications because of the potential for
excessive erosion. In addition, the various process
operations and material properties require different
protective measures.
Very little actual quantitiative data is available at this
time to indicate the most desirable materials of construc-
tion for the various operations in the magnesia schemes;
however, some guiding information was obtained from the
following sources:
1. Sulfite pulping applications in the paper industry.
2. Babcock and Wilcox pilot plant tests (27).
3. Chemico-Basic pilot plant tests (12).
4. Grille pilot plant tests (61).
73
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5. TVA pilot plant and laboratory tests of various gas
scrubbing systems.
6. Vendor recommendations.
In an attempt to obtain more complete corrosion data for
the magnesia systems, some static corrosion tests were
performed by TVA; however, the results were not quanti-
tative because the conditions expected in actual operation
were not simulated for sustained periods of time. The pH of
the slurries in contact with the various test specimens
changed during the tests and the effect of prolonged
contact at a given pH could not be determined. In addition,
the effect of erosion is not obtained using static tests. It is
expected that the Boston Edison prototype demonstration
unit will provide corrosion and erosion data from extended
periods of operation under actual dynamic conditions; this
information will be helpful in designing actual installations.
In this conceptual design, scrubber shells are constructed
of mild steel except in areas with high gas velocities which
should be of alloy steel. The scrubber shells are lined with
rubber or a plastic coating. Surge tanks, pumps, agitators,
and slurry piping in the scrubbing area are constructed of
rubber-lined carbon steel. Following current practices,
ductwork between the powerhouse and the scrubbers is
Corten. Ductwork between the scrubbers and the stack gas
reheater system is epoxy-lined mild steel. The I.D. fan and
the ductwork between the reheater and the stack are
Corten since these areas require some protection from
reheater failure. The direct reheat system is constructed of
plain carbon steel with firebrick insulation for the areas
exposed to extremely high temperatures. If a tubular,
indirect steam, reheater is used, it should be made of alloy
steel.
In the slurry processing area, the wet screens, conversion
tank, conversion tank heating coil and agitator, and the
centrifuges are constructed of stainless steel. The liquor
tank and pumps are rubber-lined mild steel, and the steam
condensate tank and pumps are carbon steel. All piping in
this area is rubber-lined mild steel except the piping
associated with the condensate tank which is carbon steel.
Wetted parts of the centrifuge include protection against
abrasion with hard-surfacing and vendor-recommended
abrasion-resistant materials.
The conveyor and elevator for feeding wet centrifuge
cake to the dryer are constructed of carbon steel. The
combustion chamber, dryer, MgS03 surge bin, calciner, and
the cyclone dust collectors are constructed of carbon steel
with the firing end of the dryer being refactory lined. The
coke storage silo, conveyors, and elevators in the dryer-
calciner area are constructed of mild steel. The bag type
dust collectors include mild steel housings with either
Nomex or Teflon bags. Fans and ducts in the dryer-calciner
area are constructed of mild steel except for high tempera-
ture service. For gas temperatures above 1100° F the ducts
should be lined with brick. The waste heat boiler is
constructed of mild steel.
For the magnesia preparation areas, all unloading,
conveying and storage facilities are constructed of mild
steel. However, the slurrying tank, agitator, slurry pumps,
and MgO slurry piping system are rubber-lined mild steel to
provide protection from abrasion. Off-site storage facilities
for fuel oil are constructed of mild steel and are insulated.
Downstream from the calciner gas cleanup system, the
sulfuric acid plant is constructed of conventional materials.
Since no new technology is introduced for sulfuric acid
manufacture, and a variety of different designs are available
for acid units, the materials of construction for the acid
plant will not be discussed. It will be mentioned, however,
that the high strength sulfuric acid can be stored at low
temperatures in plain carbon steel tanks.
Equipment Description
A process control diagram describing instrumentation
requirements for Scheme A is shown in figure B-9
(Appendix B); although not presented, control diagrams for
the other schemes are similar. A typical pilot plan repre-
senting area requirements for a new 500-mw coal-fired
power unit equipped with a magnesia slurry scrubbing-
regeneration system is shown in figure B-10.
Gas scrubbing and reheat—Because of air preheater
design, large power plants normally include multiple gas
ducts between the powerhouse and the stack. For the
current study, it was assumed that 200-mw power units are
designed with two gas ducts, whereas 500-mw and
1000-mw units are designed with four ducts. Each duct is
fitted with a separate scrubbing system and individual
scrubber bypass ducts are provided. Gas velocities of
approximately 50 ft/sec are used in design of ducts.
Coal-fired power units utilizing Schemes A, B, and D are
designed with separate scrubbers for particulate and sulfur
dioxide control. However, coal-fired power units utilizing
Scheme C and all oil-fired power units are designed with
scrubbing units capable of removing both particulates and
sulfur dioxide simultaneously.
In magnesia scrubbing systems, either venturi, mobile
bed, or spray absorbers can be provided for sulfur dioxide
absorption. A representative plan and elevation view of a
two-stage venturi scrubbing installation for Scheme A
applied to a new 500-mw coal-fired power plant is shown in
figure B-ll. A similar view of a venturi-mobile bed
configuration for this scheme is shown in figure B-12.
Figure B-13 shows a representative plan and elevation view
of a venturi-mobile bed scrubbing installation for Scheme A
applied to an existing 500-mw coal-fired power plant. The
design gas flow rates through each of the four scrubber
trains are shown in table 36 for new 500-mw coal-fired
power units.
74
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A representative plan and elevation view of a spray
scrubbing installation for Scheme B applied to a new
500-mw oil-fired power plant is shown in Figure B-14. Each
pair of parallel scrubbers on oil-fired power units (one pair
per duct) is designed for an exhaust gas rate of about
238,000 acfm at 139° F.
Since the scrubbing areas of Schemes C and D are similar
to the scrubbing area shown for Schemes A and B, no
supplemental plans are shown for these schemes.
Table 37 gives the values of liquid to gas ratio
incorporated in the design of the various scrubbers. In each
scheme, entrainment separators are provided to reduce mist
from the exhaust gas of the particulate and sulfur dioxide
scrubbers. In the absence of better mist size definition,
vendors have recommended the use of fiberglass-reinforced
polyester, chevron vane type entrainment separators for
mist control. This selection may or may not require
modification after large scale operating experience with
these and other types of devices becomes available.
For a two-stage venturi scrubbing installation applied to
a new 500-mw coal-fired power plant, each scrubber is
approximately 28 ft in diameter by 40 ft high. They are
equipped with a conical bottom liquor sump which serves
as a recirculation tank. Each particulate venturi is designed
for a gas velocity of about 125-140 ft/sec. Each sulfur
dioxide absorber is designed for a gas velocity of about 75
ft/sec. Agitators are not required. Liquid is recirculated to
each particulate scrubber at a rate of about 4,740 gpm. The
liquid circulation rate to each sulfur dioxide absorber is
about 6,320 gpm. Two 200-horsepower recirculation
pumps are included for each particulate scrubber, whereas
each sulfur dioxide absorber is provided with two
Table 36. Gas flow rates through each
scrubbing train, new 500-mw coal-fired units.
Scheme A design gas flow rate
at scrubber exit, acfm at 127°F
Particulate scrubber
Sulfur dioxide absorber
316,000
323,000
Table 37. Scrubber design conditions.
L/G, gal/Macf
Scheme
Particulate venturi scrubbera
Sulfur dioxide absorber
Venturi
Mobile bed
Spray
A
15
20
10
-
B
15
-
-
6.0
C
b
20
10
-
D
15
20
10
-
aParticu!ate scrubbers are applicable only for coal-fired units.
kparticulates are removed in the sulfur dioxide absorber for Scheme
C.
250-horsepower pumps. Spare pumps are not provided
here; during pump failure the scrubber must be operated at
a reduced L/G.
For venturi-mobile bed scrubbing installations applied to
new or existing coal-fired power plants, both the particulate
venturi and the mobile bed absorber are rectangular and are
constructed adjacent to each other. They are inter-
connected with a common sump, separated by an entrain-
ment separator, and designed for liquid drainage to separate
recirculating tanks. Each venturi scrubber is designed for a
gas velocity of about 125-140 ft/sec. Each mobile bed
absorber is a two-stage, plastic sphere type and is designed
for a gas velocity of about 12-13.5 ft/sec. The overall
dimensions of the venturi-mobile bed scrubber configura-
tion are approximately 32 ft wide by 25 ft long by 54 ft
high. Each recirculation tank is approximately 11 ft in
diameter by 16 ft high and is equipped with a 20-
horsepower turbine agitator. Liquid is recirculated to the
particulate scrubbers at a rate of about 4,740 gpm. The
liquid circulation rate of each S02 absorber is about 3,160
gpm. Two 200-horsepower recirculation pumps are
included for each venturi scrubber; whereas each mobile
bed absorber is designed with two 125-horsepower pumps.
Again, spare pumps are not provided.
For Scheme B applied to a new 500-mw oil-fired power
plant, each duct is fitted with two spray absorbers
connected in parallel, a total of eight. Each spray absorber
is designed for a gas rate of about 45-50 ft/sec and contains
three banks of spray nozzles, with four nozzles/bank. The
absorbers are 8 ft by 8 ft in cross section and are
approximately 48 ft high. Each pair of absorbers drains into
a ll/2 ft diameter by 10 ft high recirculation tank provided
with a 2-horsepower turbine agitator. A separate 75-
horsepower recirculating pump designed for a recirculation
rate of about 825 gpm is provided for each absorber with
no spares included.
Separate stack gas reheaters are provided for each power
plant duct. New coal-fired units are designed with indirect
steam reheaters; whereas existing coal, and both new and
existing oil-fired units are equipped with direct combustion
reheaters utilizing No. 6 fuel oil. Reheaters are designed to
heat the gas to approximately 160° F. The additional
reheat required is obtained from the dryer offgas, and the
heat of compression of the gas in passing through the I.D.
fan. Each duct of a new 500-mw coal-fired power unit is
fitted with two parallel bare-tube heat-exchanger bundles
with 550 ft2 of heating surface each. The tube bundles are
fitted into a duct approximately 12 ft by 12 ft. The design
temperature profile for the steam reheaters is shown in
table 38.
Radial-tip, centrifugal I.D. fans are provided for
discharging the exhaust gas. As mentioned previously, new
power plants are designed with one I.D. fan/duct located
downstream of the reheater. The ductwork to the scrubbing
75
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Table 38. Design temperature profile for
indirect steam reheater system.
Temperature, °F
In Out
Gas (shellside)
Steam-condensate (tubeside)
127
470
160
470
area of existing power units is constructed so the existing
I.D. fans can be utilized. However, supplemental I.D. fans
are provided downstream of the gas reheater to supply the
additional energy required to overcome the pressure drop
of the scrubbing system. For a new power plant, each I.D.
fan is equipped with a 2,250-horsepower motor. Each
supplemental I.D. fan for 500-mw existing power units is
equipped with a 1,575-horsepower motor.
Slurry or solution processing area--The liquor containing
SO2 absorbed in each scheme is pumped from the absorbers
to the slurry or solution processing area for separation of
solids prior to drying. In this area, full capacity spare
pumps are provided.
In Schemes A and D, the slurry containing crystalline
magnesium-sulfur compounds is fed to four elevated wet
screens for thickening; each wet screen is contained in a
vertical rectangular housing approximately 4 ft long by 5 ft
wide by 8 ft high. The wet screens will produce a
concentrated slurry containing about 40% solids. The 67%
slurry of Scheme B is not screened, but flows directly to
the conversion tank.
In Schemes A and D, the wet screens are constructed
directly above a 12 ft diameter tank designed with a 1,200
ft2 steam coil for heating the slurry and converting
MgS03-6H20 to MgS03-3H2O. The thickened slurry from
the screens flows by gravity to this tank, which is designed
for a residence time of 20 min for the thermal conversion.
The conversion tank is equipped with a 20-horsepower
turbine agitator. After conversion, the slurry is pumped to
two parallel 36 in. diameter by 72 in. long solid bowl
centrifuges for separation of the solids from the liquor.
Two 10-horsepower feed pumps are provided. Each centri-
fuge is equipped with a 200-horsepower motor. Both the
centrate and the screen undersize flow by gravity to a
common 5,000-gal receiving tank designed with
50-horsepower pumps for recycle of liquor to the scrubbers
and to the magnesia preparation area.
Because the scrubber effluent of Scheme C contains fly
ash, but does not contain undissolved magnesium com-
pounds, it is processed differently from Schemes A, B, and
D. A bleed stream of slurry from each of the sulfur dioxide
absorbers is pumped to a single 105 ft diameter conical-
bottom thickener equipped with rake and 5-horsepower
drive. The underflow from the thickener, containing about
30% fly ash, is pumped at a rate of about 94 gpm to each of
two parallel filters where the fly ash is removed. Two
15-horsepower pumps are provided. The filtrate flows by
gravity to a 3,900-gal liquor tank for recycle of solution to
the absorbers. Each filter has a surface area of about 60 ft2
and is equipped with a 100-horsepower vacuum pump. To
provide similar solids disposal as used for the other
schemes, the filter cake is slurried with water in a 1,300-gal
tank equipped with a 1-horsepower agitator and is pumped
as a 15% fly ash slurry to a disposal pond.
The overflow from the thickener flows by gravity to a
24,000-gal reaction-conversion tank equipped with a 1,900
ft2 steam coil. This tank is designed for a reaction time of
about 20 min. The magnesium sulfite slurry is pumped at a
rate of 570 gpm to each of two 36 in. diameter by 72 in.
long solid bowl centrifuges operating in parallel. Two
30-horsepower pumps are provided. Each centrifuge is
driven by a 200-horsepower motor and is elevated to allow
the centrate to flow by gravity to the 3,900-gal liquor tank
for recycle to the absorbers.
Sulfite drying-calcining-Representativz area layout plan
and elevation views of a fluid bed magnesium sulfite drying
and calcining area are shown in figures B-15 and B-16. For
comparison, a representative area layout plan view of a
rotary drying and calcining area is shown in figure B-17.
Each view includes the slurry preparation area which has
already been described.
The centrifuge cake is fed at a rate of 66,400 Ibs/hr to
the fluid bed dryer with a 16-in. screw conveyor. The
single-stage, fluid bed dryer is constructed of refractory-
lined carbon steel and is approximately 18 ft in diameter by
40 ft high. Hot gases are supplied to the dryer from an
oil-fired, horizontal, refractory-lined, carbon steel, com-
bustion chamber 10 ft in diameter by 16 ft long. A
250-horsepower blower supplies fluidizing combustion air
to the combustion chamber at a rate of approximately
13,200 acfm (ambient temperature). Cleaned dryer exhaust
gas at 400° F is recycled to the combustion chamber at
19,500 acfm as a means of controlling the temperature and
oxygen content of the feed gas to the dryer. The total gas
rate from the dryer is approximately 57,900 acfm at 400°
F, and the superficial gas velocity in the dryer is
approximately 4.0 ft/sec.
If rotary dryers and calciners are desired for regenerating
magnesia, the approximate dimensions of these systems are
as shown in table 39.
The offgas from the dryer is partially cleaned in a
refractory-lined carbon steel cyclone with a conical bottom;
secondary cleaning is accomplished with a fabric dust
Table 39. Approximate dimensions of
rotary dryers and calciners.
Rotary dryer
Rotary calciner
Shell diameter
13ft
13 ft 6 in
Shell length
100ft
200ft
76
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collector. The fabric filter contains approximately 10,500
sq ft of filter area and is 46 ft long by 12% ft wide by 21 ft
high. A 250-horsepower fan is provided for exhausting the
cleaned gas to the flue gas plenum for reheat and to the
dryer combustion chamber for temperature control.
The solids discharged from the dryer, cyclone, and bag
filter are transferred to the MgS03 silo on a common
conveyor-elevator at a rate of approximately 40,000 Ibs/hr.
The MgS03 silo is approximately 26 ft in diameter by 43 ft
high with a 12 ft conical bottom. If off-site regeneration is
required, as in Scheme D, truck loading facilities are
provided.
The coke receiving silo is approximately 15 ft in
diameter by 21 ft high with an 8 ft conical bottom. A
receiving hopper and a conveyor-elevator are included for
unloading coke. Variable speed weigh feeders are used for
feeding MgS03 and coke to a common conveyor-elevator
which discharges into the fluid bed calciner. This conveyor-
elevator also receives recycle from the secondary calciner
dust collectors and is designed for an overall feed rate to
the calciner of about 39,000 Ibs/hr.
The fluid bed calciner is refractory-lined carbon steel
and is approximately 16 ft in diameter by 38 ft high. It
contains a single calcination bed designed for operation at
1600° F and two air preheat-product cooling stages.
Combustion air is fed into the lower cooling stage at a rate
of 10,100 acfm at ambient temperature by a 400-
horsepower blower. Product MgO is withdrawn from the
lower cooling stage at a temperature of 225° F and a rate
of 16,900 Ibs/hr. The heat for calcination is obtained by
direct combustion of fuel oil in the upper stage. The gas
flow rate at the discharge of the calciner is 51,900 acfm at
1600° F, and the superficial gas velocity in the calcining
bed is approximately 4.0 ft/sec.
An off-site fuel oil storage and feeding system is
designed for heating, transferring, and feeding fuel oil to
the dryer and calciner. These facilities include insulated
storage and holding tanks with heating coils, heat
exchangers, and transfer and feed pumps; a 30-day supply
of fuel oil is provided.
The offgas from the calciner is partially cleaned in a
refractory-lined carbon-steel cyclone with a conical bottom.
Prior to secondary cleaning, the gas is cooled to about 700°
F in a waste heat boiler and is mixed with the required
amount of air for producing sulfuric acid. The combined
gas, at a temperature of 400° F and a rate of 44,500 acfm,
is fed to a fabric filter for final cleaning before entering the
sulfuric acid unit. This filter contains approximately 7,700
sq ft of cloth area and is 34 ft long by 12J/2 ft wide by 21 ft
high. The MgO collected in the bag filter is recycled to the
calciner for layout convenience and to insure calcination of
the fines.
Slurry preparation-Product MgO from the lower cooling
stage discharges onto a conveyor-elevator and is fed to the
top of a 30 ft diameter by 31 ft high storage silo with a 12
ft conical bottom. Fresh makeup MgO is received in an 18
ft diameter by 25 ft high silo with a 9 ft conical bottom. A
pneumatic conveying system with a 150-horsepower blower
is provided for unloading fresh MgO. Each of the silos is
equipped with a variable speed feeder beneath the conical
bottom. The weigh feeders discharge onto an conveyor-
elevator for feeding MgO to the slurry tank. The slurry tank
is 24 ft in diameter by 35 ft high and is equipped with a
50-horsepower turbine agitator and two 15-horsepower
pumps. The MgO is slurried in a stream of recycle centrate
and thickener underflow from the liquor tank and is
pumped to the absorption area.
The dimensions of the slurry processing, drying, cal-
cining, and slurry preparation area for a fluid bed
installation are approximately 197 ft by 188 ft for a
500-mw power unit. If rotary dryers and calciners are
provided, the dimensions for this area would be
approximately 320 ft by 188 ft.
Sulfuric acid production and storage—Representative
area plan and elevation views of the sulfuric acid pro-
duction and storage area are shown in figures B-18 and
B-19. Since dimensions of the sulfuric acid process equip-
ment depend upon specific design which may vary from
vendor to vendor, they are not discussed. However, a
500-mw power unit burning 3.5% S coal requires an area
approximately 245 ft long by 188 ft wide for the contact
sulfuric acid plant.
The cleaned calciner offgas at a rate of approximately
44,500 acfm at 400° F is dried with a recycle stream of
93% sulfuric acid, and any supplemental water which is
required for producing 98% acid is added to the drying
tower. The S02 in the offgas of the drying tower is
converted to S03 in a four-stage converter. Prior to
entering the converter, the gas is preheated in three vertical
indirect gas-to-gas heat exchangers while simultaneously
cooling the offgas from the upper and lower converter
stages. The converter is designed for supplemental cooling
of the offgases of the second and third converter stages
below the catalyst beds by indirect heat exchange with air.
The heated air is exhausted to the atmosphere. The
converter offgas, after passing through the primary heat
exchangers, is fed to the absorption tower for direct
absorption of S03 in 98% H2S04. For an on-site sulfuric
acid unit, the tail gas containing S02 is recycled to the S02
absorbers at a rate of approximately 26,200 acfm at 160°
F. For an off-site acid unit, however, separate magnesia tail
gas scrubbing, solids separation, and drying facilities are
provided. Drip type heat exchangers are incorporated for
cooling the product acid and the effluents from both the
drying and absorption towers. The net product rate is
approximately 386 tons of 98% H2S04/day for a 500-mw,
3.5% S coal-fired installation.
77
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The sulfuric acid unit is designed with three 500,000-gal
mild-steel storage tanks with an overall storage capacity
equivalent to approximately 1 month's production. These
facilities allow for storage of various strengths of acid as
may be required by the consumer. The tanks are connected
to a common loading station equipped with parallel
operating and spare loading pumps.
Equipment delivery and installation-The estimated deliv-
ery time required for the various types of equipment may
vary considerably depending upon power plant location,
method of transportation, and the size of the equipment.
Much of the equipment is large and must be field
fabricated. Scrubbers, dryers, and calciners, because of
their size, are expected to require the longest delivery and
erection time. A complete on-site magnesia facility including
scrubbing, absorbent regeneration, and sulfuric acid pro-
duction and storage areas is expected to require about
18-30 months for engineering, procurement, and erection.
78
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INVESTMENT AND OPERATING COST
On the basis of design criteria, assumptions, and equipment
selections defined in previous sections, investment and
operating cost estimates were prepared for economic
evaluation of the four magnesia scrubbing-regeneration
schemes. In addition to base case conditions for a new
500-mw power unit burning either coal with 3.5% sulfur
content or fuel oil with 2.5% sulfur content, several other
combinations of the more important variables were given
detailed treatment. Included are variations in sulfur content
of fuel, type of fuel (coal or oil), power unit size, and plant
status (new vs existing). The estimates are based on a
midwestern location and mid-1972 cost levels with the
investments corresponding to a Chemical Engineering Cost
Index of 136.
Given in table 40 are the individual cases examined.
Schemes A, B, and C are evaluated assuming all facilities,
including fly ash disposal, at the power plant site, whereas
Scheme D covers situations where scrubbing and sulfite
drying are performed at the power plant and regeneration
and acid manufacture are completed at an off-site central
processing plant.
In addition to the magnesia process estimates, updated
1972 limestone-wet scrubbing process costs based on the
latest process design, development, and operating data
available, are given for comparison. The wet limestone
process serves reasonably well as a measurable alternative
for S02 emission reduction since a directly comparable
range of estimates for each process variable can be made. In
addition, it is a nonrecovery process not requiring sulfur
product marketing. There are other valid alternatives for
SO 2 reduction including the use of low sulfur fuels and
nuclear power; however, their costs are as widely variable
and as difficult to predict as are limestone-wet scrubbing
values. Since interest in wet limestone scrubbing is
currently high and several pilot plant and full scale
installations of the process are being designed, constructed,
or operated to test the concept, comparison of magnesia
scrubbing-regeneration and wet limestone scrubbing costs
should yield a meaningful measure of application potential.
For additional evaluation, economic results are given in
terms of cost/unit of fuel consumed ($/ton of coal, $/barrel
of oil) which can be compared to the premium that must be
paid for low sulfur fuel.
The limestone slurry scrubbing process chosen for
comparison follows the same basic design premises and
criteria as the magnesia processes. For 99% dust removal on
coal-fired units, a single-stage venturi scrubber is used.
Based on TVA pilot plant test and vendor data, a
three-stage mobile bed scrubber is used for 90% SO2
removal. The particulate scrubber utilizes part of the 10%
solids slurry from the SO2 absorber effluent as scrubbing
liquid at a rate of 15 gal/Macf. A liquid to gas ratio of 40
gal/Macf is used in the SO2 absorber. Makeup limestone is
wet ground and added as a 55% solids slurry at a 130%
stoichiometric rate. Stack gas reheat to 175° F uses the
same methods as outlined for magnesia systems.
Since solids disposal is such a major consideration in
throwaway process economics, both variable, low-cost
on-site pond disposal and higher off-site disposal at $6/ton
of solids are covered. In both cases, closed loop water
recirculation is provided. Given in figure 58 is the effect of
variation in solids disposal cost on annual limestone-wet
scrubbing operating cost. To better reflect the apparent
wide range of costs associated with limestone scrubbing
between rural and metropolitan locations, along with the
high and low solids disposal costs, high and low values of
limestone raw material prices are also incorporated. In
other words, two sets of limestone wet scrubbing operating
costs are prepared, one for systems having low limestone
and variable on-site solids disposal costs and another for
those units with higher limestone and off-site solids disposal
costs. In many cases, the actual costs will probably fall
between the two extremes used.
Fixed Investment
The numerous fixed investment estimates are based on
extensive vendor contacts, which produced definitive equip-
ment proposals for several of the key process operations.
Companies contributing to the depth and accuracy of the
equipment costs are listed elsewhere. In addition, authorita-
tive publications on cost estimating are used for the minor
items such as tanks and pumps. After process equipment
costs are determined, area installation expense is added—the
magnesia process costs being estimated from layout and
arrangement drawings given in Appendix B, and the
limestone costs being determined from study drawings for
TVA's Widows Creek scrubbing project. Labor and material
breakdowns are prepared by design and cost specialists for
the base case estimate and scaled to fit the case deviations.
79
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Table 40. Case combinations for coal- and oil-fired units.
Power unit
Scheme size,mw
Case
A
B
C
D
Case
A
B
combinations-coal-fired units
200
200
500
500
500 (base case)
500
1,000
1,000
200
500 (base case)
1,000
200
500 (base case)
1,000
200
5x200
10x200
15x200
500 (base case)
2x500
4x500
6x500
1,000
2 x 1 ,000
3 x 1 ,000
combinations— oil-fired units
200
200
200
200
500
500 (base case)
500
500
1,000
1,000
1,000
1,000
200
500 (base case)
1,000
Regen-acid unit
size equiv., mw
200
200
500
500
500
500
1,000
1,000
200
500
1,000
200
500
1,000
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
200
200
200
200
500
500
500
500
1,000
1,000
1,000
1,000
200
500
1,000
Power plant status
New
Existing
Existing
New
New
New
Existing
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
New
Existing
New
New
New
Existing
New
New
New
Existing
New
New
New
Sulfur content, %
3.5
3.5
3.5
2.0
3.5
5.0
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
3.5
1.0
2.5
4.0
2.5
1.0
2.5
4.0
2.5
1.0
2.5
4.0
2.5
2.5
2.5
2.5
Installation costs include piping, ductwork, electrical,
instruments, insulation, foundations, structural steel, and
painting. In addition, definitive estimates are made on fuel
oil storage, product storage, and building needs for motor
control, laboratory, locker, and process control space. The
investment for on-site disposal ponds for fly ash is not
included in the magnesia and limestone estimates as the
power plant would be expected to provide this cost
regardless of provisions for S02 removal. In the limestone
estimates, pond cost is provided for the calcium solids when
80
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10
Wet-limestone scrubbing - X
New coal-fired units
3.5% Sin coal
7000 hr annual operation
Regulated economics
"Limestone cost = $2.05/ton
Disposal quantities include calcium solids and
both hydrate and free water
o
•o
a
o
o
o
00
a.
o
e
c
3 52,400 tons/y
4
681,400tons/yr
Represents annual operating
cost of limestone-wet scrubbing
process with variable on-site
pond disposal of solids and
low cost limestone.
144,100tons/yr
200
400
800
1000
600
Power unit size, mw
Figure 58. Effect of variation in solids disposal cost on annual limestone-wet scrubbing operating cost.
1200
disposal is on-site. Investment for service areas such as
maintenance shops, stores, communication, security, and
offices is allocated on the basis of equipment costs and
personnel needs of both power plant and stack gas clean-up
facilities. Current TVA practice is used as a guide in this
effort. For utilities, investment costs are included for
distribution facilities, but not for generation facilities. As
required in each process area, necessary electrical sub-
stations and conduit, steam, process water, fire control
water, and compressed air distribution piping are included.
The sum of all above items is called direct investment.
To the direct investment is added the indirect costs for
the project, which include engineering design and project
supervision, construction expense, contractor fees, and
contingency. The percentages of direct investment used to
estimate these items are shown in table 41.
In keeping with Federal Power Commission accounting
practice, allowances are included for start-up and
modifications plus interest during construction at
8%/annum. Applied as a percentage of total cost, these
allowances are 10% for start-up and 4% for interest. The
above percentages are used for the appropriate Scheme A,
B, and C cases and for 200-mw, 500-mw, and 1000-mw
cases of Scheme D. For the 2000-mw and 3000-mw
regeneration-acid plants considered off-site for Scheme D,
the percentages listed for new 1000-mw units are applied.
Slightly different values are used in the limestone-wet
scrubbing estimates, reflecting less complex engineering
design and construction.
Working Capital
Working capital requirements are calculated for each case
evaluated. As described later, the total of fixed investment
and working capital is used in the profitability calculations
for determination of return on total investment. For the
present study, working capital is defined as the total of 3
weeks of raw materials cost (plus shipping costs between
81
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Table 41. Indirect cost factors.
Indirect investment cost factors
percentage of direct investment
Power unit size status
200-mw
Engineering design and supervision
Construction expense
Contractors fees
Contingency
Total indirects
New
9
11
6
13
39
Existing
10
13
8
13
44
500-mw
New
7
9
4
12
32
Existing
8
12
6
13
39
1 ,000-mw
New
6
8
4
11
29
Existing
7
9
5
12
33
plants for Scheme D), 7 weeks of direct operating costs (as
defined on operating cost sheets in Appendix A), and 7
weeks of overhead cost (as defined on operating cost sheets
in Appendix A). No provisions are included for accounts
receivable (unpaid billings).
Operating Costs
To present meaningful operating cost estimates, many
ground rules and inputs must be defined. Several of the
ground rules such as plant life, operating hours/year,
process operating conditions, and rates are given in the
Study Assumption and Design Criteria section. Others,
including raw materials and shipping costs, labor rates, and
capital charges are defined here to permit calculation of
annual, lifetime, and unit operating costs. All operating cost
estimates include the appropriate cost of fly ash and/or
calcium solids disposal.
Raw materials—Magnesia process raw materials include
magnesium oxide for scrubbing slurry or solution makeup
and carbon for reducing magnesium sulfate in the calciner.
Both of these materials can be obtained in several forms;
however, the need to hold process contamination to a
minimum reduces the number of available choices.
Magnesium oxide can be obtained commercially from
several companies in one or more forms such as calcined
magnesite (dry, 98% MgO), agricultural grade calcined
magnesite (dry, 87-92% MgO), magnesium hydroxide (dry,
98% Mg(OH)2), magnesium hydroxide slurry (35-50%
Mg(OH)2 in water), and raw, uncalcined magnesite (dry,
45% MgO). Given in table 42 are the f.o.b. costs of these
materials both in bulk form and as 100% MgO.
The costs in table 42 do not include shipping which, in
most cases, will add considerably to the total charges.
Points of material origin include Gabbs, Nevada; St. Louis,
Michigan; Ludington, Michigan; Freeport, Texas; and Port
St. Joe, Florida. Raw magnesite, the least expensive form of
MgO at the point of origin, is found only in Nevada;
therefore, considerable shipping cost will be incurred to
supply it to customers in the eastern United States. Total
cost to the two locations given particular emphasis in this
Table 42. Costs for various magnesium
oxide-containing raw materials.3
Material
Calcined magnesite (98% MgO)
Agricultural grade calcined
magnesite (87% MgO)
Magnesium hydroxide (67% MgO)
Magnesium hydroxide slurry
(34% MgO)
Raw, uncalcined magnesite
(45% MgO)
Cost
Bulk
92.00
48.00
240.00
38.00
22.00
, $/ton
100% MgO
93.88
55.17
358.21
111.76
48.89
F.o.b. works, freight not included.
report, Chicago and Philadelphia, would be $90 and
$109/ton 100% MgO, respectively.
The other four materials can be obtained from most of
the listed locations; therefore, their total cost will be
influenced less by shipping charges, especially the calcined
magnesite (9 8% MgO).
Of the five materials, only the calcined magnesite (98%
MgO) and magnesium hydroxide (both dry and slurry form)
are low in impurities. Until experience is gained from
long-term operation, it has been assumed that the impurity
level of raw, uncalcined magnesite and agricultural grade
calcined magnesite would require excessive recycle or
decontamination cost. Dolomitic limestone should also be
considered in the same category.
Taking into consideration both economic and process
requirements, the calcined magnesite containing approxi-
mately 98% MgO should be considered as the prime
magnesia source. This material is produced by calcination
of magnesium hydroxide from sea water and natural brines.
A typical chemical composition is as follows:
Magnesium oxide, % 97-99 0
Calcium oxide, % 0.55-1.00
Silca (Si02), %
Iron oxide (Fe20 3), %
0.20-0.40
0.05-0.25
Aluminum oxide (A1203), % 0.04-0.20
The material is a fine, crystalline powder with a bulk
density of about 20-30 Ibs/cu ft.
82
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For purposes of calculating process operating cost, the
magnesium oxide cost to a Chicago customer is considered
to be $102.40/ton delivered and to a Philadelphia
customer, $128.40/ton delivered.
The most suitable form of carbon for addition to the
calciner is probably high grade coke. Other reductants such
as coal, excess fuel oil, natural gas, or hydrogen might tend
to promote H2S formation or increase ash contamination in
the system. Although some of these fuels, coal in particular,
are less expensive than coke, considerable additional
calcination research is needed before they can be
considered.
Based on contract high purity coke prices to TVA during
1971, the delivered cost of coke is predicted to be
$23.50/ton. Petroleum coke cost would be less ($5-
$10/ton); however, its impurity level may be too high.
Since coke cost is a minor part of the process cost, using a
high purity coke will not add appreciably to total operating
requirements.
In addition to the primary raw materials, makeup
catalyst (usually vanadium pentoxide) is required for the
sulfuric acid plant. This can be in either extruded,
pelletized, or spherical shapes, depending on the original
charge provided by the plant designer. Cost is expected to
be about $1.51/liter.
An additional raw material required for Scheme B is
manganese dioxide. In the variation researched by Grillo-
Werke AG, pyrolusite, a natural ore found in Africa and
containing 87% plus Mn02, is used as an activator for the
MgO-S02 reaction. A few U. S. companies import this
material and process it in relatively small quantities. For
such quantities as required by MgO-Mn02 scrubbing of
stack gas, indications are that ground pyrolusite can be
delivered to midwestern power plants for $90/ton.
In defining the operating costs of the limestone-wet
scrubbing process, the cost of limestone has major signifi-
cance. Data from a recent report by M. W. Kellogg (53)
indicate the costs of limestone delivered to various U. S.
power plants range from $1.95 to $13.20/ton; at least half
of the power plants in the eastern U. S. could be supplied at
$4/ton or less; and all but three could obtain limestone for
less than $6/ton. In separate studies made in the TVA area,
prices were found to range from $2.05 to $4.05/ton
delivered. Since the use of limestone-wet scrubbing as a
process comparison should reflect the possible variance in
limestone costs, operating cost projections will cover both
high and low cost raw material. The high cost will be
$6/ton and the low cost $2.05/ton. Shown in figure 59 is
the effect of limestone cost on the total annual operating
cost of the limestone-wet scrubbing process.
Shipping cost—central processing concept—To fully
define the economics of the central processing concept
(multi-location scrubbing and drying plus single location for
regeneration and acid manufacture), the shipping cost for
transferring magnesium sulfite and magnesium oxide
between locations must be included as part of the total
process operating cost. Furthermore, for display purposes,
it is necessary to assign the shipping costs to one or the
other operating cost summaries; that is, to the operating
cost for the scrubbing-drying operation or to that of the
regeneration-acid manufacturing operation. The assignment
is arbitrary; however, for purposes of this, the magnesium
sulfite shipping cost is included as part of the raw material
cost for the regeneration-acid manufacturing operation and
the magnesium oxide shipping cost is included as part of
the raw material cost for the scrubbing operation.
Combinations of scrubbing plant distances from the
central plant are almost limitless; therefore, to simplify
evaluation of shipping distance, all scrubbing-drying loca-
tions are assumed to be equidistant from the central
regeneration plant. Distances of 5, 25, 50, 75, 100, and 150
miles from the central point are examined.
For magnesium sulfite shipping, 1972 rail rates are not
available; however, the magnesium sulfate rates shown in
table 43 can be used (covered hopper cars in the
Philadelphia and Chicago areas, not less than 80,000 Ibs).
Magnesium oxide shipping costs, as shown in table 44,
apply to Philadelphia and Chicago for rail shipment in
covered hopper cars, not less than 120,000 Ibs.
Estimated trucking costs for both magnesium sulfite and
magnesium oxide for the Philadelphia and Chicago areas are
shown in table 45, assuming 40,000-lb loads and mixed
loading, that is, some trucks hauling both ways and others
Table 43. Rail shipping costs for magnesium sulfate.
Rate in cents per Rate in cents"
Miles distance hundred pounds per ton-mile
5a
25
50
75
100
150
17
35
36
41
46
52
68
28
14
11
9
7
alnside switching limits.
bEarly 1972 rates.
Table 44. Rail shipping costs for magnesium oxide.
Rate in cents per Rate in centsb
Miles distance hundred pounds per ton-mile
5a
25
50
75
100
150
17
24
25
27
31
38
68
19
10
7
6
5
alnside switching limits.
bEarly 1972 rates.
83
-------
10
o
T3
a
o
o
o
2 6
-------
Profitability and Economic Potential using different rates
of escalation. With the present uncertainty of future labor
costs and productivity increases, it is not possible to
accurately predict the effect of labor rates on the total cost.
The base operating labor rate of $6/hr includes fringe
benefits and supervisory expense. The higher labor rates of
$10/hr used for laboratory work also includes benefits,
supplies, and supervisory expense.
Utilities-The costs of utilities to the process depend on
quantity, source, and accounting practice. The values used
are fully allocated costs, as if purchased from an independ-
ent source with full capital recovery provided for. As
quantities increase, the unit cost of utilities is decreased to
show some economy of scale. For existing power plants, it
is recognized that no excess steam, water, or electricity
would be available and that new investment would be
required by the independent source; the new investment is
not included in that shown for the process, but a higher
cost is charged to permit more rapid capital recovery than
for new plants. For new plants, the utility costs are the
same as would be charged to power plant operation by the
plant accountant since provision could be made to furnish
the necessary utilities in the original design and installation.
For those cases where a heat credit is taken for export
steam to the power unit system, the value of the credit is
based only on equivalent fuel cost.
Maintenance— Maintenance costs chargeable to the mag-
nesia processes are considered "best estimates." Indications
are that some scaling and corrosion-erosion will be encoun-
tered in the scrubber system, at least to a greater extent
than for processes not using slurry scrubbing. Solids
handling and calcining operations usually are maintenance
prone. Sulfuric acid plant maintenance is more easily
predicted since such plants have been in operation for
years. For purposes of this study, table 46 shows estimated
overall maintenance costs as a percent of magnesia process
investment.
Maintenance charges used in the limestone-wet scrubbing
estimates range from 6 to 9% of investment depending on
unit size. Experience from pilot plants and actual installa-
tions seem to support a higher maintenance charge as
compared to the magnesia system because of slurry acidity
(5.5-7.0 pH vs 7.0-8.5 pH for magnesia), the greatest
tendency to form scale deposits, and the apparently higher
erosive characteristics of the calcium sulfite crystal.
Capital charges— Estimation of operating cost is compli-
cated by the fact, as discussed in the ammonia scrubbing
conceptual design study (84), that projects for sulfur and
nitrogen oxides control in power plants may be financed on
different bases—the regulated power industry basis, the
nonregulated chemical industry practice, or a combination
of the two. This has a major effect on capital charge items
such as depreciation and taxes. Because of this important
factor, two sets (one regulated, one nonregulated) of
operating cost estimates are made for each of the magnesia
Scheme A, B, and C case combinations of plant size, power
unit status, fuel type, and sulfur content of fuel. For
Scheme D a single set of estimates is prepared; however, the
operating cost of the scrubbing-drying operation is assumed
to be under power industry economics (regulated) and the
regeneration-acid plant operation under chemical industry
economics. This so-called cooperative economics probably
best describes the type of combined venture for the central
process concept. It is the most likely financing method for
a magnesia system.
For the power industry (regulated utility economics),
the usual practice is followed of including in the capital
charges a regulated return on investment and the state and
Federal income taxes. A breakdown of the capital charges is
gjven in table 47. The depreciation rate is straight line,
based on the remaining life of the power plant after the
pollution control process is installed, and is a percentage of
initial fixed investment. Interim replacements and property
insurance are also based on original fixed investment.
However, because most regulatory commissions base the
annual premissible return on investment on the remaining
depreciation base (that portion of the original investment
yet to be recovered or "written off"), a portion of the
annual capital charge to be applied to the operating cost
declines uniformly over the life of the investment.
Annual return on equity, interest on outstanding debt,
and income taxes are established in the same manner. The
cost of money to the power industry is assumed to be 8%
interest on borrowed funds and 12% return on equity
money to attract investors. Assuming a capital structure of
50% debt and 50% equity, the overall cost of money under
Table 46. Estimated overall maintenance costs.
Scrubbing
Drying-calcining
Sulfuric acid
Storage
Composite
200-mw
6
9
9
3
7
Total system
500-mw
6
7
5
3
6
maintenance-percentages of investment
1 ,000-mw
6
5
3
3
5
2,000-mw
-
5
3
3
4
3 ,000-mw
-
4
3
2
3
85
-------
Table 47. Annual capital charges for power
industry financing (new power unit with 30-yr life).
As percentage of
original investment
Depreciation (based on 30-yr
life for a new power unit)
Interim replacements (equipment
having less than 30 yr life)
Insurance
Total rate applied to
original investment
Cost of capital (capital
structure assumed to be 50%
debt and 50% equity)
Bonds at 8% interest
Equity at 12% return to
stockholder
Taxes
Federal (50% of gross return
or same as return on equity)
State (national average for states
in relation to Federal rates)
Total rate applied to
depreciation base
3.33
0.67
0.50
4.50
As percentage
of outstanding
depreciation basea
4.00
6.00
6.00
4.80
20.80b
aOriginal investment yet to be recovered or "written off."
k Applied on an average basis, the total annual percentage of original
fixed investment would be 4.5% + % (20.80%) = 14.90%.
regulated economics comes to 10%. Federal income taxes
are assumed to be 50% of gross income and state tax is
assumed to be 80% of the national tax; the resulting figure
is higher than for nonregulated industry, but is about the
nationwide average for power companies.
All operating cost estimates for the nonrecovery, lime-
stone wet scrubbing process are calculated on a regulated
economic basis.
For chemical industry financing (nonregulated econom-
ics), the only capital charges applied are depreciation, local
taxes, and insurance. Hence the estimates are not directly
comparable with those for power company financing
because the latter include return on investment and income
tax. Moreover, the depreciation rate for the nonregulated
economics basis (10%), which is commonly used in the
industry, is much higher than for regulated economics
(3.33% for 30 years).
Using different bases for the estimates is confusing, but
is necessary as these are the approaches that may be
actually used in practice. The encountered difficulty is that
the regulated and nonregulated bases can not be directly
compared. The fairly well defined return on investment for
the power company makes a low rate of depreciation
acceptable, and return on investment can be logically
included in production cost because it is a fixed charge
usually passed on to the power customer. For the chemical
company, however, a relatively high rate of depreciation is
needed because of the risk factor, and return on investment
is quite variable because it can not always be passed on to
the customer as a cost item.
Results
A summary of fixed investment for 29 Scheme A, B, and C
cases plus comparative estimates for nonrecovery limestone-
wet scrubbing with on-site solids disposal pond is presented
in table 48. The magnesia process estimates are shown by
functional area in tables A-l to A-23 in Appendix A. A
similar analysis of limestone scrubbing investment is given
in table A-32 of Appendix A.
The results for Scheme A, the basic slurry process, range
from $5,148,000 ($25.7/kw) for a new 200-mw oil-fired
unit to $36,634,000 ($36.6/kw) for an existing 1000-mw
coal-fired unit. Comparable investments for limestone-wet
scrubbing are $4,981,000 ($24.9/kw) and $30,041,000
($30.0/kw). Investments for Scheme B, the MgO-Mn02
variation, are barely higher for comparable cases (less than
3% higher), primarily because of greater material handling
costs due to inerts and Mn02 plus more dilute calciner
off gas to the sulfuric acid unit (13% S02 vs 16% for
Scheme A). Comparable Scheme C results are lower than
either slurry process, with savings coming from single stage
scrubbing (vs two stages for other coal-fired schemes) and
reduced process throughput due to less effective SO2
removal.
Given in table 49 is an equipment, labor, and material
cost breakdown for the direct investment of the process
areas in the Scheme A base case (new 500-mw coal-fired
Unit burning coal containing 3.5% sulfur). Table 50 shows
the same type breakdown for the limestone-wet scrubbing
process with on-site solids disposal. The values in these
tables can be used to scale costs to other sizes. Note,
however, that building and service facilities are not included
in these breakdowns.
The summarized results of table 48 are further consid-
ered in figures 60 to 67 which describe the effect of unit
size, unit status, fuel type and sulfur content of fuel on
total fixed investment.
During the preparation of the magnesia cost estimates,
some doubt was expressed by a process developer as to the
need for several provisions included in the proposed
conceptual designs. Items questioned in particular are:
1. The use of rubber-lined piping in the scrubber
circulation and slurry processing systems instead of carbon
steel as used in the ^Boston Edison demonstration.
86
-------
.2 30
1 1
Scheme A - O
Scheme B - ^
Scheme C-o
Wet-limestone scrubbing - X
3.5% S in coal
1000
1200
0 200 400 600 800
Power unit size, mw
Figure 60. Effect of power unit size on magnesia process
investment: new coal-fired units.
Scheme A- O
3 57= S in coal
Existing units -
New units -—
400 600 800
Power unit size mw
Figure 62. Effect of plant status (new vs existing) on
investment for magnesia Scheme A: coal-fired power units.
1—
Scheme A - O
2.57 Sin oil
I xistmg units -
New units
600
r unit size-, mw
Figure 64. Effect of plant status (new vs existing) on
investment for magnesia Scheme A: oil-fired power units.
S 20
E
Scheme A - O
Scheme B- ^
Wet-limestone scrubbing - X
2.5% Sin oil
600
Power unit size, n
Figure 61. Effect of power unit size on magnesia process
investment: new oil-fired units.
Scheme A-0
Scheme B - a
Wet-limestone scrubbing - X
New coal- and oil-fired units
- 3.5% Sin coal
2.57., S in oil
I 30
E
200 400 600 800 1000 1200
Power unit size, mw
Figure 63. Effect of power unit fuel type on investment.
| 30
E
Scheme A - O
Wet-limestone scrubbing - X
New coal-fired units
Sulfur in coal. 7,
Figure 65. Effect of sulfur content of coal
on investment: 500-mw units.
87
-------
40
E
1
•5
| 30
'1
^
fi
5 20
•a
x
1
10
0
40
S3
•3
T3
•5
| 30
c
I 20
1
«=
19
g
10
0
2
trifu
slurr
than
3
of c
a lev
4
COOT
diffi
It ca
up t
for t
first
as s
i i 1 1 1
Scheme A - O
Wet-linestone scrubbing - X
New oil-fired units
1 1 1 1 1
31 23456
Sulfur in oil, %
Figure 66. Effect of sulfur content of oil
on investment: 500-mw units.
Scheme A - O
New oil-fired units
^^-^°^^
200-mw units _,-,__
1 1 1 I 1
012345
Sulfur in oil, %
Figure 67. Effect of plant size and sulfur
content of oil on investment.
. Use of a stainless steel conversion tank and cer
ge, and rubber-lined tanks, pumps, and agitators in th
y processing and MgO slurry preparation areas rathe
carbon steel units.
. The inclusion of special facilities for purge treatmen
Dntaminents instead of allowing them to accumulate t
el such that losses would offset the inputs.
. The extra provisions for sulfite hexahydrat
ersion to sulfite trihydrate crystals which may be mor
cult to dewater.
n be seen in table 51 that those design differences ad
o a significant potential investment savings ($909,60
he base case, coal-fired Scheme A, a 4.2% savings). Th
three, of course, are included in the conceptual desig
afe measures in the face of uncertainty in proces
1 able 48. 1 otai Tixea investment
requirements— magnesia scrubbing and
limestone-wet scrubbing processes.3
Limestone-wet
Magnesia scrubbing
Case $ $/kw $ $/kw
Coal fired
Scheme A
200-mwN3.5%S 11,685,000 58.4 9,192,000 46.0
200-mw E 3.5% S 13,083,000 65.4 10,304,000 51.5
500-mw E 3.5% S 24,646,000 49.3 19,958,000 39.9
500-mw N 2.0% S 18,788,000 37.6 16,172,000 32.3
500-mw N 3.5% S 21,732,000 43.5 17,622,000 35.2
500-mw N 5.0% S 24,275,000 48.5 18,928,000 37.8
l,000-mwE3.5%S 36,634,000 36.6 30,041,000 30.0
1,000-mw N 3.5% S 33,118,000 33.1 27,413,000 27.4
Scheme B
200-mw N 3.5% S 11,990,000 60.0 9,192,000 46.0
500-mw N 3. 5% S 22,237,000 44.5 17,622,000 35.2
1,000-mw N 3.5% S 33,838,000 33.8 27,413,000 27.4
Scheme C
200-mw N 3.5% S 9,923,000 49.6 9,192,000 46.0
500-mw N 3.5% S 18,111,000 36.2 17,622,000 35.2
l,000-mwN3.5%S 27,540,000 27.5 27,413,000 27.4
Oil fired
Scheme A
200-mw N1.0%S 5,148,000 25.7 4,981,000 24.9
200-mw N 2. 5% S 6,690,000 33.4 5,700,000 28.5
200-mw N 4.0% S 7,903,000 39.5 6,288,000 31.4
200-mw E 2. 5% S 7,426,000 37.1 6,608,000 33.0
500-mw N 1 .0% S 9,888,000 19.8 9,491,000 19.0
500-mw N 2.5% S 12,439,000 24.9 10,679,000 21.4
500-mw N 4.0% S 14.568,000 29.1 11,696,000 23.4
500-mw E 2.5% S 13,920,000 27.8 12,392,000 24.8
1,000-mw N 1.0% S 14,957,000 14.9 14,766,000 14.8
l,000-mwN2.5%S 18,888,000 18.8 16,629,000 16.6
l,000-mwN4.0%S 22,046,000 22.0 18,202,000 18.2
l,000-mwE2.5%S 20,740,000 20.7 18,556,000 18.6
l~ Scheme B
e 200-mw N 2.5% S 6,806,000 34.0 5,700,000 28.5
T
500-mw N 2.5% S 12,561,000 25.1 10,679,000 21.4
l,000-mwN2.5%S 19,126,000 19.1 16,629,000 16.6
aN = New plants
° E = Existing plants
S = sulfur
e performance and the fourth provision offers considerable
e operating cost savings (lower fuel requirements in dryer) if
operationally feasible. Since the need for these provisions
d can only be determined from actual demonstration opera-
0 tion over a period of time, this study provides for their
e inclusion in the process design and cost evaluation. As data
n is received from the Boston Edison project, adjustments can
s be made accordingly to magnesia process economics.
-------
Table 49. Process equipment and installation analysis-direct cost for Scheme Aa (thousands of dollars).
New Optional Fuel
MgO H2S04 H2S04 bypass oil
Particulate SO-,
Slurry
scrubbing scrubbing processing
Equipment
Material
Labor
Piping &
insulation
Material
Labor
Ductwork, dampers,
& insulation
Material
Labor
Concrete-
foundations
Material
Labor
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint
Material
Labor
Subtotal
Direct costs
828
240
327
177
752
Inc.
105
Inc.
135
180
216
Inc.
997
256
236
101
878
Inc.
115
Inc.
145
190
340
Inc.
424b
75
52
20
—
—
30
Inc.
26
34
73
Inc.
490b
176
2
3
20
Inc.
38
Inc.
8
11
43
Inc.
665b
215
2
3
44
Inc.
46
Inc.
14
18
39
Inc.
(Additional
111
57
66
Inc.
3,194
135
75
60
Inc.
3,528
29
10
12
Inc.
785
11
4
4
Inc.
810
32
11
5
Inc.
1,094
115
27
15
4
—
—
10
Inc.
3
4
32
Inc.
instruments)
39
13
2
Inc.
264
925
Inc.
410
Inc.
741
Inc.
188
Inc.
99
Inc.
207
Inc.
185
Inc.
66
Inc.
2,821
163
Inc.
— —
— —
454
Inc.
18
Inc. —
3
4
14
Inc.
Inc. —
Inc.
1
Inc. —
203 454
122
22
Inc.
Inc.
Inc.
Inc.
21
Inc.
2
Inc.
10
Inc.
1
Inc.
Inc.
Inc.
178
4,729
1,011
1,044
308
2,889
Inc.
571
Inc.
435
441
974
Inc.
543
170
216
Inc.
13,331
aNew plant, coal-fired, 500-mw, 3.5% S in coal, 1,040,000 scfm stack gas, 378 tpd H2SO4.
Includes most instrumentations.
Inc. = included.
Another potential route to reduction of magnesia
process investment requirements is the use of an existing
sulfuric acid plant. In most such cases, new gas purification
facilities, estimated at 40% of the cost of a new acid unit,
would need to be installed. The existing heat exchangers,
converter, absorber and storage tanks could be used,
thereby saving considerable new investment as shown in
table 52. It is difficult, however, to predict how such
savings would affect overall process economics (operating
cost, potential profitability). Most accepted accounting
procedures would still require all investment utilized,
regardless of new or existing status, to be depreciated and
to earn a return. Since the age and condition of the existing
acid unit would influence the capital charges applied, each
case would have to be evaluated with care. It should be
pointed out that other chargeable operating costs such as
labor, utilities, and maintenance would not be reduced by
using an existing acid plant.
The fixed investment requirements for Scheme D, the
central processing concept, are summarized in table 53 and
shown in detail in tables A-24 to A-31 in Appendix A. As
can be seen in figure 68, Scheme D requires about 6% more
investment than Scheme A, which represents the same
process technique, but with all facilities at the same site.
For combinations of 200-mw, 500-mw, and 1000-mw
scrubbing facilities coupled with various-size central
regeneration-acid plants, figure 69 describes the effect of
total system size in megawatts on total fixed investment.
Given in table 54 are the process unit sizes in megawatts
and the equivalent sulfuric acid capacity when burning coal
with 3.5% sulfur content.
Although a single Scheme D system is moi° costly than a
single Scheme A facility, desirable investment economy can
-------
Table 50. Process equipment and installation analysis3 direct
cost for limestone-wet scrubbing process (thousands of dollars)
Limestone handling,
storage & grinding
Equipment
Material
Labor
Piping & insulation
Material
Labor
Ductwork, dampers,
& insulation
Material
Labor
Concrete-foundations
Material
Labor
Excavation, site prep.
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint
Material
Labor
Land
Subtotal— direct cost
293
75
53
31
—
—
24
56
150
17
21
80
81
12
4
6
9
30
942
Scrubbing system
including fans & reheat
2,364
306
1,062
402
812
598
51
123
125
395
428
310
217
222
186
35
65
10
7,711
Optional bypass Solids disposal
duct & pond water recycle Total
57
38
182
113
250
150
80
65
1,127
— —
— —
36
43
12
8
2
3
565
400 2,331
2,714
419
1,297
546
1,062
748
155
244
1,402
412
449
426
341
246
198
43
77
605
1 1 ,384
aNew unit, coal-fired, 500-mw, 3.5% S in coal, 1,040,000 scfm stack gas, indirect steam reheat to 175° F, on-site solids disposal, closed loop
water recycle.
Scheme A - O
Scheme D (central processing concept) -
New coal-fired units
— 3.5% S in coal
.o 30
E
I
I
I
I
600 800
Power unit size, mw
I
Figure 68. Effect of power unit size on total
fixed investment for Scheme D vs Scheme A.
Magnesia Scheme D (centra] processing concept) - •
New coal-fired units
3.5% S in coal
JL
_L
_L
_L
1000 1500 2000
Total power unit size, mw
_L
Figure 69. Effect of total system size on fixed
investment: central regeneration concept.
90
-------
Table 51. Possible reduction in investment3 requirements
for magnesia Scheme A—special design provisions.
Equipment material-change from stainless steel to carbon
steel in slurry processing and MgO slurry areas
Piping and insulation-change to a carbon steel piping system for particulate
scrubbing, SO2 scrubbing, slurry processing and MgO slurry areas
Eliminate purge treatment in slurry processing area
Eliminate slurry processing between screens and centrifuges
Subtotal direct cost savings
Engineering design and supervision
Construction expense
Contractor fees
Contingency
Subtotal fixed capital investment savings
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total fixed capital investment savings
Investment
savings
$
93,500
269,500
160,000
81,500
604,500
42,300
54,400
24,200
72,500
797,900
79,800
31,900
909,600
aNew plant, coal fired, 500-mw, 3.5% S in coal, 1,040,000 scfm stack gas, 378 tpd H2S04.
Table 52. Comparison of investment requirements
for a magnesia system including a new sulfuric acid
unit with a system using an existing acid unit.
Magnesia
investment
including
new acid unit
Case $ $/kw
Magnesia
investment
with existing
acid unit
$ $/kw
Coal fired
Scheme A
200-mwN3.5%S 11,685,000 58.4
500-mw N 3.5% S 21,732,000 43.5
l,000-mwN3.5%S 33,118,000 33.1
9,963,000 49.8
18,686,000 37.4
28,424,000 28.4
Oil fired
Scheme A
200-mwN2.5%S 6,690,000 33.4 5,673,000 28.4
500-mw N 2.5% S 12,439,000 24.9 10,648,000 21.3
l,000-mwN2.5%S 18,888,000 18.8 16,084,000 16.1
Existing acid plant investment reduction calculated using 60% of
acid plant investment cost, 100% of acid storage cost, and 20% of
service facilities cost. Appropriate indirect costs were added.
be achieved when multiboiler combinations are considered
as shown in table 55.
Presented in table 56 is a summary of annual and unit
operating costs (7,000 hrs/yr) for magnesia Schemes A, B,
and C under regulated (power industry) economics. Com-
parison with both high and low cost limestone scrubbing
(1972 cost basis) is also provided. Except for the 200-mw
cases, the magnesia operating costs fall between the high
and low limestone cost values.
Magnesia process annual and unit operating costs under
nonregulated economics are shown in table 57. As would be
expected, the nonregulated values are lower than the
regulated cost results since profit and income taxes are not
included; however, comparison of the two sets of values has
little meaning since their derivation purposes are different.
Lifetime operating costs for power unit operating
profiles given earlier are summarized in table 58 for selected
magnesia process cases. As apparent, operating costs over a
30-year power unit life are quite significant. Keep in mind
that these particular values do not include provision for
labor and materials inflation which most assuredly will
increase the expected costs.
Details backing the summarized results are given in
tables A-33 to A-80 in Appendix A. For Schemes A, B, and
C, 46 operating cost tables are included, 23 for regulated
and 23 for nonregulated examples. In addition, two
limestone-wet scrubbing operating cost estimates for a new
500-mw coal-fired unit with 3.5% sulfur in the fuel are
included. One estimate covers a low cost limestone system;
the other covers the high cost example.
Note that the annual capital charges (percent of fixed
investment) shown in the regulated base tables are average
values since it is not practical to present the variable
declining balance portion of the charge (see table 47) used
in regulated cost analysis. The average capital charge
multiplied by the number of years of operation will give the
same actual outlay of dollars as the declining balance
calculation; however, the present worth of the two methods
will be different (discounted to 1972 dollars). There is, of
91
-------
Table 53. Total fixed investment requirements Scheme D-central process concept.
Scrubbing-drying
Unit size, mw
200
5x200
10x200
15x200
500
2x500
4x500
6x500
1,000
2 x 1 ,000
3 x 1 ,000
$
7,671,000
38,355,000
76,710,000
115,065,000
14,844,000
29,688,000
59,376,000
89,064,000
22,673,000
45,346,000
68,019,000
Regeneration-acid manufacture
Unit size , mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
$
5,017,000
12,354,000
19,534,000
26,096,000
8,294,000
12,354,000
19,534,000
26,096,000
12,354,000
19,534,000
26,096,000
Total system
Unit size, mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
$
12,688,000
50,709,000
96,244,000
141,161,000
23,138,000
42,042,000
78,910,000
115,160,000
35,027,000
64,880,000
94,115,000
Table 54. Scheme D unit combinations:
rated acid production capacity.3
Scrubbing-drying size
Number mw
1
5
10
15
1
2
4
6
1
2
3
200
200
200
200
500
500
500
500
1,000
2,000
3,000
Regeneration-
acid
production
mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
Tons/day,
100%H2S04
136
680
1,360
2,040
331
662
1,324
1,986
640
1,280
1,920
aBased on burning coal with 3.5% S, 92% evolved as SO2, "90%
recovered," 3% material handling losses; and 8,000 hr annual
operation for regeneration-acid manufacturing unit.
Table 55. Comparison of Scheme A total investment with Scheme D
total investment for similar capacity installations.
course, another method (sinking fund depreciation plus
interest, or capital recovery factor) of presenting a single
annual percentage of initial investment which will give the
same present worth of the lifetime capital charges as the
declining balance calculation approach, but the actual
dollar outlay will be different. Of the two procedures, the
average capital charge method has been chosen for annual
operating cost tables because it can incorporate straight line
depreciation, thus permitting simpler adjustment of the
percentage of initial investment for power units with
various remaining lives.
Using the tables of Appendix A for 7,000 hrs/yr
operation, the effects of several variables on magnesia
process operating costs are shown graphically in figures 70
to 82.
The annual and unit operating costs for Scheme D case
combinations are shown in table 59 for operation at each
site. The totals in table 59 are described graphically in
figures 83 and 84. The values given represent a cooperative
venture utilizing regulated economics for 7,000 hrs/yr
operation at the power plant site, and nonregulated
economics with 8,000 hrs/yr operation at the acid plant
Separate site,
Single
Scheme A
Mw
One 200
Five 200
Ten 200
Fifteen 200
One 500
Two 500
Four 500
Six 500
One 1 ,000
Two 1 ,000
Three 1,000
site
system
Total investment
$
11,685,000
58,425,000
116,850,000
175,275,000
21,732,000
43,464,000
86,928,000
130,392,000
33,118,000
66,236,000
99,354,000
Scheme
Scrubbing-
drying,
mw
200
5x200
10x200
1 5 x 200
500
2x 500
4x500
6x500
1,000
2 x 1 ,000
3 x 1 ,000
D system
Regeneration-
acid mfr.,
mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
Total
investment
$
12,688,000
50,709,000
96,244,000
141,161,000
23,138,000
42,042,000
78,910,000
115,160,000
35,027,000
64,880,000
94.115,000
92
-------
Table 56. Average operating costs for magnesia scrubbing processes
compared to limestone-wet scrubbing process under regulated economics.3
Limestone-wet scrubbing process
Low limestone cost,13
Magnesia processes
Coal fired
Scheme A
200-mwE3.5%S
200-mwN3.5%S
500-mwE3.5%S
500-mwN2.0%S
500-mwN3.5%S
500-mwN5.0%S
l,000-mwE3.5%S
l,000-mwN3.5%S
Scheme B
200-mwN3.5%S
500-mwN3.5%S
l,000-mwN3.5%S
Scheme C
200-mwN3.5%S
500-mwN3.5%S
l,000-mwN3.5%S
Oil fired
Scheme A
200-mw E 2.5% S
200-mw N 1 .0% S
200-mwN2.5%S
200-mwN4.0%S
500-mwE2.5%S
500-mw N 1 .0% S
500-mw N 2.5% S
500-mw N 4.0% S
l,000-mwE2.5%S
1 ,000-mw N 1 .0% S
l,000-mwN2.5%S
l,000-mwN4.0%S
Scheme B
200-mwN2.5%S
500-mw N 2.5% S
l,000-mwN2.5%S
Average
annual cost
$
4,297,200
3,870,700
7,762,500
5,913,900
7,048,900
8,066,600
11,494,700
10,635,400
3,939,600
7,161,300
10,803,800
3,389,400
6,094,800
9,193,100
$
2,557,300
1,725,300
2,305,600
2,751,900
4,548,800
3,214,200
4,159,800
4,973,500
6,822,000
4,817,200
6,317,100
7,566,300
2,274,400
4,053,100
6,126,200
Unit
operating cost
$/ton coal
7.75
7.21
5.79
4.51
5.37
6.15
4.38
4.19
7.34
5.46
4.26
6.32
4.64
3.62
$/bbl oil
1.20
0.84
1.12
1.34
0.88
0.64
0.83
0.99
0.68
0.50
0.65
0.78
1.11
0.81
0.63
$/ton acid
92.22
85.64
68.76
93.72
63.85
51.12
52.04
49.82
87.16
64.87
50.60
87.58
64.36
50.24
$/ton acid
102.70
178.97
95.67
71.48
75.56
136.20
70.63
52.80
57.91
105.87
55.46
41.53
94,37
68.81
53.79
on-site solids disposal
Average
annual cost
$
3,214,700
2,869,200
5,927,900
4,801,000
5,376,300
5,894,000
8,981,900
8,230,900
2,869,200
5,376,300
8,230,900
2,869,200
5,376,300
8,230,900
$
2,111,700
1,596,700
1,836,700
2,044,500
3,755,100
2,898,800
3,343,600
3,747,300
5,694,500
4,443,400
5,160,400
5,824,300
1,836,700
3,343,600
5,160,400
Unit
operating cost
$/ton coal
5.80
5.35
4.42
3.66
4.10
4.49
3.42
3.24
5.35
4.10
3.24
5.35
4.10
3.24
$/bbl oil
1.03
0.78
0.89
0.99
0.73
0.58
0.66
0.74
0.57
0.46
0.53
0.60
0.89
0.66
0.53
High limestone cost,c
off-site solids disposal
Average
annual cost
$
4,002,600
3,633,400
8,253,700
6,347,600
7,621,500
8,861,700
13,879,900
12,883,100
3,633,400
7,575,900
12,883,100
3,633,400
7,575,900
12,883,100
$
2,329,800
1,638,300
2,046,900
2,441,400
4,556,000
3,163,100
4,112,500
5,046,700
7,483,800
5,079,200
6,848,000
8,607,200
2,046,900
4,122,500
6,848,000
Unit
operating cost
$/ton coal
7.22
6.77
6.15
4.84
5.81
6.75
5.08
5.08
6.77
5.77
5.08
6.77
5.77
5.08
$/bbl oil
1.10
0.80
0.99
1.19
0.89
0.63
0.82
1.00
0.74
0.52
0.70
0.88
0.99
0.82
0.70
a7,000 hr operation/yr.
^Limestone at $2.05/ton and variable disposal cost for fly ash and calcium solids-ranges from $2.85/ton to $1.33/ton.
cLimestone at $6/ton and $6/ton disposal cost for fly ash and calcium solids.
site. The costs include shipping expense in the Chicago area
for transporting the magnesium sulfite and recycle mag-
nesium oxide up to 50 miles by truck. The results are based
passing the costs incurred in the scrubbing-drying
on
operation to the raw material costs of the regeneration-acid
manufacturing operation. This procedure is used only for
the individual Scheme D cost sheets shown in Appendix A
under tables A-81 to A-94. In the Profitability and
Economic Potential section of this report, a different
procedure will be examined.
93
-------
S 7.5
£ 5.0
I
Scheme A - O
Scheme B - £
Scheme C - °
3.5% Sin coal
" 7000 hr annul
_L
_L
600
JL
Power uml size, mw
Figure 70. Effect of power unit size on annual operating
cost: new coal-fired units under nonregulated economics.
Scheme A- O
New units ——
Existing units ---
3.5% S in coal
7000 hr annual operation
600 800
Power unit size, mw
Figure 71. Effect of plant status (new vs existing) on annual
operating cost: coal-fired units under regulated economics.
Existing units
- 2.5% S moil
7000 hr annual operation
Scheme A - O
New units
400 600 800
Power unit size, mw
Figure 72. Effect of plant status (new vs existing) on annual
operating cost: oil-fired units under regulated economics.
I 10
T
T
Scheme A - O
Scheme B -&
Wet-limestone scrubbing - X
3.5% S in coal
2.5% Sin oil
7000 hr annual operation
High limestone cost-
I
600 800
Power unit size, mw
Figure 73. Effect of power unit size on annual
operating costs: regulated economics,
Scheme A - O
Scheme B - a
Scheme C-°
— Wet-limestone scrubbing - X
New coal-fired units
3 5% Sin coal
7000 hr annual operation
T
T
igh limestone cost
Low limestone cost
_L
_L
_L
D 200 400 600 800 1000 1200
Power unit size, mw
Figure 74. Effect of power unit size on unit operating
cost: coal-fired units under regulated economics.
I
I
Scheme A - O
Scheme B-&
Wet-limestone scrubbing- X
New oil-fired units
2.5% S in oil
7000 hr annual operation
Low limestone cost
400 600 800
Power unit size, mw
Figure 75. Effect of power unit size on unit operating
cost: oil-fired units under regulated economics.
-------
2 75
2
S.
Scheme A - O
Scheme B - A
Scheme C - a
New coal-fired units
3.5% S in coal
7000 hr annual operation
_L
600 800
Power unit size, mw
Figure 76. Effect of power unit size on unit operating
cost of acid: coal-fired units under nonregulated economics.
Scheme A - O
New coal-fired units
500-mw units
7000 hr annual operation
Sulfur in coal, %
Figure 78. Effect of sulfur content of coal on unit operating
cost of acid under nonregulated economics.
3000 4500
Annual on-stream time, hr.
Figure 80. Effect of annual operating time on annual
operating cost under regulated economics.
Scheme A - O
Wet-limestone scrubbing- X
New coal-fired units
500-mw units
7000 hr annual operation
High limestone cost
Low limestone cost
Sulfur in coal, %
Figure 77. Effect of sulfur content of coal on annual
operating cost under regulated economics.
115
'i
Scheme A - O
New oil-fired units
7000 hr annual operation
Sulfur in oil, %
Figure 79. Effect of sulfur content of oil on total annual
operating costs under regulated economics.
Scheme A - O
New oil-fired units
3000 4500
Annual on-stream time, hr
Figure 81. Effect of annual operating time on annual
operating cost under nonregulated economics.
-------
Scheme A - O
New coal-fired units
3000 4500
Annual on-stream time, hr
Figure 82. Effect of annual operating time on unit
operating cost of acid under nonregulated economics.
S 80
o
Magnesia Scheme D - central processing concept - •
New coal-fired units
3.5% S in coal
Applicable for central regeneration plants located up to 50 miles
from scrubbing unit
,UonoOOOO—
>bttt>»»swmS -I
I I
I I
1000 1500 2000
Total system size, mw equivalent
Figure 83. Central regeneration system:
effect of total system size on annual
operating costs under cooperative economics.
•G
™ 90
I I I 1
Magnesia Scheme D - centra] processing concept - •
New coal-fired units
3.5% S in coal
Applicable for central regeneration plants located up to 50 miles
from the scrubbing unit
Combination of 200-mw scrubbing system
- Combination of 500-mw scrubbing system
Combination of 1000-mw scrubbing system
1000 1500 2000
Total system size, mw equivalent
Figure 84. Central regeneration system:
effect of total system size on unit
operating cost under cooperative economics.
i
Scheme A - O
Scheme D - •
New coal-fired units
3 5% S in coal
600 800
Power unit size, mw
Figure 85. Effect of shipping distance on total annual
operating cost for Scheme D under cooperative economics.
96
-------
Table 57. Annual operating costs for magnesia
Magnesia processes
Coal fired
Scheme A
200-mwE3.5%S
200-mw N 3. 5% S
500-mw E 3. 5% S
500-mw N 2.0% S
500-mw N 3. 5% S
500-mw N 5. 0% S
l,000-mwE3.5%S
l,000-mwN3.5%S
Scheme B
200-mw N 3. 5% S
500-mw N 3. 5% S
l,000-mwN3.5%S
Scheme C
200-mw N 3. 5% S
500-mw N 3. 5% S
l,000-mwN3.5%S
Oil fired
Scheme A
200-mw E 2.5% S
200-mw N 1 .0% S
200-mw N 2.5% S
200-mw N 4.0% S
500-mw E 2.5% S
500-mw N 1 .0% S
500-mw N 2. 5% S
500-mw N 4.0% S
l,000-mwE2.5%S
l,000-mwN1.0%S
l,000-mwN2.5%S
l,000-mwN4.0%S
Scheme B
200-mw N 2.5% S
500-mw N 2.5% S
l,000-mwN2.5%S
Annual cost
t
4>
3,746,400
3,468,400
6,879,300
5,276,300
6,306,400
7,232,500
10,185,100
9,508,800
3,528,400
6,404,400
9,657,200
3,044,600
5,469,100
8,245,100
Annual cost
$
2,241,000
1,547,200
2,072,500
2,476,100
4,044,800
2,875,200
3,730,800
4,469,000
6,070,600
4,306,000
5,666,600
6,802,800
2,039,700
3,625,100
5,477,000
Unit operating cost
$/ton coal
6.76
6.46
5.13
4.02
4.81
5.51
3.88
3.75
6.57
4.88
3.81
5.67
4.17
3.25
$/bbl oil
1.05
0.75
1.01
1.20
0.79
0.57
0.74
0.89
0.60
0.44
0.58
0.70
0.99
0.72
0.56
$/ton acid
80.40
76.73
60.93
83.62
57.12
45.83
46.11
44.54
78.06
58.01
45.23
78.67
57.75
45.06
$/ton acid
90.00
160.50
86.00
64.31
67.19
121.83
63.34
47.44
51.53
94.64
49.75
37.34
84.64
61.55
48.09
a7,000 hr operation/yr.
T
T
T
Scheme D - •
New coal-fired units
3.5% S in coal
Combination of 500-mw power units and central
process acid plants
60 90 120
Shipping distance, miles
Figure 86. Effect of shipping distance on unit cost of acid
for combinations of Scheme D scrubbing and
regeneration plants under cooperative economics.
As can be derived from tables 56 and 59, a single unit
Scheme D system has a higher operating cost than com-
parable single-site Scheme A facilities; however, when
multiple units are considered, the potential economy is
improved as indicated in table 60. In addition, the results
indicate that the smaller the power units making up the
system, the greater the potential economy of central
processing over single-site processing.
The effect of shipping distance on total annual operating
cost for single 200-mw, 500-mw, and 1000-mw Scheme D
systems is shown in figure 85. In addition, figure 86
displays the effect of shipping distance on unit cost of acid
for combinations of 500-mw scrubbing-drying units coupled
with a central regeneration-acid production unit.
97
-------
Table 58. Lifetime operating costsa for magnesia scrubbing processes (new plants).
Regulated economics Nonregulated economics
Coal fired
~3.5%S
in coal
Total
operating cost
Unit operating cost
$/ton coal
$/ton acid
Total
operating cost
Unit operating cost
$/ton coal
$/ton acid
Scheme A
200-mw
500-mw
1,000-mw
Scheme B
200-mw
500-mw
1,000-mw
96,608,400
175,486,300
263,737,400
98,516,700
178,601,100
268,289,700
9.88
7.34
5.71
10.08
7.47
5.80
117.31
87.24
67.81
119.63
88.79
Scheme C
200-mw 84,056,700 8.60 119.14
500-mw 150,473,300 6.29 87.26
1,000-mw 225,932,400 4.89 67.79
Limestone-wet scrubbing process—low limestone cost, on-site solids disposal
200-mw 72,705,900 7.43
500-mw 136,225,900 5.70
1,000-mw 208,272,000 4.51
Limestone-wet scrubbing process—high limestone cost, off-site solids disposal
200-mw 82,657,700 8.46
500-mw 170,642,600 7.14
1,000-mw 283,172,800 6.13
60,559,000
108,584,000
161,926,500
61,556,000
110,195,000
164,349,000
53,380,500
94,586,500
141,061,000
Limestone-wet scrubbing process—low limestone cost, on-site solids disposal
200-mw 40,426,700 1.08
500-mw 73,531,800 0.81
1,000-mw 112,526,700 0.64
Limestone-wet scrubbing process—high limestone cost, off-site solids disposal
200-mw 47,671,000 1.27
500-mw 94,255,700 1.03
1.000-mw 154,350,700 0.87
6.19
4.54
3.51
6.30
4.61
3.56
5.46
3.95
3.05
73.54
53.98
41.63
74.75
54.78
42.25
75.66
54.85
42.32
Oil fired
2.5% S
in oil
Scheme A
200-mw
500-mw
1 ,000-mw
Scheme B
200-mw
500-mw
1 ,000-mw
Total
operating cost
$
57,300,100
103,052,300
155,385,400
56,979,700
101,363,200
152,398,000
$/bbl oil
1.53
1.13
0.88
1.52
1.11
0.86
$/ton acid
130.52
96.09
74.92
129.79
94.51
73.48
Total
operating cost
$
36,597,500
64,675,000
97,163,500
35,966,000
62,705,500
93,614,500
$/bbl oil
0.98
0.71
0.55
0.96
0.68
0.53
$/ton acid
83.37
60.30
46.85
81.93
58.47
45.14
a30 yr life; 7,000 hi-10 yr, 5,000 hr-5 yr, 3,500 hr-5 yr, 1,500 hi-10 yr.
98
-------
Table 59. Total operating costs for Scheme D j
Scrubbing-drying operation
(regulated economics)
Regeneration-acid manufacture
(nonregulated economics)
Total,
Mw
200
5x200
10 x 200
15x200
500
2x500
4x500
6x500
1,000
2x 1,000
3x 1,000
$
2,498,900
12,494,500
24,989,000
37,483,500
4,665,300
9,330,600
18,661,200
27,991,800
7,409,300
14,818,600
22,227,900
$/ton MgS03
44.43
44.43
44.43
44.43
34.93
34.93
34.93
34.93
28.69
28.69
28.69
Mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3,000
$
1,650,600
4,407,500
7,718,300
10,897,100
2,838,100
4,286,300
7,460,500
10,169,400
4,181,900
7,252,300
9,856,900
$/ton acid
36.52
19.50
17.08
16.07
25.71
19.41
16.89
15.35
19.59
16.98
15.39
$
4,149,500
16,902,000
32,707,300
48,380,600
7,503,400
13,616,900
26,121,700
38,161,200
11,591,200
22,070,900
32,084,800
$/ton acid
91.80
74.78
72.36
71.36
67.97
61.67
59.15
57.61
54.29
51.69
50.09
Cooperative venture economics; new coal-fired units; 3.5% S in coal; 7,000 hr/yr scrubbing-drying; 8,000 hr/yr regeneration acid manufacture.
Table 60. Total annual operating cost: combinations of power unit systems in Scheme D.
Separate site systems
(cooperative economics)
Single site systems
(regulated economics)
Mw
One 200
Five 200
Ten 200
Fifteen 200
One 500
Two 500
Four 500
Six 500
One 1,000
Two 1 ,000
Three 1,000
$
3,870,700
19,353,500
38,707,000
58,060,500
7,048,900
14,097,800
28,195,600
42,293,400
10,635,400
21,270,800
31,906,200
Scrubbing-
drying
mw
200
5x200
10x200
15x200
500
2x500
4x 500
6x500
1,000
2 x 1 ,000
3 x 1 ,000
Regeneration-
acid manufacture
mw
200
1,000
2,000
3,000
500
1,000
2,000
3,000
1,000
2,000
3000
$
4,149,500
16,902,000
32,707 300
48,380,600
7,503,400
13,616,900
26,121,700
38,161,200
11,591,200
22,070,900
32,084,800
aNew coal-fired units, 3.5% S in coal.
99
-------
PROFITABILITY AND ECONOMIC POTENTIAL
For nonrecovery stack gas desulfurization processes such as
limestone-wet scrubbing, no sale of product is involved;
therefore, identification of investment and operating costs
provides sufficient measure for comparison with some
alternate methods of pollution control. However, for
recovery processes such as magnesia scrubbing-regeneration,
which yield a salable product, a more extensive evaluation
(83) is required including the estimation of product sales
credit or revenue, the preparation of cash flow projections
over the years of power unit life, and the use of recognized
standards for measuring profitability of capital
expenditures.
Estimation of sales revenue can be particularly difficult
since many factors including plant location, plant operating
flexibility, plant capacity, sales volume, and marketing
policy affect competition with new and existing sources of
sulfur based products. In this report, a cursory market
investigation is presented to establish a basis for making this
rather hazardous forecast; however, it is recognized that a
more complete, thorough study of the sulfur, sulfuric acid,
and related markets is needed for accurate assessment of
product value.
In the market analysis given herein, consideration is
focused on defining historical sulfuric acid capacity, pro-
duction, consumption, and market growth, spotlighting
grades of acid and end-uses, plus locating acid plants and
power plants for the purpose of predicting the best end-use
markets for the acid, market location, and pricing policy.
Using assumed sales values along with the appropriate
investment and operating cost data, year-by-year computer-
calculated cash flows are prepared under regulated eco-
nomics (declining depreciation base) for each of the 29
magnesia process cases cited earlier and compared directly
with the limestone-wet scrubbing process which has no sales
revenue. In addition, appropriate nonregulated cash flows
are also projected and profitability determined for the
magnesia processes. The evaluation of the central processing
concept under cooperative economics (scrubbing-drying,
regulated; regeneration-acid manufacture, nonregulated) is
more complex than the methods used for either regulated
or nonregulated economics alone; therefore, a modified set
of assumptions will be used for Scheme D.
Marketing
The primary product of magnesia scrubbing processes,
sulfuric acid, is the most widely manufactured chemical in
the world. In 1970, approximately 91,000,000 metric tons,
100% H2S04 equivalent, were produced; 69,743,000 tons
in the noncommunist countries and 21,249,000 tons in the
communist nations (9). This represented an increase of 5%
over 1969 figures and an 8% increase over 1968. For North
America, the U. S. and Canada, 27,735,000 metric tons of
acid were produced, an increase of only 2.5% over the
previous year. The U. S. alone manufactured over 91% of
this quantity and the U. S. production of 25,260,000
metric tons represents an increase of 64% since 1960.
Consumption of sulfuric acid in the U. S. in 1970 was
approximately 3.8% greater than in 1969, which is a
slightly larger increase than for production (10). Approxi-
mately 28,675,000 metric tons were consumed, 13% more
than manufactured during the year. Most of the difference
came from inventories as very little acid is imported, only
about 90-150,000 metric tons/yr.
From U. S. Department of Commerce data (93), a
summary of sulfuric acid production in short tons for each
month of 1972 is shown in table 61. The total represents an
increase of approximately 5.5% over 1971 production.
Current manufacturing capacity for sulfuric acid
approaches 40 million short tons of acid/year with more
Table 61. Summary of U.S. sulfuric acid
production-1972 (93).
Month
Short tons
January
February
March
April
May
June
July
August
September
October
November
December
Total for year
2,439,946
2,446,800
2,678,765
2,645,560
2,712,606
2,521,804
2,487,157
2,659,375
2,494,789
2,659,767
2,627,615
2,671,892
31,046,076
100
-------
than half of capacity committed to captive use. Available
data (14) indicates that in 1966, only about 13 million tons
were marketed out of approximately 28 million tons
produced. As shown in figure 87, states having the most
capacity for acid manufacture include Florida (Tampa
region), Louisiana, Texas, New Jersey, and Illinois. A
state-by-state breakdown of capacity as of 1970 is shown in
table 62. Of the 200 or so plants in the U. S., 170 utilize
the contact process and the remainder the chamber process.
Chamber acid output is estimated to be about one-half
million tons/year or less than 2% of the total production.
Individual acid plant sizes have been on the increase for
several years, with some units of 3,000 tons/day capacity in
operation (13). The larger plants are usually part of large
fertilizer complexes using acid captively. Most plants use
sulfur as the raw material, approximately 75% in 1966;
however, the number of plants processing pyrites, smelter
gases, acid sludge, and hydrogen sulfide are increasing as
more stringent pollution control laws come into play. At
this time, only demonstration systems for catalytic oxida-
tion (EPA-Monsanto- Illinois Power) and magnesia scrubbing
(EPA-Chemico-Basic-Boston Edison) are producing sulfuric
acid from power plant offgas. More acid is sure to come
from this source.
Based on data from industry sources the major end-uses
of sulfuric acid in the U. S. are given in table 63 with the
quantities being shown for 1970. As can be seen, the
predominant consumer of sulfuric acid is chemical fertil-
izer. In 1970, North American consumption of sulfuric acid
for fertilizer manufacture represented approximately 54%
Table 62. Sulfuric acid plant capacity-
short tons per day (14).
Alabama 1,610 Mississippi 1,067
Arizona 2,627 Missouri 3r303
Arkansas 737 New Jersey 6,913
California 6,774 New Mexico 446
Colorado 1,483 New York 583
Delaware 1,050 North Carolina 3,480
Florida 23,661 Ohio 3,180
Georgia 1,369 Oklahoma 630
Idaho 3,470 Pennsylvania 2,177
Illinois 6,944 Rhode Island 50
Indiana 2,066 South Carolina 324
Iowa 1,877 Tennessee 4,421
Kansas 747 Texas 9,855
Kentucky 550 Utah 2,133
Louisiana 12,600 Virginia 1,983
Maine 223 Washington 333
Maryland 2,260 West Virginia 470
Massachusetts 330 Wisconsin 67
Michigan 1,301 Wyoming 360
Grand total 114,294
Table 63. Sulfuric acid end-use pattern-1970.
Thousand
short tons
(100% basis)
Fertilizer
Phosphoric acid products 13,750
Normal superphosphate 1 ,240
Cellulosics
Rayon 520
Cellophane 170
Pulp and paper 600
Petroleum alkylation 2,400
Iron and steel pickling 800
Nonferrous metallurgy
Uranium ore processing 300
Copper leaching 350
Chemicals
Ammonium sulfate— coke oven 500
synthetic 480
chemical byproduct 190
Chlorine drying 1 50
Alum 600
Caprolactam 260
Dyes and intermediates 370
Detergents, synthetic 400
Chrome chemicals 1 00
HC1 150
HF 880
Ti02 1,440
Alcohols 1,800
Other chemicals 380
Industrial water treatment 200
Storage batteries 140
Other processing 470
Total 28,640
of the total quantity of sulfuric acid consumed (9)
compared to approximately 43% during 1969 (8).
Although most of the sulfuric acid consumed in fertilizer
manufacture is concentrated, high quality material, wet
process phosphoric acid produced by reacting sulfuric acid
with phosphate rock can be made with off-grade acid. For
the other end-uses of sulfuric acid, high purity and high
concentration are almost mandatory.
As is apparent from table 63, sulfuric acid has a wide
variety of uses, some of which are based on excellent
physcial properties, but most on cost. Sulfuric acid is very
often preferred over other mineral acids, chemicals or
different process technology because it is the least expen-
sive alternative. For example, in phosphate rock acidula-
tions and phosphoric acid manufacture, its major end-use, it
is the lowest cost acidulant available. There was a period in
the late 1960's when this was under challenge as sulfur
prices rose to higher levels; however, the sulfur shortage was
101
-------
o
to
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/ a
P / \.
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© o
ooooooOO
901- IOO1- 1901- 2OCH- 2501- 3
< IOOO 1500 2000 2500 3OOO 3
OOOO
, """"~\J3-J / °.»...\"tf'"
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LEGEND \ \^
SULFURIC ACID PLANT SIZE- SHORT TONS PER DAY
NUMBER OF PLANTS IN AREA.
10,001-
21, BOO
Figure 87. Sulfuric acid manufacturing capacity.
-------
short in duration and supply soon exceeded demand,
driving prices back down to recent lows.
Sulfuric acid is an excellent drying agent and is used in
such applications as chlorine and nitric acid drying, DDT
and chloral production, and in nitration reactions. The acid
is an effective catalyst for many hydrocarbon and organic
chemical syntheses, such as formations of petroleum
alkylate from olefins and a paraffin, or the Beckman
rearrangement of cyclohexane oxime to caprolactam for
nylon fiber manufacture. It has been suggested that this
characteristic is associated with its strong affinity for water.
Sulfuric acid readily forms organic sulfates with many
hydrocarbons which are easily hydrolized to yield desirable
organics; this property is useful in the manufacture of
pehnol and certain alcohols.
The acid has a high boiling point which limits volatiliza-
tion losses in leaching, acidulation, and pickling operations.
It is commonly specified as an electrolyte for batteries,
used as a bath in cellulose processing, consumed in the
manufacture of chromates, used in hydrogen fluoride
production from fluorspar, and serves to process ore for
titanium dioxide and uranium manufacture.
Sulfuric acid is made and used in a variety of
concentrations which are usually indicated as follows:
% H2SO4 or °Baume-The simplest description of
sulfuric acid concentration is % H2SO4. However, because
of the distinct relationship between specific gravity and
strength (up to 93%) and the simplicity of measuring
specific gravity by hydrometer, most acid concentrations
up to 93% are expressed as degrees Baume. From 93 to
100%, acids are referred to by concentration. These are the
products assumed in this study.
Monohydmte-This is 100%H2SO4.
Oleum—Acids stronger than 100% H2S04, containing
free S03, are called oleums or fuming acids and are usually
described in terms of S03 content. For example, a 20%
oleum is comprised of 20% S03 and 80% H2S04 ; however,
in terms of acid content equivalent, it is expressed as
104.50% H2S04. Oleum is not considered as a product in
this study.
Table 64 shows a few typical acid strengths and their
major end-uses (14).
A complete market study of a chemical such as sulfuric
acid is beyond the scope of this report; however, to
properly assess the economic potential of stack gas pro-
cesses for sulfur dioxide recovery and conversion to acid, a
limited investigation is included. Hopefully, in the near
future, a thorough market study for sulfur products from
power plants and smelter sources can be completed.
For basic economic evaluation, several items need
specific coverage including market outlook, market loca-
tion, best end-use market, and pricing policy. Although
sulfuric acid is a large volume chemical with numerous
outlets, difficulty will be encountered in marketing all of
the acid produced from power plant stack gas at an
attractive price. Furthermore, production volume, which is
normally a prime variable in marketing, is set by the power
plant size and all material produced must be disposed
readily regardless of demand.
Currently, there are some spot shortages in the sulfuric
acid industry (86) even though capacity is estimated at
about 40 million tons/yr and consumption at only 30-31
million tons/yr. Several of the smaller plants have been
shutdown recently due to production economics and
environmental impact of S02 removal, and many of the
new large (1,000 tpd and larger) units are captive, operating
at rates matching internal demand. Although recent growth
in acid consumption has slowed, the long range rate is
estimated to be about 4-6%/yr which is closely tied to the
fertilizer growth pattern.
At least for several years, both supply and price
competition are expected to increase from sources of sulfur
dioxide emission which are- subject to increasingly tough air
pollution laws. Both fossil-fueled power plants and western
smelters are being pressed to clean up their emissions at a
time when their respective products, electrical energy and
non-ferrous metals," are undergoing rapid growth. At the
same time, a rapidly growing need for clean fuels has
resulted in an increase in natural gas production both in the
U. S. and Canada, such that more and more byproduct sour
gas sulfur is being made available for low cost sulfuric acid
manufacture. Already, the Canadian sour gas operations are
moving large tonnages of sulfur to market at prices as low
as $5-12/ton f.o.b. The natural gas is much more valuable
than the byproduct sulfur and will continue to be produced
regardless of value received for the sulfur.
Especially on the East Coast where byproduct sulfur is
more expensive, Chemico reports that there is much
interest'by major sulfuric acid marketers to use offgas S02
as a raw material in place of elemental sulfur for acid
manufacture. This interest particularly covers existing acid
plants, many of which will require upgrading to meet new
S02 emission standards. The construction of new and larger
acid plants to replace a number of smaller and less efficient
existing plants is also of considerable interest in a number
of areas. The marriage of an acid plant and one or more
power plants is attractive to both parties since these
industries represent two of the most reliable and consistent
types of operations in American industry with long life
periods of 30-40 years. The acid plant requires a consistent
source of sulfur values at competitive prices while the
utility requires an assured home for the S02 it produces.
Location of the power plant equipped with a magnesia
scrubbing process and producing sulfuric acid will have
major influence on process economics (for location of
major U. S. power plants burning coal or oil, see figure 88)
(30). It is expensive to ship sulfuric acid very far, with
150-200 miles being a practical limit for most rail and truck
103
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SOUTH DAKOTA I Q
\ 9J "~"~~Q—'-.-._ _
POWER GENERATION SIZE - MEGAWATTS
o o o O O O
0- 501- 1001- 1501- ZOO1- 2501- 3001- 35OI- 4001-
500 1000 1500 2000 2500 3000 35OO 4OOO 5000
5001- 6001- 70OI - 6001- 9001- 10,001-
6000 7000 BOOO 9000 10,000 15, 000
Figure 88. Location of major coal- and oil-fired power units—1971 (30).
-------
Table 64. Typical sulfuric acid strengths and major end uses (14).
% H2SO4
35.67
62.18-69.65
77.67
80.00
93.19
98-99
100.00
104.50
106.75
109.00
111.25
113.50
114.63
122.50
°Be
30.8
50-55
60.0
61.3
66.0
66.4-66 .3b
66.2b
-
-
-
-
—
—
-
% Oleum
(% S03 content)
_
—
-
-
—
—
—
20
30
40
50
60
65
100
Uses3
Batteries
Normal superphosphate and fertilizers.
Normal superphosphate and fertilizers
isoproply and secbutyl alcohols.
Copper leaching.
Phosphoric acid, TiO2 .
Phosphoric acid, alkylation, ethyl
alcohol, boric acid.
Alkylation.
Caprolactam (Beckmann rearrangement); explosives
and nitrations, chlorine and nitric acid drying;
surface active agents, synthetic petroleum
sulfonates, and other sulfonations; blending with
weaker acids.
^These data do not imply that only the indicated concentrations are used for the applications shown.
At concentrations approaching 100% H2SO4, specific gravity begins to decrease.
loads. For longer distances, acid could be shipped eco-
nomically by barge. The major U. S. markets for sulfuric
acid are concentrated on the East and Gulf Coasts. At
present, the States of Florida, Louisiana, Texas, Illinois,
and New Jersey consume close to half the U. S. total acid
output with Florida taking one-quarter of the total.
Waterways in these areas would allow transport of large
quantities of acid for long distances at competitive prices.
Similarly, it is possible to place a central processing plant
some distance from the power units and incur transport
costs for the MgO and MgS03 between the plants involved.
Florida is a major acid market since the reserves of
phosphate rock are plentiful for fertilizer manufacture.
Currently, sulfur is barged-in from Mexico, Texas, and
Louisiana and with sulfur at $24/long ton f.o.b. and freight
at $4-5/ton, Florida sulfuric acid can be produced for
$10-15/shortton.
With such large quantities of acid as can be produced by
a large power plant (378 tons/day, 500-mw, 3.5% S in coal)
or central process acid complex (3000-mw equivalent,
2,000 tpd acid), the best end-use market appears to be the
phosphate fertilizer industry. One of several devices could
be utilized to improve economics, either long-term purchase
contracts, on-site fertilizer plant adjacent to power plant, or
barge shipments of product acid to large fertilizer com-
plexes. The other end-use markets could be pursued also;
however, such markets could place great pressures on single
unit operation for a steady, continuous source of acid.
With the exception of Illinois, most of the large acid
consuming areas are served by power plants fueled with oil
or gas. In addition, nuclear plants are moving into Florida.
The best location for a power plant equipped with a
sulfuric acid producing system appears to be in the
Midwest, preferably Illinois with its abundance of high
sulfur coal. The Midwest, of course, consumes great
quantities of phosphate fertilizer (54% of national con-
sumption) and currently, intermediate phosphatic materials
are shipped by barge from Florida to the Midwest; however,
if low cost acid were available, it might be feasible to ship
phosphate rock to the Midwest and process with local acid.
Consumption statistics for phosphatic fertilizer in the
midwestern states are shown in table 65 (90).
Assuming 2.7 tons of sulfuric acid/ton P2OS (an average
figure), approximately 10,980,000 tons of sulfuric acid
could have been utilized" in 1970 for phosphate fertilizers
consumed in the listed states. This is equivalent to over
45,000-mw of power plant capacity.
Marketing sulfuric acid in large quantities requires some
product flexibility; that is, more than one concentration of
Table 65. Consumption of phosphate fertilizers
in the midwestern states (90).
State
Ohio
Indiana
Illinois
Michigan
Wisconsin
Missouri
Iowa
Minnesota
Total
1968
thousand
208
284
457
128
116
165
361
214
3,866
1969
tons P205
212
253
497
123
121
160
382
292
4,080
(Prelim)
1970
216
243
528
127
120
171
405
223
4,066
105
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acid should be available for sale. Indications are that three
concentrations dominate 80% of the market, 60° Be (78%),
66° Be (93%), and 98%. Any plant producing for the
merchant market (non-captive) would probably need
minimum storage facilities for three products for 30 days.
In addition to storage needs, 70-75 tank cars or several
barges would be required to transport the production of a
500-mw power unit to market. If these cars or barges can
be purchased or leased on a long-term basis, shipping costs
in the range of $l-2/ton can sometimes be achieved.
Estimated commercial shipping costs for sulfuric acid
moved by rail and truck for Chicago and Philadelphia
locations are shown in table 66.
Current 1972 list prices for tank car quantities of
sulfuric acid (100% basis) range from $30-34/ton. Usually,
these prices are discounted for volume consumers to a range
of $20-28/ton, 100% acid. Although some quantities from a
power plant may be disposed of at these prices, the volumes
produced by large power units will result in a pricing policy
somewhat less dependent on current market values. The
major factors affecting the pricing policy of byproduct
sulfuric acid are:
1. Area competitive forces.
2. The cost of sulfur to existing plants.
3. The flexibility of acid unit operation to match
demand.
In addition, as with any sulfuric acid market, the distances
of customers from available acid sources will influence net
revenue to the manufacturer. For a midwestern location,
current prices of sulfur from the Gulf Coast would permit
an acid manufacturing cost of $12-16/ton, whereas
Canadian sulfur at $5-8/long ton and freight costs of
$14-16/ton would yield an acid cost of $10-14/ton. These
values include capital'charges which, if neglected for those
plants operating on margin only, would reduce acid values
to $8-10 minimum f.o.b. cost.
For midwestern acid producers, the stiffest competition
for sale of sulfuric acid to fertilizer plants would be the
processing and shipment of fertilizers from Florida. For
phosphate rock to be shipped to the Midwest for acidula-
tion and the resultant pro'ducts to remain competitive with
the processed material from Florida, sulfuric acid from
midwestern power plants would need to be available for
about $4-1 I/ton delivered. This means that the fertilizer
plant needs to be close to the acid plant to minimize
transportation costs.
For purposes of this study, it will be assumed that for
the first 10 years of operation, the net sales revenue
(revenue after all sales and shipping expense deducted) for
acid consumed in all markets averages $8/ton when
supplied from single-site power-acid systems. To give more
complete coverage, this value will be subjected to sensitivity
analysis in the economic evaluation by varying the net sales
revenue from $0-32/ton. In addition, after the tenth year of
Table 66. Sulfuric acid shipping costs.
Published rail shipping rates for sulfuric or spent
sulfuric acid in tank cars, minimum weight
rule 35, but not less than 140,000 Ibs per car.
From Philadelphia, Pennsylvania, and Chicago, Illinois
Rate in
To (miles) cents/net tona
25
50
100
150
300
22 5b
25 lb
397
633
1,127
Estimated private costs for
shipping sulfuric acid in tank trucks.0
From Philadelphia, Pennsylvania and Chicago, Illinois
Cost in cents
To (miles) /net ton
3003
25
50
75
100
150
300
300
375
500
750
1,500
aRates lower than those shown may be published from Philadelphia
or Chicago to specific destinations in any given mileage category.
As an illustration, rate of 625 cents/net ton, minimum weight
140,000 Ibs is published from Chicago to Wood River, Illinois (276
miles), restricted to apply only on movement of sulfuric acid, the
virgin acid to the point of distribution and the spent acid in return
from point of distribution to origin for processing, and so certified
on bill of lading.
"Subject to minimum rate of 383 cents per net ton per car, on
traffic originating at or destined to points in the Chicago switching
district. This minimum of 383 cents per net ton does not apply on
movements where the origin and destination are both outside the
Chicago switching district.
cEstimated on basis of 60 cents per mile for distances of 50 miles or
less and 50 cents per mile for distances over 50 miles. Cents are
calculated on round trip mileage, assuming load of 40,000 Ibs in
one direction and an empty return in the other direction.
"Estimated minimum cost, based on charges presently published by
commercial carriers.
operation, net sales revenue will be assumed to drop to
$5/ton due to the increasing competition from other
byproduct sources of acid.
It is entirely probable that the acid produced in central
acid processing systems (Scheme D) would command a
higher price than for inflexible single-site systems.
Assuming better choice of location and flexible operating
rates, a net sales revenue averaging $12/ton is predicted for
the 10 years of central process unit life.
Regulated Economic Evaluation
The basic premise of regulated economics ascribes that the
power company will be permitted to charge electricity
customers sufficiently to earn up to a prescribed return on
106
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base investment. Since electrical power producers rarely
compete with each other in a given geographical area,
regulation of power rates is necessary to prohibit unreason-
able profits, but at the same time assure an adequate return
on investment sufficient to attract capital for expansion to
meet growing demand. In the United States, regulation is
usually the responsibility of state or local agencies with the
Federal Power Commission responsible for setting guide-
lines for accounting procedures and for rates on interstate
transactions.
If a power company provides all or a portion of the
investment for pollution abatement facilities, its investment
will almost certainly be merged with the total power plant
investment as is presently done with dust removal equip-
ment and, therefore, increase the "rate base" on which the
utility is allowed to earn at the rate set by the regulatory
commission. Thus, a return on equity or profit must be
included in any process evaluation under regulated
economics; it is the "cost of money" as any other operating
cost item such as fuel or labor.
As with previous conceptual design studies, the regulated
"cost of money" is added to operating costs as part of the
capital charges applied (see table 47 of Investment and
Operating Cost section). For nonrecovery processes, a
direct comparison of total operating costs will generally
serve as a means of process evaluation; however, sales
revenue must be recognized for processes producing a
product. In addition, the annual operating cost will vary
each year as the rate base declines due to depreciation
"write off (the cost of money and income taxes are
applied to undepreciated portion of investment) and with
any changes in onstream time of the power unit; therefore,
it is desirable to have a year-to-year tabulation of operating
costs for any given case. Furthermore, recognizing the time
value of money, these annual operating costs should be
discounted at the cost of money (10% for this study) to the
initial year of operation for ready comparison of present
worth to other pollution control means such as the annual
costs required for low sulfur fuels.
Since rate of investment profitability is prescribed under
regulated economics, the data generated by the tabulation
of operating costs only indicate which process or method of
pollution abatement yields the minimum cost to the
consumer. Depending on the achievable net sales revenue,
the process or method used will either increase or decrease
the cost of power to the consumer.
Tables A-95 to A-132, presented in Appendix A, are
computer printouts which show year-to-year operating
costs under regulated economics, projected sales revenue,
and the resultant cost effect on power consumers for the 29
magnesia Scheme A, B, and C cases over their expected
project life. Included in these tables are comparable
limestone-wet scrubbing operating costs with examples
shown for both the low and high cost variations. Actual
outlay values are given for each year along with the
discounted and actual cumulative total costs and unit costs
either per ton of coal burned, per barrel of oil burned, or
mills per kilowatt hour. A summary of these results is
shown in table 67 for the 30-year life of new 200-mw,
500-mw, and 1000-mw units burning coal containing 3.5%
S or oil containing 2.5% S. Shown in table 68 is a
comparison of cumulative present worth of magnesia and
limestone costs over the project life for several other coal-
and oil-fired unit case variations.
These results are shown graphically in figures 89 and 90
which describe the effect of power unit size on cumulative
present worth of the total and unit change in the cost of
power over the life of new coal-fired units utilizing either
the magnesia schemes or limestone-wet scrubbing for S02
removal. Figure 91 describes the same effect for oil-fired
units. With acid sales revenue at $8/ton. the costs of the
magnesia schemes are between the extremes of the
limestone-wet scrubbing process; however, at low unit sizes,
the magnesia Scheme A and B costs are greater than the
high cost limestone example. As unit size increases, the
magnesia schemes become much more competitive. Table
69 gjves the acid sales revenue per ton required for each
magnesia scheme to yield the same overall cost as the
limestone-wet scrubbing examples.
Displayed in figures 92 and 93 is the effect of sulfur
content of coal and oil on the change in cost of power due
to magnesia Scheme A and limestone-wet scrubbing.
The effect of 7,000 hrs/yr of constant operating time
over the life of the power unit can be seen in figures 94 and
95. These values should be compared to those in figures 89
and 90 which represent the declining onstream pattern.
Another interesting point can be examined in figure 96
which describes the change in cost of power for power units
of varying remaining life and years of 7,000 hour operation.
The operating period for the existing units is assumed to
follow the same schedule as for new units, with the number
of years of 7,000 hour operation being the only period
reduced.
The relationship of fixed investment on net cost is
shown in figures 97 and 98 using sensitivity analysis of
investment for Scheme A on coal- and oil-fired systems.
Shown in figures 99 and 100 are the cumulative total
and unit cost effects of variations in net sales revenue for
single-site Scheme A. For Scheme A to yield the same
increase in cost of power as the low cost limestone-wet
scrubbing example, a revenue of approximately $16-20/ton
of acid would have to be realized. This is slightly lower than
the current going f.o.b. price of acid marketed by existing
producers. When compared to the high cost wet limestone
example, the magnesia Scheme A does not need any
revenue from acid sales to be competitive.
Most of the operating cost estimates given in this report
reflect no labor cost escalation over the life of the system;
107
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Table 67. Actual and discounted cumulative total and unit increase (decrease) in the cost
of power for magnesia schemes and limestone-wet scrubbing process under regulated economics.a
Actual cumulative net increase
Coal fired (decrease) in cost of power
3. 5% Sin coal $ $/ton coal Mills/kwh
Scheme A
200-mw 91,134,900 9.32 3.57
500-mw 162,116,800 6.78 2.54
1,000-mw 237,884,900 5.15 1.87
Scheme B
200-mw 93,043,200 9.52 3.65
500-mw 165,231,600 6.91 2.59
1,000-mw 242,437,200 5.25 1.90
Scheme C
200-mw 79,368,200 8.12 3.11
500-mw 139,009,800 5.81 2.18
1,000-mw 203,777,400 4.41 1.60
Limestone-wet scrubbing-low limestone cost, on-site solids disposal
200-mw 72,059,000 7.44 2.85
500-mw 136,225,900 5.70 2.14
1,000-mw 208,272,000 2.51 1.63
Limestone-wet scrubbing— high limestone cost, off-site solids disposal
200-mw 82,657,700 8.46 3.24
500-mw 170,642,600 7.14 2.68
1,000-mw 283,172,800 6.13 2.22
Oil fired
2.5% Sin oil $ $/bbloil Mills/kwh
Scheme A
200-mw 54,382,100 1.45 2.13
500-mw 95,922,800 1.05 1.50
1,000-mw 141,598,400 0.80 1.11
Scheme B
200-mw 54,061,700 1.44 2.12
500-mw 94,233,700 1.03 1.48
1,000-mw 138,611,000 0.78 1.09
Limestone-wet scrubbing— low limestone cost, on-site solids disposal
200-mw 46,352,800 1.24 1.82
500-mw 84,224,500 0.92 1.32
1,000-mw 129,543,900 0.73 1.02
Limestone-wet scrubbing— high limestone cost, off-site solids disposal
200-mw 47,671,000 1.27 1.87
500-mw 94,255,700 1.03 1.48
1,000-mw 154,350,700 0.87 1.21
Cumulative
increase
present worth of net
(decrease in
power, discounted at
$
36,354,900
64,708,000
94,910,200
37,116,300
65,952,600
96,743,000
31,679,000
55,530,300
81,383,500
29,257,300
54,984,900
84,316,100
33,873,300
70,296,800
117,261,000
$
21 ,670,900
38,313,300
56,611,200
21,510,000
37,564,700
55,284,000
18,625,500
34,007,700
52,482,100
19,409,800
38,632,900
63,589,800
$/ton coal
3.72
2.71
2.05
3.80
2.76
2.09
3.24
2.32
1.76
2.99
2.30
1.82
3.47
2.94
2.54
$/bbl oil
0.58
0.42
0.32
0.57
0.41
0.31
0.50
0.37
0.30
0.52
0.42
0.36
cost of
10%/yr
Mills/kwh
1.43
1.02
0.74
1.46
1.03
0.76
1.24
0.87
0.64
1.15
0.86
0.66
1.33
1.10
0.92
Mills/kwh
0.85
0.60
0.44
0.84
0.59
0.43
0.73
0.53
0.41
0.76
0.61
0.50
Over 30 yr power unit life.
however, this is probably not realistic. To show the effect
of labor cost escalation over the life of the unit at different
annual rates of increase, figure 101 is presented. Because
108
labor costs for most S02 removal processes are comparable,
the exclusion of an escalation rate does not radically affect
process evaluation.
-------
30 MM
o J=
•O O
.HI
— w D.
« h <—
o
30 MM
S8l«
= S "3 8 w
8 K 5 .s te
60 MM
E
5
90 MM
120 MM
Magnesia Scheme A - O
Scheme B - A
Scheme C - D
Limestone-wet scrubbing - X
I I ]
New coal-fired units
3.5%Sin coal
Regulated economics
Annual values discounted at 10% to
initial year
Low limestone
'process cost
0
200
400
800
1000
600
Power unit size, mw
Figure 89. Effect of power unit size on cumulative present worth of total
net increase or decrease in the cost of power to consumers
for coal-fired power units using magnesia schemes.
1200
s 8
8 S
E
C
'-50
S 8
•S-0
II 0
1.50
o o 3.00
4.50
6.00
Magnesia Scheme A - 0
Scheme B - a
Scheme C - a
Limestone-wet scrubbing - X
I I
New coal-fired units
3.5%S in coal
Regulated economics
Annual values discounted at 10% to
initial year
0.54 S
Low limestone process cost
High limestone process cost
0.54
1.14 8 .
K E
200
400
600
Power unit si/.e, mw
800
1000
1.74
2.34
1200
Figure 90. Effect of power unit size on cumulative present worth of unit
increase or decrease in the cost of power to consumers for
coal-fired power units using magnesia schemes.
109
-------
Table 68. Comparison of present worth of cumulative total and unit increase (decrease) in cost of power for
case variations of magnesia Scheme A and limestone-wet scrubbing processes under regulated economics.3
Magnesia process
Present worth of net increase
(decrease) in cost of power
Low limestone cost, on-site
solids disposal
Present worth of net increase
(decrease) in cost of power
Limestone-wet scrubbing process
High limestone cost, off-site
solids disposal
Present worth of net increase
(decrease) in cost of power
Cases
Coal fired $
Scheme A
200-mw
500-mw
500-mw
500-mw
1,000-mw
E3.5%S
N2.0%S
N5.0%S
E3.5%S
E3.5%S
34,079,300
56,387,000
71,813,900
68,678,700
98,600,300
Oil fired $
Scheme A
200-mw
200-mw
200-mw
500-mw
500-mw
500-mw
1 ,000-mw
1,000-mw
1 ,000-mw
N 1 .0% S
N4.0%S
E2.5%S
N 1 .0% S
N4.0%S
E2.5%S
N 1 .0% S
N 4.0% S
E2.5%S
16,807,100
25,230,000
20,155,600
31,092,000
44,197,900
40,215,400
45,980,700
64,717,200
58,523,000
$/ton
coal
6.02
2.36
3.00
3.36
2.47
$/bbl
oil
0.45
0.67
0.93
0.34
0.48
0.51
0.26
0.37
0.38
Mills/kwh
2.38
0.88
1.13
1.29
0.93
Mills/kwh
0.66
0.99
1.41
0.49
0.69
0.76
0.36
0.51
0.55
$
27,307
49,407
59,995
57,749
87,046
$
16,221
20,682
17,862
29,653
37,916
36,435
45,517
58,833
54,890
,600
,100
,400
,700
,700
,100
,100
,000
,900
,800
,400
,600
,700
,100
$/ton
coal
4.82
2.07
2.51
2.83
2.18
$/bbl
oil
0.43
0.55
0.82
0.32
0.41
0.47
0.26
0.33
0.36
Mills/kwh
1.91
0.78
0.94
1.08
0.82
Mills/kwh
0.64
0.81
1.25
0.47
0.59
0.68
0.36
0.46
0.52
$
29,700,800
59,934,100
80,351,300
71,875,200
118,354,600
$
16,024,900
22,684,400
17,878,200
30,902,700
46,211,700
40,622,200
49,293,200
77,761,400
65,428,700
$/ton
coal
5.25
2.51
3.36
3.52
2.96
$/bbl
oil
0.43
0.61
0.82
0.34
0.50
0.52
0.28
0.44
0.43
Mills/kwh
2.08
0.94
1.26
1.35
1.11
Mills/kwh
0.63
0.89
1.25
0.48
0.72
0.76
0.39
0.61
0.61
aOver previously defined power plant life.
IMonregulated Economic Evaluation
If chemical companies or other nonregulated business
groups enter into sulfuric acid production by using a
magnesia scrubbing-regeneration process on a power unit,
either contributing all or part of the required investment,
profitability of the venture becomes of paramount
importance. A nonregulated company, with.no guarantee of
income or profitability and with all the uncertainties
associated with the future pricing of sulfur and related
products, must be able to see promise of a competitive rate
of return to justify capital expenditures on such a project.
The cost of recovering sulfur oxides as sulfuric acid and
the expected sales revenue of the acid have been estimated
previously. For single-site applications, one other source of
income can also be considered; namely, a payment by the
power producer to-the chemical company for performing
the service of pollution abatement. This seems reasonable
since the power company must incur a considerable cost in
any event for reducing the sulfur oxides in the gas (by
either purchasing low sulfur fuel at a premium, or
contributing necessary capital for the project itself).
The amount of payment presumably would be
negotiated between the two companies, and could range
from zero to the full cost of alternate throwaway processes
such as limestone-wet scrubbing. Again, there are several
alternatives available to a power company; however, the
cost of the limestone-wet scrubbing process can be varied
by the same parameters as recovery processes; therefore, it
should serve as a reasonable measure of possible payment.
Hence, the profitability estimates under nonregulated
economics have been calculated on three bases—full pay-
ment equivalent to either high or low cost limestone-wet
scrubbing and no payment. In practice, the expected
payment could be almost anywhere between the high
equivalent payment and none at all.
The question regarding the attractiveness of a process for
chemical industry investment can be answered best by
applying a venture appraisal method that relates profit-
making potential to the investment requirements. Several
types of venture appraisal techniques are used in nonregu-
lated industry; three of the more common ones (annual
return on initial investment, payout period, and interest
rate of return) have been calculated for all applicable cases
where nonregulated industry economics are involved. The
110
-------
Table 69. Required unit sales revenue
for sulfuric acid to equalize magnesia and
limestone scrubbing process costs.
Net sales revenue $/ton of acid
Cases
Coal fired
Scheme A
200-mwN3.5%S
200-mwE3.5%S
500-mw N 2.0% S
500-mwN3.5%S
500-mw N 5. 0% S
500-mwE3.5%S
l,000-mwN3.5%S
l,000-mwE3.5%S
Scheme B
200-mwN3.5%S
500-mw N 3. 5% S
l,000-mwN3.5%S
Scheme C
200-mwN3.5%S
500-mwN3.5%S
l,000-mwN3.5%S
Oil fired
Scheme A
200-mw N 1 .0% S
200-mwN2.5%S
200-mw N 4.0% S
200-mw E 2. 5% S
500-mw N 1 .0% S
500-mw N 2. 5% S
500-mw N 4.0% S
500-mw E 2.5% S
l,000-mwN1.0%S
l,000-mwN2.5%S
l,000-mwN4.0%S
l,000-mwE2.5%S
Scheme B
200-mw N 2.5% S
500-mw N 2. 5% S
l,000-mwN2.5%S
Low limestone
cost, on-site
solids disposal
29.03
37.35
22.50
19.52
17.78
22.42
14.26
15.69
31.34
21.07
15.43
16.09
8.26
5.30
15.79
24.94
23.79
26.61
15.97
17.56
16.67
17.25
8.85
12.46
11.93
12.39
24.21
16.05
11.02
High limestone
cost, off-site
solids disposal
16.94
29.29
1.86
2.41
1.86
5.60
a
a
19.26
3.96
a
1.98
a
a
20.04
21.93
18.12
28.29
10.06
8.20
6.04
8.35
a
0.50
a
0.43
21.20
6.63
a
aMagnesia scrubbing operating cost without sulfuric acid revenue is
less than limestone scrubbing cost.
annual return on investment is defined as the annual net
income after taxes divided by the initial total investment
including working capital; the composite tax rate for
nonregulated industry is assumed to be 50% of gross
income. Payout period is the number of years required to
recover the initial investment by cash flow (depreciation
plus net income after taxes). Interest rate of return, often
referred to as discounted cash flow, is best described as the
interest rate at which the sum of the present worth of the
yearly receipts (depreciation plus after-tax profit) becomes
equal to the sum of the present worth of the disbursements.
Another definition is the interest rate a savings bank would
have to pay to accept and return cash on the same schedule
as the proposal. Of the three methods, only interest rate of
return recognizes the time value of money.
It is difficult to say what degree of profitability is large
enough to attract chemical investors to the magnesia
process since each company has its own criteria as to what
is considered an attractive venture; no standard can be set.
However, a rough concensus for new chemical ventures
appears to be greater than 10% annual return on investment
after taxes, 15% interest rate of return after taxes and a
payout in less than 6 years. For an established industry
such as sulfuric acid, such profitability is not often attained
except through captive use markets where a more valuable
end product can justify higher profitability. More reason-
able values might be 7-10% annual return after taxes,
12-15% interest rate of return after taxes, and 5-6 years
payout. These guides should help in examining the results
of this evaluation.
The results of the profitability analysis under nonregu-
lated economics are presented for each case as computer
printouts in Appendix A (tables A-133 to A-176). The
printouts describe each year of operation including yearly
operating costs for the prescribed periods, net sales revenue,
gross and net income, and the annual cash flow over the
power unit life. Payout periods and interest rates of return,
with high and low equivalent payment and without any
payment, are shown for each case. These values are
summarized in table 70.
The data indicate that without a payment for air
pollution control equivalent to the high cost limestone-wet
scrubbing process, at $8/ton of acid, the magnesia
scrubbing-regeneration schemes are not at all attractive; in
fact, they have a negative interest rate of return when there
is no payment. With the higher payment, however, the units
500-mw and larger show sufficient promise to possibly
attract chemical industry investment.
To fully consider the results, several graphs have been
prepared describing the effects of particular variables. The
effect of power unit size on the payout period and interest
rate of return for coal-fired units are given in figures 102 to
107. The data compares Schemes A, B, and C, indicating that
best results are obtained with Scheme C. Similar results for
oil-fired units are shown in figures 108 to 111 indicating
Scheme B to be slightly better than Scheme A. For
single-site situations, increasing power unit size shows only
moderate improvement in economic profitability.
Figures 112 to 115 describe the effect of sulfur content
of fuel on profitability for oil- and coal-fired power units.
As the sulfur content of fuel increases, profitability is not
111
-------
20 MM
u- °
20 MM
40 MM
60 MM
80 MM
I I
Scheme A - 0
Scheme B -"
Limestone-wet scrubbing - X
New oil-fired units
2.5% Sin oil
I I I
Regulated economics
Annual values discounted at 10% to
initial year
Low limestone process cost
High limestone process cosr
200
400
600
Power unit size, mw
800
1000
1200
Figure 91. The effect of power unit size on cumulative present worth of total
net increase or decrease in the cost of power to consumers for
oil-fired power units using magnesia schemes.
radically altered indicating that incremental production
costs are just offset by incremental revenue when acid is
sold for $8/ton net back. If the acid could be marketed at
values higher than incremental operating costs, profitability
would be noticeably improved.
The effect of net sales revenue for sulfuric acid can be
seen in figures 116 to 119 covering Scheme A, coal-fired
units with sales revenue ranging from 0 to 400% ($0-
32/ton) of the $8/ton base value. Graphs are shown for
cases including both high and low payments equivalent to
limestone-wet scrubbing. If revenue of $20-30/ton could be
obtained and coupled with the high equivalent limestone-
wet scrubbing payment, all sizes of the magnesia process
would be attractive as a means of acid manufacture.
Varying expected fixed investment requirements for
Scheme A on coal-fired units yields the results shown in
figures 120 and 121. It can be seen that reduction in
forecasted investment could increase profitability to
acceptable levels.
The effect of onstream time is described in figure 122
which gives payout of various Scheme A unit sizes for
either 7,000 hours or 5,000 hours annual operation over
the 30-year life of the unit. When the high equivalent
payment is negotiated, higher onstream time is quite
helpful toward improving profitability. The influence of
unit status or age on interest rate of return, with
appropriate reduction in years of 7,000 hour operation, is
displayed in figure 123. As remaining onstream time
declines, alternatives requiring very little capital investment
such as low sulfur fuel are better choices.
The reduction in interest rate of return and increase in
payout period for varying rates of labor cost escalation over
the 30-year operating period are given for Scheme A,
500-mw coal-fired units in figures 124 and 125. If the
payments for air pollution control are also escalated, the
change in profitability would be negated.
Cooperative Economics-Central
Processing Concept
Thus far, the profitability potential of single-site, magnesia
scrubbing-regeneration systems has been evaluated by
assuming that the total process investment requirements are
provided by either a regulated power company or a
nonregulated chemical company and by using the appro-
priate economic evaluation technique. It is possible, how-
ever, to have combinations of the two types of economics if
a power company and a chemical company each provide a
portion of the investment needs of single or multiple
systems. Probably the simplest of such cooperative
112
-------
30 MM
1 s.
u. .2
a ^-s
"
li
S E g
t— O o
o «£; „
111
is
*»
'
30 MM
60 MM
90 MM
120 MM
Magnesia Scheme A - 0
Limestone-wet scrubbing - X
New coal-fired units
500-mw units
I T
Regulated economics
Annual values discounted at 1
to initial year
Low limestone
' process cost
High limestone
process cost
I
12345
Sulfur in coal, %
Figure 92. Effect of sulfur content of coal on cumulative present
worth of total net increase or decrease in the cost of
power to consumers for magnesia Scheme A.
20 MM
.3 5
M
O 3
III
- -
1
20 MM
40 MM
£30 «--
* a s. .s s
C O 41 J
a. b. u ^
s S -
•|| 60 MM
80 MM
I
Magnesia Scheme A - 0
Limestone-wet scrubbing - X
New oil-fired units
Regulated economics
Annual values discounted at 10%
to initial year
• Low limestone process cost
200-mw
12345
Sulfur in oil, %
Figure 93. Effect of sulfur content of oil on cumulative present
worth of total net increase or decrease in cost of power
to consumers for magnesia Scheme A.
113
-------
35 MM
8 1
-------
Table
With payment equivalent toa
Low limestone cost,
on-site solids disposal
Cases
Coal fired
Scheme A
200-mwN3.5%S
2QO-mwE3.5%S
500-mw N 2.0% S
500-mwN3.5%S
500-mwN5.0%S
500-mw E 3. 5% S
l,000-mwN3.5%S
l,000-mwE3.5%S
Scheme B
200-mwN3.5%S
500-mw N 3. 5% S
l,000-mwN3.5%S
Scheme C
200-mw N 3. 5% S
500-mw N 3. 5% S
l,000-mwN3.5%S
Oil fired
Scheme A
200-mw N 1 .0% S
200-mw N 2.5% S
200-mw N 4.0% S
200-mw E 2.5% S
500-mw N 1 .0% S
500-mw N 2. 5% S
500-mw N 4.0% S
500-mw E 2.5% S
l,000-mwN1.0%S
l,000-mwN2.5%S
l,000-mwN4.0%S
l,000-mwE2.5%S
Scheme B
200-mw N 2.5% S
500-mwN2.5%S
l,000-mwN2.5%S
Payout
yr
8.3
8.2
7.4
7.6
7.7
7.7
7.1
7.1
8.5
7.8
7.3
6.9
6.2
5.9
6.5
7.6
8.1
7.3
6.6
7.2
7.5
7.0
6.3
6.8
6.9
6.7
7.5
7.0
6.6
Interest rate
of return, %
7.4
6.6
9.5
8.8
8.5
8.4
10.0
9.6
6.9
8.4
9.6
10.7
12.5
13.6
11.8
8.8
7.7
8.8
11.5
9.8
9.0
10.0
12.4
10.9
10.5
10.9
9.1
10.3
11.5
High limestone cost, off-
site solids disposal
Payout
yr
6.7
7.2
5.7
5.6
5.4
5.7
4.8
4.9
6.9
5.7
4.9
5.6
4.6
4.0
6.6
7.1
7.0
7.1
6.2
6.1
5.8
6.0
5.7
5.3
4.9
5.3
7.0
5.9
5.2
Interest rate
of re turn, %
11.0
8.5
14.3
14.9
15.7
13.6
18.1
17.1
10.5
14.4
17.6
14.6
19.2
22.8
11.5
9.9
10.0
8.8
12.6
13.0
14.0
12.7
14.5
15.8
17.6
15.3
10.1
13.5
16.2
Without
Payout
yr
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
None
payment
Interest rate
of return, %
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
aPayment from power company to chemical company for SOj removal-equivalent to comparable limestone-wet scrubbing process costs.
arrangements would be for the power company to finance
the scrubbing-drying operations and the chemical company
to provide capital for the regeneration-acid manufacturing
facilities. Each company would then be responsible for only
its portion of activity; that is, the power company for
particulate and sulfur dioxide removal, and the chemical
company for acid disposal. Under this arrangement the
power companies would supply magnesium sulfite to the
chemical company and would receive regenerated
magnesium oxide. The power company would be involved
only in the sale of power under regulated economics and
the chemical company would handle the sale of sulfuric
acid or other products under nonregulated economics.
Even though single-site operations could function under
such arrangements, the most promising application of a
cooperative venture would be the central processing
concept where several power units at separate sites
independently provide the magnesium sulfite for a central
115
-------
•ill
, .
Ill
•S 3?
o § 2
is 8 -
r 2 P
3.00
.00
3.00
E
4.00
-------
30 MM
.5
8
I
•a — '
1 e
£ I
S % ti
30 MM
60 MM
i!1
« 2
II
I
.s s
I I
jj "8
•= 90 MM
120 MM
Magnesia Scheme A - O
Limestone-wet scrubbing - X
New coal-fired units
3.5% S in coal
Regulated economics
i r
Annual values discounted at 10%
to initial year
Fixed investment varied by the amount
indicated from base values
Low limestone
.. process cost
70%
120%
200
400
600
Power unit size, mw
800
1000
1200
Figure 97. Effect of fixed investment on cumulative present worth of total net increase or
decrease in the cost of power to consumers for coal-fired units using magnesia Scheme A.
20 MM
•S s
~ 1
-------
30 MM
» I
•S "5
II
a S
I
30 MM
60 MM
90 MM
120 MM
Magnesia Schefne A - 0 '
Limestone-wet scrubbing - X
New coal-fired units
3.5% S in coal
Annual values discounted at 10%
to initial year
Regulated economics I
Net sales revenue as percent of
amount indicated in
market study for single
site operation
Low limestone
process cost
High limestone
process cost
200
400
600
Power unit size, mw
800
1000
1200
Figure 99. The effect of variation in net sales revenue on cumulative
present worth of total net increase or decrease in the cost of power
to consumers for coal-fired units using magnesia Scheme A.
•= o
8 ~
a a o
o O «
* 3
+-. C
c o
O. i_
> I
•^ o
— ^
1 ^
3
CJ
11"
D. C
4.0
I
Magnesia Scheme A - O
Limestone-wet scrubbing - X
New coal-fired units
3.5% Sin coal
Regulated economics
Annual values discounted at 10%
to initial year
Net sales revenue as percent of
amount indicated in market study
for single site operation
0.38
0.38
0.76
1.14
-n
200
400
800
1000
1200
1.52
600
Power unit size, mw
Figure 100. Effect of variation in net sales revenue on cumulative present worth of unit increase
or decrease in cost of power to consumers for coal-fired plants using magnesia Scheme A.
118-
-------
30 MM,
la
8 §
8-a £-
J o H
+* C O
u O D,
G •.£ t*.
3 g S
O p. **-;
"" O "~
S P S
Sis
O <*- («
x t2 8
s s
I g.
1 "=
3
30 MM
60 MM
90 MM
120 MM
Scheme A - 0 Annual labor cost
New units escalation varied,
3.5%S in coal by the percentage
Regulated economics indicated
Annual values discounted at 10% to initial year
200
400
600
Power unit size, mw
800
1000
1200
Figure 101. Effect of annual labor cost variation on cumulative present worth of total increase
or decrease in cost of power to consumers for coal-fired units using magnesia Scheme A.
generating unit, paying full price for makeup MgO
($102.40/ton Chicago area), plus paying partial price and
shipping cost of recycle MgO (approximately $5-65/ton
depending on size of operation). In addition, they would
"dispose" of their dry, waste magnesium sulfite crystals at
no charge other than for shipping to the chemical company
(which means no additional cost or space requirements). As
long as the power companies are not charged excessively for
recycle MgO, they can remove particulates and S02 by
magnesia wet-scrubbing at a total cost equivalent to or less
than the least cost alternate; for comparison, limestone-wet
scrubbing is assumed for the alternate. If the price for
recycle MgO is sufficient, when coupled with sulfuric acid
revenue, a chemical company could justify investment in a
sulfuric acid plant with magnesium sulfite as raw material
rather than elemental sulfur.
In the evaluation to follow, the operating cost of
magnesia scrubbing-drying operations over the power unit
life is computed under regulated economics using varying
recycle magnesium oxide costs and compared with appro-
priate high and low limestone-wet scrubbing costs to
determine prices for the recycle material. The recycle MgO
revenue, coupled with acid sales revenue, permits profit-
ability determination for the central regeneration-acid plant
under nonregulated evaluation techniques. For this venture
only a 10-year regeneration-acid plant life at 8,000 hrs/yr
will be assumed. If the central processing concept is sound,
in that several independent power units with varying load
factors and operating lives will supply the. magnesium
sulfite so that the loss of any one or two power units is not
critical to operation of the acid plant, then, with power
demand growing as projected, the life of the acid plant is
independent of the power units involved. As one acid plant
wears out, another can be justified to take its place.
As shown in computer printouts of tables A-177, A-178,
A-187, A-188, A-197, and A-198 in Appendix A, when acid
revenue is $12/ton and MgO shipping distance is less than
50 miles, the prices which could be charged for recycle
MgO permitting competitive costs with limestone-wet
scrubbing are $25-55/ton for 200-mw scrubbing systems,
$15-55/ton for 500-mw scrubbing systems, and $10-55/ton
for 1000-mw scrubbing systems. These values can be
examined further in figure 126 which describes the effect
of recycle MgO cost on the discounted change in cost of
power to consumers for the scrubbing-drying (regulated)
portion of magnesia Scheme D. Using the same data, figure
127 relates the premium in actual and discounted $/ton of
low sulfur coal which would be competitive with 200-mw,
500-mw, and 1000-mw magnesia scrubbing-drying units
paying various rates for recycle MgO. Presented in figure
128 is the effect of shipping distance for $50-55/ton
119
-------
20
EIS
1 I I T
Scheme A - O
New units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
400 600 800
Power unit size, mw
Figure 102. The effect of power unit size on payout period
for magnesia Scheme A on coal-fired units.
~r
"T
~r
Scheme B - ^
New coal-fired units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
High equivalent payment
200 400 600 800 1000 1200
Power unit size, mw
Figure 103. The effect of power unit size on payout period
for magnesia Scheme B on coal-fired units.
Scheme C - o
New units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
High equivalent payment
200 400 600 800
Power unit size, mw
Figure 104. The effect of power unit size on payout period
for magnesia Scheme C on coal-fired units.
Scheme A - O
New coal-fired units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
Low equivalent payment
_l I
0 200 400 600 800 1000 1200
Power unit size, mw
Figure 105. The effect of power unit size on interest rate
of return for magnesia Scheme A on coal-fired units.
Scheme B -a
New coal-fired units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent pay men t
Low equivalent payment
600 800
Power unit size, mw
Figure 106. The effect of power unit size on interest rate
of return for magnesia Scheme B on coal-fired units.
I 30
Scheme C - °
New coal-fired units
3.5% S in coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
Low equivalent payment
600
Power unit size, mw
Figure 107. The effect of power unit size on interest rate
of return for magnesia Scheme C on coal-fired units.
-------
Scheme A - O
New oil-fired units
2,5% S in oil
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
High equivalent payment
Power unit'size, mw
Figure 108. The effect of power unit size on payout period
for magnesia Scheme A on ojl-fired units.
Scheme B - a
New oil-fired units
2.5% Sin oil
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
I
High equivalent payment
Power unit size, mw
Figure 109. The effect of power unit size on payout period
for magnesia Scheme B on oil-fired units.
40
sa
E 30
3
E
^
S
S
1 20
S
10
Q
1 1 1 I 1
Scheme A - O
New oil-fired units
2.5% S in oil
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
.
High equivalent payment ^ _
^r?777777Z%ff%%
* 'U^ Low equivalent payment
1 1 1 1 1
40
^
I 30
£
u
c
| 20
j;
10
0
1 1 1 •( 1
Scheme B - ^
New oil-fired units
2 5% S in oil
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
-
High equivalent payment _
^rfr777Ztf%%/Z%,
fgb'^Zii**^^^^ t
Low equivalent payment
1 1 1 i i
0 200 400 600 800 1 000 1 200 0 200 400 600 800 1 000 1 2C
Power unit size, mw Power unit size, mw
Figure 110. The effect of power unit size on interest rate
of return for magnesia Scheme A on oil-fired units.
Figure 111. The effect of power unit size on interest rate
of return for magnesia Scheme B on oil-fired units.
B 15
Magnesia Scheme A - O
New coal-fired units
500-mw units
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
High equivalent payment
Sulfur in coal, °t
Figure 112. The effect of sulfur content of coal on payout
period for magnesia Scheme A on coal-fired units.
I 30
a
§20
Scheme A - O
New 500-mw units
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
1
Low equivalent payment
234
Sulfur in coal, %
Figure 113. The effect of sulfur content of coal on interest
rate of return for magnesia Scheme A on coal-fired units.
-------
CIS
Scheme A - O
New 500-mw oil-fired units
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
Low equivalent payment
High equivalent payment
0123456
Sulfur in oil, %
Figure 114. The effect of sulfur content of oil on payout
period for magnesia Scheme A on oil-fired units.
Scheme A - 0
New 500-mw units
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
Low equivalent payment
Sulfur in oil, %
Figure 115. The effect of sulfur content of oil on interest
rate of return for magnesia Scheme A on oil-fired units.
recycle MgO on the discounted cost of power to consumers
for scrubbing-drying unit sizes of 200-mw, 500-mw, and
1000-mw.
Using the range of recycle MgO prices so developed, the
economic potential of central regeneration-acid units can be
evaluated for various combinations of 200-mw, 500-mw,
and 1000-mw scrubbing-drying systems. Shown in tables 71
and 72 are the expected payout periods and interest rates
of return for acid plants with magnesium sulfite feed
supplied by scrubbing systems on new power units burning
coal with 3.5% sulfur. The results are given for a $12/ton
acid net revenue combined with various recycle MgO
revenues which equate magnesia scrubbing-drying costs
with both low and high cost limestone-wet scrubbing.
Detailed calculations are shown in Appendix A tables
A-179-186, A-189-196, and A-199-204.
Although the results shown in table 71 indicate, at best,
marginal profitability potential, those of table 72, where
recycle MgO revenue ranges from $50-55/ton, show
excellent economic promise. Two trends are apparent—the
larger the central acid plant, the greater the profitability,
and the smaller the individual power plant scrubbing-drying
systems -supplying the MgSO3, the greater the profitability.
The reason for this latter relationship is the relatively higher
cost of limestone-wet scrubbing on smaller scrubbing units
permits a higher price for recycle MgO. In addition, the
smaller power units are assumed to be less efficient,
requiring more fuel to be burned; hence, more recycle MgO
and acid for a given size system. As the results show,
2000-3000-mw (1,333-2,000 tons/day of 100% acid)
systems composed of 10-15 small suppliers of sulfite could
be very profitable; however, it will be difficult to find,
assemble, and coordinate that many systems within a
reasonable geographic area.
Presented in figure 129 is the effect of system size on
interest rate of return for regeneration-acid units supplied
by combinations of 200-mw, 500-mw, and 1000-mw
scrubbing-drying units. Also, shown in figures 130 and 131
is the effect of magnesium sulfite shipping distances on
interest rate of return covering central unit combinations of
500-mw scrubbing systems with $15/ton and $55/ton
recycle MgO revenue. In situations where the magnesia
process must compete with low cost limestone scrubbing
(rural areas), MgO shipping distance is extremely important.
Figures 132, 133, and 134 describe the effect of
variation in net sales revenue for recycle MgO on interest
rate of return for the various 200-mw, 500-mw, and
1000-mw combinations of systems. In addition, the effect
of variation in sulfuric acid revenue on interest rate of
return is described in figures 135 through 140 assuming the
required price ranges of recycle MgO for each size system.
It can be seen that in situations where high recycle MgO
revenue can be obtained, acid revenue is not even required
to attain desirable profitability levels with any large
centralized regeneration-acid plant. For the lower levels of
recycle MgO income, however, acid revenue is extremely
important.
Another logical approach to evaluation of the central
process concept is to establish a minimum price for recycle
MgO consistent with acceptable profitability; then, deter-
mine the conditions which would make MgO scrubbing
competitive with limestone scrubbing or the premium for
low sulfur fuel. For a 2000-mw equivalent acid plant selling
acid at $12/ton, MgO recycle price would have to be
approximately $20, $27, and $34/ton, respectively, for 10,
15, and 20% after tax rates of return. At the intermediate
price level ($27/ton, 15% rate of return), the MgO
scrubbing process would be less expensive than low cost
122
-------
Table 71. Profitability of central regeneration-acid manufacturing unit under cooperative
economics.3 Magnesium sulfite supplied from combinations of new 200-, 500-, or 1,000-mw
units burning coal with 3.5% sulfur. Regulated stack gas scrubbing costs equivalent to
limestone-wet scrubbing process with low limestone cost, on-site solids disposal.
Case
units and size
200-mw equivalent
5 x 200-mw equivalent
10 x 200-mw equivalent
1 5 x 200-mw equivalent
500-mw equivalent
2 x 500-mw equivalent
4 x 500-mw equivalent
6 x 500-mw equivalent
1 ,000-mw equivalent
2 x 1,000-mw equivalent
3 x 1,000-mw equivalent
Payout,
Recycle MgO
at $25/ton
None
6.6
5.2
4.6
Recycle MgO
at $15/ton
None
9:9
7.7
6.5
Recycle MgO
at $10/ton
None
9.9
8.3
years
Recycle MgO
at $30/ton
None
5.7
4.-5
4.0
Recycle MgO
at $20/ton
None
8.1
6.3
5.4
Recycle MgO
at $15/ton
None
7.8
6.6
Interest
Recycle MgO
at $25/ton
Neg.
8.2
14.0
17.2
Recycle MgO
at $15/ton
Neg.
0.3
5.1
8.7
Recycle MgO
at $10/ton
Neg.
0.1
3.5
rate of re turn, %
Recycle MgO
at $30/ton
Neg.
11.6
17.9
21.4
Recycle MgO
at $20/ton
Neg.
4.1
9.5
13.2
Recycle MgO
at$15/ton
Neg.
4.8
8.4
aNonregulated portion of system with 10 yr life; acid revenue-$12/ton.
Table 72. Profitability of central regeneration-acid manufacturing unit under cooperative
economics.3 Magnesium sulfite supplied from combinations of new 200-, 500- or 1,000-mw
units burning coal with 3.5% sulfur. Regulated stack gas scrubbing costs equivalent to
limestone-wet scrubbing process with high limestone cost, off-site solids disposal.
Case
units and size
200-mw equivalent
5 x 200-mw equivalent
1 0 x 200-mw equivalent
15 x 200-mw equivalent
500-mw equivalent
2 x 500-mw equivalent
4 x 500-mw equivalent
6 x 500-mw equivalent
1 ,000-mw equivalent
2x 1,000-mw equivalent
3x1 ,000-mw equivalent
Payout,
Recycle MgO
at $50/ton
9.3
3.7
2.9
2.6
Recycle MgO
at $50/ton
5.6
3.8
3.0
2.6
Recycle MgO
at $50/ton
3.9
3.1
2.7
years
Recycle MgO
at $55/ton
8.4
3.4
2.7
2.4
Recycle MgO
at $55/ton
5.1
3.5
2.8
2.4
Recycle MgO
at $55/ton
3.6
2.9
2.5
Interest
Recycle Mgo
at $50/ton
1.3
23.8
32.2
36.9
Recycle MgO
at $50/ton
12.1
22.6
30.9
36.2
Recycle MgO
at $50/ton
21.8
29.9
35.1
rate of return, %
Recycle MgO
at$55/ton
3.3
26.6
35.5
40.6
Recycle MgO
at$55/ton
14.4
25.3
34.1
39.7
Recycle MgO
at $55/ton
24.4
33.0
38.5
aNomegulated portion of system with 10 yr life; acid revenue-$12/ton.
123
-------
Scheme A - O
New units
3.5% S in coal
Nonregulated economics
Net sales revenue varied as percent of base
amount indicated in market study for
single site operation
Assumes payment for air pollution control
equivalent to low cost limestone scrubbing
400 600 600
Power unit size, mw
Figure 116. The effect of variation in net sales
revenue on interest rate of return for
magnesia Scheme A on coal-fired units—low payment.
Scheme A - O
New units
3.5% S in coal
Nonregulated economics
Net sales revenue varied as percent of base
amount indicated in market study for
single site operation
Assumes payment for air pollution control
equivalent to low cost.limestone scrubbing
600 800
Power unit size, mw
Figure 118. The effect of variation in net sales
revenue on payout period for magnesia
Scheme A on coal-fired units—low payment.
I 15
K
C
i 10
T
"T
Scheme A - O
New units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to
low cost of limestone scrubbing
Fixed investment varied by the amount indicated from base values
600 800
Power unit size, mw
Figure 120. The effect of variation in fixed
investment on interest rate of return for
magnesia Scheme A on coal-fired units-low payment.
1
Scheme A - O
New units
3.5% Sin coal
Nonregulated economics
1 ' 1 '
Net sales revenue varied as percent of base
amount indicated in market study for
single site operation
Assumes payment for air pollution control
equivalent to high cost limestone scrubbing
600 800
Power unit size, mw
Figure 117. The effect of variation in net sales
revenue on interest rate of return for magnesia
Scheme A on coal-fired units-high payment.
Scheme A - O
New units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution
control equivalent to high cost
limestone scrubbing
Net sales revenue varied as percent of
base amount indicated in market
study for single site operation
600 800
Power unit size, mw
Figure 119. The effect of variation in net sales
revenue on payout period for magnesia
Scheme A on coal-fired units-high payment.
S20
Scheme A - O
New units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to
high cost of limestone scrubbing
Fixed investment varied by the amount indicated from base values
200
400
1000
600 800
Power unit size, mw
Figure 121. The effect of variation in fixed
investment o/i interest rate of return for
magnesia Scheme A on coal-fired units—high payment.
-------
1 1
Assumes payment for air pollution
control equivalent to high and low
cost limestone s
Operation at 30 years for indicated
600 800
Power unit size, mw
Figure 122. The effect of constant onstream time on payout
period for magnesia Scheme A on coal-fired units.
Scheme A - O
New units
Existing units
3.5%Sin coal
Nonregulated economics
Assumes payment for air pollution
control equivalent to high and
low cost limestone scrubbing
Years remaining life
Includes low equ,valent payment
600
Power unit size, mw
Figure 123. The effect of power unit age or status on
interest rate for magnesia Scheme A on coal-fired units.
Scheme A - O
New 500-mw units
3.5% S in coal
Nonregulated economics
__ Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
High equivalent payment
3.0 4.5 6.0
Ajinual labor cost escalation, %
Figure 124. The effect of annual labor cost
escalation on interest rate of return for
magnesia Scheme A on coal-fired units.
Scheme A - O
New 500-mw units
3.5% Sin coal
Nonregulated economics
Assumes payment for air pollution control equivalent to both
high and low cost limestone scrubbing
3.0 4.5 6.0
Annual labor cost escalation, %
Figure 125. The effect of annual labor escalation on payout
period for magnesia Scheme A on coal-fired units.
125
-------
5 8
G. C
-SJB
0.50
.S o
S D. S
111
IH
^_ o S
Is"
o P y
a 11
» S
la
| |
1*3
a
~ 0
2.20
V
-------
*-
0
c _.
"" O
i §
5 "
u c
•o o
o |
*" "3 ^
5 -a o.
C « u,
— * <*« 4>
s ° *
= c §.
l'| 2
S g-SS
£ £ o
O <*- (/i
j= £2 S
1M
* 3 g
— C D-
C o
S y
£! ^
^^
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1 s-
i "s
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5 "2 0.40
D. c
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^ 13
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C t_
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1 g
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2.60
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£• 1 3-°°
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*j —a
o o
•S *S
S G
n O
es
S 3.40
3.80
1 1 1
Scheme D - •
New coal-fired units
3.5% S in coal
1
1000-mw units
1 1
Annual values discounted at 10%
to initial year
«•
Recycle MgO at $50/ton
500-mw units
200-mw units
B
Recycle MgO at $55/ton
Recycle MgO at $50/ton
RecycirMgO at $55/ton '
Recycle MgO at $50/ton
1 1 1
Recycle MgO at $55/ton
I |
0.16 -5 x
i 4.
1
« t-T
S *
u o
n Q ex
u
i
).96
1.12 ^
ii
o --^
u «
'» e
i i
O o
1.28 £ o.
1.44
25
125
150
50 75 100
Shipping distance, miles
Figure 128. The effect of shipping distance for recycle magnesium oxide on cumulative
present worth of the increase or decrease in unit cost of power to consumers in
the regulated portion of magnesia Scheme D under cooperative economics.
limestone scrubbing for power units 200-mw and smaller
(see figure 126) up to 50 miles from the central plant
location. For 500-mw power units located 50 miles from
the central processing plant, the price of recycle MgO
would have to be approximately $18/ton to be competitive
with low cost limestone scrubbing and this would result in
an 8% interest rate of return to the chemical company. If a
high cost limestone process is the competition (permitting
$55/ton for recycle MgO), even a single 500-mw equivalent
regeneration-acid plant could be justified.
127
-------
g 20
s
s
i I i i
Scheme D - •
Combinations of new 200, 500, 1000-mw coal-fired units
Nonregulated portion of cooperative economics
3.5% Sin coal
Revenue from sulfuric acid - S12.00/ton
Revenue from recycle MgO; $10.00, S15.00, $25.00
and $55.00/ton
1000 1500 2000
Power unit size, mw
Scheme D - •
Combination of new 500-mw coal-fired units
3.5% S in coal
Nonregulated portion of cooperative economics
_ Revenue from recycle MgO- $15.00/ton; sulfunc acid - $12.00/ton
Shipping distance varied from 0-1 50 miles
1000 1500 2000
Power unit size, mw
Figure 129. The effect of power unit size on interest
rate of return of centralized regeneration-acid plants
supplied by combinations of 200-, 500-, and 1000-mw
scrubbing systems under cooperative economics.
Figure 130. The effect of shipping distance on
interest rate of return for centralized regeneration-acid
units-combinations of 500-mw scrubbing
systems, recycle MgO cost—$15/ton.
§30
£20
S
Scheme D - •
Combinations of new 500-mw coal-fired units
3.5% S in coal
Nonregulated portion of cooperative economics
Revenue from recycle MgO - $55.00/ton, sulfuric acid - $12.00/ton
Shipping distance varied from 0-150 miles
15«
Scheme D - •
Combinations of new 200-mw coal-fired units
3.5% S in coal
. Nonregulated portion of cooperative economics
| Revenue from recycle MgO varied
$10.00-$60.00/ton
Revenue from sulfuric acid
$12.00/ton
I 3°
K
| 20
S
1500 2000
Power unit size, mw
Figure 131. The effect of shipping distance
on interest rate of return for centralized
regeneration-acid units—combinations of 500-mw
scrubbing systems, recycle MgO cost—$55/ton.
1500 2000
'ower unit size, mw
Figure 132. The effect of variation in sales
revenue for recycle MgO on interest rate of
return of centralized regeneration-acid
units—combinations of 200-mw scrubbing systems.
128
-------
I I
Scheme D - •
Combinations of new 500-mw coal-fired units
3.5% Sin coal
Nonregulated portion of cooperative economic
— Revenue from sulfuric acid - SI 2.00/ton
Revenue from recycle MgO varied
S10.00-S60.00/ton
T
Scheme D - •
Combinations of new 1000-mw coal-fired units
3.5% Sin coal
Nonregulated portion of cooperative economics
Revenue from sulfuric acid - SI 2.00/ton
Revenue from recycle MgO
varied SIO.00-J60.00/ton
1000 1500 2000
Equivalent power unit size, mw
Figure 133. The effect of variation in sales
revenue for recycle MgO on interest rate of
return of centralized regeneration-acid
units—combinations of 500-mw scrubbing systems.
1000 1500 2000
Equivalent power unit size, mw
Figure 134. The effect of variation in sales
revenue for recycle MgO on interest rate of
return for centralized regeneration-acid
plants-combinations of 1000-mw scrubbing systems.
Scheme D - •
Combinations of new 200-mw coal-fired units
3.5% S in coal
Nonregulated portion of cooperative economic
Revenue from recycle MgO - $25.00/ton
Revenue from sulfuric acid varied
$9.00-$ 3 0.00/ton
1000 1500 2000
Equivalent power unit size, mw
Scheme D - •
Combinations of new 200-mw coal-fired units
3.5% Sin coal
Nonregulated portion of cooperative economics
Revenue from recycle MgO- S55.00/ton
Revenue from sulfuric acid varied
$9.00-$30.00/ton
1500
Power unit size, mw
Figure 135. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units—combinations
of 200-mw scrubbing systems-recycle MgO cost-$25/ton.
Figure 136. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units—combinations
of 200-mw scrubbing systems—recycle MgO cost—$55/ton.
129
-------
Scheme D - •
Combinations of new 500-m
3.5% S in coal
Nonregulated portion of cooperative economics
Revenue from recycle MgO- $15.00/ton
Revenue from sulfuric acid varied
$9.00-$30.00/ton
1000 1500 2000
Equivalent power unil size, n
Figure 137. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units—combinations
of 500-mw scrubbing systems—recycle MgO cost—$15/ton.
Scheme D - •
Combinations of new 500-mw coal-fired units
3.5% Sin coal
Nonregulated portion of cooperative economics
1— Revenue from recycle MgO - J55.00/ton
Revenue from sulfuric acid varied
$9.00-$30.00/ton
1000 1500 2000
Equivalent power unit size, mw
Figure 138. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units—combinations
of 500-mw scrubbing systems-recycle MgO cost-$55/ton.
1 ! !
Scheme D - •
Combinations of ne
3.5%Sincoa
Nonregulated portion of cooperative economics
— Revenue from recycle MgO - S10.00/ton
Revenue from sulfuric acid varied $9.00-$30.00/ton
1000-mw coal-fired units
Scheme D - •
Combinations of new 1000-mw coal-fired units
3.5% Sin coal
Nonregulated portion of cooperative economics
_ Revenue from recycle MgO- $55.00/ton
Revenue from sulfuric acid varied $9.00-S30.00/ton
E40
1000 1500 2000
Equivalent power unit size, mw
1000 1500 2000
Equivalent power unit size, mw
Figure 139. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units—combinations
of 1000-mw scrubbing systems—recycle MgO cost—$10/ton.
Figure 140. The effect of variation in net sales
revenue for sulfuric acid on interest rate of return
for centralized regeneration-acid units-combinations
of 1000-mw scrubbing systems—recycle MgO cost-$55/ton.
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RESEARCH AND DEVELOPMENT NEEDED
Of the four processes evaluated under the EPA-TVA
conceptual design and cost series, the magnesia process
development was probably the most advanced at the time
the study was initiated. As mentioned earlier, a 155-mw
demonstration system utilizing the magnesia slurry process
(Scheme A) has been built and was started up in early 1972
on an oil-fired Boston Edison power unit. A number of
items needing further research and development are being
studied in the demonstration scale system.
Further development work needed can be classified into
three categories: process phases, equipment performance,
and system operation. Although it is desirable to have
additional information such as physical properties, mass
transfer rates, absorber efficiencies and pilot plant
operating data, the emphasis should be centered on process
confirmation and improvement, equipment performance
and reliability, and system compatibility with power plant
operation.
There are several process phases worthy of additional
attention, including use of unrefined magnesia as raw
material, formation of magnesium sulfite trihydrate crystals
in scrubbing slurry, contamination buildup and removal,
crystal growth and scaling, oxidation in the scrubber and
dryer, clear liquor scrubbing and sulfite precipitation, and
the manufacture of sulfur in the calciner. With the
exception of scaling and contamination, which can interfere
with process operation, most of these areas of study are
process modifications to extend usefulness and to improve
economics.
The least expensive forms of magnesium oxide are
dolomite and raw magnesia. If process contamination
tolerances can be defined, some raw material savings might
be achieved by using these materials.
Potential problems associated with buildup of con-
taminants from recycle of process raw material have been
given some attention in this report; however, very little data
exists to define the actual compounds, their rate of
buildup, and their effect on the process. Data of this type
can only be obtained over a long period of process
operation with remedial measures taken after definition. It
may well be that contaminants and the level of buildup will
vary from operation to operation depending on fuel
characteristics, source of makeup MgO, and process water
composition. Although the flow diagram for each scheme
shows a point where a decontamination purge should be
taken, actual results may indicate otherwise.
Some investigators have indicated that magnesium sulfite
trihydrate rather than hexahydrate crystals may be formed
in the scrubbing loop at scrubbing temperatures normally
encountered (125-135° F). Research data available does
not generally confirm this; however, the data is not all
inclusive, and some doubt remains, especially with actual
slurries as opposed to simulated slurries. Considerable heat
savings could be derived if easily separatable trihydrate
crystals could be formed directly in the scrubbing slurry.
Even using induced thermal conversion of the hexahydrate
crystals to form trihydrate material, as suggested in this
report, may not be acceptable if the smaller trihydrate
crystals (1:10) can not be dewatered easily. Additional data
from pilot plant or demonstration-scale operation is
desirable to clarify this procedure.
Oxidation of sulfite to sulfate in the scrubbing and
drying operations requires increased use of reducing coke or
higher temperatures in the calciner. As discussed in the
Process Chemistry, Properties and Kinetics section, various
organic compounds can be used to retard oxidation in the
scrubber; however, they probably would be consumed or
decomposed in the drying-calcination steps and would need
to be replaced. Since these organics are generally expensive,
their value as an oxidation retardant would have to be
compared to their replacement expense. Data is needed
both on their effectiveness as retardants and their expected
losses per cycle. In addition to oxidation in the scrubber
loop, information on sulfite oxidation in the dryer under
various combustion conditions and in storage over a period
of time may be worthwhile.
Chemico-Basic has carried out some development with
clear liquor scrubbing, Scheme C, with less than desirable
S02 removal; however, these results were limited. As can be
seen in the economic evaluation, Scheme C has the least
investment and operating costs of the schemes studied, and
on that basis, appears worthy of additional development
work. Perhaps minor pH changes to the 6.0-6.5 range or
increased L/G would permit improved S02 removal with a
totally soluble sulfite-bisulfite liquor.
One of the most important process phases requiring
additional study is crystal size and growth. Crystal charac-
teristics are important in the scrubber system for MgS03
formation and scale prevention, in the dewatering step for
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liquids-solids separation, and in the dryer for agglomera-
tion. Figures 12, 13, and 14 in the Process Chemistry,
Properties and Kinetics section are photomicrographs of
synthetically prepared sulfite tri- and hexahydrate crystals
and are helpful in studying ciystal habit. It appears
desirable to form crystals as large as possible to promote
sulfite precipitation without scaling and liquid-solid
separation. Although not confirmed, larger crystals also
may reduce erosion in the system.
In connection with crystal growth and scaling is a
process variable needing additional study, solids concentra-
tion in the scrubbing slurry. Results at TVA in limestone
slurry scrubbing indicate a relationship between slurry
solids concentration, and scaling and erosion of unpro-
tected surfaces. With greater solids concentration, less
scaling is encountered, but more erosion is usually
experienced. From a liquid-solid separation viewpoint, it is
desirable to feed the highest possible solids concentration
to the thickener, screen, and centrifuge. Although
preliminary tests have been made, their results have not
provided conclusive data.
Speculation has been raised as to possible direct manu-
facture of sulfur in the calcination step by alteration of
calciner design and/or operating conditions. As discussed in
the Process Chemistry, Properties and Kinetics section,
some small-scale work has been done in the area; however,
application to commercial systems remains suspect. Such a
concept, if development were successful, could result in
investment cost savings and a more desirable end product.
Areas of additional equipment development include
spray scrubbing, corrosion and erosion protection, mist
elimination in slurry service, and fluid bed drying and
calcination. The Grillo work with high gas velocities in
concurrent spray scrubbers indicates potential scrubber cost
savings for MgO-Mn02 slurries (Scheme B). It is conceivable
that additional development in spray scrubbing technology
could lead to application in the magnesia slurry and clear
liquor schemes (A, C, D) where sulfite oxidation is less than
for MgO-Mn02 scrubbing. Recent test work at TVA using
limestone slurries in spray scrubbing has been promising;
however, mist elimination at high gas velocities and
plugging of the eliminators were major problems. This area
of research might best be relegated to equipment vendors;
however, there is considerable opportunity for joint process
and equipment development.
In aqueous scrubbing processes, TVA pilot plant testing
has shown mist elimination to be a difficult and expensive
operation, especially in slurry service. High elimination
efficiency to prevent reentrainment of scrubbing salts and
lower reheat requirements, plus the prevention of plugging
in separation devices, are essential for large-scale application
of aqueous scrubbing systems. Much equipment
development effort is needed in this area.
Fluid bed dryers and calciners are used in the schemes
presented in this report; however, very little magnesia
process test work has been performed using these devices.
Initial development, including the Boston Edison demon-
stration plant, utilizes the less efficient, but dependable,
rotary dryer and calciner. Fluid bed equipment vendors feel
that their devices should work well in these services, and
available cost estimates justify considerable effort in this
direction. Due to previous successes in the sulfite pulping
industry, process developers think it is only a matter of
time until fluid bed systems are used for magnesium sulfite
drying and magnesia regeneration to obtain the potential
cost savings and achieve a more uniform product. If direct
sulfur production is to be accomplished, it probably will be
with fluid bed systems.
With potential problems such as corrosion, erosion,
scaling, and start and stop operation, considerable work will
be required to obtain satisfactory coupling of the magnesia
process to a power plant. In some cases when aqueous stack
gas scrubbing processes have been tested on power units,
difficulty has been encountered in obtaining long term,
continuous operation. Limited success has been obtained in
a few cases, but only after alterations and modifications
were made. The Boston Edison demonstration systems
should indicate which process alterations and modifications
are required for the magnesia process. Questionable areas
for specific problems include the reliability of gas by-pass
dampers if used, corrosion-erosion resistant materials and
linings in scrubber loop, gas and liquid channeling in
scrubber units, mist elimination and reheat systems, process
materials storage requirements, the need for spare
equipment, and location or type of instrumentation
required to quickly obtain consistent, even operation under
frequent changes in power unit load.
In absence of definitive corrosion and erosion data for
the magnesia scrubbing operations, considerable materials
testing is recommended for future development. Limited
tests under static simulation are almost worthless and data
under sustained, dynamic operation conditions are desir-
able. Knowing the effects of frequent starts and stops,
adverse process upsets and length of operation should be
very helpful to the design engineers.
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CONCLUSIONS AND RECOMMENDATIONS
In reviewing processes for sulfur dioxide removal from
power plant stack gas, thus far, no single process studied
has exhibited outstanding superiority over all others. Each
process has shown some advantages and disadvantages when
subjected to a thorough appraisal. In this respect, the
magnesia scrubbing-regeneration process is no different;
however, it is apparent that the technology of the concept
is well founded and its development has advanced
considerably during the past few years.
Aqueous scrubbing processes such as the magnesia
system have advantages over dry absorption including:
1. Better mass transfer.
2. Easier absorbent handling and circulation.
3. No physcial deterioration of the absorbent.
At the same time, disadvantages such as:
1. Necessity for stack gas reheat.
2. Increased corrosion.
3. Potential to form scale deposits in the scrubbing
system.
4. The need to remove water for regeneration of
absorbent.
In comparison with other aqueous scrubbing processes,
the advantages and disadvantages of the magnesia concept
depend on the process with which it is compared. For
instance, at a given liquor to gas flow ratio, the mass
transfer rate of sulfur dioxide in the stack gas to the
aqueous magnesia absorbent is superior to limestone
scrubbing, but less than that of the more soluble sodium,
potassium, and ammonium compounds. The corrosion-
erosion rates and potential to form scale deposits of
magnesia slurry scrubbing are less than limestone slurries,
but possibly greater than the soluble alkali salts. Reheat,
entrainment, and absorbent loss problems are nearly the
same for all aqueous scrubbing schemes.
Unlike the nonrecovery limestone processes studied
earlier in the EPA-TVA series, the magnesia scrubbing
process recovers the S02 in the stack gas as a salable,
commercial product. Either concentrated (98%) sulfuric
acid, liquified sulfur dioxide, or elemental sulfur could be
produced for sale.
The most attractive assets of the magnesia concept are:
1. The ease of separation of the sulfite salt from the
scrubber liquor.
2. The ability to regenerate and recycle the absorbent,
magnesium oxide.
3. The avoidance of a solids disposal problem.
4. The possibility of setting up a centralized
regeneration-acid unit separating both financially and
operationally the power unit-scrubbing system from the
commercial, chemical product function.
It is the last two advantages that have captured the interest
of the decision-making officials in the power industry; the
ability to remove S02 from the stack gas and dispose of it
off-site, remaining free of any chemical marketing liability.
The process does have notable requirements such as:
1. The need for two scrubbing stages when using slurry
on coal-fired units to avoid mixing the fly ash with
undissolved magnesium.
2. Relatively high energy usage to generate more
concentrated S02.
3. The necessity to market the product(s) with limited
flexibility in demand.
Probably, the greatest obstacle to immediate, wide applica-
tion is the current market price for sulfur which permits
less expensive manufacture of sulfuric acid by conventional
routes as compared to the calcination of magnesium sulfite,
even if the sulfite could be obtained free of charge.
Advanced development has been carried forth on three
technological variations of the magnesia process. Pilot plant
runs have been made on the critical portions of the
following sulfur'dioxide removal schemes:
Scheme A—Slurry scrubbing with partially dissolved
magnesium oxide-magnesium sulfite at a basic pH,
separation and drying of the predominantly sulfite crystals,
regeneration to MgO, and concentrated (16%) sulfur
dioxide.
Scheme B—Slurry scrubbing with partially dissolved
magnesium oxide-magnesium sulfite-manganese dioxide,
separation and drying of the solids, and regeneration to
MgO, Mn02, and concentrated (13%) S02 .
Scheme C—Solution scrubbing with dissolved magnesium
sulfites at an acidic pH, precipitation of sulfite by addition
of MgO, and separation and drying of resultant crystals
with regeneration to MgO and concentrated (16%) S02.
Although all three variations appear feasible, only the
basic slurry scrubbing schemes (A and B) are capable of
90% plus sulfur dioxide removal from power plant stack gas
(less than 4,000 ppm, S02). The high vapor pressure of
S02 over the solution of sulfites makes it difficult to obtain
efficiencies greater than 80-85% with Scheme C. Because of
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the greater S02 removal, the slurry variations have received
more attention during recent years. As previously stated,
there is a need for some additional pilot plant studies of
various process phases; however, the slurry concepts are
definitely ready for larger scale demonstration.
Recently, some research has been carried out on NOX
removal by magnesia scrubbing and the manufacture of
sulfur directly in the calciner offgas. Based on preliminary
results reported by Babcock and Wilcox (26), the magnesia
process does not appear to be effective for NOX removal
(10% or less) and, therefore, should not be depended on as
a means of NOX control. For the direct manufacture of
sulfur, little applied research has been reported, but
theoretical evaluation indicates some merit for additional
work. At the present value of elemental sulfur, however,
the additional cost required to produce sulfur rather than
acid may not be justified (11).
Full scale equipment which would permit at least limited
operation of the magnesia scrubbing-regeneration process
could be purchased today. Several scrubber designs are
available including venturi, mobile bed, and spray types for
slurries and, in addition to these, packed and tray types for
solutions. Performance and reliability data for full scale
equipment is not yet available; however, within limits,
fabricators could provide workable devices. Although the
Boston Edison, 155-mw demonstration is the first large
scale application of the magnesia process, many of the
items such as centrifuges, screens, pumps, conveyors, and
tanks require no special design other than specification of
materials of construction. Sulfuric acid plant designers
could easily provide systems to produce acid from calciner
offgas.
One major area of equipment design needing further
attention is in fluid bed drying and calcination. The
155-mw demonstration system uses rotary equipment;
however, future installations may be fluid bed types. There
are companies who feel they can adapt current fluid bed
designs without major alterations.
At this time, mist eliminator design is of concern;
however, development of efficient, reliable devices should
be forthcoming as soon as experience is obtained in large
stack gas wet-scrubbing applications. More than likely,
entrainment separators for magnesia scrubbing will be very
similar to devices used for other wet scrubbing processes.
The unit investment requirements for magnesia
scrubbing-regeneration vary over a wide range—$14.9/kw
for a new, 1000-mw, 1.0% S in fuel, oil-fired power system
to $65.4/kw for an existing, 200-mw, 3.5% S in fuel,
coal-fired system. Comparable limestone-wet scrubbing
figures are $14.8/kw to $51.5/kw; however, no product is
produced and a large solids disposal problem must be
endured. In 1969-70, investment for the three ammonia
scrubbing-fertilizer manufacturing processes evaluated
under the EPA-TVA series (87) ranged from $24.6/kw for a
new, 1000-mw system to $62.6/kw for a 200-mw, existing
system; however, these values are not up-to-date and the
processes evaluated manufactured finished, consumer
products (28-14-0, 26-19-0, and 20-15-0 N.P.K. fertilizers).
For coal-fired units, the investment requirements for
magnesia Scheme C are lowest of the three technological
variations studied and those of Scheme B, only marginally
the highest. The use of a single scrubber to remove both fly
ash and sulfur dioxide is the primary reason for reduced
cost of Scheme C; however, the reduced throughput of
material due to lower S02 removal also has some effect.
The Scheme B scrubber cost is less than Scheme A because
of the improved mass transfer using Mn02 in the slurry;
however, this cost improvement is offset by the quantity of
material which must be dried and handled. Impurities and
Mn02 from pyrolusite, the purchased form of manganese
dioxide, are a noticeable burden even though the Mn02
improves mass transfer in the scrubber, and permits
calcination of sulfite-sulfate without coke at only slightly
higher temperature. Again, for oil-fired units (Scheme C not
applicable), Scheme A investment is slightly less than
Scheme B. As expected, process investment for oil-fired
units is much less than for coal-fired systems.
The investment for magnesia systems on existing power
units is estimated at about 10% greater than for new units,
but it should be recognized that actual applications may be
considerably higher due to low service and utility avail-
ability, unfavorable physical layout, shutdown require-
ments, and construction efficiency. Also, the investment
cost for a single unit under the central processing concept,
Scheme D, is about 6% higher than for a single-site Scheme
A system; however, when multiple units are considered,
Scheme D investment is less, by as much as 13%.
The lowest cost source materials for makeup magnesium
oxide are raw magnesite and dolomite, but these materials
may contain considerable undesirable impurities. At least
until proven otherwise, calcined'magnesite should be used
as the primary raw material. It is expected to cost between
$94 and $140/ton, 100% MgO delivered, depending on
shipping destination.
Magnesia process operating costs have been examined
under both regulated (cost of money and income taxes
included) and nonregulated bases for 7,000 hr/yr operation.
In most respects, the results are similar to investment
requirements in that Scheme C is the least costly variation,
existing units are more expensive to operate, oil-fired
systems have lower costs than coal-fired systems, and
Scheme D for a single-unit system is more costly than
Scheme A, but on a multiple unit basis, is less expensive.
One notable exception to the investment relationships is
that operating costs are for oil-fired Scheme B systems just
slightly less costly than comparable Scheme A systems. For
coal-fired systems, Scheme A is slightly lower. The
explanation for this disparity lies almost solely with fuel oil
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requirements for reheating the humidified stack gas. In
both coal-fired systems, the gas is totally humidified to a
saturation temperature of approximately 127° F as it
passes through both the particulate and S02 scrubbers. In
the oil-fired system design, however, Grillo indicates only
partial saturation to a temperature of 140° F in the
single-spray absorber used for MgO-Mn02 scrubbing
whereas Scheme A is assumed to be totally saturated to
127° F. Although the resulting different scrubber tempera-
tures could easily be questioned, nevertheless, the lower
requirements for reheating the partially saturated Scheme B
scrubber gas to 175° F accounts for the lower Scheme B
operating cost in the oil-fired system comparison.
Regulated operating costs range from $3.62-7.75/ton of
coal burned for the coal-fired units and from
$0.50-1.34/barrel of oil for oil-fired units. Sulfuric acid
manufacturing costs by magnesia scrubbing range from
$41.53-178.97/ton of acid. For comparable cases, the
limestone-wet scrubbing process is estimated at
$3.24-5.80/ton of coal burned and $0.46-1.03/barrel of oil
burned when a low cost limestone and on-site solids
disposal are utilized. Values for the high cost limestone and
off-site solids disposal range from $5.08-7.22/ton of coal
burned and $0.52-1.19/barrel of oil burned. Except for the
200-mw units, the magnesia system operating costs fall
between the high and low cost limestone estimates.
Premium costs for low sulfur coal and low sulfur oil are
quite variable, depending on location delivered, but values
appear to range from $2-8/ton of coal and $0.75-2/barrel of
oil.
Under Scheme D, the operating costs for producing acid
in a central plant is estimated to range from
$15.35-36.52/ton of acid when magnesium sulfite is
supplied from one or more 200-mw, 500-mw, or 1000-mw
scrubbing systems at no cost other than shipping expense.
This acid cost is $2-23 higher than that from acid plants
burning elemental sulfur at current prices ($24-27/long ton
of sulfur).
Fairly large quantities of sulfuric acid can be produced
from the S02 emitted by power plants, on the order of 378
tons/day for a 500-mw unit burning coal containing 3.5%
sulfur, or 2,000 tons/day for a central process acid plant
equivalent to 3000-mw. With a projected annual growth
rate of 4.6%, marketing large quantities of byproduct
sulfuric acid from power plants will take special planning.
Probably, the best end-use market is the phosphate fertil-
izer industry and the prime plant locations would be in the
Midwest near high sulfur coal and large consumers of
phosphate fertilizers. Even in this area, competition will be
rough and average net revenue can not often be expected to
exceed $8/ton of acid for single power unit applications.
Since flexibility will be limited, in that acid demand will
not coincide with production, heavy discounting may be
necessary to assure disposal of the product. For central
process acid plants, flexibility is higher and, assuming more
independence from the fertilizer market, an average net
revenue of $12/ton is more appropriate.
Final economic potential of the magnesia schemes is
considered by three different financial procedures: regu-
lated profitability as practiced by the power industry,
nonregulated profitability as used in the chemical industry,
and a combination of the two-cooperative economics.
Under regulated economics, a limited, fixed return on
investment is provided; for nonregulated economics, profit-
ability depends entirely on competitive forces. For alterna-
tives under regulated economics, the evaluation compares
only the resultant cost effects to power consumers; with
nonregulated alternative appraisal, the most profitable
route is derived. In cooperative economics, the portion of
investment under regulation is so evaluated, and that under
nonregulation is subjected to profitability analysis.
Regardless of the financial basis of evaluation, the
measure of potential for any process scheme depends on
several factors including:
1. Plant size.
2. Sulfur content of fuel.
3. Fuel type.
4. Plant status (new or existing unit at the time the S02
removal process is installed).
5. Operating onstream time.
6. Revenue from sale of product(s) and for operations
at more than one site (Scheme D).
7. Shipping costs of transferred material.
Although these variables can be examined individually, the
magnitude of each depends on the level chosen for the
others.
Using regulated economics, the single-site magnesia
Schemes A, B, and C are compared to each other and both
high (metropolitan) and low (rural) cost limestone
scrubbing. Scheme C is the lowest cost magnesia process for
coal-fired units with Scheme B only slightly higher than
Scheme A. Only Scheme C applied to power units larger
than 500-600-mw is less expensive than low cost limestone
scrubbing; however, when compared with high cost ($6/ton
limestone, off-site solids disposal at $6/ton) limestone
scrubbing, all three magnesia schemes are less costly for
units above 300-400-mw in size. For oil-fired units, results
are similar for Schemes A and B; Scheme C (solution
scrubbing) is not applicable to oil-fired units.
Usually increasing sulfur content of fuel or annual
onstream time improves the economics; however, since it
costs more than $8/ton to manufacture the acid from free
MgS03, an increased quantity of throughput, at least up to
the levels reviewed, increases total cost of magnesia
schemes.
From this data, it can be seen that when regulated power
industry funding is necessary for single-site applications,
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only large units should be considered for magnesia
scrubbing-regeneration.
When investment is provided by a nonregulated com-
pany, it can be assumed that some fee or payment might be
charged to the power company for the service performed; a
maximum could be the cost of comparable limestone-wet
scrubbing and a minimum would be zero. Under the terms
of maximum payment equivalent to high cost limestone
scrubbing and $8/ton revenue, the best profitability of the
cases examined is for Scheme C on a new 1000-mw,
coal-fired unit—22.8% interest rate of return or 4.0 year
payout. Without any payment, all cases evaluated have
negative interest rates of return and no payouts (which
means original capital investment was not even recovered).
The most profitable case for Scheme A, again assuming the
high equivalent limestone payment, is a new, coal-fired
(3.5% S), 1000-mw unit with an interest rate of return of
18.1% and a payout in 4.8 years. It should be stated,
however, that projections of the profitability curves
indicate that little improvement can be achieved by
increasing unit size above 1000-mw for single-site
applications.
For applications where competition is a low cost
limestone scrubbing system, an expected lower payment
restricts the magnesia process profitability considerably.
Under nonregulated economics, $8/ton acid revenue, and
low or no air pollution control payment, single-site
magnesia processes attached to a power unit would not be
attractive as a chemical industry investment.
When investment arrangements are cooperative (that is,
the scrubbing-drying operation is provided by power
company funds and the regeneration-acid unit built by
nonregulated company capital), the best qualities of the
magnesia process are utilized. Not only financial responsi-
bility, but also operating and marketing requirements are
more compatible with power plant operation and chemical
manufacturing. Assuming supply of magnesium sulfite to
the central regeneration plant from several power plant
sources, acid manufacture becomes independent of the
cyclic nature of power demand and chemical plant
operation can be more readily optimized.
A major obstacle to such arrangement, however, is that
acid revenue alone will not produce sufficient profitability
to justify nonregulated capital investment in the
regeneration-acid plant. The incentive for power companies
to invest in magnesia scrubbing is much stronger since
magnesia scrubbing is less expensive than limestone
scrubbing when magnesium sulfite is swapped for
magnesium oxide. To improve the potential for sulfuric
acid plant investment, another revenue source can be
sought; that of charging for recycle MgO. This should be
feasible as long as the price charged permits magnesia
scrubbing costs to be less than limestone scrubbing.
For 1000-mw size magnesia scrubbing systems, the cost
of recycle MgO would need to be limited to $10-15/ton and
for 500-mw systems, $15-20/ton when competition is a low
cost limestone scrubbing system. However, as the unit size
of the individual scrubbing-drying system decreases, or the
cost of a limestone scrubbing system increases, the possible
price of recycle MgO increases. As the recycle MgO revenue
rises, the profitability potential of the central process
concept becomes more and more attractive.
For a 3000-mw equivalent central acid plant with
magnesium sulfite supplied by six 500-mw slurry scrubbing
units within a 50-mile radius, and net revenue of $12/ton of
acid and $15/ton for recycle MgO, the interest rate of
return is only 8.7% with a payout of 6.5 years. If
competitive limestone scrubbing has a high cost ($6/ton
limestone, off-site solids disposal at $6/ton), approximately
$55/ton can be charged for recycle MgO which would
permit an interest rate of return of 39.7% and a payout of
2.4 years. Therefore, depending on competitive costs of
alternate methods of SO2 control, the attractiveness of the
magnesia central process concept can range from poor to
excellent.
Since the data presented in figure 126 indicate that a
higher price can be charged for recycle MgO as the power
unit size decreases, it can be concluded that the greatest
profitability of the central process concept lies with smaller
scrubbing systems tied to large acid plants. For instance, a
3000-mw equivalent acid plant supplied by fifteen 200-mw
scrubbing-drying systems within a 50-mile radius could earn
a 40.6% interest rate of return if $55/ton is obtained for
recycle MgO. When a low cost limestone process is the
competition, and only $25/ton can be obtained for the
recycle absorbent, the interest rate of return would be
17.2% which is still attractive.
In the analysis of» the central processing concept, the
effect of shipping cost for transferring MgSO3 and MgO
between the plants deserves particular attention. Shipping
cost is not a large fraction (7-8% for 50-miles) of total
operation cost; therefore, it is not surprising to find that
interest rates of return are decreased only about 1-3% for
every 25-miles distance. Because shipping rates are
unchanged in the first 50-miles, there is no effect inside this
radius.
The effect of acid revenue on economic potential varies
with each of the three financial arrangements studied. If,
instead of $8/ton of acid, $16-20/ton could be obtained,
the magnesia process would be competitive with low cost
limestone scrubbing for single-site applications under
regulated economics. Under nonregulated profitability, an
increase of 250-300% in. acid revenue ($20-24/ton) would
be necessary to make single magnesia scrubbing-
regeneration systems attractive when coupled with only a
low equivalent payment. With the central process concept,
an increase in acid revenue from $12/ton-20/ton would
136
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permit attractive profitability since such large volumes of
acid are involved.
In summation, it can be concluded that most magnesia
scrubbing systems would be economically attractive under
any financial arrangement if competition for S02 control is
high cost limestone scrubbing, and high premium, low
sulfur fuel. Locations meeting these conditions would be
mostly in midwestern and eastern metropolitan areas of the
United States and western Europe. In such areas where
limestone cost is relatively low and solids disposal is not
unduly expensive, magnesia scrubbing-regeneration might
possibly be attractive, but unexpectedly high acid prices
would have to be obtained. If total system financing must
be under regulated conditions, only large power units
should be considered for application of magnesia
scrubbing-regeneration.
137
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REFERENCES AND ABSTRACTS
1. Bagwell, F A., et al. Oxides of Nitrogen Emission
Reduction Program for Oil- and Gas-Fired Utility
Boilers. Proc. American Power Conf. 32, pp. 683-94
(1970). This paper describes combustion control
techniques which reduce emission levels of oxides of
nitrogen from existing natural gas-fired units to 150
to 250 ppm at full load. Testing performed, together
with digital computer generated data, indicates that
NOX levels below 50 ppm may be possible for natural
gas- and oil-fired units constructed in the future. This
could entail redesign of the furnace to ensure comple-
tion of combustion within the radiant sections of the
boiler, and would add both to the initial cost of the
unit and to operational cost. But, NOX control by
combustion modification appears more economical
than complete combustion product gas processing.
2. Bagwell, F. A., et al. Utility Boiler Operating Modes
for Reduced Nitric Oxide Emissions./. Air Pollution
Control Assoc. 21 (11), 702-8 (1971). An under-
standing of NO formation and the controlling factors
is presented, followed by a discussion of the combus-
tion control techniques of off-stoichiometric com-
bustion and reduced combustion temperatures.
Results of field testing employing these techniques
are demonstrated. Finally, boiler operating charac-
teristics affecting NO and the implementation of the
techniques for achieving operating reductions in NO
emissions are discussed.
3. Bartok, W., et al. (Esso Research and Engineering
Company). Systems Study of Nitrogen Oxide Control
Methods for Stationary Sources. Springfield, Virginia
22151: National Technical Information Service. (PB
192-789) (November 20, 1969). This is a report
describing the magnitude and concentration of nitro-
gen oxide emissions from stationary sources. A
systems study was made of NOX control methods and
costs. Recommendations for process research and
development were made.
4. Bartok, W., Crawford, A. R., and Skopp, A. Control
of NOX Emissions From Stationary Sources. Chem
Eng. Prog. 67 (2), 64-72 (Feb. 1971). Cost-
effectiveness analyses of potential NOX control
methods for stationary combustion sources are pre-
sented, and research and development needs in this
area are critically evaluated. NAPCA-sponsored
research at Esso, related to stationary NOX control, is
discussed including modeling of NO kinetics in
combustion processes and the scrubbing of NOX from
flue gases.
5. Bartok, W., Crawford, A. R., and Piegari, G. J. (Esso
Research and Engineering Company). Systematic
Investigation of Nitrogen Oxide Emissions and Com-
bustion Control Methods for Power Plant Boilers.
Atlantic City, N. J.: Symp. on Combustion Processes
and Air Pollution Control, AIChE 70th Annual
Meeting. Based on research conducted under Contract
No. CPA 70-90, funded by the Office of Air Programs
of the Environmental Protection Agency. Results are
presented for a statistically designed experimental
program aimed at establishing new or improved
nitrogen oxide (NOX) emission factors for fossil fuel
power plants and defining the scope of applicability
of known and potential combustion modifications for
NOX abatement. Results on gas-fired utility boilers
indicate that NOX emissions can be controlled with a
fair to high degree of effectiveness by modification of
boiler operating conditions without increasing the
emission of other pollutants, such as CO and hydro-
carbons. To a lesser extent, these findings apply to
oil-fired boilers also. Limited emission data indicate
the potential feasibility of such approaches for
coal-fired boilers, particularly when the bulk of the
combustion occurs under fuel rich conditions.
6. Botsaris, G. D. and Denk, E. G. Growth Rates of
Aluminum Potassium Sulfate Crystals in Aqueous
Solutions. Ind. Eng. Chem. Fund. 9 (2), 276-83
(1970). The linear growth rates of the 100, 110, and
111 faces of potassium alum crystals in aqueous
solutions were measured as a function of super-
saturation and liquid flow velocity. A compound
growth mechanism (dislocation growth plus mono-
nuclear two-dimensional nucleation) can correlate the
growth rates of the crystal faces for the range of
supersaturation studied (0-18%).
7. Bottomley, G. A. and Cullen, W. R. Induction Effects
in the Oxidation of Bisulfite Ion at pH 4. /. Chem.
Soc. pp. 4,592-95 (1957). The rate of oxygen
absorption by bisulfite solutions at pH 4 in the
presence of Cu+2 and Mn+2 has been studied with
emphasis on the phenomena occurring when the
138
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oxygen supply is temporarily withdrawn. The absorp-
tion of oxygen after interruption follows a different
course from that of an uninterrupted reaction and is
most satisfactorily explained by a slow reaction of the
metal catalyst with the sulfite solution.
8. The British Sulphur Corporation Ltd. Statistical
Supplement No. 2. (Nov.-Dec. 1970). World produc-
tion and consumption statistics for sulfuric acid,
sulfur, and fertilizer materials are summarized in this
report.
9. The British Sulphur Corporation Ltd. Statistical
Supplement, No. 4. (Nov.-Dec. 1971). World produc-
tion and consumption statistics for sulfuric acid,
sulfur, and fertilizer materials are summarized in this
report.
10. The British Sulphur Corporation Ltd. World Sulphur
Statistics. International Superphosphate and Com-
pound Manufacturers Association Ltd. Preliminary
Sulfur and Sulfuric Acid Statistics-1970 (Jan. 1971).
An authoritative summary of world sulfur and
sulfuric acid statistics for 1970 and past years is
presented, including production and consumption by
country with some end-use data.
11. Chemical Construction Corporation. The High Sulfur
Combustor, A Study of Systems for Coal Refuse
Processing. Air Pollution Control Administration,
Department of Health, Education and Welfare. (PB
203-958) (Feb. 1971). This report provides a narra-
tive summary of high sulfur content coal refuse
processing for recovery of sulfur values. An evaluation
of process technology and economics under NAPCA
contract is included.
12. Chemical Construction Corporation. Technical Devel-
opment Report, Magnesium Base Processes for SO,
Recovery and Fly Ash Removal From Stack Flue
Gases, (unpublished internal report). This is a pro-
prietary report of pilot plant work at various power
plants and industrial sites to prove the technical
feasibility of S02 recovery processes which are based
on magnesia scrubbing.
13. Chemical Data Services. Sulfuric Acid Plant Capacity.
London, England'. (Nov. 1971). Up-to-date capacities
and locations of sulfuric acid plants are shown in
detail.
14. Chemical Economics Handbook. Sulfuric Acid.
Stanford Research Institute. (Dec. 1967). A complete
study of sulfuric acid capacity, manufacturers, plant
locations, production, prices, product grades, and
end-uses is included in the handbook.
15. Chertkov, B. A. Mass Transfer Coefficients During
Absorption of Sulfur Dioxide From Gases, Using
Magnesium Sulfite and Bisulfite Solutions. Kfiitn.
Prom. 7, 537-41 (1963). Data on mass transfer in a
system of sulfur dioxide and a solution of magnesium
sulfite-bisulfite were interpreted. It was determined
that resistance to flow in the liquid phase was small
enough to be negligible at pH values of 6.1-6.2 in the
absorbent solution. The total mass transfer coefficient
can be equated to the partial coefficient of the gas
phase. In this paper, the application of magnesia
scrubbing of S02 to smelters is reported.
16. Chertkov, B. A. and Dobromyslova, N. S. The
Influence of Traces of Sulfate on the Partial Pressure
of SO2 Over Ammonium Sulfite-Bisulfite Solutions.
/. Appl. Chem. U.S.S.R. 37 (8), 1707-11 (1964).
When the concentration of ammonium sulfate present
is greater than the concentration of the sulfite-
bisulfite or in a dilute solution, or in a process in
which the solutions obtained approach a state of
equilibrium with the gas of a given concentration, the
partial pressure of S02 over the solution may be
seriously affected by changes in the concentration of
ammonium sulfate.
17. Chertkov, B. A. Oxidation of Magnesium Sulfite and
Bisulfite During Extraction of SO2 From Gases. /.
Appl. Chem. U.S.S.R. 33 (10), 2136-42 (1960). The
oxidation rates of magnesium sulfite-bisulfite solu-
tions formed during extraction of S02 from dilute
gases were determined; it was found that the con-
centration of the oxidation product, MgS04, in the
liquor has the greatest influence on the coefficient of
oxygen absorption. The coefficient of oxygen absorp-
tion varies inversely with the viscosity and density of
the liquid phase. The oxidation rate in the liquor can
be reduced by about half by introducing 0.001%
p-aminophenol to the liquor.
18. Chertkov, B. A. General Equation for the Oxidation
of Sulfite-Bisulfite Solutions in the Extraction of SO2
From Gases. /. Appl. Chem. U.S.S.R. 34 (4), 743-47
(1961). Data on the oxidation kinetics under
industrial conditions were correlated and an empirical
equation was derived for calculating the oxidation
rates of various sulfite-bisulfite solutions used in
extraction of S02 at low concentrations from gases.
19. Chertkov, B. A. The Influence of SO2 Concentration
in a Gas on its Rate of Absorption by Different
Solvents. Khim. Prom. 7, 586-91 (1959). The mass
transfer coefficient remains constant during the varia-
tion of the initial S02 concentration from 0.08 to
3.5% by volume. At higher S02 concentrations, a
constant decrease in the coefficient is observed.
20. Chertkov, B. A. and Puklina, D. L. Effect of
Temperature on the Rate of SO2 Absorption From
Gases. /. Appl. Chem. U.S.S.R. 33 (1), 7-10 (1960).
Laboratory experiments were conducted to obtain
data on the effect of temperature changes alone on
the rate of S02 absorption. The strong temperature
effects observed in the S02-NH3 system are ascribed
139
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to the large increase in S02 vapor pressure with
temperature increase. In systems where the S02 vapor
pressure is very low, no large temperature effect
should be observed.
21. Chilton, T. H. Reducing SO2 Emission From Station-
ary Sources. Chem. Eng. Progress 67 (5), 69-72 (May
1971). This article provides estimates and projections
by the National Air Pollution Control Administration
(now Environmental Protection Agency) on the
emission of sulfur dioxide by various sources for years
1967 to 2000.
22. Clontz, N. A., et al. The Growth of Magnesium Sulfate
Heptahydrate Crystals From Solution. Cincinnati,
Oh.: Am. Inst. of Chem. Engrs. Paper 26a, 69th
Meeting (1971). At low solution velocity past the
crystal face of MgS04-7H20, the crystal growth rate
is greatly influenced by solution velocity. At higher
solution velocity, no dependence of growth rate on
solution velocity is observed.
23. Conrad, F. and Brice, D. The Solubility of Sulfur
Dioxide in Magnesium Bisulfite Solutions. TAPPI 32
(5), 222-26 (1949). The Duhring relation was applied
to a three-phase, three-component system for the
determination of the combined sulfur dioxide. Sulfur
dioxide pressure-composition curves are presented in
terms of combined and total SO2 for temperatures
ranging from 5 to 60° C.
24. Crynes, B. L. and Maddox, R. N. Status of NOX
Control From Combustion Sources. Chem. Tech. pp.
502-9 (1971). At present, schemes for nitrogen oxides
emission control that seem most favorable for
immediate application are those involving combustion
modification. These include two-stage combustion,
flue gas recirculation, use of low excess air, and
modification of present burner design and configura-
tion. Some of these schemes are immediately
applicable to existing plants; others are best applied
to plants of future construction.
25. Cuffe, Stanley T. and Gerstle, Richard W. Emissions
From Coal-Fired Power Plants: A Comprehensive
Study. National Center for Air Pollution Control, U.
S. Dept. of Health, Education, and Welfare. (1967).
The Public Health Service and the Bureau of Mines
conducted a study of air pollutant emissions from the
six main types of coal-burning power plants. The
components tested include sulfur oxides, nitrogen
oxides, polynuclear hydrocarbons, total gaseous
hydrocarbons, solid particulates, formaldehyde,
organic acids, arsenic, trace metals, and carbon
monoxide. This report relates the effects of variables
such as method of operation, type of boiler furnace
and auxiliaries, re-injection of fly ash, and type of coal
burned to the concentrations of gaseous and
particulate pollutants in the products of combustion.
26. Downs, W. Equimolar I\!O-IM02 Absorption into
Magnesia Slurry-A Pilot Feasibility Study. Babcock
and Wilcox Company for Environmental Protection
Agency: Res. Center Report 4653. The author inves-
tigated the feasibility of absorption of equimolar
concentrations of N0-N02 into MgO slurry on a
1,500 cfm wet scrubbing pilot plant. Seventeen tests
were performed and in no case did NOX absorption
efficiency exceed 10%. The author recommends that
MgO slurry should be removed from consideration for
aqueous NOX absorption.
27. Downs, W. and Kubasco, A. J. Magnesia Base Wet
Scrubbing of Pulverized Coal Generated Flue Gas-
Pilot Demonstration. Babcock and Wilcox Company
for Environmental Protection Agency: Res. Center
Report 5153, (Order 4152-01) (Sept. 1970). A wet
scrubbing pilot plant consisting of three scrubbers was
designed and constructed. An existing test furnace
was modified to burn pulverized coal at a rate of 500
Ibs/hr. These three scrubbers consisted of a venturi-
type particulate scrubber, a venturi-type absorber,
and a tray-type absorber (floating bed absorber). Over
100 short-term tests were performed to determine the
most satisfactory operating conditions for each
scrubber. These were followed by several extended
tests.
28. Duecker, Werner W. and West, James R. The Manu-
facture of Sulfuric Acid. New York, N. Y.:Reinhold
Publishing Corporation. (1959). The science and
technology required for the production of sulfuric
acid are presented, and information is provided
concerning the variety of raw materials used. Data on
handling, shipping, and using sulfuric acid are given.
The chemistry and technology of manufacturing acid
are included with special reference to production by
the contact process.
29. Environmental Protection Agency. Standards of
Performance for New Stationary Sources. Washing-
ton, D.C.. Federal Register 36 247 Part II (Dec. 23,
1971). Proposed standards of performance of steam
generators, portland cement plants, incinerators,
nitric acid plants, and sulfuric acid plants are given.
The proposed standards, applicable to sources con-
structed or modified after August 17, 1971, include
emission limits for particulate matter, sulfur dioxide,
nitrogen oxides, and sulfuric acid mist. Included are
requirements for performance testing, stack gas moni-
toring, record keeping and reporting, and procedures
by which EPA will provide preconstruction review
and determine the applicability of the standards to
specific sources.
30. Federal Power Commission. Steam-Electric Construc-
tion Cost and Annual Production Expenses. 22nd
Annual Supplement, 1969, FPC S-209. A compilation
140
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of operating costs, construction expense, and
locations are given for all U. S. power plants.
31. Federal Power Commission. Hydroelectric Power
Evaluation. Washington, D. C. 20402: Superintendent
of Documents, U.S. Government Printing Office FPC
P-35 (1968) and Supplement No. 1, FPC P-38 (1969).
This publication is a guide for the evaluation of the
hydroelectric power aspects of water resource devel-
opments. Included is information concerning invest-
ment and operating costs of hydroelectric and
thermal-electric power plants and transmission
facilities, methods for economic analysis of projects,
and methods for presenting the annual costs
associated with power generation and transmission
under regulated economics.
32. Foerster, F. and Kubel, K. Decomposition of Sulfite
Salts at Red Heat. Z. Anorg. Allg. Chem. 139, pp.
261-92 (1924). Results of thermal decomposition of
MgS03 carried out between 300 and 550° C show
that sulfur dioxide is the primary decomposition
product above 520° C. Above 500° C no thiosulfate
was observed.
33. Frazier, W. H. and Jordan, J. E. (Tennessee Valley
Authority, Muscle Shoals, Alabama). Private
communication.
34. Gamson, B. W. and Elkins, R. H. Sulfur From
Hydrogen Sulfide. Chem. Eng. Progr. 49 (4), 203-15
(1953). This paper includes a literature review of
hydrogen sulfide conversion to sulfur and a thermo-
dynamic investigation of the conversion.
35. Click, H. S., Klein, J. J., and Squire, W. Single-Pulse
Shock Tube Studies of the Kinetics of the Reaction
N2 + O2 ^ 2NO Between 2000-3000° K./. Chem.
Physics 27(4), 850-57 (1957). The single temperature
pulse technique has been used to study the kinetics of
the formation of nitric oxide in the temperature range
from 2000 to 3000° K. They found that the kinetics
of the reaction are consistent with the chain
mechanism proposed by Zeldovich. The rate-
determining step in the chain is: 0 + N2 -> NO + N,
with an activation energy of 74±5 kcal/mole. The
activation energy for the forward reaction N2 + 02 -*•
2ND was 135 ±5 kcal/mole.
36. Guccione, E. From Pyrite: Iron Ore and Sulfur via
Flash Smelting. Chem. Eng. 73, pp. 122-24 (1966).
Pyrite concentrate, FeS2, is decomposed to FeS and
sulfur, in a reducing atmosphere, at about 1800° C.
The reaction gases containing C02, H20, N2, S02,
H2S, CO, H2, and sulfur are cooled step-wise, first to
about 595° C to allow CO and H2 to react with S02
to yield sulfur and H2S, then further cooled to
about 300° C to increase the sulfur content via the
reaction:
2H2S + S02 ->2H20 + 3/2S2
The last reaction requires an alumina catalyst.
37. Hadley, G. Nonlinear Programming. Reading, Mass.:
Addison-Wesley. pp. 315-484 (1964).
38. Hagisawa, H. Bull. Inst. Phys. Chem. Research
(Tokyo), 12, 976-83 (1933). From the determination
of solubility over the temperature range 0-95°C, two
hydrates, MgS03-6H20 and MgS03-3H20, were
found. A transition temperature of 40° C was
reported. The dehydration of MgS03-6H20 was
examined by use of a thermobalance and no other
hydrates were found.
39. Hagisawa, H. The Science Reports of Tokyo Imp. U.
23, (2), 182-92 (1934). The vapor pressure of sulfur
dioxide over MgS03 was determined by the statistical
method.
40. Hanig, G. (Grillo-Werke AG), Private communication
to G. G. McGlamery, Tennessee Valley Authority,
August 22, 1972.
41. Harris, M. E., et al. Reduction of Air Pollutants from
Gas Burner Flames. Washington, D.C.: Dept. of
the Interior, Bureau of Mines. Bull. 653 (1970). The
formation of nitrogen oxides, the decay of carbon
monoxide, and the concentrations of residual hydro-
carbons in the secondary combustion zones of
propane-air and methane-air flames were studied in
three enclosed burners. From this study four
principles were derived that will insure minimal
emissions of air pollutants.
1. Oxides of nitrogen can best be kept low by
depressing peak temperatures to about 3050° F.
2. If this is not possible, then the secondary
combustion zone should be cooled rapidly to this
temperature.
3. Carbon monoxide concentrations can be limited
by rapid induction of secondary air.
4. Hydrocarbon concentrations can be controlled by
designing for well-seated, stable flames.
Empirical reaction rates were derived that predict the
concentrations of nitrogen oxides and carbon
monoxide in the primary and secondary combustion
zones.
42. Hatfield, J. H. (Tennessee Valley Authority, Muscle
Shoals, Alabama). Private communication.
43. Hatfield, J. D., Lehr, J. R., McClellan, G. H., Frazier,
A. W., Gremillion, L. R., Scheib, R. M., and Trasher,
R. D. Progress Report, Fundamental Research Branch
of Chemical Development, Tennessee Valley
Authority, p. 25, Aug. 1970 (unpublished). This
report presents results of an investigation of the
dehydration properties of MgS03-3H20 and MgS03-
6H20. Optical properties of MgS03-3H20 are also
included in the report.
44. Hatfield, J. D., Kim, Y. K., and Dunn, R. L. Progress
Report, Fundamental Research Branch, Chemical
141
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Development, Tennessee Valley Authority, p. 67,
Mar. 1971 (unpublished). The thermal decomposition
rate of MgS03 is of order 3/2 in MgSO3. This order
suggests that decomposition products interfere with
the thermal decomposition of MgS03. Extrapolation
to higher temperature shows that about 8 seconds is
required for 99.9% decomposition at 1000° C.
45. Hull, William Q., Baker, R. E., and Rogers, C. E.
Magnesia-Base Sulfite Pulping. Ind. Eng. Chem. 43,
2424-35 (1951). The history, process, development,
and economics of magnesia-base sulfite pulping are
discussed here. The process is one which fully utilizes
the energy content of the organic waste and recovers
the chemicals used in cooking; all products recovered
are reused in the pulping process.
46. JANAF Thermochemical Tables. Springfield, Va.
22151: National Technical Information Service. (PB
168-370) (1964) and (PB 168-370-1) (1966).
47. Johnstone, H. F. Progress in the Removal of Sulfur
Compounds From Waste Gases. Combustion 2, pp.
19-30 (1933). The possibility of economically
washing large quantities of gases with water is very
remote. The limits impos'ed by the solubility of SO2
from such dilute gases are those of the quantity of
water required, and time and surface of contact
needed. Bubble type scrubbing was found to require
the least time of contact and smallest volume of
scrubber space.
48. Johnstone, H. F. Metallic Ions as Catalysts for the
Removal of Sulfur Dioxide from Boiler Furnace
Gases. Ind. Eng. Chem. 23, pp. 559-61 (1931). Iron
and manganese ions catalyze the air oxidation of
sulfite. The presence of zinc, nickel, chromium, and
the alkali metals neither inhibits nor promotes the
catalysis by manganese ions.
49. Jonke, A. A., et al. Reduction of Atmospheric
Pollution by the Application of Fluidized-Bed Com-
bust! on. Argonne National Laboratory.
(ANL/ES-CEN-1001) (June 1969).
50. Jordan, J. E. (Tennessee Valley Authority, Muscle
Shoals, Alabama). Private communication.
51. Jordan, J. E. (Tennessee Valley Authority, Muscle
Shoals, Alabama). Private Communication.
52. Kellogg, H. H. Equilibria in the Systems C-O-S and
C-O-S-H as Related to Sulfur Recovery from Sulfur
Dioxide. Met. Trans. 2, 2161-69 (Aug. 1971). Equi-
libria phase diagrams showing gas composition as a
function of temperature, sulfur to oxygen atom ratio,
and carbon to oxygen atom ratio were calculated
from thermochemical data. In the ternary system,
production of sulfur vapor reaches a sharp maximum
at C/O = 0.50. With the quaternary system, sulfur
vapor is maximized in a gas having atom ratio (H +
C)/O = (1 + X)/(2 + X/2) where X is the atom ratio
H/C in the reducing agent.
53. M. W. Kellogg Co. Availability of Limestones and
Dolomites. Environmental Protection Agency, (Task
Report No. 1, No. CPA 70-68) (PB 206-963) (Feb. 1,
1972).
54. Ketov, A. N. and Pechkovskii, V. V. Study of the
Thermal Decomposition of Magnesium Sulfite. Russ.
J. Inorg. Chem. 4 (2), 18 (1959). The main sulfur
containing compound arising from the thermal
decomposition of MgSO3 above 400° C is sulfur
dioxide.
55. Kim, Y. K. (Tennessee Valley Authority, Muscle
Shoals, Alabama). Private communication.
56. Kurgaev, E. F. The Viscosity of Suspensions. Dokl.
Akad. Nauk. SSSR 13 (2), 392 (1960). A formula to
calculate the viscosity of slurries is derived from fluid
mechanics. The agreement with experimentally
derived results is quite good for slurries with up to
25% solids (volume/volume).
57. Kuzminykh, I. N. and Babushkina,M. D. Equilibrium
Between Sulfur Dioxide and Magnesium Bisulfite
Solutions. J. Appl. Chem. U.S.S.R. 30 (3), 495-98
(1957). The authors measured sulfur dioxide vapor
pressures over magnesium sulfite-bisulfite solutions
over the temperature range of 10 to 70° C.
58. Linek, V. and Mayrhoferova. The Kinetics of Oxida-
tion of Aqueous Sodium Sulfite Solution. Chem. Eng.
Sci 25, pp. 787-800 (1970). Kinetic data on sulfite
oxidation were taken from the absorption rate of
oxygen into mechanically agitated solutions. The
reaction, in the presence of cobalt catalyst, is first
order in oxygen above oxygen concentrations of
approximately 6 x 10"4 k mole/m3 at the interface
and second order for lower oxygen concentration.
The influence of sulfite purity on rate constants is
quite pronounced.
59. Link, W. F. Solubilities of Inorganic and Metal
Organic Compounds, Volume II. Washington, D.C.:
American Chemical Society p. 524 (1965). This book
is a compilation of solubility of numerous inorganic
compounds in water including MgSO3, MgS04, and
Mg(OH)2.
60. Lowell, P. S. A Theoretical Description of the
Limestone-Wet Scrubbing Process, Volume I. U.S.
Dept. of Commerce, National Bureau of Standards
(PB 193-029) (1970). A computer program to
calculate the partial pressure of S02 and CO2 over
aqueous solutions containing Ca++, Mg++, Na+, N03",
C02, S02, SO4=, and Cl' was written and checked
• against experimental data. Thermodynamic data for
the dissociation constants of CaS03 and MgSO3 and
the solubility product constants for CaS03-^H20
were determined experimentally.
142
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61. Lowicki, Norbert, Hanig, Gernot, and Husmann,
Klaus. The Grillo Exhaust Gas Sulfur Process.
Duisburg-Hambom, Duisburg, Germany: Grillo-Werke
AG to Labor and Social Minister, Nordrhein-
Westfalen and Firma Union Rheinische Braunkohlen-
Draftstoff, Wesseling. Report on the Development of
a Process for the Desulfurization of Flue-Gases. (Oct.
1969). The Grillo ACS process for the desulfurization
of flue-gases of oil-fired boiler installations and the
economics of it are described here. A particular
advantage of the Grillo process is that the loaded
material from different desulfurization installations
can be regenerated at central locations. The use of
manganese dioxide as an activator for the MgO-S02
scrubbing reaction is discussed; a spray absorber
device is recommended.
62. Manvelyan, M. G. et al. Effect of Inhibitors on
Oxidation of Magnesium Sulfite to Sulfate by Atmos-
pheric Oxygen in Presence of Traces of Nitrogen
Oxides. /. Appl. Chem. U.S.S.R. 34 (4), 896 (1961).
Phenol, p-aminophenol, hydroquinone, glycerol and
furfural are powerful inhibitors of the oxidation of
magnesium sulfite by atmospheric oxygen. Traces of
nitrogen oxides greatly diminish the retarding effect
of inhibitors.
63. Markant, H. P., Mcllroy, R. A., and Matty, R. E.
Absorption Studies, MgO-SO2 Systems. TAPPI 45,
pp. 849-54 (1962). This paper describes pilot plant
studies made to determine the equilibrium vapor
pressure of SO2 over various magnesium bisulfite
solutions. Sulfur dioxide mass transfer coefficients
were found to increase with gas mass flow rate.
64. Markant, H. P, Phillips, N. D, and Shah, I. S.
Physcial and Chemical Properties of Magnesia—Base
Pulping Solutions. TAPPI 48 (11), 648-53 (1965).
The specific gravity, viscosity, and surface tension of
MgS03 solutions and slurries are reported at various
temperatures. Magnesium sulfite solubility deter-
minations made between 45 and 77° C are in good
agreement with earlier work.
65. McCabe, W. L. and Stevens, R. P. Rate of Growth of
Crystals in Aqueous Solutions. Chem. Eng. Prog. 47
(4), 168-74 (1951). The growth rate of copper sulfate
pentahydrate is not affected directly by crystal size;
but, at low values of solution velocity, the growth
rate is markedly influenced by the solution velocity
past the crystal face. As the solution velocity
increases, the effect of velocity on growth rate
diminishes and finally becomes negligibly small.
66. Mellor, J. W. Magnesium Oxides and Hydroxides. A
Comprehensive Treatise on Inorganic and Theoretical
Chemistry, Vol. IV, London, Longmans, Green and
Co., Ltd., 280-96 (1929). Magnesium oxide is a
product of the oxidation of the metal. It is also
produced in the amorphous or crystalline form by the
calcination of many of the salts of magnesium. It is
made commercially for the manufacture of magnesia
bricks by the calcination of magnesite in various kinds
of kilns.
67. Okabe, T. and Hori, S. Thermal Decomposition of
Magnesium Sulfite and Magnesium Thiosulfate.
Tokoku University Technology Report 23 (2), 85-9
(1959). The thermal decomposition of magnesium
sulfite was studied by differential thermal analysis,
x-ray diffraction, and infrared spectrometry, and the
following results obtained. The dehydration of
crystalline water occurs through three phases, at 60,
100, and 200° C with oxidation occurring at 450° C
and dissociation at 560° C.
68. Peisakhov, I. L. and Chertkov, B. A. Purification of
Flue Gases from Sulfurous Anhydride. Khim. Prom.
17 (10), 6-14 (1940). In 1938 and 1939 experiments
were conducted on processes for purifying flue gases;
work was directed toward obtaining some product
that could be sold to partially compensate for the
cost of the purification. At an experimental plant
built at the Kashir power station of L..M. Kaganovich,
the magnesite and the acid-catalytic methods were
studied, reporting the disadvantages as well as the
advantages of both methods. Diagrams are given for
both methods.
69. Pinaev, V. A. Mutual Solubility of Magnesium Sulfite,
Bisulfite and Sulfate. J. Appl. Chem. U.S.S.R. 37(6),
1353-55 (1964). The mutual solubility of magnesium
sulfite-bisulfite-sulfate is reported at 40, 50, and 60°
C. The author unexpectedly finds that magnesium
sulfite solubility is increased by addition of
magnesium sulfate.
70. Pinaev, V. A. The Viscosity and Density of Mag-
nesium Sulfite-Bisulfite-Sulfate Solutions. /. Appl.
Chem. U.S.S.R. 36 (10), 2253-55 (1963). The vis-
cosity and density of magnesium sulfite-bisulfite-
sulfate solutions are reported between 30 and 60° C.
The magnesium sulfate concentration ranged between
50 and 125 g/1. The concentration ranges of MgS03
and Mg(HS03)3 were 2 to 12 g/1. and 4 to 32 g/1.,
respectively.
71. Pinaev, V. A. SO2 Pressure Over Magnesium Sulfite-
Bisulfite-Sulfate Solutions. /. Appl. Chem. U.S.S.R.
36 (10), 2049-53 (1963). A dynamic method was
used to determine the S02 partial pressure over
magnesium sulfite-bisulfite-sulfate solutions.
72. Pinaev, V. A. Stabilization of Magnesium Sulfite
Hexahydrate Crystals by Addition of p-phenylene-
diamine as Inhibitor. /. Appl. Chem. U.S.S.R. 57(4),
899-900 (1964). Crystals of magnesium sulfite hexa-
hydrate are easily and rapidly (2-3 days) oxidized by
aerial oxygen with the formation of 11-13% MgS04
143
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during intermediate storage. The rate of oxidation of
the magnesium sulfite crystals to sulfate is reduced
20-30 fold by the addition of 0.01-0.05 wt % of
p-phenylenediamine to the system.
73. Potts, J. M., Slack, A. V., and Hatfield, J. D. Removal
of Sulfur Dioxide From Stack Gases by Scrubbing
with Limestone Slurry: Small-Scale Studies at TV A.
New Orleans, Louisiana: Environmental Protection
Agency, Proc. Second Intern, Lime/Limestone Wet
Scrubbing Symposium. (APTD-1161) (Nov. 8-12,
1971). The authors report results from a small scale
SO2 scrubbing test program using limestone slurry.
74. Schmidt, A. and Weinrotter, F. Process for the
Removal of Lower Oxides of Nitrogen from Gaseous
Mixtures Containing Them. U.S. 3,034,853, May 15,
1962, Appl. Aug. 4, 1969, 5 pp. This patent describes
a process in which two-thirds of the lower oxides of
nitrogen contained in the waste gases emerging from
nitric acid producing plants can be recovered and put
to use as such. The process involves scrubbing N203
from an SO2-free gas stream with MgC03 or
Mg(OH)2, thermally decomposing the resulting
Mg(N02)2 to Mg(NO3)2, M2(OH)2, and NO, air-
oxidation of the NO to N02, and bleeding sufficient
N02 back into the gas stream to convert the NO in
the tail gas to N203. The Mg(N03)2 is converted to
Mg(OH)2 and NH4N03 with recycle of the Mg(OH)2.
75. Schmidt, Paul F. Fuel Oil Manual. New York, N.Y.:
Industrial Press, Inc. p. 263 (1969) (Third Edition).
Technical information concerning the properties and
characteristics of fuel oil, the general uses and
limitations of each grade, combustion requirements,
definition of impurities, and a general guideline for
selecting oil are presented. Specific information
defining the various grades of oil and relating API
gravity to chemical composition of a fuel oil is given.
76. Schroeter, L. C. Sulfur Dioxide, Applications in
Food, Beverages and Pharmaceuticals. London, Eng.:
Pergamon Press p. 44 (1966). This book covers almost
all phases of SO2 chemistry and technology. The
section on sulfite and SO2 oxidation is applicable to
S02 recovery from flue gas. In it are discussed
oxidation reaction mechanisms, metal ion catalysis,
and inhibition of sulfite oxidation by organic
compounds.
77. Selvig, W. A. and Gibson, F. H. Analysis of Ash From
United States Coals. Bureau of Mines, Bull. 567, p.
32. This Bureau of Mines bulletin presents ash
analysis for hundreds of coal samples from the United
States.
78. Semishin, V. I., Abramov, 1.1., and Vorotnitskaya, L.
T. Solubility of Magnesium Sulfite. Khim. i Khim.
Technol 2, pp. 834-35 (1959). The authors have
measured the density and pH of magnesium
sulfite-bisulfite solutions containing 0 and 10%
MgS04. The solubility of MgS03 in these solutions is
also reported.
79. Shah, I. S. (Chemical Construction Corporation).
Recovery of Sulfur Dioxide From Waste Gases. U.S.
3,577,219, May 4, 1971, Appl. Nov. 1968, 5 pp. A
process is provided to efficiently and economically
absorb and recover sulfur dioxide from a waste gas
such as the tail gas from a sulfuric acid plant or flue
gas from combustion of a sulfur containing fuel. The
waste gas is scrubbed with a recirculating aqueous
slurry containing magnesium oxide and magnesium
sulfite. A small quantity of magnesium sulfate may be
present from oxidation of sulfite or absorption of
sulfur trioxide.
80. Shah, I. S. (Chemical Construction Corp., New York,
New York) to A. V. Slack (TVA). Private
communication.
81. Sillen, L. G. and Andersson, T. Solid-Gas Equilibria of
Importance in Burning Concentrated Calcium or
Magnesium Sulfite Waste Liquor. Sv. Papperstidning
55, p. 622 (1952). The equilibria between gas and
ashes, when calcium or magnesium sulfite waste
liquor is burnt under various conditions, are discussed
with special emphasis on the recovery of sulfur. With
magnesium, one can obtain all sulfur in the gas phase
(as S02 or H2S) under a wide range of oxidizing and
reducing conditions. It is not possible to obtain MgS
by combustion.
82. Slack, A. V. (Tennessee Valley Authority, Muscle
Shoals, Alabama). Private communication to
Administrative Files on visit to Showa Denko on
January 6, 1970.
83. Slack, A. V., McGlamery, G. G., and Falkenberry, H.
L. Economic Factors in Recovery of Sulfuric Dioxide
From Power Plant Stack Gas./. Air Pollution Control
Assoc. 21 (1), 9-15 (Jan. 1971). Discussion is pre-
sented on key economic and operating factors for
chemical processes recovering SO2 from power plant
stack gas. Capacity factors and unit life of coal-
burning power units are given, plus definitions of
sulfur content of fuel, plant sizes, products, methods
of financing, and profitability requirements. A basic
alternative of one recovery process is also described.
84. Slack, A. V. Sulfur Dioxide Removal from Waste
Gases. Park Ridge, New Jersey: Noyes Data Corpora-
tion, Pollution Control Review No. 4 (1971). This
book is the fourth in a series dealing with environ-
mental contamination problems. Included are dis-
cussions of the sources of sulfur dioxide and
particulate emission from various types of plants and
methods for their control. Both throwaway and
recovery processes are discussed. Economics of the
144
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throwaway processes, and factors which affect the
economics of recovery processes, are presented.
85. Smithson, G. L. and Bakhshi, N. N. The Kinetics and
Mechanism of Hydration of Magnesium Oxide in a
Batch Reactor. Can. J. Chem. Eng. 47, pp. 508-13
(1969). The rate of reaction of MgO with water was
found to be directly proportional to the surface area
contained in a shell at the surface of the MgO
particles.
86. Svenson, 0. W. Su If uric Acid Supply and Demand in
the United States. Sulfur No. 100 (May-June 1972).
The report, describing current supply and demand
features of the sulfuric acid market, considers many
of the problems to be faced in the near future in
selling byproduct sulfuric acid.
87. Tennessee Valley Authority. Sulfur Oxide Removal
From Power Plant Stack Gas-Ammonia Scrubbing:
Production of Ammonium Sulfate and Use as Inter-
mediate in Phosphate Fertilizer Manufacture. Spring-
field, Virginia 22151: National Technical Information
Service. (PB 196-804) (1970). This report is a
conceptual design and cost study on the use of
ammonia in aqueous solutions to recover S02 from
power plant stack gas using the intermediate,
ammonium sulfate, in fertilizer manufacture.
Flowsheets, design assumptions, equipment
selections, and economic evaluation techniques for
salable products are presented. Financing under
regulated and nonregulated bases are discussed in
detail.
88. Tennessee Valley Authority. Sulfur Oxide Removal
From Power Plant Stack Gas: Sorption by Limestone
or Li me-Dry Process. Springfield, Virginia 22151:
National Technical Information Service. (PB 178-972)
(1968). Injection of dry limestone or lime into the
boiler is considered the simplest and least costly
process for removing S02 from power plant stack
gases. Product is calcium sulfate which is discarded.
The process can be operated intermittently. A
detailed economic evaluation is presented.
89. Tennessee Valley Authority. Sulfur Oxide Removal
From Power Plant Stack Gas: Use of Limestone in
Wet-Scrubbing Process. Springfield, Virginia 22151:
National Technical Information Service. (PB 183-908)
(1969). Use of limestone or lime in a wet scrubber is
one of the more promising methods of recovery of
SO 2, and has the advantage of simultaneous removal
of fly ash. The lime can be injected into the boiler
and caught in a wet scrubber after the air heater; this
method removes some S02 ahead of the scrubber,
provides some protection from corrosion, and con-
verts the lime into a more reactive form. Another
method is to introduce the lime into the scrubber
system; this eliminates many boiler and equipment
operating problems. Plume cooling and water
pollution problems are discussed. Economics are
reported.
90. Tennessee Valley Authority. Fertilizer Summary
Data-1970. Muscle Shoals, Alabama: National
Fertilizer Development Center. 126 pp. A summary
of pertinent fertilizer consumption statistics for the
United States is given.
91. Thorpe's 27, Dictionary of Applied Chemistry.Mag-
nesium Sulfate. Longmans, Green and Co-, pp. 453-54,
(1946) (Fourth Edition) (Vol. VII). The magnesium
sulfate of commerce is largely obtained from the
mineral kieserite found in the Stassfurt, Germany,
salt beds. Its medicinal value was discovered in the
reign of Good Queen Bess (1558-1603). The com-
mercial salt usually occurs in a powdery form con-
sisting of minute needles obtained by rapid crystalliza-
tion from a concentrated solution. Magnesium sulfate
forms a large number of hydrates and, in addition,
forms an isomorphous series of double salts with the
sulfates of the alkali metals.
92. Tomlinson, G. H. Waste Sulfite Liquor Recovery. U.S.
2,285,876, June 9, 1942, Appl. Jan. 26, 1938, 12 pp.
This invention provides a simple and economically
feasible cyclic process of manufacturing sulfite pulp
from cellulosic fibrous material and more particularly
a process which is characterized by the efficient
recovery of the heat values and recovery and regenera-
tion of the inorganic chemical constituents of the
residual pulp liquor for reuse in the process. A further
and more specific provision is that of an improved
process of treating the residual liquor resulting from
the digestion of cellulosic fibrous material in a pure
magnesium base sulfite cooking liquor to recover the
heat and chemical values therein.
93. U.S. Department of Commerce. Inorganic Fertilizer
Materials and Related Acids, January 1973. Current
Industrial Reports, Bureau of Census, Series:
M28B(73)-2 (Mar. 1973). A month-by-month
summary of sulfuric acid production compiled by the
U.S. Government is given in this report.
94. United States Department of Interior. Cost Estimates
of Liquid Scrubbing Processes for Removing Sulfur
Dioxide From Flue Gases. Bureau of Mines Report of
Investigations No. 5469. p. 51, (1959). Estimated
capital and operating costs are reported for removing
S02 from flue gases of a power plant of 120-mw
capacity by liquid purification processes, using lime-
stone, ammonia, or sodium sulfite as the reactant.
95. Whitney, R. P, Elias, R. M., and May, M. N. Chemical
Reaction Equilibria in Calcium and Magnesium Base
Sulfite Recovery Systems. TAPPI 34 (9), p. 396400,
(1951). This paper presents the results of calculations
of chemical reaction equilibria for many of the
145
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important reactions which may be involved in the
combustion of calcium base and magnesium
base spent sulfite liquors. They show the con-
ditions under which the oxide, sulfide, and sulfate
of magnesium and calcium might be expected to
predominate.
96. Winchell, A. N. and Winchell, H. The Microscopical
Characters of Artificial Inorganic Solid Substances-
Optical Properties of Artificial Minerals. New York,
N.Y.. Academic Press, pp. 57, 68, 133, 162, 166,
(1964). This book is a compilation of the optical
properties of numerous inorganic compounds.
97. Winston, Arthur W. and Kenaga, Ivan A. Method of
Making Magnesium Sulfate. U.S. 1,865,224, June 28,
1932, Appl. Mar. 5, 1929. 5 pp. This patent applica-
tion describes the process for making magnesium
sulfate by air oxidation of sulfite. A magnesium
sulfite-bisulfite liquor is prepared by absorbing S02 in
an aqueous suspension of Mg(OH)2, adjusting the
composition of the resulting liquor so that the normal
sulfite constitutes from 40 to 50% of the total sulfite
present, and then oxidizing the sulfite-bisulfite
mixture to sulfate by blowing with air. The oxidation
step is carried out in the presence of a catalyst.
98. Winton, John M. Dark Cloud on Sulfur's Horizon.
Chem. Week 108 (6), 25, (Feb. 10, 1971). This report
is an appraisal of the production, consumption, and
growth of elemental sulfur industry including the
effect of expected pollution control laws and sour gas
processing on supply. Recovered sulfur now accounts
for more than 50% of western world production and
is expected to grow rapidly. Oversupply is expected
to persist for years.
99. Wright, James P. Reduction of Stack Gas SO2 to
Elemental Sulfur. Sulfur No. 100, pp. 72-75, (1972).
This report describes a process, developed by Allied
Chemical, to convert sulfur dioxide to elementary
sulfur. The entire process consists of three stages: gas
purification, SO2 reduction, and sulfur recovery.
100. Yakimets, E. M. and Arkhipova, M. S. Partial
Pressures of Sulfur Dioxide and Water Over the
Solutions of Magnesium Sulfite and Bisulfite. Urals
Sci. Res. Chem. Inst. 1, pp. 112-18 (1954). The
authors determined the vapor pressure of S02 over
MgS03 slurry between 5 and 75° C.
146
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APPENDIX A
Cost Tables
147
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Table A-1. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(200-mw new coal-fired power unit, 3.5% S in fu el;
6.5
Land, site clearance, excavation, landscaping, roads, railways, walkways
Particulate scrubbers (2 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities)
Sulfur dioxide scrubbers (2 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans)
Optional bypass duct around scrubbers
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors)
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper)
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors)
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps)
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04)
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps)
Control room building, including motor controls, laboratory, and lockers
Service facilities and buildings allocation for maintenance, shops, and offices
Subtotal direct investment
Engineering design and supervision
Construction expense
Contractor fees
Contingency
Subtotal fixed capital investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total fixed capital investment
Investment, $
200,000
1,445,000
1,602,000
209,000
416,000
470,000
635,000
140,000
1,495,000
108,000
94,000
150,000
410,000
7,374,000
664,000
811,000
442,000
959.000
10,250,000
1 ,025,000
410.000
1 1,685,000
aBasis: o
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
148
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Table A-2. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(200-mw existing coal-fired power unit, 3.5% S in fuel;
6.7 tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 260,000
Particulate scrubbers (2 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 1,763,000
Sulfur dioxide scrubbers (2 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 1,823,000
Optional bypass duct around scrubbers —
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 432,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 486,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 656,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 145,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,552,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2 S04 ) 112,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 130,000
Control room building, including motor controls, laboratory, and lockers 170,000
Service facilities and buildings allocation for maintenance, shops, and offices 440,000
Subtotal direct investment 7,969,000
Engineering design and supervision 797,000
Construction expense 1,036,000
Contractor fees 638,000
Contingency 1,036,000
Subtotal fixed capital investment 11,476,000
Allowance for startup and modifications 1,148,000
Interest during construction (8%/annum rate) 459,000
Total fixed capital investment 13,083,000
aBasis:
Stack gas reheat to 175UF. by direct oil-fired reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
149
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Table A-3. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new coal-fired power unit, 2.0% S in fuel;
9.0 tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 250,000
Particulate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 3,194,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,505,000
Optional bypass duct around scrubbers 454,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 534,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 575,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 777,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 180,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,918,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2 S04) 138,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 121,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 640,000
Subtotal direct investment 12,486,000
Engineering design and supervision 874,000
Construction expense 1,124,000
Contractor fees 499,000
Contingency 1,498,000
Subtotal fixed capital investment 16,481,000
Allowance for startup and modifications 1,648,000
Interest during construction (8%/annum rate) 659,000
Total fixed capital investment 18,788,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
150
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Table A-4. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new coal-fired power unit, 3.5% S in fuel;
15.8 tons/hrH2SOj
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 270,000
Participate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 3,194,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,528,000
Optional bypass duct around scrubbers 454,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 785,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 810,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,094,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 264,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,821,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 203,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 178,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 640,000
Subtotal direct investment 14,441,000
Engineering design and supervision 1,011,000
Construction expense 1,300,000
Contractor fees 578,000
Contingency 1,733,000
Subtotal fixed capital investment 19,063,000
Allowance for startup and modifications 1,906,000
Interest during construction (8%/annum rate) 763,000
Total fixed capital investment 21,732,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
151
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Table A-5. Summary of Estimated Fixed Investment:2
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new coal-fired power unit, 5.0% S in fuel;
22.5 tons/hrH-2 S04 )
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 290,000
Particulate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 3,194,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,551,000
Optional bypass duct around scrubbers 454,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 1,005,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 1,004,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,357,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 338,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 3,611,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 260,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 228,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 640,000
Subtotal direct investment 16,132,000
Engineering design and supervision 1,129,000
Construction expense 1,452,000
Contractor fees 645,000
Contingency 1,936,000
Subtotal fixed capital investment 21,294,000
Allowance for startup and modifications 2,129,000
Interest during construction (8%/annum rate) 852,000
Total fixed capital investment 24,275,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location—1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
152
-------
Table A-6. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw existing coal-fired power unit, 3.5% S in fuel;
16.1
Land, site clearance, excavation, landscaping, roads, railways, walkways
Participate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities)
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans)
Optional bypass duct around scrubbers
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors)
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper)
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors)
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps)
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04)
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps)
Control room building, including motor controls, laboratory, and lockers
Service facilities and buildings allocation for maintenance, shops, and offices
Subtotal direct investment
Engineering design and supervision
Construction expense
Contractor fees
Contingency
Subtotal fixed capital investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total fixed capital investment _
Investment, $
350,000
3,919,000
4,056,000
—
801 ,000
818,000
1,105,000
269,000
2,877,000
207,000
242,000
230,000
680,000
15,554,000
1,244,000
1,866,000
933,000
2,022,000
21,619,000
2,162,000
865,000
24,646,000
aBasis:
Stack gas reheat to 175 °F. by direct oil-fired reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
153
-------
Table A-7. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(1000-mw new coal-fired power unit, 3.5% S in fuel;
30.5 tons/hr HI SO4 )
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 400,000
Participate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 5,055,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 5,698,000
Optional bypass duct around scrubbers 631,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 1,248,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 1,207,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,630,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 420,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 4,485,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 323,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 283,000
Control room building, including motor controls, laboratory, and lockers 250,000
Service facilities and buildings allocation for maintenance, shops, and offices 890,000
Subtotal direct investment 22,520,000
Engineering design and supervision 1,351,000
Construction expense 1,802,000
Contractor fees 901,000
Contingency 2,477,000
Subtotal fixed capital investment 29,051,000
Allowance for startup and modifications 2,905,000
Interest during construction (8%/annum rate) 1,162,000
Total fixed capital investment 33,118,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
154
-------
Table A-8. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(1000-mw existing coal-fired power unit, 3.5% S in fuel:
3L6tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 500,000
Paniculate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 6,114,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 6,432,000
Optional bypass duct around scrubbers -
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 1,272,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 1,231,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,663,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 428,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 4,570,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 329,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 383,000
Control room building, including motor controls, laboratory, and lockers 290,000
Service facilities and buildings allocation for maintenance, shops, and offices 950,000
Subtotal direct investment 24,162,000
Engineering design and supervision 1,691,000
Construction expense 2,175,000
Contractor fees 1,208,000
Contingency 2,899,000
Subtotal fixed capital investment 32,135,000
Allowance for startup and modifications 3,214,000
Interest during construction (8%/annum rate) 1,285,000
Total fixed capital investment 36,634,000
aBasis:
Stack gas reheat to 175°F. by direct oil-fired reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
155
-------
Table A-9. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(200-mw new oil-fired power unit, 2.5% S in fuel;
3.4 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 130,000
Sulfur dioxide scrubbers (2 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 1,517,000
Optional bypass duct around scrubbers 103,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 243,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS04 storage hopper) 300,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 405,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 82,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 875,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 63,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 84,000
Control room building, including motor controls, laboratory, and lockers 150,000
Service facilities and buildings allocation for maintenance, shops, and offices 270,000
Subtotal direct investment 4,222,000
Engineering design and supervision 380,000
Construction expense 464,000
Contractor fees 253,000
Contingency 549,000
Subtotal fixed capital investment 5,868,000
Allowance for startup and modifications 587,000
Interest during construction (8%/annum rate) 235.000
Total fixed capital investment 6,690,000
aBasis:
Stack gas reheat to 175°F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
156
-------
Table A-10. Summary of Estimated Fixed Investment:2
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new oil-fired power unit, 1.0% S in fuel;
3.4 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 200,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,428,000
Optional bypass duct around scrubbers 228,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 243,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 292,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 394,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 82,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 875,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04 ) 63,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 116,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 450,000
Subtotal direct investment 6,571,000
Engineering design and supervision 460,000
Construction expense 591,000
Contractor fees 263,000
Contingency 789,000
Subtotal fixed capital investment 8,674,000
Allowance for startup and modifications 867,000
Interest during construction (8%/annum rate) 347,000
Total fixed capital investment 9,888,000
aBasis:
Stack gas reheat to 175 F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
157
-------
Table A-11. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new oil-fired power unit, 2.5% S in fuel;
8.4tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 220,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,450,000
Optional bypass duct around scrubbers 228,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 455,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 510,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 689,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 153,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,636,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 118,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 157,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 450,000
Subtotal direct investment 8,266,000
Engineering design and supervision 579,000
Construction expense 744,000
Contractor fees 331,000
Contingency 992,000
Subtotal fixed capital investment 10,912,000
Allowance for startup and modifications 1,091,000
Interest during construction (8%/annum rate) 436,000
Total fixed capital investment 12,439,000
aBasis:
Stack gas reheat to IVS^F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
158
-------
Table A-12. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw new oil-fired power unit, 4.0% S in fuel;
13.5 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 240,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,473,000
Optional bypass duct around scrubbers 228,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 636,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 680,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 919,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 214,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,285,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 164,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 192,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 450,000
Subtotal direct investment 9,681,000
Engineering design and supervision 678,000
Construction expense 871,000
Contractor fees 387,000
Contingency 1,162,000
Subtotal fixed capital investment 12,779,000
Allowance for startup and modifications 1,278,000
Interest during construction (8%/annum rate) 511,000
Total fixed capital investment 14,568,000
aBasis:
Stack gas reheat to 175° F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
159
-------
Table A-13. Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(500-mw existing oil-fired power unit, 2.5% S in fuel;
8.6tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 250,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 4,036,000
Optional bypass duct around scrubbers —
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 463,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgSO3 storage hopper) 518,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 700,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 156,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,664,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2 S04) 120,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 158,000
Control Rroom building, including motor controls, laboratory, and lockers 230,000
Service facilities and buildings allocation for maintenance, shops, and offices 490,000
Subtotal direct investment 8,785,000
Engineering design and supervision 703,000
Construction expense 1,054,000
Contractor fees 527,000
Contingency 1,142,000
Subtotal fixed capital investment 12,211,000
Allowance for startup and modifications 1,221,000
Interest during construction (8%/annum rate) 488,000
Total fixed capital investment 13,920,000
aBasis:
Stack gas reheat to 175°F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
160
-------
Table A-14.Summary of Estimated Fixed Investment:3
Scheme A—Magnesia Slurry Scrubbing-Regeneration Process
(1000-mw new oil-fired power unit, 2.5% S in fuel;
16.3 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 360,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 5,369,000
Optional bypass duct around scrubbers 317,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 730,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 761,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,028,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 246,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,624,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 189,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 249,000
Control room building, including motor controls, laboratory, and lockers 250,000
Service facilities and buildings allocation for maintenance, shops, and offices 720,000
Subtotal direct investment 12,843,000
Engineering design and supervision 771,000
Construction expense 1,027,000
Contractor fees 514,000
Contingency 1,413,000
Subtotal fixed capital investment 16,568,000
Allowance for startup and modifications 1,657,000
Interest during construction (8%/annum rate) 663,000
Total fixed capital investment 18,888,000
aBasis:
Stack gas reheat to 175° F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
161
-------
Table A-15. Summary of Estimated Fixed Investment:3
Scheme B— MgQ-IVInQ2 Slurry Scrubbing-Regeneration Process
(200-mw new coal-fired power unit, 3.5% S in fuel;
6.5 tons/hrH2SOt)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 200,000
Particulate scrubbers (2 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 1,445,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 1,481,000
Optional bypass duct around scrubbers 209,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 393,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03-MgS04 storage hopper) 497,000
Calcining (fluid bed calcining system, fans, MgO-Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 751,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 273,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,547,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 108,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 102,000
Control room building, including motor controls, laboratory, and lockers 150,000
Service facilities and buildings allocation for maintenance, shops, and offices 410,000
Subtotal direct investment 7,566,000
Engineering design and supervision 681,000
Construction expense 832,000
Contractor fees 454,000
Contingency 984,000
Subtotal fixed capital investment 10,517,000
Allowance for startup and modifications 1,052,000
Interest during construction (8%/annum rate) 421,000
Total fixed capital investment 11,990,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
162
-------
Table A-16. Summary of Estimated Fixed Investment:3
Scheme B—MgO-IVlnO2 Slurry Scrubbing-Regeneration Process
(500-mw new coal-fired power unit, 3.5% S in fuel;
15.8 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 270,000
Participate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 3,194,000
Sulfur dioxide scrubbers (8 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,299,000
Optional bypass duct around scrubbers 454,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 741,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03-IVlgS04 storage hopper) 857,000
Calcining (fluid bed calcining system, fans, MgO-Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,295,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 515,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,918,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 203,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 192,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 640,000
Subtotal direct investment 14,778,000
Engineering design and supervision 1,034,000
Construction expense 1,330,000
Contractor fees 591,000
Contingency 1.773.000
Subtotal fixed capital investment 19,506,000
Allowance for startup and modifications 1,951,000
Interest during construction (8%/annum rate) 780,000
Total fixed capital investment 22,237,000
aBasis:
Stack gas reheat to 175° F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
163
-------
Table A-17. Summary of Estimated Fixed Investment:2
Scheme B—IVIgO-MnO2 Slurry Scrubbing-Regeneration Process
(1000-mw new coal-fired power unit, 3.5% S in fuel;
30.5 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 400,000
Particulate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 5,055,000
Sulfur dioxide scrubbers (8 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 5,313,000
Optional bypass duct around scrubbers 631,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 1,178,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03-MgS04 storage hopper) 1,277,000
Calcining (fluid bed calcining system, fans, MgO-Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,930,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 819,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 4,639,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 323,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 305,000
Control room building, including motor controls, laboratory, and lockers 250,000
Service facilities and buildings allocation for maintenance, shops, and offices 890,000
Subtotal direct investment 23,010,000
Engineering design and supervision 1,381,000
Construction expense 1,841,000
Contractor fees 920,000
Contingency 2,531,000
Subtotal fixed capital investment 29,683,000
Allowance for startup and modifications 2,968,000
Interest during construction (8%/annum rate) 1,187,000
Total fixed capital investment ^ 33,838,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
64
-------
Table A-18. Summary of Estimated Fixed Investment:3
Scheme B—IVIgO-MnO2 Slurry Scrubbing-Regeneration Process
(200-mw new oil-fired power unit, 2.5% S in fuel;
3.4tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 130,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 1,398,000
Optional bypass duct around scrubbers 103,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 230,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 -MgS04 storage hopper) 317,000
Calcining (fluid bed calcining system, fans, MgO and Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 479,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 160,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 905,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 63,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 90,000
Control room building, including motor controls, laboratory, and lockers 150,000
Service facilities and buildings allocation for maintenance, shops, and offices 270,000
Subtotal direct investment 4,295,000
Engineering design and supervision 387,000
Construction expense 472,000
Contractor fees 258,000
Contingency 558,000
Subtotal fixed capital investment 5,970,000
Allowance for startup and modifications 597,000
Interest during construction (8%/annum rate) 239,000
Total fixed capital investment 6,806,000
aBasis:
Stack gas reheat to 175 F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared.
165
-------
Table A-19. Summary of Estimated Fixed Investment:3
Scheme B—MgO-MnO2 Slurry Scrubbing-Regeneration Process
(500-mw new oil-fired power unit, 2.5% S in fuel;
8.4 tons/hrH^SO^)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 220,000
Sulfur dioxide scrubbers (8 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,185,000
Optional bypass duct around scrubbers 228,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 430,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03-MgS04 storage hopper) 540,000
Calcining (fluid bed calcining system, fans, MgO-Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 816,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 299,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,692,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 118,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 169,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 450,000
Subtotal direct investment 8,347,000
Engineering design and supervision 584,000
Construction expense 751,000
Contractor fees 334,000
Contingency 1,002,000
Subtotal fixed capital investment 11,018,000
Allowance for startup and modifications 1,102,000
Interest during construction (8%/annum rate) 441,000
Total fixed capital investment 12,561,000
aBasis:
Stack gas reheat to 175° F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared.
166
-------
Table A-20. Summary of Estimated Fixed Investment:3
Scheme B—iyigO-iyinO2 Slurry Scrubbing-Regeneration Process
dOOO-mw new oil-fired power unit, 2.5% S in fuel'
16.3 tons/hrH2S04)
Investment, 3
Land, site clearance, excavation, landscaping, roads, railways, walkways 360,000
Sulfur dioxide scrubbers (8 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 4,996,000
Optional bypass duct around scrubbers 317,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 689,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgSCvMgSC^ storage hopper) 806,000
Calcining (fluid bed calcining system, fans, MgO-Mn02 and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,217,000
Magnesium oxide-manganese oxide slurrying (MgO and Mn02 unloading and storage
facilities, feeders, conveyors, elevators, slurry tank, agitator, and pumps) 479,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,714,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 189,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 269,000
Control room building, including motor controls, laboratory, and lockers 250,000
Service facilities and buildings allocation for maintenance, shops, and offices 720,000
Subtotal direct investment 13,006,000
Engineering design and supervision 780,000
Construction expense 1,040,000
Contractor fees 520,000
Contingency 1,431,000
Subtotal fixed capital investment 16,777,000
Allowance for startup and modifications 1,678,000
Interest during construction (8%/annum rate) 671,000
Total fixed capital investment 19,126,000
aBasis:
Stack gas reheat to 175 F. by direct oil-fired reheat.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared.
167
-------
Table A-21. Summary of Estimated Fixed Investment:3
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration Process
(200-mw-new coal-fired power unit, 3.5% S in fuel;
5.5 tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 200,000
Particulate and sulfur dioxide scrubbers (2 scrubbers with surge tanks, agitators,
pumps, mist eliminators, flue gas reheaters, and fans) 1,940,000
Optional bypass duct around scrubbers 138,000
Solution-slurry processing (thickner, filters, tanks, pumps, agitators and heating
coils, purification facilities, centrifuges, and conveyors) 784,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 429,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 569,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 133,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,348,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 78,000
Fuel loil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 83,000
Control room building, including motor controls, laboratory, and lockers 150,000
Service facilities and buildings allocation for maintenance, shops, and offices 410,000
Subtotal direct investment 6,262,000
Engineering design and supervision 564,000
Construction expense 689,000
Contractor fees 376,000
Contingency 814,000
Subtotal fixed capital investment 8,705,000
Allowance for startup and modifications 870,000
Interest during construction (8%/annum rate) 348,000
Total fixed capital investment 9,923,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
168
-------
Table A-22. Summary of Estimated Fixed Investment:3
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration Process
(500-mw new coal-fired power unit, 3.5% S in fuel;
13.5 tons/hr HI SO4 )
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 270,000
Particulate and sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators,
pumps, mist eliminators, flue gas reheaters, and fans) 4,327,000
Optional bypass duct around scrubbers 300,000
Solution-slurry processing (thickner, filters, tanks, pumps, agitators, and heating
coils, purification facilities, centrifuges, and conveyors) 1,479,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 740,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 981,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 251,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,544,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 147,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 157,000
Control room building, including motor controls, laboratory, and lockers 200,000
Service facilities and buildings allocation for maintenance, shops, and offices 640,000
Subtotal direct investment 12,036,000
Engineering design and supervision 843,000
Construction expense 1,083,000
Contractor fees 481,000
Contingency 1,444,000
Subtotal fixed capital investment 15,887,000
Allowance for startup and modifications 1,589,000
Interest during construction (8%/annum rate) 635,000
Total fixed capital investment 18,111,000
aBasis:
Stack gas reheat to 175°F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
169
-------
Table A-23. Summary of Estimated Fixed Investment:3
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration Process
(1000-mw new coal-fired power unit, 3.5% S in fuel;
26.1 tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 400,000
Participate and sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators,
pumps, mist eliminators, flue gas reheaters, and fans) 6,925,000
Optional bypass duct around scrubbers 417,000
Solution-slurry processing (thickner, filters, tanks, pumps, agitators, and
heating coils, purification facilities, centrifuges, and conveyors) 2,352,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper) 1,103,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors) 1,462,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 399,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 4,045,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04 ) 234,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 250,000
Control room building, including motor controls, laboratory, and lockers 250,000
Service facilities and buildings allocation for maintenance, shops, and offices 890,000
Subtotal direct investment 18,727,000
Engineering design and supervision 1,124,000
Construction expense 1,498,000
Contractor fees 749,000
Contingency 2,060,000
Subtotal fixed capital investment 24,158,000
Allowance for startup and modifications 2,416,000
Interest during construction (8%/annum rate) 966,000
Total fixed capital investment 27,540,000
aBasis:
Stack gas reheat to 175 F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location —1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
170
-------
Table A-24. Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Slurry Scrubbing-Drying Unit
Central Processing Concept
(200-mw new coal-fired power unit, 3.5% S in fuel:
7.8tonslhrMgS03)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 130,000
Particulate scrubbers (2 scrubbers with surge tanks, agitators, pumps,
and fly ash neutralization and disposal facilities) 1,445,000
Sulfur dioxide scrubbers (2 scrubbers with surge tanks, agitators,
pumps, mist eliminators, flue gas reheaters, and fans) 1,570,000
Optional bypass duct around scrubbers 205,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 408,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper, and loading system) 478,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 165,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 55,000
Control room building, including motor controls, laboratory, and lockers 105,000
Service facilities and buildings allocation for maintenance, shops, and offices 28,000
Subtotal direct investment 4,841,000
Engineering design and supervision 436,000
Construction expense 533,000
Contractor fees 290,000
Contingency 629,000
Subtotal fixed capital investment 6,729,000
Allowance for startup and modifications 673,000
Interest during construction (8%/annum rate) 269,000
Total fixed capital investment 7,671,000
aBasis:
Stack gas reheat to 175" F. by indirect steam reheat.
Direct disposal of neutralized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
171
-------
Table A-25. Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Regeneration-Sulfuric Acid Unit
Central Processing Concept
(Equivalent to 200-mw new coal-fired power unit, 3.5% S in fuel;
5.7tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 270,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors,
loading and unloading equipment) 649,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 1,360,000
Tail gas scrubbing (scrubber, tanks, pumps, dryer, conveyor) 184,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2 S04) 98,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 55,000
Control room building, including motor controls, laboratory, and lockers 100,000
Service facilities and buildings allocation for maintenance, shops and offices 450,000
Subtotal direct investment 3,166,000
Engineering design and supervision 285,000
Construction expense 348,000
Contractor fees 190,000
Contingency 412,000
Subtotal fixed capital investment 4,401,000
Allowance for startup and modifications 440,000
Interest during construction (8%/annum rate) 176,000
Total fixed capital investment 5,017,000
aBasis:
Tail gas recovery of 90% SO2 and SO3
Midwest plant location—1972 costs.
In process storage of 72 hours.
from acid absorber, reheat to 175° F.
172
-------
Table A-26. Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Slurry Scrubbing-Drying Unit
Central Processing Concept
(500-mw new coal-fired power unit, 3.5% S in fuel;
19.1 tons/hrMgS03)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 180,000
Particulate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 3,194,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 3,457,000
Optional bypass duct around scrubbers 445,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 769,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, and MgS03 storage hopper, and loading system) 824,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 311,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 104,000
Control room building, including motor controls, laboratory, and lockers 140,000
Service facilities and buildings allocation for maintenance, shops, and offices 440,000
Subtotal direct investment 9,864,000
Engineering design and supervision 690,000
Construction expense 888,000
Contractor fees 395,000
Contingency 1,184,000
Subtotal fixed capital investment 13,021,000
Allowance for startup and modifications 1,302,000
Interest during construction (8%/annum rate) 521,000
Total fixed capital investment 14,844,000
aBasis:
Stack gas reheat to 175°F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location-1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
173
-------
Table A-27. Summary of Estimated Fixed Investment:*
Scheme D—Magnesia Regeneration-Sulfuric Acid Unit
Central Processing Concept
(Equivalent to 500-mw new coal-fired power unit, 3.5% S in fuel;
13.8 tons/hrH2S04)
I nvestment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 370,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors,
loading and unloading equipment) 1,118,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 2,567,000
Tail gas scrubbing (scrubber, tanks, pumps, dryer, conveyor) 339,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 185,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 103,000
Control room building, including motor controls, laboratory, and lockers 130,000
Service facilities and buildings allocation for maintenance, shops, and offices 700,000
Subtotal direct investment 5,512,000
Engineering design and supervision 386,000
Construction expense 496,000
Contractor fees 220,000
Contingency 661,000
Subtotal fixed capital investment 7,275,000
Allowance for startup and modifications 728,000
Interest during construction (8%/annum rate) 291,000
Total fixed capital investment 8,294,000
aBasis:
Tail gas recovery of 90% SOj and 863 from acid absorber, reheat to 175 F.
Midwest plant location-1972 costs.
In process storage of 72 hours.
174
-------
Table A-28. Summary of Estimated Fixed lnvestment:a
Scheme D—Magnesia Slurry Scrubbing-Drying Unit
Central Processing Concept
(1000-mw new coal-fired power unit, 3.5% S in fuel;
36.9 tons/hrMgS03)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 270,000
Participate scrubbers (4 scrubbers with surge tanks, agitators, pumps, and fly
ash neutralization and disposal facilities) 5,055,000
Sulfur dioxide scrubbers (4 scrubbers with surge tanks, agitators, pumps,
mist eliminators, flue gas reheaters, and fans) 5,584,000
Optional bypass duct around scrubbers 618,000
Slurry processing (screens, tanks, pumps, agitators and heating coils,
purification facilities, centrifuges, and conveyors) 1,223,000
Drying (fluid bed drying system, fans, combustion chamber, dust collectors,
conveyors, MgS03 storage hopper, and loading system) 1,228,000
Magnesium oxide slurrying (MgO unloading and storage facilities, feeders,
conveyors, elevators, slurry tank, agitator, and pumps) 494,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 165,000
Control room building, including motor controls, laboratory, and lockers 170,000
Service facilities and buildings allocation for maintenance, shops, and offices 610,000
Subtotal direct investment 15,417,000
Engineering design and supervision 925,000
Construction expense 1,233,000
Contractor fees 617,000
Contingency 1,696,000
Subtotal fixed capital investment 19,888,000
Allowance for startup and modifications 1,989,000
Interest during construction (8%/annum rate) 796,000
Total fixed capital investment 22,673,000
aBasis:
Stack gas reheat to 175° F. by indirect steam reheat.
Direct disposal of neutalized ash slurry (15% solids) with recycle of water to fly ash scrubber.
Disposal pond distance of 1 mile.
Midwest plant location—1972 costs.
Minimum in process storage; only pumps are spared; ash pond not included.
175
-------
Table A-29. Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Regeneration-Sulfuric Acid Unit
Central Processing Concept
(Equivalent to 1000-mw new coal-fired power unit, 3.5% S in fuel;
26.7tons/hrH2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 540,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors,
loading and unloading equipment) 1,666,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 4,082,000
Tail gas scrubbing (scrubber, tanks, pumps, dryer, conveyor) 525,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 294,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 164,000
Control room building, including motor controls, laboratory, and lockers 160,000
Service facilities and buildings allocation for maintenance, shops, and offices 970,000
Subtotal direct investment 8,401,000
Engineering design and supervision 504,000
Construction expense 672,000
Contractor fees 336,000
Contingency 924,000
Subtotal fixed capital investment 10,837,000
Allowance for startup and modifications 1,084,000
Interest during construction (8%/annum rate) 433,000
Total fixed capital investment 12,354,000
aBasis:
Tail gas recovery of 90% SO2 and SOs from acid absorber, reheat to 175 F.
Midwest plant location—1972 costs.
In process storage of 72 hours.
176
-------
Table A-30, Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Regeneration-Sulfuric Acid Unit
Central Processing Concept
(Equivalent to 2000-mw new coal-fired power unit, 3.5% S in fuel:
53.3 tons/hr H2S04)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 820,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors,
loading and unloading equipment) 2,525,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 6,631,000
Tail gas scrubbing (scrubber, tanks, pumps, dryer, conveyor) 853,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2S04) 478,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 266,000
Control room building, including motor controls, laboratory, and lockers 240,000
Service facilities and buildings allocation for maintenance, shops, and offices 1,470,000
Subtotal direct investment 13,283,000
Engineering design and supervision 797,000
Construction expense 1,063,000
Contractor fees 531,000
Contingency 1,461,000
Subtotal fixed capital investment 17,135,000
Allowance for startup and modifications 1,714,000
Interest during construction (8%/annum rate) 685,000
Total fixed capital investment 19,534,000
aBasis:
Tail gas recovery of 90% SO2 and SO3 from acid absorber, reheat to 175 F.
Midwest plant location-1972 costs.
In process storage of 72 hours.
177
-------
Table A-31. Summary of Estimated Fixed Investment:3
Scheme D—Magnesia Regeneration-Sutfuric Acid Unit
Central Processing Concept
(Equivalent to 3000-mw new coal-fired power unit, 3.5% S in fuel;
80.0tons/hrH2SO4)
Investment, $
Land, site clearance, excavation, landscaping, roads, railways, walkways 1,040,000
Calcining (fluid bed calcining system, fans, MgO and coke storage hoppers,
feeders, conveyors, elevators, waste heat boiler, dust collectors,
loading and unloading equipment) 3,221,000
Sulfuric acid plant (complete contact unit for sulfuric acid production,
dry gas purification system) 9,172,000
Tail gas scrubbing (scrubber, tanks, pumps, dryer, conveyor) 1,133,000
Sulfuric acid storage (storage and shipping facilities for 30 days
production of H2SO4) 634,000
Fuel oil storage (fuel oil storage and distribution system including storage
tank, hold tanks, heat exchanger, transfer and feed pumps) 354,000
Control room building, including motor controls, laboratory, and lockers 310,000
Service facilities and buildings allocation for maintenance, shops, and offices 1,880,000
Subtotal direct investment 17,744,000
Engineering design and supervision 1,065,000
Construction expense 1,420,000
Contractor fees 710,000
Contingency 1,952,000
Subtotal fixed capital investment 22,891,000
Allowance for startup and modifications 2,289,000
Interest during construction (8%/annum rate) 916,000
Total fixed capital investment 26,096,000
aBasis:
Tail gas recovery of 90% SO2 and SO3 from acid absorber, reheat to 175°F.
Midwest plant location-1972 costs.
In process storage of 72 hours.
178
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Table A-32. Summary of Estimated Fixed Investment Requirements:
Limestone Wet-Scrubbinga
(500-mw new coal-fired power unit, 3.5% S in fuel)
Yard improvements
Road and general yard modifications
Limestone storage and handling facilities
Wet grinding ball mill and classifier
Slurry storage and pumping
Scrubber (four 3-stage wet scrubbers with pumps,
piping, foundations, structures, and hold tank)
Duct work, dampers, and insulation
Optional by-pass duct
Solids disposal system
Equipment and piping
Disposal pond and land
Stack gas reheat system
Central control room and equipment
Electrical
Buildings
Service facilities
Subtotal direct cost
Engineering design and supervision
Construction expense
Contractor fees
Contingency
Total fixed capital investment
Allowance for start-up and modification
Interest during construction (8%/annum rate)
Total fixed capital investment
I nvestment, $
375,000
236,000
298,000
81,000
4,996,000
1,430,000
400,000
395,000
1,737,000
225,000
444,000
767,000
220,000
500,000
12,104,000
605,000
1,089,000
484,000
1.452,000
15,734,000
1,259,000
629,000
17,622,000
aBasis:
Stack gas reheat to 175° F. by indirect steam method.
Direct on-site solids disposal as 10% slurry.
Scrubber-to-pond distance of 1 mi., closed loop water recycle.
Midwest plant location-197 2 costs.
179
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Table A-33. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(200-mw new coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil 2,
Steam
Heat credit
Process water
Electricity 27,
Maintenance
54.8 tons
448 tons
31 2 tons
736 liters
30,440 man-hr
1 90,000 gal
1 80,000 M Ib
8,300 MM Btu
902,700 M gal
300,000 kwh
S in fuel; 45,200 tons/yr
Unit cost, $
16.00/ton
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.60/M lbb
-0.40/MM Btu
0.05/Mgalb
0.007/kwhb
Labor and material .07 x 11,685,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Total annual
cost, $
900
45,900
7,300
1,100
55,200
182,600
197,100
108,000
(3,300)
45,100
191,100
817,900
45,000
1,583,500
1,638,700
1,741,100
316,700
I
Cost/ton
of acid, $
.020
1.015
.162
.024
1.221
4.040
4.361
2.389
(.073)
.998
4.228
18.095
.995
35.033
36.254
38.520
7.007
Administrative, research, and service.
1 1 % of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for
H2S04
Cost/ton
of coal
burned, $
7.212
1 74,200
2,232,000
Total
annual
cost, $
3,870,700
3.854
49.381
Cost/ton
of acid, $
85.635
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $11,685,000; working capital, $281,300.
'-'Cost of utility supplied from power plant at full value.
180
-------
Table A-34 Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
— — " — '
(200-mw existing coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
56.6 tons
463 tons
322 tons
760 liters
30,440 man-hr
3, 166,000 gal
-M Ib
8,600 MM Btu
931, 400 M gal
28,1 90,000 kwh
S in fuel; 46,600 tons/yr 100% H2SO4
Total annual
Unit cost, $ cost, $
16.007 ton
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.60/M lbb
-0.40/MM Btu
0.05/M galb
0.007/kwhb
Labor and material, .07 x 13,083,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.7%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
900
47,400
7,600
1,100
57,000
182,600
284,900
(3,400)
46,600
197,300
915,800
45,000
1,668,800
1,725,800
2,054,000
333,800
)
Cost/ton
of acid, $
.019
1.017
.163
.024
1.223
3.919
6.114
(.073)
1.000
4.234
19.652
.966
35.812
37.035
44.077
7.163
Administrative, research, and service,
1 1 % of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/ton
of coal
burned, $
7.754
183,600
2,571,400
Total
annual
cost, $
4,297,200
3.940
55.180
Cost/ton
of acid, $
92.215
aBasis:
Remaining life of power plant, 22 yr.
Coal burned, 554,200 tons/yr-9,500 Btu/kwh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $13,083,000; working capital, $296,300.
of utility supplied from power plant at full value.
181
-------
Table A-35. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
(500-mw new
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06
Analyses
— — OL , H '
coal-fired power unit, 2. 0%
Annual quantity
76.6 tons
620 tons
436 tons
1,029 liters
32,520 man-hr
3,06 1,000 gal
440,000 M Ib
11, 600 MM Btu
1 ,350,000 M gal
58,970,000 kwh
x 18,788,000
S in fuel; 63,100 tons/yr
Unit'cost, $
16.00/ton
102.407 ton
23.50/ton
1.51/liter
6.00/ man-hr
.09/gal
0.55/M lbb
-0.40/MM Btu
0.04/M galb
0.006/kwhb
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at
14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion
Administrative, research,
1 1% of conversion costs
Subtotal indirect costs
costs
and service,
Total annual manufacturing costs for H2S04
Cost/ton
of coal
burned, $
4.506
Total annual
cost, $
1,200
63,500
10,200
1,600
76,500
195,100
275,500
242,000
(4,600)
54,000
353,800
1,127,300
76,000
2,319,100
2,395,600
2,799,400
463,800
255,100
3,518,300
Total
annual
cost, $
5,913,900
;
Cost/ton
of acid, $
.019
1.006
.162
.025
1.212
3.092
4.366
3.836
(.073)
.856
5.607
17.865
1.204
36.753
37.965
44.365
7.350
4.043
55.758
Cost/ton
of acid, $
93.723
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $18,788,000; working capital, $411,200.
Cost of utility supplied from power plant at full value.
182
-------
Table A-36. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06
Analyses
coal-fired power unit, 3.5% S
Annual quantity
134.1 tons
1,086 tons
763 tons
1,800 liters
39,200 man-hr
5,356,000 gal
440,000 M Ib
20,300 MM Btu
2,207,500 M gal
66,760,000 kwh
x 21, 732,000
in fuel; 110,400 tons/yr 100% H^SO4)
Total annual
Unit cost, $ cost, $
16.00/ ton
102.407 ton
23. 507 ton
1.51/liter
6.007 man-hr
0.097 gal
0.55/M lbb
-0.407 MM Btu
0.03/M galb
0.0067 kwhb
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at
14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion
Administrative, research,
1 1% of conversion costs
Subtotal indirect costs
costs
and service,
Total annual manufacturing costs for H2S04
Cost/ton
of coal
burned, $
5.371
2,100
1 1 1 ,200
17,900
2,700
133,900
235,200
482,000
242,000
(8,100)
66,200
400,600
1 ,303,900
85,000
2,806,800
2,940,700
3,238,100
561,400
308,700
4,108,200
Total
annual
cost, $
7,048,900
Cost/ton
of acid, $
.019
1.007
.162
.024
1.212
2.130
4.366
2.192
(.073)
.600
3.629
11.811
.770
25.425
26.637
29.331
5.085
2.797
37.213
Cost/ton
of acid, $
63.850
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stieam time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $21,732,000; working capital, $505,600.
^Cost of utility supplied from power plant at full value.
183
-------
Table A-37. Regulated Company Economics-Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
(500-mw new coal-fired power unit, 5.0% S
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
191. 5 tons
1,551 tons
1 ,090 tons
2,571 liters
45,880 man-hr
7,652,000 gal
440,000 M Ib
29,000 MM Btu
3,063,900 M gal
74,550,000 kwh
in fuel; 157,800 tons/yr 1 00% H2SO4 ,
Total annual
Unit cost, $ cost, $
16. 007 ton
102.407 ton
23.507 ton
1.51/liter
6.00/man-hr
0.09/gal
0.55/M lbb
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Labor and material, .06 x 24,275,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
3,100
158,800
25,600
3,900
191,400
275,300
688,700
242,000
(11,600)
61,300
447,300
1 ,456,500
91,000
3,250,500
3,441,900
3,617,000
650,100
)
Cost/ton
of acid, $
.020
1.006
.162
.025
1.213
1.745
4.364
1.534
(.074)
.388
2.835
9.230
.577
20.599
21.812
22.921
4.120
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/ton
of coal
burned, $
6.146
357,600
4,624,700
Total
annual
cost, $
8,066,600
2.266
29.307
Cost/ton
of acid, $
51.119
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, l,312,500otons/yr-9,000 Btu/kwh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $24,275,000; working capital, $592,500.
^Cost of utility supplied from power plant at full value.
184
-------
Table A-38. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
—— ... ...,— ..M (
(500-mw existing coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
137.0 tons
1,1 10 tons
780 tons
1,840 liters
39,200 man-hr
7,665,000 gal
-M Ib
20,800 MM Btu
2,256,1 00 M gal
68,240,000 kwh
in fuel; 11 2,900 tons/yr 100% H2SOt
Total annual
U nit cost, $ cost, $
16.00/ton
102.40/ton
23.5/ton
1.51/liter
6.00/man-hr
0. 097 gal
0.55/M lbb
-0.40/MM Btu
0.04/M galb
0.006/kwhb
Labor and material, .06 x 24,646,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.1%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
2,200
113,700
18,300
2,800
137,000
235,200
689,900
—
(8,300)
90,200
409,400
1,478,800
85,000
2,980,200
3,117,200
3,721,500
596,000
Cost/ton
of acid, $
.019
1.007
.162
.025
1.213
2.083
6.111
—
(.073)
.799
3.626
13.098
.753
26.397
27.610
32.963
5.279
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/ton
of coal
burned, $
5.786
327,800
4,645,300
Total
annual
cost, $
7,762,500
2.904
41.146
Cost/ton
of acid, $
68.756
aBasis:
Remaining life of power plant, 27 yr.
Coal burned, 1,341,700 tons/yr-9,200 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $24,646,000; working capital, $535,800.
bCost of utility supplied from power plant at full value.
185
-------
Table A-39. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A-
(1000-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 33,1
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
259.2 tons
2,078 tons
1,475 tons
3,480 liters
47,960 man-hr
10,356 ,000 gal
850,000 M Ib
39,300 MM Btu
4,267,000 M gal
1 29,070,000 kwh
18,000
in fuel; 213,500 tons/yr 100% H2SO4
Total annual
U nit cost, $ cost, $
16.00/ton
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
Cost/ton
of coal
burned, $
4.191
4,100
212,800
34,700
5,300
256,900
287,800
932,000
425,000
(15,700)
85,300
645,400
1,655,900
140,000
4,155,700
4,412,600
4,934,600
831,100
457,100
6,222,800
Total
annual
cost, $
10,635,400
Cost/ton
of acid, $
.019
.997
.162
.025
1.203
1.348
4.365
1.990
(.074)
.400
3.023
7.756
.656
19.464
20.667
23.113
3.894
2.141
29.148
Cost/ton
of acid, $
49.815
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $33,118,000; working capital, $759,900.
Cost of utility supplied from power plant at full value.
186
-------
Table A-40. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(1000-mw existing coal-fired power unit, 3.5% S in fuel; 220,900 tons/yr 100% H2SO4)
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 36,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
268.1 tons
2, 150 tons
1,526 tons
3,600 liters
47,960 man-hr
14,998,000 gal
-M Ib
40,600 MM Btu
4,41 3,900 M gal
1 33,520,000 kwh
634,000
16.00/ ton
1 02.40/ ton
23.50/ton
1.51/liter
6.00/ man-hr
0. 097 gal
0.50/M lbb
-0.40/MM Btu
0.02/Mgalb
0.005/kwhb
4,300
220,200
35,900
5,400
265,800
287,800
1 ,349,800
—
(16,200)
88,300
667,600
1,831,700
140,000
4,349,000
4,614,800
.019
.997
.163
.024
1.203
1.303
6.110
—
(.073)
.400
3.022
8.292
.634
19.688
20.891
Average capital charges at 15.1%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
5,531,700
869,800
25.042
3.937
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
Cost/ton
of coal
burned, $
4.379
478,400
6,879,900
Total
annual
cost, $
1 1 ,494,700
2.166
31.145
Cost/ton
of acid, $
52.036
aBasis:
Remaining life of power plant, 27 yr.
Coal burned, 2,625,000 tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $36,634,000; working capital, $794,600.
''Cost of utility supplied from power plant at full value.
187
-------
Table A-41. Regulated Company Economics— Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A— Magnesia Slurry Scrubbing-Regeneration
00% HO^)
Cost/ton
of acid, $
(200-mw new oil-fired power unit, 2.5% S in fuel; 24,100 tons/yr 100% H^O^
Total annual
Annual quantity _ Unit cost, $ _ cost,_$
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 6,690,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
239 tons
166 tons
393 liters
28,360 man-hr
2,103,000 gal
4,430 MM Btu
508,000 M gal
12,190,000 kwh
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.07/M galb
0.007/kwhb
Total annual manufacturing costs for H2S04
Cost/BBL
of fuel oil
burned,$
24,500
3,900
600
29,000
1700,200
189,300
(1,800)
35,600
85,300
468,300
30,000
976,900
1,005,900
996,800
195,400
107,500
1,299,700
Total
annual
cost, $
1.120
1.017
.162
.025
1.204
7.062
7.855
(.075)
1.477
3.539
19.432
1.245
40.535
41.739
41.361
8.108
4.461
53.930
Cost/ton
of acid, $
2,305,600 95,669
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 2,058,200 BBL/yr-9,200 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $6,690,000; working capital, $172,600.
Cost of utility supplied from power plant at full value.
188
-------
Table A-42. Regulated Company Economics-Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
— " ' —
(500-mw new oil-fired power unit, 1.0% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 232 tons
Coke 163 tons
Catalyst 394 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 30,440 man-hr
Utilities
Fuel oil 3,31 3,000 gal
Heat credit 4,330 MM Btu
Process water 601 ,800 M gal
Electricity 23,990,000 kwh
Maintenance
Labor and material, .06 x 9,888,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 23,600 tons/yr
Unit cost, $
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.06/M galb
0.006/kwhb
Cost/BBL
of fuel oil
burned, $
0.639
100%H2S04)
Total annual
cost, $
23,800
3,800
600
28,200
182,600
298,200
(1,700)
36,100
143,900
593,300
55,000
1,307,400
1,335,600
1,473,300
261,500
143,800
1,878,600
Total
annual
cost, $
3,214,200
Cost/ton
of acid, $
1.009
.161
.025
1.195
7.737
12.636
(.072)
1.530
6.097
25.140
2.330
55.398
56.593
62.428
11.081
6.093
79.602
Cost/ton
of acid, $
136.195
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $9,888,000; working capital, $228,900.
t>Cost of utility supplied from power plant at full value.
189
-------
Table A-43. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
— _^__ _- - - g- _ t__
(500-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 579 tons
Coke 407 tons
Catalyst 960 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 32,520 man-hr
Utilities
Fuel oil 5,1 42,000 gal
Heat credit 10,830 MM Btu
Process water 1,241,100 M gal
Electricity 29,810,000 kwh
Maintenance
Labor and material, .06 x 12,439,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1 % of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 58,900 tons/yr
Unit cost, $
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
Cost/BBL
of fuel oil
burned, $
0.826
100%H2SO4)
Total annual
cost, $
59,300
9,600
1,400
70,300
195,100
462,800
(4,300)
62,100
1 78,900
746,300
66,000
1 ,706,900
1,777,200
1 ,853,400
341,400
187,800
2,382,600
Total
annual
cost, $
4,159,800
Cost/ton
of acid, $
1.007
.163
.024
1.194
3.312
7.857
(.073)
1.054
3.037
12.671
1.121
28.979
30.173
31.467
5.797
3.188
40.452
Cost/ton
of acid, $
70.625
"Basis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $12,439,000; working capital, $305,300.
Cost of utility supplied from power plant at full value.
190
-------
Table A-44. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new oil-fired power unit, 4.0% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
926 tons
651 tons
1,536 liters
34,600 man-hr
6,856,000 gal
17,330 MM Btu
1 ,880,400 M gal
35,630,000 kwh
in fuel; 94,200 tons/yr
Unit cost, $
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0. 097 gal
-0.40/MM Btu
0.04/M galb
0.006/kwhb
Labor and material, .06 x 14,568,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
100%H2S04)
Total annual
cost, $
94,800
15,300
2,300
112,400
207,600
617,000
(6,900)
75,200
213,800
874,100
73,000
2,053,800
2,166,200
2,170,600
410,800
Cost/ton
of acid, $
1.006
.162
.024
1.192
2.204
6.550
(0.073)
0.798
2.270
9.279
0.775
21.803
22.995
23.043
4.361
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/BBL
of fuel oil
burned, $
0.988
225,900
2,807,300
Total
annual
cost, $
4,973,500
2.398
29.802
Cost/ton
of acid, $
52.797
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $14,568,000; working capital, $372,700.
^Cost of utility supplied from power plant at full value.
191
-------
Table A-45. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
(500-mw existing oil-fired power unit, 2.5%
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
592 tons
416 tons
981 liters
32,520 man-hr
5,256,000 gal
11, 070 MM Btu
1, 268,800 M gal
30,450,000 kwh
S in fuel; 60,200 tons/yr 100% H2SO4
Total annual
Unit cost, $ cost, $
102.407 ton
23.507 ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
Labor and material, .06 x 13,920,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.1%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
60,600
9,800
1,500
71,900
195,100
473,000
(4,400)
63,400
182,700
835,200
68,000
1,813,000
1 ,884,900
2,101,900
362,600
Cost/ton
of acid, $
1.006
.163
.025
1.194
3.241
7.857
(.073)
1.053
3.035
13.874
1.130
30.117
31.311
34.915
6.023
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/BBL
of fuel oil
burned^ $
0.884
199,400
2,663,900
Total
annual
cost, $
4,548,800
3.312
44.250
Cost/ton
of acid, $
75.561
aBasis:
Remaining life of power plant, 27 yr.
Fuel oil burned, 5,145,400 BBL/yr-9,200 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $13,920,000; working capital, $323,800.
"Cost of utility supplied from power plant at full value.
192
-------
Table A-46. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(1000-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
1,1 08 tons
787 tons
1,856 liters
39,200 man-hr
9,940,000 gal
20,940 MM Btu
2,399,600 M gal
57,640,000 kwh
in fuel; 113,900 tons /yr
Unit cost, $
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0. 097 gal
-0.40/MM Btu
0.04/M galb
0.005/kwhb
Labor and material, .05 x 18,888,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
100%H2S04)
Total annual
cost, $
113,500
18,500
2,800
1 34,800
235,200
894,600
(8,400)
96,000
288,200
944,400
121,000
2,571,000
2,705,800
2,814,300
514,200
Cost/ton
of acid, $
.997
.162
.025
1.184
2.065
7.854
(.074)
.843
2.530
8.292
1.062
22.572
23.756
24.709
4.514
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2 S04
Cost/BBL
of fuel oil
burned, $
0.649
282,800
3,611,300
Total
annual
cost, $
6,317,100
2.483
31.706
Cost/ton
of acid, $
55.462
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 9,731,500 BBL/yr-8,700 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $18,888,000; working capital, $465,500.
of utility supplied from power plant at full value.
193
-------
Table A-47. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-MnO2 Slurry Scrubbing-Regeneration
(200-mw new
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07
Analyses
coal-fired power unit, 3.5%
Annual quantity
54.8 tons
448 tons
301 tons
736 liters
30,440 man-hr
2,374,000 gal
1 80,000 M Ib
40, 100 MM Btu
903,000 M gal
24,070,000 kwh
x 11,990,000
S in fuel; 45,200 tons/yr
Unit cost, $
16.007 ton
102.407 ton
90.007 ton
1.51/liter
6.00/man-hr
0.097 gal
0.607 M lbb
-0.407 MM Btu
0.05/M galb
0.0077 kwhb
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at
14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion
Administrative, research,
1 1% of conversion costs
Subtotal indirect costs
costs
and service,
Total annual manufacturing costs for H?S04
Cost/ton
of coal
burned, $
7.340
Total annual
cost, $
900
45,900
27,100
1.100
75,000
182,600
213,700
1 08,000
(16,000)
45,200
168,500
839,300
45,000
1,586,300
1,661,300
1,786,500
317,300
174,500
2,278,300
Total
annual
cost, $
3,939,600
}
Cost/ton
of acid, $
.020
1.015
.600
.024
1.659
4.040
4.728
2.389
(.354)
1.000
3.728
18.569
.995
35.095
36.754
39.524
7.020
3.861
50.405
Cost/ton
of acid, $
87.159
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr 9,200 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $11,990,000; working capital, $285,600.
^Cost of utility supplied from power plant at full value.
194
-------
Table A-48. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-IVInO2 Slurry Scrubbing-Regeneration
(500-mw new coal-fired power unit, 3.5% S in fuel; 110,400 tons/yr 100% H2SO4)
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Lime 134.1 tons
Magnesium oxide (98%) 1,086 tons
Manganese dioxide 724 tons
Catalyst 1,798 liters
Subtotal raw material
16.007 ton
102.407 ton
90.007 ton
1.51/liter
2,100
111,200
65,200
2,700
181,200
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 22,237,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
11% of conversion costs
Subtotal indirect costs
39,200 man-hr
5,806,000 gal
440,000 M Ib
98,000 MM Btu
2,207,000 M gal
58,870,000 kwh
6.007 man-hr
0.097 gal
0.55/M lbb
-0.407MM Btu
0.03/M galb
0.0067 kwhb
Cost/ton
of coal
burned.$
235,200
522,500
242,000
(39,200)
66,200
353,200
1,334,200
85.000
2,799,100
2,980,300
3,313,300
559,800
307,900
4,181,000
Total
annual
cost. $
.019
1.007
.591
.024
1.641
Total annual manufacturing costs for
5.456
7,161,300
2.130
4.733
2.192
(.355)
.600
3.199
12.085
.770
25.354
26.995
30.012
5.071
2.789
37.872
Cost/ton
of acid. $
64.867
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, l,312,500otons/yr-9,000 Btu/kwh.
Stack gas reheat to 175 ° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $22,237,000; working capital, $513,400.
''Cost of utility supplied from power plant at full value.
195
-------
Table A-49. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
(1000-mw new coal-fired power unit, 3.5% S
Annual auantitv
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil 11,
Steam
Heat credit
Process water 4,
Electricity 113,
Maintenance
259. 2 tons
2,078 tons
1,385 tons
3,477 liters
47,960 man-hr
225,000 gal
850,000 M Ib
189,500 MM Btu
266,000 M gal
81 0,000 kwh
in fuel; 213,500 tons/yr 100% H2SO4
Total annual
Unit cost. $ cost. $
16. 007 ton
102.40/ton
90.007 ton
1.51/liter
6.00/ man-hr
0.09/gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
Labor and material, .05 x 33,838,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
4,100
212,800
124,700
5.300
346,900
287,800
1,010,300
425,000
(75,800)
85,300
569,100
1,691,900
140.000
4,133,600
4,480,500
5,041,900
826,700
Cost/ton
of acid. $
.019
.997
.584
.025
1.625
1.348
4.732
1.991
(.355)
.399
2.665
7.925
.656
19.361
20.986
23.615
3.872
Administrative, research, and service.
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for
H2S04
Cost/ton
of coal
burned, $
4.258
454.700
6,323,300
Total
annual
cost. $
10,803,800
2.130
29.617
Cost/ton
of acid. $
50.603
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $33,838,000; working capital, $773,400.
Cost of utility supplied from power plant at full value.
196
-------
Table A-50. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-MnC^ Slurry Scrubbing-Regeneration
• - ., . W "
(200-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 239 tons
Manganese dioxide 159 tons
Catalyst 393 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 28,360 man-hr
Utilities
Fuel oil 1,821, 000 gal
Heat credit 21,400 MM Btu
Process water 498,000 M gal
Electricity 9,320,000 kwh
Maintenance
Labor and material, .07 x 6,806,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
k4 l-E
in fuel; 24,100 tons/yr
Unit cost, $
1 02.40/ ton
90.00/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.07/M galb
0.007/kwhb
Cost/BBL
of fuel oil
burned. $
1.105
100%H2S04)
Total annual
cost, $
24,500
14,300
600
39,400
170,200
163,900
(8,600)
34,900
65,200
476,400
30.000
932,000
971,400
1,014,100
186,400
102,500
1 ,303,000
Total
annual
cost, $
2,274,400
Cost/ton
of acid, $
1.017
.593
.025
1.635
7.062
6.801
(.357)
1.448
2.705
19.768
1.245
38.672
40.307
42.079
7.734
4.253
54.066
Cost/ton
of acidr $
94.373
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 2,058,^00 BBL/yr-9,200 Btu/kwh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $6,806,000; working capital, $169,000.
^Cost of utility supplied from power plant at full value.
197
-------
Table A-51. Regulated Company Economics-Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-MnO2 Slurry Scrubbing-Regeneration
u •« *•
(500-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 579 tons
Manganese dioxide 386 tons
Catalyst 959 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 32,520 man-hr
Utilities
Fuel oil 4,454,000 gal
Heat credit 52,300 MM Btu
Process water 1,217,000 M gal
Electricity 22,780,000 kwh
Maintenance
Labor and material, .06 x 12,561,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 58,900 tons/yr
Unit cost, $
1 02.407 ton
90.00/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
Cost/BBL
of fuel oil
burned, $
.805
Total annual
cost, $
59,300
34,700
1.400
95,400
195,100
400,900
(20,900)
60,900
136,700
753,700
66,000
1,592,400
1,687,800
1,871,600
318,500
175.200
2,365,300
Total
annual
cost, $
4,053,100
Cost/ton
of acid, $
1.007
.589
.024
1.620
3.312
6.807
(.355)
1.034
2.321
12.796
1.120
27.035
28.655
31.776
5.407
2.975
40.158
Cost/ton
of acid, $
68.813
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location—1972 costs.
Capital investment, $12,561,000; working capital, $294,800.
"Cost of utility supplied from power plant at full value.
198
-------
Table A-52. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-IVInO2 Slurry Scrubbing-Regeneration
(1000-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 1,108 tons
Manganese dioxide 739 tons
Catalyst 1,855 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 39,200 man-hr
Utilities
Fuel oil 8,61 1,000 gal
Heat credit 101,000 MM Btu
Process water 2,352,000 M gal
Electricity 44,050,000 kwh
Maintenance
Labor and material, .05 x 19,126,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2 S04
in fuel; 113,900 lons/yr
Unit cost, $
102.40/ton
90.00/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.04/M galb
0.005/kwhb
Cost/BBL
of fuel oil
burned, $
.630
100%H2S04
Total annual
cost, $
113,500
66,500
2.800
182,800
235,200
775,000
(40,400)
94,100
220,300
956,300
121.000
2,361,500
2,544,300
2,849,800
472,300
259.800
3,581,900
Total
annual
cost, $
6,126,200
Cost/ton
of acid, $
.996
.584
.025
1.605
2.065
6.805
(.355)
.826
1.934
8.396
1.062
20.733
22.338
25.020
4.147
2.281
31.448
Cost/ton
of acid, $
53.786
aBasis:
Remaining life of power plant, 30 yr.
Fuel oil burned, 9,731,500 BBL/yr-8,700 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $19,126,000; working capital, $445,700.
'-'Cost of utility supplied from power plant at full value.
199
-------
Table A-53. Regulated Company Economics-Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme C-Magnesia Clear Liquor Scrubbing-Regeneration
--_--- cj , . • —
(200-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
373 tons
130 tons
630 liters
30,440 man-hr
1,836,000 gal
247,000 M Ib
40,400 MM Btu
837,300 M gal
24,583,000 kwh
in fuel; 38, 700 tons/yr
Unit cost, $
102.40/ton
23.50/ton
1.51 /liter
6.00/man-hr
0.09/gal
0.60/M lbb
-0.40/MM Btu
0.05/M galb
.007/kwhb
Labor and material, .07 x 9,923,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Total annual
cost, $
38,200
3,100
1,000
42,300
182,600
165,200
148,200
(16,200)
41,900
172,100
694,600
38,000
1 ,426,400
1 ,468,700
1 ,478,500
285,300
;
Cost/ton
of acid, $
.987
.080
.026
1.093
4.718
4.269
3.829
(.419)
1.082
4.447
17.948
.982
36.858
37.951
38.204
7.372
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/ton
of coal
burned, $
6.315
156,900
1,920,700
Total
annual
cost, $
3,389,400
4.054
49.630
Cost/ton
of acid, $
87.581
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $9,923,000; working capital, $252,000.
Cost of utility supplied from power plant at full value.
200
-------
Table A-54. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration
(500-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 18,1
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
911 tons
31 9 tons
1,542 liters
39,200 man-hr
4,490,000 gal
604,000 M Ib
98,700 MM Btu
2,048,800 M gal
60, 11 9,000 kwh
11.000
in fuel; 94, 700 tons/yr
Unit cost, $
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0. 097 gal
0.55/M lbb
-0.40/MM Btu
0.037 M galb
0.0067 kwhb
Total annual
cost, $
93,300
7,500
2,300
103,100
235,200
404,100
332,200
(39,500)
61,500
360,700
1 ,086,700
73,000
2,513,900
2,617,000
2,698,500
502,800
Cost/ ton
of acid, $
.986
.079
.024
1.089
2.484
4.267
3.508
(.417)
.649
3.809
11.475
.771
26.546
27.635
28.495
5.309
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for H2S04
Cost/ton
of coal
burned, $
4.644
276,500
3,477,800
Total
annual
cost, $
6,094,800
2.920
36.724
Cost/ton
of acid, $
64.359
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location—1972 costs.
Capital investment, $18,111,000; working capital, $449,600.
'•'Cost of utility supplied from power plant at full value.
201
-------
Table A-55. Regulated Company Economics—Total Venture Average Annual
Manufacturing Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration
(1000-mw new
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05
Analyses
.-. _ . " - *
coal-fired power unit, 3.5%
Annual quantity
1,761 tons
617 tons
2,980 liters
47,960 man-hr
8,681, 000 gal
1,1 68,000 M Ib
190,800 MM Btu
3,961, BOOM gal
11 6,228,000 kwh
x 27,540,000
S in fuel; 183,000 tons/yr 100% H2SO4
Total annual
Unit cost, $ cost, $
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at
14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion
Administrative, research,
1 1% of conversion costs
Subtotal indirect costs
costs
and service,
Total annual manufacturing costs for H2S04
Cost/ton
of coal
burned, $
3.623
180,300
14,500
4,500
199,300
287,800
781,300
584,000
(76,300)
79,200
581,100
1,377,000
119,000
3,733,100
3,932,400
4,103,500
746,600
410,600
5,260,700
Total
annual
cost, $
9,193,100
;
Cost/ton
of acid, $
.985
.079
.025
1.089
1.573
4.269
3.191
(.417)
.433
3.175
7.525
.650
20.399
21.488
22.423
4.080
2.244
28.747
Cost/ton
of acid, $
50.235
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Stack gas reheat to 175^ F.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $27,540,000; working capital, $676,500.
Cost of utility supplied from power plant at full value.
202
-------
Table A-56. Regulated Company Economics—Average Annual
Operating Costs for Limestone-Wet Scrubbing of Power Plant Stack Gasa
Low Limestone Cost. On-Site Solids Disposal
(500-mw new coal-fired power unit, 3.5% S in fuel)
Annual quantity
Total annual Cost/ton
Unit cost, $ cost, $ of coal burned, $
Direct Costs (excluding solids disposal)
Delivered raw material
Limestone
Subtotal raw material
1 92.5 M tons 2.05/ton 394,600
394,600
.301
.301
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 14,364,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs (excluding solids disposal)
Average capital charges at 14.9%
23,280 man-hr
379,000 MM Btu
210,000 M gal
56,420,000 kwh
6.00/man-hr
.507MM Btu
.07/M galb
0.006/kwhb
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,5OO.tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $14,364,000 plus $3,258,000 on-site solids disposal investment.
Solids disposed 234,300 tons/yr calcium solids including hydrate water
118,100 tons/yr free water
Total 352,400 tons/yr
"Cost of utility supplied from power plant at full value.
139,700
189,500
14,700
338,500
1,149,100
38,000
1,869,500
2,264,100
.106
.145
.011
.258
.875
.029
1.424
1.725
of initial fixed investment
Overhead
Plant, 17.5% of conversion costs
Administrative, 1 1% of operating labor
Subtotal indirect costs
Total annual operating costs,
excluding costs for disposal of solids
Annual operating costs for on-site
pond disposal of solids
Total annual operating costs,
including disposal costs
2,140,200
327,000
15,400
2,482,600
4,746,700
629,600
5,376,300
1.630
.249
.012
1.891
3.616
.480
4.096
203
-------
Table A-57. Regulated Company Economics—Average Annual
Operating Costs for Limestone-Wet Scrubbing of Power Plant Stack Gasa
High Limestone Cost, Off-site Solids Disposal
(500-mw new coal-fired power unit, 3.5% S in fuel)
Annual quantity Unit cost, $
Direct Costs (excluding solids disposal)
Delivered raw material
Limestone 192.5 M tons 6. 007 ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 23,280 man-hr 6.00/man-hr
Utilities
Steam 379,000 MM Btu .50/MM Btu
Process water 210,000 M gal .07/M galb
Electricity 56,420,000 kwh 0.006/kwhb
Maintenance
Labor and material, .08 x 14,364,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs (excluding solids disposal)
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 17.5% of conversion costs
Administrative, 1 1% of operating labor
Subtotal indirect costs
Total annual operating costs,
excluding costs for disposal of solids
Annual operating costs for off-site
disposal of solids at $6/ton
Total annual operating costs,
including disposal costs
Total annual
cost, $
1,155,000
1,155,000
139,700
189,500
14,700
338,500
1,149,100
38,000
1,869,500
3,024,500
2,140,200
327,000
15,400
2,482,600
5,507,100
2,114,400
7,621,500
Cost/ton
of coal burned, $
.881
.881
.106
.145
.011
.258
.875
.029
1.424
2.305
1.630
.249
.012
1.891
4.196
1.611
5.807
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $14,364,000.
Solids disposed 234,300 tons/yr calcium solids including hydrate water
118,100 tons/yr free water
Total 352,400 tons/yr
bCost of utility supplied from power plant at full value.
204
-------
Table A-58. Nonregulated Company Economics—Total Venture Annual
Manufacturing Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(200-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 11,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
54.8 tons
448 tons
31 2 tons
736 liters
30,440 man-hr
2,1 90,000 gal
1 80,000 M Ib
8,300 MM Btu
902,700 M gal
27,300,000 kwh
685,000
in fuel; 45,200 tons/yr 100% H2SO4)
Total annual
U nit cost, $ cost, $
16.007 ton
1 02.407 ton
23.50/ton
1.51/liter
6.007 man-hr
0.097 gal
-0.60/M lbb
-0.40/MM Btu
0.05/M galb
0.007/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
900
45,900
7,300
1,100
55,200
182,600
197,100
108,000
45', 100
191,100
817,900
45,000
1,583,500
1 ,638,700
1,168,500
233,700
316,700
110,800
1,829,700
3,468,400
Cost/ton
of acid, $
.020
1.015
.162
.024
1.221
4.040
4.361
2.389
(.073)
.998
4.228
18.095
.995
35.033
36.254
25.852
5.170
7.007
2.451
40.480
76.734
aBasis:
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $11,685,000; working capital, $281,300
^Cost of utility supplied from power plant at full value.
205
-------
Table A-59. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(200-mw existing coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 13,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
56.6 tons
463 tons
322 tons
760 liters
30,440 man-hr
3,1 66,000 gal
-M Ib
8,600 MM Btu
931, 400 M gal
28,1 90,000 kwh
083,000
S in fuel; 46,600 tons/yr 100% H2SO4
Total annual
Unit cost, $ cost, $
16.007 ton
102.40/ton
23.50/ton
1.51/liter
6.00/ man-hr
0.09/gal
0.60/M lbb
-0.40/MM Btu
0.05/M galb
0.007/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
900
47,400
7,600
1,100
57,000
182,600
284,900
—
(3,400)
46,600
197,300
915,800
45,000
1 ,668,800
1,725,800
1 ,308,300
261,700
333,800
)
Cost/ton
of acid, $
.019
1.017
.163
.024
1.223
3.919
6.114
—
(.073)
1.000
4.234
19.652
.966
35.812
37.035
28.075
5.616
7.163
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
116,800
2,020,600
3,746,400
2.506
43.360
80.395
aBasis:
Coal burned, 554,200 tons/yr-9,500 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175 F.
Midwest plant location-1972 costs.
Capital investment, $13,083,000; working capital, $296,300.
"Cost of utility supplied from power plant at full value.
206
-------
Table A-60. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new coal-fired power unit, 2.0%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 18,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
76.6 tons
620 tons
436 tons
1,029 liters
32,520 man-hr
3,06 1,000 gal
440,000 M Ib
11, 600 MM Btu
1, 350,1 00 M gal
58,970,000 kwh
788,000
Sin fuel; 63,100 tons/yr
Unit cost, $
16.00/ton
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.55/M lbb
-0.40/MM Btu
0.04/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
100%H2SO4)
Total annual
cost, $
1,200
63,500
10,200
1,600
76,500
195,100
275,500
242,000
(4,600)
54,000
353,800
1,127,300
76,000
2,319,100
2,395,600
1,878,800
375,800
463,800
Cost/ton
of acid, $
.019
1.006
.162
.025
1.212
3.092
4.366
3.836
(.073)
.856
5.607
17.865
1.204
36.753
37.965
29.775
5.956
7.350
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
162,300
2,880,700
5,276,300
2.572
45.653
83.618
aBasis:
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $18,788,000; working capital, $411,200.
"Cost of utility supplied from power plant at full value.
207
-------
Table A-61. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Lime 134.1 tons
Magnesium oxide (98%) 1,086 tons
Coke 763 tons
Catalyst 1,800 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 39,200 man-hr
Utilities
Fuel oil 5,356,000 gal
Steam 440,000 M Ib
Heat credit 20,300 MM Btu
Process water 2,207,500 M gal
Electricity 66,760,000 kwh
Maintenance
Labor and material, .06 x 21,732,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 110,400 tons/yr 100% H2SO4 )
Total annual
Unit cost, $ cost, $
16. 007 ton
102.407 ton
23.507 ton
1.51/liter
6.007 man-hr
0.09/gal
0.55/M lbb
-0.407 MM Btu
0.03/M galb
0.006/kwhb
2,100
1 1 1 ,200
17,900
2,700
1 33,900
235,200
482,000
242,000
(8,100)
66,200
400,600
1,303,900
85,000
2,806,800
2,940,700
2,173,200
434,600
561,400
196,500
3,365,700
6,306,400
Cost/ton
of acid, $
.019
1.007
.162
.024
1.212
2.130
4.366
2.192
(.073)
.600
3.629
11.811
.770
25.425
26.637
19.685
3.936
5.085
1.780
30.486
57.123
aBasis:
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr;acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $21,732,000; working capital, $505,600.
"Cost of utility supplied from power plant at full value.
208
-------
Table A-62. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new coal-fired power unit, 5.0% S
Annual quantity
Direct Costs
Delivered raw material
Lime 191. 5 tons
Magnesium oxide (98%) 1,551 tons
Coke 1 ,090 tons
Catalyst 2,571 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 45,880 man-hr
Utilities
Fuel oil 7,652,000 gal
Steam 440,000 M Ib
Heat credit 29,000 MM Btu
Process water 3,063,900 M gal
Electricity 74,550,000 kwh
Maintenance
Labor and material, .06 x 24,275,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 157,800 tons/yr 100% H2SO4)
Total annual
Unit cost, $ cost, $
16.00/ton
102.40/ ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.55/M lbb
-0.40/MM Btu
0.02/M galb
0.006/kwhb
3,100
158,800
25,600
3,900
191,400
275,300
688,700
242,000
(11,600)
61,300
447,300
1 ,456,500
91,000
3,250,500
3,441,900
2,427,500
485,500
650,100
650,100
3,790,600
7,232,500
Cost/ton
of acid, $
.020
1.006
.162
.025
1.213
1.745
4.364
1.534
(.074)
.388
2.835
9.230
.577
20.599
21.812
15.383
3.076
4.120
4.120
24.021
45.833
aBasis:
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $24,275,000; working capital, $592,500.
^Cost of utility supplied from power plant at full value.
209
-------
Table A-63. Nonregulated Company Economics-Total Venture Annual Manufacturing
Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw existing coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 24,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
137.0 tons
1,1 10 tons
780 tons
1,840 liters
39,200 man-hr
7,665,000 gal
-M Ib
20,800 MM Btu
2,256,1 00 M gal
68,240,000 kwh
646,000
Sin fuel; 11 2, 900
Unit cost, $
16.007 ton
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.55/M lbb
tons/yrlOO%H2S04)
Total annual
cost, $
2,200
113,700
18,300
2,800
137,000
235,200
689,900
—
-0.40/MM Btu (8,300)
0.04/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
90,200
409,400
1,478,800
85,000
2,980,200
3,117,200
2,464,600
492,900
596,000
Cost/ton
of acid, $
.019
1.007
.162
.025
1.213
2.083
6.111
—
(.073)
.799
3.626
13,098
.753
26.397
27.610
21.830
4.366
5.279
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
208,600
3,762,100
6,879,300
1.848
33.323
60.933
aBasis:
Coal burned, 1,341,700 tons/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $24,646,000; working capital, $535,800.
Cost of utility supplied from power plant at full value.
210
-------
Table A-64. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
. __ u 1
(1000-mw new coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 33,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
259.2 tons
2,078 tons
1,475 tons
3,480 liters
47,960 man-hr
10,356,000 gal
850,000 M Ib
39,300 MM Btu
4,267,000 M gal
1 29,070,000 kwh
118,000
S in fuel; 213,500 tons/yr 100% H2SO4)
Total annual
Unit cost, $ cost, $
16.007 ton
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0. 097 gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
4,100
212,800
34,700
5,300
256,900
287,800
932,000
425,000
(15,700)
85,300
645,400
1,655,900
140,000
4,155,700
4,412,600
3,311,800
662,400
831,100
Cost/ton
of acid, $
.019
.997
.162
.025
1.203
1.348
4.365
1.990
(.074)
.400
3.023
7.756
.656
19.464
20.667
15.512
3.103
3.893
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
290,900
5,096,200
9,508,800
1.363
23.871
44.538
aBasis:
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $33,118,000; working capital, $759,900.
bCost of utility supplied from power plant at full value.
211
-------
Table A-65. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
. , . —._ *-f * _
(1000-mw existing coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 36,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
268.1 tons
2,1 50 tons
1,526 tons
3,600 liters
47,960 man-hr
14,998,000 gal
-M Ib
40,600 MM Btu
4,41 3,900 M gal
1 33,520,000 kwh
634,000
S in fuel; 220,900 tons/yr 100% H^SO
Total annual
Unit cost, $ cost, $
16.007 ton
102.407 ton
23.507 ton
1.51/liter
6.00/man-hr
0.09/gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
4,300
220,200
35,900
5,400
265,800
287,800
1 ,349,800
—
(16,200)
88,300
667,600
1,831,700
140,000
4,349,000
4,614,800
3,663,400
732,700
869,800
*)
Cost/ ton
of acid, $
.019
.997
.163
.024
1.203
1.303
6.110
—
(.073)
.400
3.022
8.292
.634
19.688
20.891
16.584
3.317
3.937
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
304,400
5,570,300
10,185,100
1.378
25.216
46.107
aBasis:
Coal burned, 2,625,000 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175 F.
Midwest plant location-197 2 costs.
Capital investment, $36,634,000; working capital, $794,600.
"Cost of utility supplied from power plant at full value.
212
-------
239 tons
166 tons
393 liters
28,360 man-hr
2,103,000 gal
4,430 MM Btu
508,000 M gal
12,190,000 kwh
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.07/Mgalb
0.007/kwhb
24,500
3,900
600
29,000
Table A-66. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(200-mw new oil-fired power unit, 2.5% S in fuel; 24,100 tons/yr 100% H2SO4)
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 6,690,000
Analyses
Subtotal conversion costs
Subtotal direct costs
170,200
189,300
(1,800)
35,600
85,300
468,300
30,000
976,900
1,005,900
1.017
.162
.025
1.204
7.062
7.855
(.075)
1.477
3.539
19.432
1.245
40.535
41.739
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
669,000
133,800
195,400
68,400
1 ,066,600
2,072,500
27.759
5.552
8.108
2.838
44.257
85.996
aBasis:
Fuel oil burned, 2,058,200 BBL/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $6,690,000; working capital, $172,600.
^Cost of utility supplied from power plant at full value.
213
-------
Table A-67. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2 SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new oil-fired power unit, 1.0% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
232 tons
1 63 tons
384 liters
30,440 man-hr
3,3 13,000 gal
4,330 MM Btu
601, 800 M gal
23,990,000 kwh
in fuel; 23,600 tons/yr
Unit cost, $
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.06/M galb
0.006/kwhb
Labor and material, .06 x 9,888,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
100%H2S04)
Total annual
cost, $
23,800
3,800
600
28,200
182,600
298,200
(1,700)
36,100
143,900
593,300
55,000
1,307,400
1 ,335,600
988,800
197,800
261,500
Cost/ton
of acid, $
1.009
.161
.025
1.195
7.737
12.636
(.072)
1.530
6.097
25.140
2.330
55.398
56.593
41.898
8.382
11.081
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
91,500
1 ,539,600
2,875,200
3.877
65.238
121.831
aBasis:
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $9,888,000; working capital, $228,900.
"Cost of utility supplied from power plant at full value.
214
-------
579 tons
407 tons
960 liters
32,520 man-hr
5,142,000 gal
10,830 MM Btu
1,241,100 M gal
29,810,000 kwh
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
59,300
9,600
1,400
70,300
195,100
462,800
(4,300)
62,100
178,900
746,300
66,000
1,706,900
1,777,200
1.007
.163
.024
1.194
Table A-68. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
(500-mw new oil-fired power unit, 2.5% S in fuel; 58,900 tons/yr 100% H2S04)
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 12,439,000
Analyses
Subtotal conversion costs
Subtotal direct costs
3.312
7.857
(.073)
1.054
3.037
12.671
1.121
28.979
30.173
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
1,243,900
248,800
341,400
119,500
1 ,953,600
3,730,800
21.119
4.224
5.796
2.029
33.168
63.341
aBasis:
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $12,439,000; working capital, $305,300.
^Cost of utility supplied from power plant at full value.
215
-------
Table A-69. Nonregulated Company Economics— Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A— Magnesia Slurry Scrubbing-Regeneration
00% HSO)
Cost/ton
of acid, $
(500-mw new oil-fired power unit, 4.0% S in fuel; 94,200 tons/yr 100% H^SO4)
Total annual
Annual quantity _ Unit cost, $ _ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x
Analyses
Subtotal conversion costs
Subtotal direct costs
926 tons
651 tons
1,536 liters
34,600 man-hr
6,856,000 gal
17,330 MM Btu
1,880,400 M gal
35,630,000 kwh
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.04/M galb
0.006/kwhb
94,800
15,300
2,300
112,400
207,600
617,000
(6,900)
75,200
213,800
874,100
73.000
2,053,800
2,166,200
1.006
.162
.024
1.192
2.204
6.550
(0.073)
0.798
2.270
9.279
0.775
21.803
22.995
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2SO4
1 ,456,800
291,400
410,800
143,800
2,302,800
4,469,000
15.466
3.093
4.361
1.527
24.447
47.442
aBasis:
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $14,568,000; working capital, $372,700.
''Cost of utility supplied from power plant at full value.
216
-------
Table A-70. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration .
(500-mw existing oil-fired power unit, 2.5% S in fuel; 60,200 tons/yr 100% HI SO*)
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
592 tons
41 6 tons
981 liters
102.40/ton
23.507 ton
1.51/liter
60,600
9,800
1,500
71,900
1.006
.163
.025
1.194
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 13,920,000
Analyses
Subtotal conversion costs
Subtotal direct costs
32,520 man-hr
5,256,000 gal
11,070 MM Btu
1,268,800 M gal
30,450,000 kwh
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
195,100
473,000
(4,400)
63,400
182,700
835,200
68,000
1,813,000
1,884,900
3.241
7.857
(.073)
1.053
3.035
13.874
1.130
30.117
31.311
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
1 ,392,000
278,400
362,600
1 26,900
2,159,900
4,044,800
23.123
4.624
6.023
2.108
35.878
67.189
aBasis:
Fuel oil burned, 5,145,400 BBL/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $13,920,000; working capital, $323,800.
''Cost of utility supplied from power plant at full value.
217
-------
Table A-71. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme A—Magnesia Slurry Scrubbing-Regeneration
. ; ^ J-
(1000-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 18,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
1,1 08 tons
787 tons
1,856 liters
39,200 man-hr
9,940,000 gal
20,940 MM Btu
2,399,600 M gal
57,640,000 kwh
888,000
in fuel: 11 3, 900 tons/yr
Unit cost, $
102.407 ton
23.507 ton
1.51/liter
6.007 man-hr
0.09/gal
-0.407 MM Btu
0.047 M galb
0.0057 kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
100% HiSO4,
Total annual
cost, $
113,500
18,500
2,800
134,800
235,200
894,600
(8,400)
96,000
288,200
944,400
121,000
2,571,000
2,705,800
1 ,888,800
377,800
514,200
)
Cost/ton
of acid, $
.997
.162
.025
1.184
2.065
7.854
(.074)
.843
2.530
8.292
1.062
22.572
23.756
16.583
3.317
4.515
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
180,000
2,960,800
5,666,600
1.580
25.995
49.751
aBasis:
Fuel oil burned, 9,731,500 BBL/yr-8,700 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $18,888,000; working capital, $465,500.
"Cost of utility supplied from power plant at full value.
218
-------
Table A-72. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
(200-mw new coal-fired power unit, 3.5%
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 11
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
54.8 tons
448 tons
301 tons
736 liters
30,440 man-hr
2,374,000 gal
1 80,000 M Ib
40, 100 MM Btu
903,000 M gal
24,070,000 kwh
,990,000
S in fuel; 45,200 tons/yr
Unit cost, $
16.00/ton
1 02.40/ ton
90.007 ton
1.51/liter
6.007 man-hr
0.097 gal
0.60/M lbb
-0.407 MM Btu
0.05/M galb
0.007/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Total annual
cost, $
900
45,900
27,100
1.100
75,000
182,600
213,700
108,000
(16,000)
45,200
168,500
839,300
45.000
1,586,300
1,661,300
1,199,000
239,800
317,300
Cost/ton
of acid, $
.020
1.015
.600
.024
1.659
4.040
4.728
2.389
(.354)
1.000
3.728
18.569
.995
35.095
36.754
26.527
5.305
7.020
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
1 1 1 ,000
1,867,100
3,528,400
2.456
41.308
78.062
"Basis:
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175° F.
Midwest plant location-1972 costs.
Capital investment, $11,990,000; working capital, $285,600
°Cost of utility supplied from power plant at full value.
219
-------
Table A-73. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—IVIgO-IVlnO2 Slurry Scrubbing-Regeneration
(500-mw new coal-fired power unit, 3.5% S in fuel; 110,400 tons /yr 100% H2SO4)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 22
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
134.1 tons
1,086 tons
724 tons
1,798 liters
39,200 man-hr
5,806,000 gal
440,000 M Ib
98,000 MM Btu
2,207,000 M gal
58,870,000 kwh
,237,000
16. 007 ton
102.40/ton
90. 007 ton
1.51/liter
6.00/ man-hr
0.09/gal
0.55/M lbb
-0.40/MM Btu
0.03/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
2,100
1 1 1 ,200
65,200
2.700
181,200
235,200
522,500
242,000
(39,200)
66,200
353,200
1 ,334,200
85.000
2,799,100
2,980,300
2,223,700
444,700
559,800
Cost/ton
of acid, $
.019
1.007
.591
.024
1.641
2.130
4.733
2.192
(.355)
.600
3.199
12.085
.770
25.354
26.995
20.142
4.028
5.071
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2SO4
195.900
3,424,100
6,404,400
1.775
31.016
58.01 1
aBasis:
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175° F.
Midwest plant location—1972 costs.
Capital investment, $22,237,000; working capital, $513,400.
"Cost of utility supplied from power plant at full value.
220
-------
Table A-74. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-MlnO2 Slurry Scrubbing-Regeneration
(1000-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Lime
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 33,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
259.2 tons
2,078 tons
1,385 tons
3,477 liters
47,960 man-hr
1 1 ,225,000 gal
850,000 M Ib
189,500 MM Btu
4,266,000 M gal
11 3,81 0,000 kwh
838,000
in fuel; 213,500 tons/yr 100% H2SO4/
Total annual
Unit cost, $ cost, $
16.00/ton
102.40/ton
90.007 ton
1.51/liter
6.00/ man-hr
0. 097 gal
0.507 M lbb
-0.407 MM Btu
0.027 M galb
0.0057 kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
4,100
212,800
1 24,700
5,300
346,900
287,800
1,010,300
425,000
(75,800)
85,300
569,100
1,691,900
140,000
4,133,600
4,480,500
3,383,800
676,800
826,700
)
Cost/ ton
of acid, $
.019
.997
.584
.025
1.625
1.348
4.732
1.991
(.355)
.399
2.665
7.925
.656
19.361
20.986
15.849
3.170
3.872
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
289.400
5,176,700
9,657,200
1.356
24.247
45.233
aBasis:
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175 F.
Midwest plant location-1972 costs.
Capital investment, $33,838,000; working capital, $773,400.
Cost of utility supplied from power plant at full value.
221
-------
239 tons
159 tons
393 liters
28,360 man-hr
1,821,000 gal
21,400 MM Btu
498,000 M gal
9,320,000 kwh
102.40/ton
90.007 ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.07/M galb
0.007/kwhb
1.017
.593
.025
1.635
Table A-75. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-M.nO2 Slurry Scrubbi.ng-Regeneration
(200-mw new oil-fired power unit, 2.5% S in fuel; 24,100 tons/yr 100% H2SO4 )
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 6,806,000
Analyses
Subtotal conversion costs
Subtotal direct costs
24,500
14,300
600
39,400
170,200
163,900
(8,600)
34,900
65,200
476,400
30.000
932,000
971,400
7.062
6.801
(.357)
1.448
2.705
19.768
1.245
38.672
40.307
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2 S04
680,600
136,100
186,400
65,200
1,068,300
2,039,700
28.241
5.647
7.734
2.706
44.328
84.635
aBasis:
Fuel oil burned, 2,058,200 BBL/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175° F.
Midwest plant location-1972 costs.
Capital investment, $6,806,000; working capital, $169,000.
^Cost of utility supplied from power plant at full value.
222
-------
579 tons
386 tons
959 liters
32,520 man-hr
4,454,000 gal
52,300 MM Btu
1,217,000 M gal
22,780,000 kwh
59,300
34,700
1,400
95,400
Table A-76. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgQ-MnO2 Slurry Scrubbing-Regeneration
(500-mw new oil-fired power unit, 2.5% S in fuel; 58,900 tons/yr 100% H2SO4 )
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 12,561,000
Analyses
Subtotal conversion costs
Subtotal direct costs
102.407 ton
90.007 ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
195,100
400,900
(20,900)
60,900
136,700
753,700
66,000
1,592,400
1,687,800
1.007
.589
.024
1.620
3.312
6.807
(.355)
1.034
2.321
12.796
1.120
27.035
28.655
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
1,256,100
251 ,200
318,500
1 1 1 .500
1,937,300
3,625,100
21.326
4.265
5.407
1.894
32.892
61.547
aBasis:
Fuel oil burned, 5,033,600 BBL/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175° F.
Midwest plant location-1972 costs.
Capital investment, $12,561,000; working capital, $294,800.
Cost of utility supplied from power plant at full value.
223
-------
Table A-77. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme B—MgO-IVInO2 Slurry Scrubbing-Regeneration
(1000-mw new oil-fired power unit, 2.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Manganese dioxide
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 19,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
1,1 08 tons
739 tons
1,855 liters
39,200 man-hr
8,6 11, 000 gal
101, 000 MM Btu
2,352,000 M gal
44,050,000 kwh
126,000
in fuel; 11 3, 900 tons/yr
Unit cost, $
1 02.40/ ton
90. 007 ton
1.51/liter
6.007 man-hr
0.09/gal
-0.407 MM.Btu
0.047 M galb
0.0057 kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
Total annual
cost, $
113,500
66,500
2,800
182,800
235,200
775,000
(40,400)
94,100
220,300
956,300
121,000
2,361,500
2,544,300
1,912,600
382,500
472,300
165,300
2,932,700
5,477,000
Cost/ton
of acid, $
.996
.584
.025
1.605
2.065
6.805
(.355)
.826
1.934
8.396
1.062
20.733
22.338
16.792
3.358
4.147
1.451
25.748
48.086
aBasis:
Fuel oil burned, 9,731,500 BBL/yr-8,700 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175 F.
Midwest plant location-1972 costs.
Capital investment, $19,126,000; working capital, $445,700.
"Cost of utility supplied from power plant at full value.
224
-------
Table A-78. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration
• • M E
(200-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%) 373 tons
Coke 130 tons
Catalyst 630 liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 30,440 man-hr
Utilities
Fuel oil 1,836,000 gal
Steam 247,000 M Ib
Heat credit 40,400 MM Btu
Process water 837,300 M gal
Electricity 24,583,000 kwh
Maintenance
Labor and material, .07 x 9,923,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
in fuel; 38,700 tons/yr
Unit cost, $
102.407 ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.60/M lbb
-0.40/MM Btu
0.05/M galb
0.007/kwhb
100%H>2SO4)
Total annual
cost, $
38,200
3,100
1,000
42,300
182,600
165,200
148,200
(16,200)
41,900
172,100
694,600
38,000
1 ,426,400
1,468,700
992,300
198,500
285,300
99,800
1 ,575,900
3,044,600
Cost/ton
of acid, $
.987
.080
.026
1.093
4.718
4.269
3.829
(.419)
1.083
4.447
17.948
.982
36.858
37.951
25.641
5.129
7.372
2.579
10.721
78.672
aBasis:
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location-1972 costs.
Capital investment, $9,923,000; working capital, $252,000.
^Cost of utility supplied from power plant at full value.
225
-------
Table A-79. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gasa
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration
. — . • .t-g_... . • .
(500-mw new coal-fired power unit, 3.5% S
Annual quantity
Direct Costs
Delivered raw material
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x 18,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
911 tons
319 tons
1,542 liters
39,200 man-hr
4,490,000 gal
604,000 M Ib
98,700 MM Btu
2,048,800 M gal
60, 11 9,000 kwh
1 1 1 ,000
in fuel; 94, 700 tons/yr
Unit cost, $
102.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
0.55/M lbb
-0.40/MM Btu
0.03/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
100%H2S04)
Total annual
cost, $
93,300
7,500
2,300
103,100
235,200
404,100
332,200
(39,500)
61,500
360,700
1,086,700
73,000
2,513,900
2,617,000
1,811,100
362,200
502,800
Cost/ton
of acid, $
.986
.079
.024
1.089
2.484
4.267
3.508
(.417)
.649
3.809
11.475
.771
26.546
27.635
19.125
3.825
5.309
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
176,000
2,852,100
5,469,100
1.858
30.117
57.752
aBasis:
Coal burned, 1,312,500 tons/yr-9,000 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175° F.
Midwest plant location-1972 costs.
Capital investment, $18,111,000; working capital, $449,600.
"Cost of utility supplied from power plant at full value.
226
-------
Table A-80. Nonregulated Company Economics—Total Venture Annual Manufacturing
Costs for 98% H2SO4 from Scrubbed Power Plant Stack Gas3
Scheme C—Magnesia Clear Liquor Scrubbing-Regeneration
(1000-mw new coal-fired power unit, 3.5% S in fuel; 183,000 tons/yr 100% H2SO4 )
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 1,761 tons
Coke 617 tons
Catalyst 2,980 liters
Subtotal raw material
102.40/ton
23.50/ton
1.51/liter
180,300
14,500
4,500
199,300
47,960 man-hr
8,681,000 gal
1,168,000 M Ib
190,800 MM Btu
3,961,500 M gal
116,228,000 kwh
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 27,540,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs for H2S04
6.OO/man-hr
0.09/gal
0.50/M lbb
-0.40/MM Btu
0.02/M galb
0.005/kwhb
287,800
781,300
584,000
(76,300)
79,200
581,100
1,377,000
119,000
3,733,100
3,932,400
2,754,000
550,800
746,600
261,300
4,312,700
8,245,100
.985
.079
.025
1.089
1.573
4.269
3.191
(.417)
.433
3.175
7.525
.650
20.399
21.488
15.049
3.010
4.080
1.428
23.567
45.055
aBasis:
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Power unit on-stream time, 7,000 hr/yr; acid plant on-stream time, 7,000 hr/yr.
Stack gas reheat to 175°F.
Midwest plant location—1972 costs.
Capital investment, $27,540,000; working capital, $676,500.
Cost of utility supplied from power plant at full value.
227
-------
Table A-81. Cooperative Economics—Joint Power-Chemical Company Venture
Regulated Power Company Portion
Annual Manufacturing Costs for Mangesium Sulfite
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Slurry Scrubbing-Drying System
(200-mw new coal-fired power unit, 3.5% S in fuel; 56,250 tons/yrMgSO3)
Total annual Cost/ton of
Annual quantity Unit cost, $ cost, $ MgSQ,. $
Direct Costs
Delivered raw material
Lime
Make-up magnesium oxide (98%)
Shipping cost for recycle MgOc
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Maintenance
Labor and material, .07 x 7,671,000
Analyses
Subtotal conversion costs
54.8 tons
623 tons
23,600 tons
21,680man-hr
1,014,000 gal
80,000 M Ib
85,000 M gal
22,523,000 kwh
16.00/ton
102.40/ton
2.40/ton
6.00/man-hr
0.097 gal
0.60/M lbb
0.05/M gal
0.007/kwhb
900
63,800
56,600
121,300
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
130,100
91,300
48,000
4,300
158,000
537,000
27.000
995,700
1,117,000
Total annual manufacturing costs for MgS03
Cost/ton
of coal
burned,$
1,143,000
199,100
39.800
1,381,900
Total
annual
cost, $
0.016
1.135
1.006
2.157
2.313
1.623
0.853
0.076
2.809
9.547
0.480
17.701
19.858
4.656
20.320
3.540
0.708
24.568
Cost/ton of
MgSO^.S
2,498,900 44.426
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr-9,200 Btu/kwh.
Stack gas reheat to 175° F.
Power unit on-steam time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $7,671,000; working capital, $189,600.
Cost of utility supplied from power plant at full value.
cAverage shipping distance between power plant and regeneration plant-25 miles, truck shipping assumed.
228
-------
Table A-82. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 200-mw new coal-fired power unit, 3.5% S in fuel; 45,200 tons/yr 100% H^
Magnesium sulfite source— one 200-mw unit
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .07 x 5,017
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
56,250 tons
56,250 tons
31 2 tons
736 liters
21,680 man-hr
1,1 41, 000 gal
4,352 MM Btu
820,000 M gal
5,033,600 kwh
,000
44.437 ton
2.40/ton
23.507 ton
1.51/liter
6.00/ man-hr
0.09/gal
-0.40/MM Btu
0.05/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing costs for H2S04
2,498,900
135,000
7,300
1,100
2,642,300
130,100
102,700
(1,700)
41,000
30,200
351,200
18,000
671,500
3,313,800
501,700
100,300
134,300
99,400
835,700
4,149,500
Cost/ton
of acid, $
55.285
2.987
0.162
0.024
58.458
2.877
2.272
(0.038)
0.907
0.668
7.770
0.398
14.854
73.312
11.100
2.220
2.971
2.200
18.491
91.803
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8^000 hr/yr.
Acid stack gas reheat to 175 F.
Capital investment, $5,017,000; working capital, $629,200.
bCost of utility supplied at full value.
cAveiage shipping distance between Power Plant and Regeneration-Acid Plant—25 miles, truck shipping assumed.
229
-------
Table A-83. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 1000-mw new coal-fired power unit, 3.5% S in fuel; 226,000 tons/yr 100% H2SO4 )
Magnesium sulfite source—five 200-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 12,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
281, 250 tons
281, 250 tons
1,560 tons
3,680 liters
30,440 man-hr
5,705,000 gal
21, 760 MM Btu
4,1 00,000 M gal
25,1 68,000 kwh
354,000
44.43/ton
2. 407 ton
23. 507 ton
1.51/liter
6.007 man-hr
0.097 gal
-0.407 MM Btu
0.02/M galb
0.0067 kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
1 2,494,500
675,000
36,700
5,600
13,211,800
182,600
513,500
(8,700)
82,000
151,000
494,200
58,000
1 ,472,600
14,684,400
1,235,400
247,100
294,500
440,600
2,217,600
16,902,000
55.285
2.987
0.162
0.024
58.458
0.808
2.272
(0.039)
0.363
0.668
2.187
0.257
6.516
64.974
5.466
1.093
1.303
1.949
9.811
74.785
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8^000 hi/yr.
Acid stack gas reheat to 175 F.
Capital investment, $12,354,000; working capital, $2,834,000.
"Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant—25 miles, truck shipping assumed.
230
-------
Table A-84. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
.^___ Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 1000-mw new coal-fired power unit, 3.5% S in fuel, 452,000 tons/yr 100% H2SO4 )
Magnesium sulfite source—ten 200-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 19
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
562,500 tons
562,500 tons
3, 120 tons
7,360 liters
37,120 man-hr
11, 41 0,000 gal
43,520 MM Btu
8,200,000 M gal
50,336,000 kwh
,534,000
44.437 ton
2.40/ton
23.507 ton
1.51/liter
6.007 man-hr
0.097 gal
-0.407 MM Btu
0.02/M galb
0.0067 kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
24,989,000
1 ,350,000
73,300
11,100
26,423,400
222,700
1,026,900
(17,400)
164,000
302,000
781,400
79,000
2,558,600
28,982,000
1,953,400
390,700
511,700
869,500
3,725,300
32,707,300
55.285
2.987
0.162
0.024
58.458
0.493
2.272
(0.039)
0.363
0.668
1.729
0.175
5.661
64.119
4.322
0.864
1.132
1.924
8.242
72.361
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175 F.
Capital investment, $19,534,000; working capital, $5,604,000.
''Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant—25 miles, truck shipping assumed.
231
-------
Table A-85. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 3000-mw new coal-fired power unit, 3.5% S in 'fuel; 678,000 tons/yr 100% H2SO4 )
Magnesium sulfite source—fifteen 200-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 26,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
843,750 tons
843,750 tons
4,680 tons
11, 040 liters
39,200 man-hr
17,1 15,000 gal
65,280 MM Btu
1 2,300,000 M gal
75,504,000 kwh
096,000
44.437 ton
2.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0. 097 gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
37,483,500
2,025,000
110,000
16,700
39,635,200
235,200
1 ,540,400
(26,100)
246,000
453,000
1 ,043,800
105.000
3,597,300
43,232,500
2,609,600
521,900
719,500
1,297.100
5,148,100
48,380,600
55.285
2.987
0.162
0.024
58.458
0.347
2.273
(0.039)
0.363
0.668
1.540
0.155
5.307
63.765
3.849
0.770
1.061
1.913
7.593
71.358
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175 ° F.
Capital investment, $26,096,000; working capital, $8,366,200
"Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
232
-------
Table A-86. Cooperative Economics—Joint Power-Chemical Company Venture
Regulated Power Company Portion
Average Annual Manufacturing Costs for Magnesium Sulfite
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Slurry Scrubbing-Drying System
(500-mw new coal-fired power unit, 3.5% S in fuel-133,580 tons/yr 100%MgS03)
Total annual Cost/ton of
Annual quantity Unit cost, $ cost, $ MgS03, $
Direct Costs
Delivered raw material
Lime 134.1 tons
Make-up magnesium oxide (98%) 1,480 tons
Shipping cost for recycle MgOc 56,000 tons
Subtotal raw material
16.007 ton
102.407 ton
2.40/ton
2,100
151,600
134,400
288,100
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Maintenance
Labor and material, .06 x 14,844,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of initial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
21,680 man-hr
2,480,000 gal
195,000 M Ib
208,000 M gal
55,082,000 kwh
6.007 man-hr
0.09/gal
0.55/M lbb
0.03/M galb
0.006/kwhb
Total annual manufacturing costs for MgS03
Cost/ton
of coal
burned,$
130,000
223,200
107,300
6,200
330,500
890,600
57,000
1,744,800
2,032,900
2,211,800
349,000
71,600
2,632,400
Total
annual
cost, $
0.016
1.135
1.006
2,157
3.555
4,665,300
0.973
1.671
0.803
0.046
2.474
6.667
0.427
13.061
15.218
16.558
2.613
.536
19.707
Cost/ton of
MgS03,$
34.925
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, l,312,500otons/yr-9,000 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location-197 2 costs.
Capital investment, $14,844,000; working capital, $334,200.
^Cost of utility supplied from power plant at full value.
cAverage shipping distance between power plant and regeneration plant-25 miles, truck shipping assumed.
233
-------
Table A-87. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 500-mw new coal-fired power unit, 3.5% S in fuel; 110,400 tons/yr 100% h
Magnesium sulfite source— one 500-mw unit
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
133,580 tons
133,580 tons
740 tons
1,800 liters
28,360 man-hr
2,790,000 gal
10,884 MM Btu
2,000,702 M gal
1 2,584,000 kwh
34.937 ton
2.40/ton
23.507 ton
1.51/liter
6.007 man-hr
0.097 gal
-0.407 MM Btu
0.03/Mgalb
0.0067 kwhb
Labor and material, .06 x 8,294,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
4,665,300
320,600
17,400
2,700
5,006,000
1 70,200
251,100
(4,400)
60,000
75,500
497,600
38,000
1,088,000
6,094,000
829,400
165,900
217,600
196,500
1 ,409,400
7,503,400
?a SO4 )
Cost/ton
of acid, $
42.258
2.904
0.158
0.024
45.344
1.542
2.275
(0.040)
0.543
0.684
4.507
0.344
9.855
55.199
7.513
1.503
1.917
1.780
12.767
67.966
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175°F.
Capital investment, $8,294,000; working capital, $1,143,000.
^Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
234
-------
Table A-88. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 1000-mw new coal-fired power unit, 3.5% S in fuel; 220,800 tons/yr 100% H2SO4)
Magnesium sulfite source—two 500-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
267, 160 tons
267, 160 tons
1,480 tons
3,600 liters
30,440 man-hr
5,770,792 gal
22,504 MM Btu
4,1 38,220 M gal
26,028,545 kwh
34.93/ton
2.40/ton
23.50/ton
1.51/liter
6. OO/ man-hr
0.09/gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Labor and material, .04 x 12,354,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
9,330,600
641 ,200
34,800
5,400
10,012,000
182,600
519,400
(9,000)
82,800
1 56,200
494,200
57,000
1 ,483,200
1 1 ,495,200
1 ,235,400
247,100
296,600
342,600
2,121,700
13,616,900
42.258
2.904
.158
.024
45.344
.827
2.352
(0.40)
.375
.707
2.238
.258
6.717
52.061
5.595
1.119
1.343
1.552
9.609
61.670
"Basis:
Midwest plant location—1972 costs.
Acid plant on-stream time, SjOOO hr/yr.
Acid stack gas reheat to 175 F.
Capital investment, $12,354,000; working capital, $2,163,000.
Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
235
-------
Table A-89. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 2000-mw new coal-fired power unit, 3.5% S in fuel; 441,600 tons/yr 100% H2SO4)
Magnesium sulfite source—four 500-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 19,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
534,320 tons
534,320 tons
2,960 tons
7,200 liters
37,120man-hr
11, 54 1,584 gal
45,008 MM Btu
8,276,440 M gal
52,057,090 kwh
534,000
34.937 ton
2.407 ton
23.50/ton
1.51/liter
6.007 man-hr
0.09/gal
-0.407 MM Btu
0.027 M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
18,66T,200
1,282,400
69,600
10,800
20,024,000
222,700
1 ,038,700
(18,000)
165,500
312,300
781,400
77,000
2,579,600
22,603,600
1 ,953,400
390,700
515,900
658,100
3,518,100
26,121,700
42.258
2.904
0.158
0.024
45.344
0.504
2.352
(0.041)
0.375
0.707
1.770
0.174
5.841
51.185
4.423
0.885
1.168
1.491
7.967
59.152
aBasis:
Midwest plant location-1972 costs.
Acid plant cm-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175° F.
Capital investment, $19,534,000; working capital, $4,260,000.
''Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant—25 miles, truck shipping assumed.
236
-------
Table A-90. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 3000-mw new coal-fired power unit, 3.5% S in fuel; 662,400 tons/yr 100% H2SO4 )
Magnesium sulfite source— six 500-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfitec
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .03 x 26,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
801, 480 tons
801, 480 tons
4,440 tons
10,800 liters
39,200 man-hr
17,3 12,376 gal
67,512 MM Btu
1 2,41 4,660 M gal
78,085,635 kwh
096,000
34.937 ton
2.40/ton
23.50/ton
1.51/liter
6.00/ man-hr
0.09/gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
27,991,800
1,923,600
104,300
16,300
30,036,000
235,200
1,558,100
(27,000)
248,300
468,500
782,900
102,000
3,368,000
33,404,000
2,609,600
521,900
673,600
952,100
4,757,200
38,161,200
42.258
2.904
.158
.024
45.344
0.355
2.352
(0.041)
0.375
.707
1.182
0.154
5.084
50.428
3.940
0.788
1.017
1.437
7.182
57.610
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175°F.
Capital investment, $26,096,000; working capital, $6,304,200.
''Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
237
-------
Table A-91.Cooperative Economics—Joint Power-Chemical Company Venture
Regulated Power Company Portion
Annual Manufacturing Costs for Magnesium Sulfite
from Scrubbed Power Plant Stack Gasa
(1000-mw new coal-fired power unit, 3.5% S in fuel; 258,250 tons/yr MgSO3)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime
Make-up magnesium oxide (98%)
Shipping cost for recycle MgOc
Subtotal raw material
259.2 tons
2,861 tons
108,265 tons
16.007 ton
102.40/ton
2.40/ton
4,100
293,000
259,800
556,900
Cost/ton of
MgSO,,$
0.016
1.134
1.006
2.156
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Maintenance
Labor and material, .06 x 22,673,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of in'rtial fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
30,440 man-hr
4,795,000 gal
377,000 M Ib
402,000 M gal
106,490,000 kwh
6.00/man-hr
0.09/gal
0.50/M lbb
0.02/M galb
0.005/kwhb
Total annual manufacturing costs for MgSO3
Cost/ton
of coal
burned,$
2.920
182,600
431,600
188,500
8,000
532,500
1,360,400
94,000
2,797,600
3,354,500
3,378,300
559,500
117,000
4,054,800
Total
annual
cost, $
7,409,300
0.707
1.671
0.730
0.031
2.062
5.268
0.364
10.833
12.989
13.081
2.167
.453
15.701
Cost/ton of
MgSO-,. $
28.690
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr-8,700 Btu/kwh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location-1972 costs.
Capital investment, $22,673,000; working capital, $568,300.
"Cost of utility supplied from power plant at full value.
cAverage shipping distance between power plant and regeneration plant-25 miles, truck shipping assumed.
238
-------
Table A-92. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 1000-mw new coal-fired power unit, 3.5% S in fuel; 213,500 tons/yr 100% I
Magnesium sulfite source—one 1000-mw unit
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 12,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
258,250 tons
258,250 tons
1 ,480 tons
3,480 liters
30,440 man-hr
5,580,000 gal
21,760 MM Btu
4, 00 1, 404 M gal
25,1 68,000 kwh
354,000
28.69/ton
2.40/ton
23. 507 ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2SO4
7,409,300
619,800
34,800
5,200
8,069,100
182,600
502,200
(8,700)
80,000
151,000
494,200
56,000
1 ,457,300
9,526,400
1 ,235,400
247,000
291,500
290,900
2,064,800
11,591,200
Cost/ton
of acid, $
34.704
2.903
0.163
0.024
37.794
0.855
2.352
(0.040)
0.375
0.707
2.315
0.262
6.826
44.620
5.786
1.157
1.365
1.362
9.670
54.290
aBasis:
Midwest plant location—1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175° F.
Capital investment, $12,354,000; working capital, $1,833,200.
^Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
239
-------
Table A-93. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 2000-mw new coal-fired power unit, 3.5% S in fuel; 427,000 tons/yr 100% H2SO4 )
Magnesium sulfite source—two 1000-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfite0
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 19,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
5 16,500 tons
5 16,500 tons
2,960 tons
6,960 liters
37,120man-hr
11, 160,000 gal
43,520 MM Btu
8,002,808 M gal
50,336,000 kwh
534,000
28.69/ton
2.40/ton
23.507 ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2SO4
14,818,600
1 ,239,600
69,600
10,500
16,138,300
222,700
1 ,004,400
(17,400)
160,000
302,000
781,400
75,000
2,528,100
18,666,400
1 ,953,400
390,700
505,600
554,800
3,404,500
22,070,900
34.704
2.903
0.163
0.025
37.795
0.521
2.352
(0.041)
0.375
0.707
1.830
0.176
5.920
43.715
4.574
0.915
1.184
1.300
7.973
51.688
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8,000 hr/yr.
Acid stack gas reheat to 175° F.
Capital investment, $19,534,000; working capital, $3,600,500.
"Cost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
240
-------
Table A-94. Cooperative Economics—Joint Power-Chemical Company Venture
Nonregulated Chemical Company Portion
Annual Manufacturing Costs for 98% H2 SO4
from Scrubbed Power Plant Stack Gasa
Scheme D—Magnesia Regeneration-Acid Manufacture
(Equivalent to 3000-mw new coal-fired power unit, 3.5% S in fuel; 640,500 tons/yr 100% H2S04 )
Magnesium sulfite source—three 1000-mw units
Total annual Cost/ton
Annual quantity Unit cost, $ cost, $ of acid, $
Direct Costs
Delivered raw material
Magnesium sulfite
Shipping cost for magnesium
sulfitec
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil
Heat credit
Process water
Electricity
Maintenance
Labor and material, .03 x 26,
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
774,750 tons
774,750 tons
4,440 tons
10,440 liters
39,200 man-hr
16,740,000 gal
65,280 MM Btu
12,004,212 M gal
75,504,000 kwh
096,000
28.697 ton
2.40/ton
23.50/ton
1.51/liter
6.00/man-hr
0.09/gal
-0.40/MM Btu
0.02/M galb
0.006/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service
Subtotal indirect costs
Total annual manufacturing
costs for H2S04
22,227,900
1 ,859,400
104,300
15,800
24,207,400
235,200
1 ,506,600
(26,100)
240,000
453,000
782,900
99,000
3,290,600
27,498,000
2,609,600
521,900
658,100
797,200
4,586,800
32,084,800
34.704
2.903
0.163
0.025
37.795
0.367
2.352
(0.041)
0.375
0.707
1.222
0.155
5.137
42.932
4.074
0.815
1.028
1.245
7.162
50.094
aBasis:
Midwest plant location-1972 costs.
Acid plant on-stream time, 8^000 hr/yr.
Acid stack gas reheat to 175 F.
Capital investment, $26,096,000; working capital, $5,314,900.
bCost of utility supplied at full value.
cAverage shipping distance between Power Plant and Regeneration-Acid Plant-25 miles, truck shipping assumed.
241
-------
to
->.
to
Table A-95
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MM. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
11685000
Includes comparison with projected operating cost of low-cost limestone process
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 TOCO
6 7000
7 7000
8 7000
9 7000
1Q 7000 .
11 5000
12 5000
13 5000
14 5000
15 5QOO-
16 3500
17 3500
18 3500
19 3500
20 _25CO
21 1500
22 1500
23 1500
24 1500
_21 1502-
26 1500
27 1503
28 1500
29 1500
30_ 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
45200
45200
45200
45200
45200 .
45200
45200
45200
45200
- - 45200
32300
32300
32300
32300
3230.0,
22600
22600
22600
22600
22600
9700
9700
97JO
9700
2100 -
9700
9700
9700
9700
_97QO
823500
COST, DOLLARS
TOTAL
MFG. COST
INCLUDING
REGULATED NET
ROI FOR
POWER
COMPANY,
S/YEAR
5086300
5005300
4924200
4843200
4262200-
4681200
4600200
4519200
4438200
REVENUE,
t/TON
100?
H2S04
8.00
8.00
8.00
8.00
8.QQ
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
361600
361600
361600
361600
261600
361600
361600
361600
361600
4257100 .8.00 361600
3809100
3728100
3647100
3566100
5.00
5.00
5.00
5.00
161500
161500
161500
161500
24S510.fi 5«.QQ 1615QQ
3027000
2946000
2865000
2784000
.2703000 _ . _
2047700
1966600
1885600
1804600
172360Q __
1642600
1561600
1480500
1399500
_ 1212500
96608400
PER TON OF COAL
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5&Q..O.
5.00
5.00
5.00
5.00
5*00
BURNED
113000
113000
113000
113000
112QQQ _
48500
48500
48500
48500
48500
48500
48500
48500
48500
485QQ
5473500
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH,
PRESENT WORTH,
AT 10.0? TO INITIAL YEAR
DOLLARS PER TON
OF COAL
, DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
4724700
4643700
4562600
4481600
_ 4400600
4319600
4238600
4157600
4076600
222550C
3647600
3566600
3485600
3404600
2222600
2914000
2833000
2752000
2671000
_ 2520000
1999200
1918100
1837100
1756100
1625100
1594100
1513100
1432000
1351000
1210000
91134900
9.32
3.57
36354900
3.72
1,43
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4724700
9368400
13931000
18412600
22fil22QQ
27132800
31371400
35529000
39605600
42601100
47248700
50815300
54300900
57705500
61022100
63943100
66776100
69528100
72199100
747891QO
76788300
78706400
80543500
82299600
22214100
85568800
87081900
88513900
89864900
9H349QO
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR t $
3825400
3761700
3698000
3634200
2520500 J
3506800
3443000
3379300
3315600
2251200 _J
2868100
2804400
2740700
2676900
2612200 J
2288900
2225100
2161400
2097700
2022200
1567700
1504000
1440200
1376500
1312800
1249100
1185300
1121600
1057900
8993001
882000)
864600)
847400)
L S.221001-J
812800)
795600)
778300)
761000)
L 2426001 J
7795001
7622001
7449001
727700)
L 1104001 J
625100)
607900)
5906001
573300)
L 5561001 J
431500)
414100)
396900)
3796001
L 3623001
3450001
327800)
3104001
293100)
899300)
1781300)
2645900)
3493300)
L_ 42234201
5136200)
5931800)
6710100)
7471100)
L_ £2141201
8994200)
9756400)
105013001
11229000)
1123.24021
12564500)
13172400)
13763000)
14336300)
L_ 14.82Z4021
15323900)
15738000)
16134900)
16514500)
16SJ6BOQ1
17221800)
17549600)
17860000)
181531001
224100 i 2252021-1 18.4220.201
72705900 ( 18429000)
7.44
2.85
29257300 ( 7097600)
2.99
1.15
-------
Table A-96
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MW. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
11685000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YFARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR J/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100% COMPANY, 100* REVENUE,
START KW H2S04 t/YEAR H2S04 $/YEAR
1 7000 45200 5086300 8.00
2 7000 45200 5005300 8.00
3 7000 45200 4924200 8.00
4 7000 45200 4843200 8.00
5 1000 4.5.200 4162200 fi^OO
6 7000 45200 4681200 8.00
7 7000 45200 4600200 8.00
8 7000 45200 4519200 8.00
9 7000 45200 4438200 8.00
10 7000 45200 43511QQ 8*00
11 5000 32300 3809100 5.00
12 5000 32300 3728100 5.00
13 5000 32300 3647100 5.00
14 5000 32300 3566100 5.00
11_ 5.0QQ_ 22200- _ 24.fl5J.QQ 5,^00 _
16 3500 22600 3027000 5.00
17 3500 22600 2946000 5.00
18 3500 22600 2865000 5.00
19 3500 22600 2784000 5.00
20 35QQ 22600 __ _27Q3QOO .. . _ _ 5*00
21 1500 9700 2047700 5.00
22 1500 9700 1966600 5.00
23 1500 9700 1885600 5.00
24 1500 9700 1804600 5.00
26 1500 9700 1642600 5.00
27 1500 9700 1561600 5.00
28 1500 9700 1480500 5.00
29 1500 9700 1399500 5.00
3fl 1500 2700 1318500 5*00
TOT 127500 823500 96608400
EQUIVALENT COST, DOLLARS PER TON OF COAL BURNED
EQUIVALENT COST, MILLS PER KILOWATT-HOUR
PRESENT WORTH IF DISCOUNTED AT 10.0* TO INITIAL YEAR
EQUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR
to
U)
361600
361600
361600
361600
2616QO
361600
361600
361600
361600
261600
161500
161500
161500
161500
11300C
113000
113000
113000
112QOQ
48500
48500
48500
48500
4^50.0
48500
48500
48500
48500
5473500
, DOLLARS
BURNED
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
4724700
4643700
4562600
4481600
4400600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4724700
9368400
13931000
18412600
22813200
4319600 27132800
4238600 31371400
4157600 35529000
4076600 39605600
2225.5.00 426.0.1100—
3647600 47248700
3566600 50815300
3485600 54300900
3404600 57705500
_222260Q_ _&1Q221QQ .
2914000
2833000
2752000
2671000
252QQflfl__
1999200
1918100
1837100
1756100
1594100
1513100
1432000
1351000
122QQQO__
91134900
9.32
3.57
36354900
3.72
1.43
63943100
66776100
69528100
72199100
242fi21Qfl_
76788300
78706400
80543500
82299600
83974.100
85568800
87081900
88513900
89864900
__ 21124.200.
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
J/YEAR $ *
4388700
4338300
4288000
4237700
41B22Qfl__J
4137000
4086700
4036300
3986000
2225JQQ J
3252900
3202600
3152200
3101900
30516fifl__J
2508100
2457800
2407500
2357100
22Q6flQQ J
1550300
1499900
1449600
1399300
1298600
1248200
1197900
1147600
102220fl__J
82657700
8.46
3.24
33873300
3.47
1.33
336000)
305400)
274600)
243900)
L 2122QQ1-J
182600)
151900)
121300)
90600)
L 52fiQQl_J
394700)
364000)
333400)
302700)
L 2220001_J
405900)
375200)
344500)
313900)
L 2B.22QQ1_J
448900)
418200)
387500)
356800)
L 2262QQ1-J
295500)
264900)
234100)
203400)
L 122flQ01_J
8477200)
2481600)
336000)
641400)
916000)
1159900)
L 12222001
1555800)
1707700)
1829000)
1919600)
L 12224001
2374100)
2738100)
3071500)
3374200)
1 264.6200.1
4052100)
4427300)
47718001
5085700)
5817800)
6236000)
6623500)
6980300)
L_ 22065001
76020001
7866900)
8101000)
8304400)
1 64222001
-------
Table A-97
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MW. EXISTING COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
13083000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
8
9 7000
12 1222-
11 5000
12 5000
13 5000
14 5000
_15__ 5_QO_0_
16 3500
17 3500
18 3500
19 3500
22 3_522_
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 71500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
46600
466.0.0.
33300
33300
33300
33300
22222
23300
23300
23300
23300
_222C2
10000
10000
10000
10000
10.0.0.2
10000
10000
10000
10000
-12222
476200
COST, DOLLARS
INCLUDING
REGULATED NET
ROI FOR
POWER
COMPANY,
$/YEAR
5657300
5522622
4923700
4800000
4676300
4552600
442S90Q _
3911100
3787400
3663700
3540000
3416300
2688800
2565100
2441400
2317700
219.4Q.O.O. _ _
2070300
1946600
1822900
1699200
15.15.5.0.0.
74212400
PER TON OF COAL
REVENUE,
J/TON
100%
H2S04
8.00
8_t2fl
8.00
8.00
8.00
8.00
S..22
8.00
8.00
8.00
5.00
_5*22
5.00
5.00
5.00
5.00
5*20
5.00
5.00
5.00
5.00
5*22 .
BURNED
TOTAL
NET
SALES
REVENUE,
t/YEAR
372800
. -222222 _
266400
266400
266400
266400
26.6.40.0. _
186400
186400
186400
116500
116.50.0. _
50000
50000
50000
50000
. 52222
50000
50000
50000
50000
52222
3369800
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH,
PRESENT WORTH,
AT 10.0* TO INI
DOLLARS PER TON
TIAL YEAR,
DOLLARS
OF COAL BURNED
MILLS PER KILOWATT-HOUR
NET ANNUAL
INCREASE
(DECREASEI
IN COST OF
POWER,
$
5284500
5162222—
4657300
4533600
4409900
4286200
_ 4162522—
3724700
3601000
3477300
3423500
32998QO
2638800
2515100
2391400
2267700
2144222-.
2020300
1896600
1772900
1649200
-152552J3-.
70842600
12.52
4.95
34079300
6.02
2.38
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
5284500
12445222- .
15102600
19636200
24046100
28332300
.2242420.2 _.
36219500
39820500
43297800
46721300
52221122
52659900
55175000
57566400
59834100
61222122 _
63998400
65895000
67667900
69317100
22242622
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
4276000
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
$ $
( 1008500)
4112522- I 2ai3Qfll I
3741100
3644600
3548100
3451600
._ 2255122—
2979200
2882700
2786200
2689700
2522122
2064200
1967700
1871200
1774700
_ -1622222
1581700
1485200
1388600
1292100
916200)
889000)
861800)
8346001
. 2224221-
745500)
7183001
691100)
733800)
i 2262221
574600)
547400)
520200)
493000)
i 4652221
( 438600)
( 411400)
( 384300)
( 357100)
1008500)
12426021
2906000)
3795000)
4656800)
5491400)
62S22221
7044300)
7762600)
84537001
9187500)
22242221
10468800)
11016200)
11536400)
12029400)
124252221
12933800)
13345200)
13729500)
14086600)
_ 1125.622 L 329900) ( 14416500)
56426100
9.97
3.95
27307600
4.82
1.91
( 14416500)
( 6771700)
-------
Table A-98
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIREO POWER PLANT, 2.0 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
18788000
Includes comparison
with projected operating cost of low-cost limestone process
PRODUCT R4TE,
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
12
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
22
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7COO
7000
7000
2222- -
7000
7000
7000
7000
7QOQ
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
EQUIVALENT
TONS/YEAR
100%
H2S04
63100
63100
03100
63100
62122
63100
63100
63100
63100
62122
45100
45100
45100
45100
4519Q
31600
31600
31600
31600
.31600... _
13500
13500
13500
13500
TOTAL
"FG. COST
INCLUDING
REGULATED NET
ROI FOR
POWER
COMPANY,
S/YEAR
7868500
7739200
7608000
7477730
__2242422_
7217200
7086900
6956600
6826300
6626122
5861400
5731100
5600900
5470600
_ 5242222- _
4645900
4515700
4385400
4255100
_ 4124222
3149000
3018700
2888500
2758200
13500 7627900
13500
13500
13500
13500
1252fi
2497600
2367400
2237100
2106800
—1216622 __
REVENUE,
i/TON
100?
H2S04
8.00
8.00
8.00
8.00
_ fl«.22
8.00
8.00
8.00
8.00
fl^.22 _
5.00
5.00
5.00
5.00
_5«.22_
5.00
5.00
5.00
5.00
5«.22 _
5.00
5.00
5.00
5.00
5^22
5.00
5.00
5.00
5.00
_ 5*22
TOTAL
NET
SALES
REVENUE,
t/YEAR
504800
504800
504800
504800
524B22
504800
504800
504800
504800
524.222 .
225500
225500
225500
225500
-225522 .
158000
158000
158000
158000
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
7363700
7233400
7103200
6972900
68.42622
6712400
6582100
6451800
6321500
6121322
5635900
5505600
5375400
5245100
5114322
4487900
4357700
4227400
4097100
152222 3366300
67500
67500
67500
67500
-62522 .
67500
67500
67500
67500
3081500
2951200
2821000
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
7363700
14597100
21700300
28673200
25515B22
42228200
48810300
55262100
61583600
62114222
73410800
78916400
84291800
89536900
24651122
99139600
103497300
107724700
111821800
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
$/YEAR $ $
6483500
6371300
6259200
6147100
6224222
5922800
5810700
5698500
5586400
5424322-
4840900
4728800
4616700
4504500
4222422
3853100
3746000
3633800
3521700
115iafil22_ 34.09.600
118870200
121821400
124642400
2690700 127333100
2651800
2539700
2427600
2315400
. _ 2562422 1228.93500 2203300
2430100
2299900
2169600
2039300
132323600
134623500
136793100
138832400
61522 1222122 142241522-.
2091200
1979000
1866900
1754800
880200)
862100)
844000)
825800)
fl222221_J
789600)
771400)
753300)
735100)
L_ 2122221_!
795000)
776800)
758700)
740600)
7224QQ)
629800)
6117001
593600)
575400)
55730Q)
429700)
411500)
393400)
375300)
L _2511221_
338900)
320900)
302700)
284500)
880200)
1742300)
2586300)
3412100)
$2198001
5009400)
5780800)
6534100)
7269200)
7986?OOI
8781200)
9558000)
10316700)
11057300)
112222221
12409500)
13021200)
13614800)
141902001
[ 141415221
15177200)
15588700)
159821001
16357400)
L 162145221
17053400)
17374300)
176770001
17961500)
. 1642622 _i 2665221_i_ Ifl22£2221
TOT 127500 1149500 148382000 7640500 140741500
EOUIVALENT COST, DOLLARS PER TON OF COAL BURNED 5.89
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 2.21
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 56387000
EQUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL BURNED 2.36
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.88
122513500
5.12
1.92
49407100
2.07
0.78
( 182280001
6979900)
to
-------
ON
Table A-99
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT:
21732000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KH
1 7000
2 7000
3 7000
4 7000
„ 5 1000
6 7000
7 7000
8 7000
9 7000
;Q 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
2? 1500 _
26 1500
27 1500
28 1500
29 1500
30 15QQ
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
EQUIVALENT
TONS/YEAR
100%
H2S04
110400
110400
110400
110400
J.1Q40Q
110400
110400
110400
110400
112422
78900
78900
78900
78900
_7B9QQ
55200
55200
55200
55200
55222-
23700
23700
23700
23700
23700
23700
23700
23700
23700
23222-
2011500
COST, DOLLARS
REGULATED NET
ROI FOR
POWER
COMPANY,
S/YEAR
9309800
9159100
9008400
8857700
2222122-
8556400
8405700
8255000
8104400
7953700
6930400
6779700
6629100
6478400
6322222
5481000
5330400
5179700
5029000
4323322-
3690600
3539900
3389200
3238500
_ 3237900
2937200
2786500
2635800
2485200
2334522
175486300
PER TON OF COAL
REVENUE,
S/TON
100?
H2S04
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
883200
883200
883200
883200
NET ANNUAL
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
CUMULATIVE INCLUDING
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
8426600
8275900
8125200
7974500
(DECREASE)
IN COST OF
POWER,
$
8426600
16702500
24827700
32802200
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
7209600 (
7087400 (
6965200 (
6843000 (
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSSI (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
S S
1217000)
11885001
1160000)
1131500)
8.00 883200 7823900 _4Q6261QQ _ 6120900 i 11030001
8.00
8.00
8.00
8.00
_ 3*22
5.00
5.00
5.00
5.00
5«.02
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
-.5. 00,
5.00
5.00
5.00
5.00
5*oo
BURNED
883200
883200
883200
883200
__ 333222
394500
394500
394500
394500
324522
276000
276000
276000
276000
„ 226.222-
118500
118500
118500
118500
11B522--
118500
118500
118500
118500
H8-5QO
13369500
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10.0* TO INITIAL YEAR
, DOLLARS PER TON
OF COAL
, DOLLARS
BURNED
, MILLS PER KILOWATT-HOUR
7673200
7522500
7371800
7221200
--2222522 __
6535900
6385200
6234600
6083900
48299300
55821800
63193600
70414800
_ 22435322-
84021200
90406400
96641000
102724900
5233222 1DS658.1Q2
5205000
5054400
4903700
4753000
_ 4622322-
3572100
3421400
3270700
3120000
113863100
118917500
123821200
128574200
133126522-
136748600
140170000
143440700
146560700
2262422 142532122
2818700
2668000
2517300
2366700
2216222
162116800
6.78
2.54
64708000
2.71
1.02
152348800
155016800
157534100
159900800
162116322
6598700 (
6476500 (
6354300 (
6232100 (
6112222 1.
5381100 (
5258900 (
5136700 (
5014500 (
_ 4322422 1.
4280700 <
4158500 (
4036300 (
3914200 (
3.222222 I.
2926100 (
2803900 (
2681700 (
2559600 (
2432422- i.
2315200 (
2193000 (
2070800 (
1948700 (
1326522 I
136225900 (
5.70
2.14
54984900 (
2.30
0.86
1074500)
1046000)
1017500)
989100)
_ 2625221-
1154800)
1126300)
10979001
1069400)
-12423221-
924300)
895900)
867400)
838800)
3122221-
646000)
617500)
1217000)
2405500)
3565500)
4697000)
5322222J.
6874500)
7920500)
8938000)
99271001
10887600)
12042400)
13168700)
14266600 »
15336000)
L6326B221
17301100)
18197000)
19064400)
19903200)
1 221135221
21359500)
21977000)
589000) ( 22566000)
560400) ( 231264001
5322221-i- 236534221
503500) ( 24161900)
475000) ( 24636900)
446500) ( 250834001
418000) ( 25501400)
3325221 1 253222221
25890900)
9723100)
-------
Table A-100
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 ? S IN FUEL, 98S H2S04 PRODUCTION.
FIXED INVESTMENT:
21732000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
,5 2222—
6 7000
7 7000
8 7000
9 7000
100?
H2S04
110400
110400
110400
110400
-112422 _
110400
110400
110400
110400
„«,_ 2QQQ 110400
11 5000
12 5000
13 5000
14 5000
15 5QQO
16 3500
17 3500
18 3500
19 3500
22_ -3.522
21 1500
22 1500
23 1500
24 1500
2.5 1500 .
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
78900
78900
78900
78900
COMPANY,
S/YEAR
9309800
9159100
9008400
8857700
3222122
8556400
8405700
8255000
8104400
2253222
6930400
6779700
6629100
6478400
Z320.Q_ 6327700 _._
55200
55200
55200
55200
55222
23700
23700
23700
23700
23700
23700
23700
23700
23700
22202
2011500
COST, DOLLARS
5481000
5330400
5179700
5029000
4323322- _
3690600
3539900
3389200
3238500
3087900
2937200
2786500
2635800
2485200
2234.5qo
175486300
PER TON OF COAL
100?
H2S04
8.00
8.00
8.00
8.00
8. 00
8.00
8.00
8.00
8.00
_3*22 _
5.00
5.00
5.00
5.00
5*22- —
5.00
5.00
5.00
5.00
5»OQ .
5.00
5.00
5.00
5.00
5*20
5.00
5.00
5.00
5.00
5.QQ
BURNED
REVENUE,
S/YEAR
883200
883200
883200
883200
282200
883200
883200
883200
883200
-332222-
394500
394500
394500
394500
224502
276000
276000
276000
276000
2760ppr .
118500
118500
118500
118500
113522 _
118500
118500
118500
118500
_ 113522 _
13369500
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10.0* TO INITIAL YEAR,
DOLLARS
, DOLLARS PER TON OF COAL BURNED
, MILLS PER KILOWATT-HOUR
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
NET ANNUAL CUMULATIVE INCLUDING
INCREASE NET INCREASE REGULATED
(DECREASE) (DECREASE) ROI FOR
IN COST OF IN COST OF POWER
POWER,
$
8426600
8275900
8125200
7974500
78239QQ
7673200
7522500
7371800
7221200
2222520 _
6535900
6385200
6234600
6083900
59232PQ
5205000
5054400
4903700
4753000
. 46Q23QQ
3572100
3421400
3270700
3120000
POWER,
$
8426600
16702500
24827700
32802200
42626122
48299300
55821800
63193600
70414800
_ 774853QO
84021200
90406400
96641000
102724900
COMPANY,
S/YEAR
9115900
9016300
8916700
8817100
3212622
8618000
8518400
8418800
8319200
821960Q
6719600
6620000
6520400
6420800
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF HET-
LIMESTONE
SCRUBBING,
$
689300
740400
791500
842600
322222-
944800
995900
1047000
1098000
1142122
183700
234800
285800
336900
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF HET-
LIMESTONE
SCRUBBING,
$
689300
1429700
2221200
3063800
2252522-
4902300
5898200
6945200
8043200
2122222-
9376000
9610800
9896600
10233500
103653100 6321200 388000 10621500
113863100
118917500
123821200
128574200
133176500
136748600
140170000
143440700
146560700
„ 2262420 1425301QQ
2818700
2668000
2517300
2366700
„ 2216002-
162116800
6.78
2.54
64708000
2.71
1.02
152348800
155016800
157534100
159900800
162116320
5139500
5039900
4940300
4840700
4241122
3114300
3014700
2915100
2815500
(
(
(
(
(
(
— 22152QO__i
2616400
2516800
2417200
2317600
(
(
(
(
65500)
14500)
36600
87700
13BB2Q
457800)
406700)
355600)
304500)
2525221
202300)
151200)
100100)
49100)
10556000
10541500
10578100
10665800
10324622
10346800
9940100
9584500
9280000
2226522
8824200
8673000
8572900
8523800
2213222- 2000 85258OO
170642600
7.14
2.68
70296800
2.94
1.10
8525800
5588800
-------
Table A-101
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 5.0 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
24275000
Includes comparison with projected operating cost of low-cost limestone process
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7QOO_
6 7000
7 7000
8 7000
9 7000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
157800
157800
157800
157800
157803
157800
157300
157800
157800
TOTAL
MFG. COST
INCLUDING
REGULATED NET
ROI FOR
POWER
COMPANY,
$/YEAR
10592000
10423700
10255400
10087100
9919700
9750400
9582100
9413800
9245500
1C 7000 _ . 157BQQ . 9077200 „
11 5000
12 5000
13 5000
14 5000
15 500Q_
16 3500
17 3500
18 3500
19 3500
20 J500
21 1500
22 1500
23 1500
24 1500
25 1503
26 1500
27 1500
28 1500
29 1500
30 15QQ
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
112700
112700
112700
112700
_ 1122C2
78900
78900
78900
7d900
23.20.2 _
33300
338CO
33800
33800
333QQ
33800
33800
33800
33800
33800 .
2874000
COST, DOLLARS
7881000
7712700
7544300
7376000
2222122-
6221800
6053500
5885200
5716900
REVENUE,
S/TON
100?
H2S04
8.00
8.00
8.00
8. 00
2*02
8.00
8.00
8.00
8.00
fl*22
5.00
5.00
5.00
5.00
5*0.0.
5.00
5.00
5.00
5.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
1262400
1262400
1262400
1262400
1262422
1262400
1262400
1262400
1262400
126.24.0.0. _
563500
563500
563500
563500
563.502
394500
394500
394500
394500
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
9329600
9161300
8993000
8824700
3656222
8488000
8319700
8151400
7983100
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
9329600
18490900
27483900
36308600
-44264222
53452900
61772600
69924000
77907100
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
$/YEAR $ $
7863100
7731900
7600700
7469400
23.3.8.20.0. _
7207000
7075800
6944500
6813300
2314.322 fl5J212QQ 66B2100
7317500
7149200
6980800
6812500
6644222
5827300
5659000
5490700
5322400
93039400
100188600
107169400
113981900
122626122
126453400
132112400
137603100
142925500
5543522 _5»QO 294500 _5154QOO 148079500
4167600
3999300
3831000
3662700
_ 3.424.4.Q2
3326100
3157700
2989400
2821100
26.5230.0.
199595600
PER TON OF COAL
5.00
5.00
5.00
5.00
5. 00
5.00
5.00
5.00
5.00
_5*2C
BURNED
169000
169000
169000
169000
162200 _
169000
169000
169000
169000
162222 _
19104000
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10.0? TO INITIAL YEAR
, DOLLARS PER TON
OF COAL
, DOLLARS
BURNED
, MILLS PER KILOWATT-HOUR
3998600
3830300
3662000
3493700
2225422
3157100
2988700
2820400
2652100
152078100
155908400
159570400
163064100
1663.a95.20.
169546600
172535300
175355700
178007800
24fi3.flO.fl 180491600
180491600
7.55
2.83
71813900
3.00
1.13
5865300
5734000
5602800
5471600
, , 534Q200
4657600
4526400
4395200
4263900
4.13.2122
3168900
3037700
2906400
2775200
2644222
2512700
2381500
2250300
2119100
1466500)
1429400)
1392300)
1355300)
12131221 1
1281000)
1243900)
1206900)
1169800)
__113.22221
1452200)
1415200)
13780001
1340900)
_ 13.222221
1169700)
1132600)
1095500)
1058500)
12212221
829700)
7926001
755600)
718500)
6314221
644400)
607200)
5701001
533000)
1466500)
2895900)
4288200)
5643500)
6.26.16201
8242600)
9486500)
10693400)
11863200)
_ 122252221
14448100)
158633001
172413001
18582200)
L_ 12flfl61221
21055800)
22188400)
23283900)
24342400)
253.63.2221
26193400)
26986000)
27741600)
28460100)
221415221
29785900)
30393100)
30963200)
31496200)
12fl2fl2Q i 4262221 1 3.12222221
148499400 ( 31992200)
6.21
2.33
59995400 ( 11818500)
2.51
0.94
-------
Table A-102,
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MM. EXISTING COAL FIRED POMER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
24646000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POMER SALES
UNIT KW-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 S/YEAR H2S04 S/YEAR
1
2
3
4 7000
^ 5 7QOO_ . .
6 7000
7 7000
8 7000
9 7000
_12 2222_
11 5000
12 5000
13 5000
14 5000
15 5CQO
16 3500
17 3500
18 3500
19 3503
_2Q 2522
21 1500
22 1500
23 150C
24 1500
25 L522_
26 1500
27 1500
28 1500
29 1500
3Q 1 500
TOT 106500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
112900
_ _ 112900
112900
112900
112900
112900
112220_
80600
80600
80600
80600
56400
56400
56400
56400
24200
24200
24200
24200
24222
2^200
24200
24200
24200
242QO.
10326700
9946900
9757100
9567200
9377400
_ 21&2522
8083000
7893200
7703300
7513400
2222622
6400900
6211100
6021200
5831300
5641522-
4354100
4164200
3974400
3784500
3.5247QO
3404800
3214900
3025100
2835200
2645300
8.00
8.00
8.00
8oOO
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
__5*22
5.00
5.00
5.00
5.00
5.00
1717300 171919300
COST, DOLLARS PER TON OF COAL BURNED
CCST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR
PRESENT WORTH, DOLLARS PEP TON OF CCAL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
903200
222222
903200
903200
903200
903200
_ __223222_
644800
644800
644800
403000
_423222
282000
282000
282000
282000
2S.2222 -
121000
121300
121000
121000
121222--
121000
121000
121000
121000
_121222__
11682800
, DOLLARS
BURNED
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
9423500
_ 2232622—
9043700
8853900
8664000
84742CO
fi2S4222__
7438200
7248400
7058500
7110400
_ 6222622-
6118900
5929100
5739200
5549300
52525fl2_.
4233100
4043200
3853400
3663500
2422222-
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
9423500
12652122
27700800
36554700
45218700
53692900
61222222
69415400
76663800
83722300
90832700
22252322
103872200
109801300
115540500
121089800
_126442222_.
130682400
134725600
138579000
142242500
145.116230
3283300 149000000
3093900 152093900
2904100 154998000
2714200 157712200
25243_22_ 1602365QO
160236500
7.85
3.01
68678700
3.36
1.29
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR S t
7979600 ( 1443900)
2E22622 i 14Q6QQQ1_J
7675700
7523800
7371900
7220000
JQ680QO
6270500
6118600
5966700
5814700
5662322 J
4988600
4836700
4684700
4532800
42B2222 1
3432400
3280500
3128500
2976600
. 28.24222
2672800
2520800
2368900
2217000
2265102 i
1368000)
1330100)
1292100)
1254200)
12162021_J
1167700)
1129800)
1091800)
1295700)
12523001-]
1130300)
1092400)
1054500)
10165001
8007001
762700)
724900)
686900)
L 6420221-
611000)
573100)
535200)
497200)
I 4592001
1443900)
2849900)
4217900)
5548000)
6840100)
8094300)
10478300)
11608100>
12699900)
13995600)
i 152524221
16383700)
17476100)
18530600)
19547100)
L—225252221
21326400)
220891001
22814000)
235009001
L 241422221
24760900)
25334000)
25869200)
26366400)
( 26R?5600»
133410900 ( 268256001
6.54
2.51
57749700 ( 10929000)
2.83
1.08
\D
-------
Table A-103
MAGNESU SCHEME A, REGULATED POWFR CO. ECONOMICS, 1000 MW. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98Z H2S04 PRODUCTION.
FIXED INVESTMENT:
Includes comparison with projected operating cost of low-cost limestone process
33118000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START
KW
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
TOTAL
MFG. COST
INCLUDING
REGULATED
RQI FOR
POWER
COMPANY
S/YEAR
NET REVENUE,
$/TON
TOTAL
NET
SALES
NET ANNUAL
INCREASE
(DECREASEI
IN COST OF
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
6
7
8
9
LQ.
11
12
13
14
.15-
16
17
18
19
.20.
21
22
23
24
25
7000
70CO
7000
7uOO
-1222_-
7000
7000
7000
7000
-2222.
5000
5000
5000
5000
.5Q.Q.Q
213500
213500
213500
213500
-212522-
213500
213500
213500
213500
-213522-
152500
152500
152500
152500
3500
3500
3500
3500
-3522-
1500
1500
1500
1500
1500
106800
106800
106800
106400
26
27
28
29
3Q
1500
1500
1500
1500
-1522—
45dOO
45800
45800
45800
45322.
45800
45800
45800
45800
45322-
14080700
13851100
13621500
13391900
13162222-
12932700
12703100
12473500
12243900
12314222.
10428600
10199000
9969400
9739800
2512222
8210800
7981200
7751600
7521900
2222302
5499000
5269400
5039800
4810200
4532622-.
4351000
4121400
3891700
3662100
3432522-
100%
H2S04
8.00
8.00
8.00
8.00
! fi*2fl_
8.00
8.00
8.00
8.00
1 S...22
5.00
5.00
5.00
5.00
1 5*22
5.00
5.00
5.00
5.00
5»C2
5.00
5.00
5.00
5.00
5»22_
5.00
5.00
5.00
5. CO
_ _ 5*22_
REVENUE, POWER,
$/YEAR t
1708000
1708000
1708000
1708000
_ __122fi222
1708000
1708000
1708000
1708000
__112a222
762500
762500
762500
762500
16.2522
534000
534000
534000
534000
534222
229000
229000
229000
229000
222QQQ
12372700
12143100
11913500
11683900
.114.54322—
11224700
10995100
10765500
10535900
.123.26222—
9666100
9436500
9206900
8977300
—fllillQfl-
POWER,
$
12372700
24515800
36429300
48113200
—52562522-
70792200
81787300
92552800
103088700
—113324222
123061000
132497500
141704400
150681700
1524224DJJ
7676800 167106200
7447200 174553400
7217600 181771000
6987900 188758900
-filSfliflfl 125512222-
5270000 200787200
5040400 205827600
4810800 210638400
4581200 215219600
4351600 219571200
COMPANY, SCRUBBING,
S/YFAR t
11082800 (
10892700
10702700
10512600
123.22522
10132500
9942400
9752300
9562200
23.22.222—
8236300
8046200
7856200
7666100
24.I6.flQ.fl _
6530600
6340600
6150500
5960400
5222422
4451700
4261600
4071600
3881500
3691400
229000 4122000 223693200 3501300
229000 3892400 227585600 3311300
229000 3662700 231248300 3121200
229000 3433100 234681400 2931100
222222- __.222352fl 22228.4.222 224.1122__
1289900) (
1250400) (
1210800) (
1171300) (
ii3.ia22i_i_
1092200) (
10527001 (
1013200) (
9737001 (
22422Bl_i_
1429800) (
1390300) (
1350700) (
1311200) (
12112201 i
11462001 (
1106600) (
1067100) (
1027500) (
2322221 I
818300) (
778800) (
7392001 (
6997001 <
6622221 1
620700) (
581100> (
541500) (
502000) (
L 4624221-1-
SCRUBBING,
$
12899001
2540300)
3751100)
4922400)
6&542221
7146400)
8199100)
9212300)
10186000)
-111222221
12549800)
13940100)
15290800)
16602000)
_12fi232flQl
19019900)
20126500)
21193600)
222211001
-232222221
24027300}
24806100)
25545300)
26245000)
-26.20.5.20.21
27525900)
28107000)
28648500)
291505001
226122221
TOT 127500 3889500 263737400 25852500 237884900
EQUIVALENT COST, DOLLARS PER TON OF COAL BURNED 5.15
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.87
PRESENT WORTH IF DISCOUNTED AT 10oO? TO INITIAL YEAR, DOLLARS 94910200
EQUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL BURNED 2.05
EQUIVALENT PRESENT WORTH, MILLS PEP KILOWATT-HOUR 0.74
208272000
4.51
1.63
84316100
1.82
0.66
( 29612900)
( 10594100)
-------
Table A-104
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 1000 MW, NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
33118000
Includes comparison with projected operating cost of high-cost limestone process
YEARS ANNUAL
AFTER OPERA-
PDWER TION,
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
TOTAL
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWFR
NET
REVENUE,
S/TON
TOTAL
NET
SALES
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONF
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 2222-
6 7000
7 7000
8 7000
9 7000
12 IQOQ
11
12
13
~16
17
18
19
21
22
23
24
~26
27
28
29
30
5000
5000
5000
5000
,5.Qo.p_,
3500
3500
3500
3500
_3_500
1500
1500
1500
1500
15QQ
1500
1500
1500
1500
-15QQ-.
100%
H2S04
COMPANY,
S/YFAR
213500 14080700
213500 13851100
213500 13621500
213500 13391900
_ 213520 13162300
213500
213500
213500
213500
-212500
152500
152500
15250'0
152500
_ 152522
106800
106800
106800
106800
_126fi22
45800
45800
45800
45800
45.B.22 _
45800
45800
45800
45800
_ _ _45flQQr_
12932700
12703100
12473500
12243900
12014202
10428600
10199000
9969400
9739800
-25.12202
8210800
7981200
7751600
7521900
22223.00 _
5499000
5269400
5039800
4810200
45fi0602
4351000
4121400
3891700
3662100
3.432500
100%
H2S04
8.00
8.00
8.00
8.00
fl^.20
8.00
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5^.20
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5^.20
5.00
5.00
5.00
5.00
REVENUE,
S/YEAR
1708000
1708000
1708000
1708000
122BJ122
1708000
1708000
1708000
1708000
1708000
762500
762500
762500
762500
Z62522
534000
534000
534000
534000
_534QOQ__
229000
229000
229000
229000
222000
229000
229000
229000
229000
_ 222020
POWER,
$
12372700
12143100
11913500
11683900
1145,4302
11224700
10995100
10765500
10535900
__12326222_
9666100
9436500
9206900
8977300
8747700
7676800
7447200
7217600
6987900
5270000
5040400
4810800
4581200
4351600
4122000
3892400
3662700
3433100
-3203500
POWFR,
J
COMPANY, SCRUBBING,
t/YEAR S
12372700 15208800
24515800 15053700
36429300 14898600
48113200 14743500
525625,20 _145flfl40C
70792200 14433200
81787300 14278100
92552800 14123000
103088700 13967900
113324202 138128QO
123061000
132497500
141704400
150681700
1594294.00
167106200
174553400
181771000
188758900
___125512200
200787200
205827600
210638400
215219600
21957.120Q
223693200
227585600
231248300
234681400
23.2flfl420fl
11154900
10999800
10844700
10689600
_1Q534500
8458700
8303600
8148500
7993400
_ 1428200 ^
5007900 (
4852800 (
4697700 (
4542500 (
4332400
4232300
4077200
3922100
3767000
2611200
2836100
2910600
2985100
3059600
2124102 _
3208500
3283000
3357500
3432000
2506600-
1488800
1563300
1637800
1712300
_12fl6flOQ
781900
856400
930900
1005500
1QS.2202-
262100)
187600)
113100)
38700)
25S20
110300
184800
259400
333900
SCRUBBING,
*
2836100
5746700
8731800
11791400
™18134000~
21417000
24774500
28206500
__31H3JLOa_
33201900
34765200
36403000
38115300
—22202.100
40684000
41540400
42471300
43476800
44294700
44107100
43994000
43955300
--4222110Q
44101400
44286200
44545600
44879500
TOT 127500 3889500 263737400 25852500 237884900
EQUIVALENT COST, DOLLARS PER TON OF COAL BURNED 5.15
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.87
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 94910200
EQUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL BURNED 2.05
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.74
283172800
6.13
2.22
117261000
2.54
0.92
45287900
22350800
-------
Table A-105
MAGNESIA SCHEME A, REGULATED POWER COo ECONOMICS, 1000 MW. EXISTING COAL FIRED POWER PLANT, 3.5 ? S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT:
$ 36634000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPFRA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ IOC1? COMPANY, 100* REVENUE,
START KW H2S04 S/YEAR H2S04 S/YEAR
1
2
3
4 70CO 220900 15306000
5 ZflQfl_ 22090C 15023800
6 7000
7 7000
8 7000
<3 7000
10 70CQ
11 5000
12 5000
13 5000
14 5000
_15 SQflO
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
2i ISflfl
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 106500
EQUIVALENT
EQUIVALENT
PRESET WORTH
EQUIVALENT
EQUIVALENT
220900
220900
220900
220900
157800
157800
157800
157800
110400
110400
110400
110400
47300
47300
47300
47300
47300
47300
47300
47300
14741500
14459300
14177100
13894900
13.6.122Qfl
11923100
11640900
11358600
11076400
9399100
9116900
883470C
8552500
8.2Zfl2QQ
6354900
6072700
5790500
5508300
4943900
466160&
4379400
4097200
3S150QQ
8.
8.
8.
8.
8.
8.
8.
8.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
00
00
00
00
00
00
00
00
00
00
00
00
00
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
1767200 13538800
126.22QQ 13256600
1767200
1767200
1767200
1767200
1262400
1262400
1262400
789000
552000
552000
552000
552000
_5520_Qfl
12974300
12692100
12409900
12127700
10660700"
10378500
10096200
10287400
lflCfl5.2flfl_
8847100
8564900
8282700
8000500
121B2QQ
00 236500 6118400
00 236500 5836200
00 236500 5554000
00 236500 5271800
Qfl 23.6, 5J3Q 4.2fl26flfl.
00 236500 4707400
00 236500 4425100
00 236500 4142900
00 236500 3860700
00 23.&5QQ 35_Ifi5DQ
3360300 253031500
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0* TO INITIAL YEAR
PRESENT WORTH, DOLLARS PER TON OF COAL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
22860600
, DOLLARS
BURNED
230170900
5.76
2.16
98600300
2.47
0.93
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
CUMULATIVE INCLUDING
NET INCREASE REGULATED
(DECREASE) ROI FOR
IN COST OF POWER
POWER, COMPANY,
$ S/YEAR
13538800
39769700
52461800
64871700
76999400
99505600
109884100
119980300
130267700
149120000
157684900
165967600
173968100
187804700
193640900
199194900
204466700
214163700
218588800
222731700
226592400
22Qi2fl2Qfl
12063000
11324202-
11606700
11378600
11150400
10922200
94327QO
9204600
8976400
8748300
_a5_2fllflQ-
746750C
7239300
7011100
6783000
_i554£flfl
5098000
4S69800
4641700
4413500
£I£5.Aflfl.
3957200
3729100
3500900
3272700
_ 3-Q4.4.6.flQ
200300600
5.02
1.88
87046700
2.18
0. 82
(
~(
(
(
(
(
(
(
(
f
(
(
(
(
-_i
(
(
(
(
-_i
(
(
(
— 1
(
(
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
S $
1475800) (
1367600)"
1313500)
1259500)
1205500)
115.14.Qfll_J
1228000)
1173900)
1119800)
1539100)
1379600)
1325600)
1271600)
12175001
1020400)
966400)
912300)
858300)
££42QQJL_
750200)
696000)
642000)
588000)
5.3.3.2Q0.1
29870300)
11553600)
1475800)
_ 2a225QQi
42651001
5578600)
6838100)
8043600)
2125.QCQ1
10423000)
11596900>
12716700)
14255800)
1 L524Q2flfll
17120500)
18446100)
19717700)
20935200)
22fl2B.6P.Ql
23119000)
24085400)
249977001
258560001
L__266£.fl2flfll
27410400)
28106400)
28748400)
29336400)
L__22fl2fl2flfll
-------
Table A-106
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MW. NEW OIL FIRED POWER PLANT, 1.0 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
Includes comparison with projected operating cost of low-cost limestone process
5148000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
TOTAL
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWER
NET REVENUE,
I/TON
TOTAL
NET
SALES
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
CUMULATIVE
NET INCREASE
(DECREASEI
IN COST OF
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
UNIT
START
1
2
3
4
6
7
8
9
-10
11
12
13
14
15
16
17
18
19
_22
21
22
23
24
-25—
26
27
28
29
22- -
KW-HR/
K.W
7000
7000
7000
7000
2222_
7000
7000
7000
7000
700.0
5003
5000
5000
5000
5222-
3500
3500
3500
3500
2522
1500
1500
1500
1500
L522-
1500
1500
1500
1500
1522-
100?
H2S04
9600
9600
9600
9600
9600
9600
9600
9600
6900
6900
6900
6900
&.9.0.Q
4800
4800
4300
4800
2100
2100
2100
2100
2122 _
2100
2100
2100
2100
2122 __
COMPANY,
t/YEAR
2260900
2225200
2189500
2153800
2113122
2082400
2046700
2011000
1975300
-12226.22-
1701200
1665500
1629800
1594100
1555422
1356800
1321100
1285400
1249700
1214222-
922600
886900
851200
315500
222222 _
744200
703500
672830
637100
621422
100?
H2S04
8.00
8.00
8.00
8.00
a«.Qo
8.00
3.00
8.00
8.00
5.00
5.00
5.00
5.00
5»2C
5.00
5.00
5.00
5.00
__ _5«.Qfl__ .
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
REVENUE,
t/YEAR
76800
76800
76800
76800
76800
76800
76800
76800
26.B22
34500
34500
34500
34500
24522
24000
24000
24000
24000
_ 24222
10500
10500
10500
10500
. 12522
10500
10500
10500
10500
L2522--
POWER,
t
2134100
2148400
2112700
2077000
2241322
2005600
1969900
1934200
1898500
-ia6.28.22
1666700
1631000
1595300
1559600
1332800
1297100
1261400
1225700
1122222—
912100
876400
840700
805000
26.2422—
733700
698000
662300
626600
522222
POWER,
$
2184100
4332500
6445200
8522200
1256_3522
12569100
14539000
16473200
18371700
22234522
21901200
23532200
25127500
26687100
25211222
COMPANY, SCRUBBING, SCRUBBING,
t/YEAR $ t
2114800
2080300
2045800
2011300
1226222 J
1942200
1907700
1873200
1838600
1624122 I
1592500
1557900
1523400
1488900
1454400
29543800 1274200
30840900 1239700
32102300 1205200
33328000 1170600
_ 345LS222- „ 1136.10C
35430100
36306500
37147200
37952200
39455300
40153300
40815600
41442200
42222122
874300
839800
805200
770700
226.222—
701600
667100
632600
598100
-56.2522-
69300) I
68100) (
66900)
65700)
6.46.221 J
63400)
62200)
610001
59900)
58.2221 J
74200)
73100)
71900)
70700)
L 6.25221_J
58600)
57400)
56200)
55100)
L 522221-J
37800)
36600)
35500)
34300)
L 232221—
32100)
30900)
29700)
2«500)
t 274001
693001
1374001
204300)
270000)
224£221
398000)
460200)
521200)
581100)
6.2.28.221
714000)
787100)
859000)
929700)
1 2322221
1057800)
1115200)
1171400)
1226500)
L 12324221
1318200)
1354800)
1390300)
1424600)
L_ 14528.221
1489900)
1520800)
1550500)
1579000)
L —16.26.4221
TOT 127500 175500 43198600 1165500 42033100
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED 1.12
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.65
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 16807100
EQUIVALENT PRESENT WORTH, DOLLARS PER BARREL OF OIL BURNED 0.45
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUK 0.66
40426700
1.08
1.59
16221100
0.43
0.64
1606400)
586000)
-------
Table A-107
MAGNESIA SCHEME A, REGULATED POWER CD. ECONOMICS, 200 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
6690000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
1C 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 3.5.QO.
21 1500
22 1500
23 1500
24 1500
_25_ 15QQ_
26 1500
27 1500
28 1500
29 1500
3Q 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
EQUIVALENT
TONS/YEAR
100S
H2S04
24100
24100
24100
24100
_ _ -24100.
24100
24100
24100
24100
24100
17200
17200
17200
17200
17200
12000
12000
12000
12000
_ _12flQQ
5200
5200
5200
5200
5200 _
5200
5200
5200
5200
52Qfl _
439000
COST, DOLLARS
REGULATED
ROI FOR
POWER
COMPANY,
t/YEAR
3001600
2955200
29C8900
2862500
2fll6,10_Q
2769700
2723300
2676900
2630500
25fl42Qfl
2256000
2209600
2163200
2116800
2Q704QQ
1795600
1749200
1702800
1656400
NET REVENUE,
t/TON
100?
H2S04
8.00
8.00
8.00
8.00
-fliflfl
8.00
8.00
8.00
8.00
fliO.fi
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
161QQQO „,- 5.00
1212800
1166500
1120100
1073700
1Q2J300
980900
934500
888200
841800
225400 _
57300,100
PER BARREL OF
5.00
5.00
5.00
5.00
5»Cfl
5.00
5.00
5.00
5.00
5&0£
OIL BURNED
TOTAL
NET
SALES
REVENUE,
t/YEAR
192800
192800
192800
192800
-1228.00.
192800
192800
192800
192800
122&QO
86000
86000
86000
86000
3.6QQfl_
60000
60000
60000
60000
60000
26000
26000
26000
26000
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
t
2808800
2762400
2716100
2669700
__ 26222QO--
2576900
2530500
2484100
2437700
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
CUMULATIVE INCLUDING
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
2808800
5571200
8287300
10957000
1358Q300
16157200
18687700
21171800
23609500
2221400 26000900
2170000
2123600
2077200
2030800
__ 123.44QQ__
1735600
1689200
1642800
1596400
155QflOO
1186800
1140500
1094100
1047700
28170900
30294500
32371700
34402500
3638690Q
38122500
39811700
41454500
43050900
44600200
45787700
46928200
48022300
49070000
260QQ 1001300 50071300
26000
26000
26000
26000
26000
2918000
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH,
PRESENT WORTH,
AT 10.0? TO
DOLLARS PER
INITIAL YEAR,
BARREL OF OIL
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
954900
908500
862200
815800
769400
54382,100
1.45
2.13
21670900
0.58
0.85
51026200
51934700
52796900
53612700
542fl21Qfl
REGULATED
ROI FOR
POWER
COMPANY,
t/YEAR
2429700 (
2390200 {
2350700 (
2311100 (
2221600 I
2232100 (
2192600 (
2153100 (
2113500 (
2fl24QOfl i
1826600 (
1787100 (
1747600 (
1708000 (
X668500 (
1459000 (
1419500 (
1380000 (
1340400 (
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
t t
379100)
372200)
365400)
358600)
2^17.0.0.1
344800)
337900)
331000)
3242001
2124001
343400)
336500)
329600)
322800)
315900)
276600)
269700)
262800)
256000)
12UQ20Q- i 24910Q1
997500 (
958000 (
918500 (
878900 (
522400 1
799900 (
760400 (
720900 (
681300 (
6418.00 L
46352800 (
1.24
1.82
18625500 (
0.50
0.73
189300)
1825001
175600)
168800)
1612001
155000)
148100)
1413001
134500)
379100)
751300)
1116700)
1475300?
1327000?
2171800)
2509700)
2840700)
3164900)
L_ 24322001
3825700)
4162200)
4491800)
4814600)
513050P1
5407100)
5676800)
5939600)
6195600)
-64442001
6634000)
6816500)
6992100)
7160900)
t 2222.8Q01
7477800>
7625900)
7767200)
7901700)
1226001 I £.0222001
8029300)
30454001
-------
Table A-108
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MW. NFW OIL FIRED POWER PLANT, 2.5 * S IN FUFL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
6690000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
_5 2000
6 7000
7 7000
8 7000
9 7000
J.Q . 7000 ,
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 3500- .
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
32 1502-
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
EQUIVALENT
TONS/YEAR
100*
H2S04
24100
24100
24100
24100
24122
24100
24100
24100
24100
24122
17200
17200
17200
17200
12220
12000
12000
12000
12000
12222
5200
5200
5200
5200
5220
5200
5200
5200
5200
5220
439000
REGULATED NET
ROI FOR
POWER
COMPANY,
S/YEAR
3001600
2955200
2908900
2862500
2316102-
2769700
2723300
2676900
2630500
2534220
2256000
2209600
2163200
2116800
2020420
1795600
1749200
1702800
1656400
1612020-
1212800
1166500
1120100
1073700
1022300
980900
934500
883200
841800
225400
57300100
COST, DOLLARS PER BARREL OF OIL
COST, MILLS PER
KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INIT
PRESENT WORTH,
PRESENT WORTH,
REVENUE,
$/TON
100?
H2S04
8.00
8.00
8.00
8.00
B_»20_
8.00
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5 _ no
5.00
5.00
5.00
5.00
5_*Q2
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5.00
BURNED
IAL YEAR,
DOLLARS PER BARREL OF OIL
TOTAL
NET
SALES
REVENUE,
$/YEAR
192800
192800
192800
192800
122300
192800
192800
192800
192800
122300.
86000
86000
86000
86000
36.202
60000
60000
60000
60000
60002
26000
26000
26000
26000
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
2808800
2762400
2716100
2669700
2623322
2576900
2530500
2484100
2437700
.__ 2321400
2170000
2123600
2077200
2030800
1234400
1735600
1689200
1642800
1596400
ISSQQflfl.
1186800
1140500
1094100
1047700
26000 _ 1001300
26000
26000
26000
26000
-26200
2918000
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
954900
908500
862200
815800
262400.
54382100
1.45
2.13
21670900
0.58
0.85
CUMULATIVE
NFT INCREASE
(DECREASE)
IN COST OF
POWER,
*
2808800
5571200
8287300
10957000
1353Q3QQ
16157200
18687700
21171800
23609500
26222222
28170900
30294500
32371700
34402500
36336220
38122500
39811700
41454500
43050900
44602202-
45787700
46928200
48022300
49070000
5027X3QQ
51026200
51934700
52796900
53612700
54332100
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONF USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED
ROI FOR
POWER
COMPANY,
$/YEAR
2514300
2483200
2452000
2420900
2332200
2358600
2327400
2296200
2265100
2233200-
1875000
1843800
1812600
1781500
1250300
1460900
1429700
1398600
1367400
1336200-
927600
896400
865300
834100
302200
771800
740600
709500
678300
&.42220-
47671000
1.27
1.87
19409800
0.52
0.76
INSTEAD
OF WET-
LIMESTONE L
INSTEAD
OF HET-
IMESTONE
SCRUBBING, SCRUBBING,
$
( 294500) (
( 279200) (
( 264100) (
( 248800) (
$
294500)
573700)
837800)
1086600)
i 2336221 1 1320200)
( 218300) (
( Z03100) (
I 187900) (
( 172600) (
i _ 1525001 1
( 295000) I
( 279800) (
( 264600) (
( 249300) (
I 2341001 1
( 274700) (
( 259500) (
( 244200) (
( 229000) (
_I_ 2133001 I
( 259200) (
( 244100) (
( 228800) (
( 213600) 1
i 1234001 i
( 183100) (
( 167900) (
( 152700) (
( 137500) (
1538500)
1741600)
1929500)
2102100)
22526021
2554600)
2834400)
3099000)
3348300)
353^4221
3857100)
4116600)
4360800)
4589800)
43236221
5062800)
5306900)
5535700)
5749300)
52422221
6130800)
6298700)
6451400)
6588900)
i 1222001 L_ 6711100, j
( 6711100)
( 2261100)
-------
Table A- 109
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 HW. NEW OIL FIRED POWER PLANT, 4.0 ? S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
7903000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR i/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 i/YEAR H2S04 i/YEAR
1
2
3
4
7000
7000
7000
7000
-_2QQQ_
6 7000
7 7000
8 7000
9 7000
_lfl 2000
11 5000
12 5000
13 5000
14 5000
15_ 5000
16
17
18
19
_20
21
22
23
24
_25_
26
27
28
29
20 -
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
38500
38500
38500
38500
38500
38500
38500
38500
27500
27500
27500
27500
22500
19300
19300
19300
19300
12300
8300
8300
8300
8300
220Q_
8300
8300
8300
8300
_ _ £200
3574100
3519300
3464500
3409800
3355000 ._
3300200
3245400
3190600
3135800
-208.1000
2682700
2627900
2573100
2518300
246.2500
2130400
2075600
2020800
1966100
-1211200-
1433200
1378400
1323600
1268800
. L2140QO-
1159200
1104500
1049700
994900
. -__2401QO___
8.00
8.00
8.00
8.00
suoo
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5..0C-
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5*00
308000
308000
308000
308000
20B.OOQ
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
i i
3266100
3211300
3156500
3101800
3D410QQ
308000 2992200
308000 2937400
308000 2882600
308000 2827800
202000 2773000
137500
137500
137500
137500
_ 122500
96500
96500
96500
96500
26.500
41500
41500
41500
41500
41500-
41500
41500
41500
41500
-41500—
2545200
2490400
2435600
2380800
2226.000
2033900
1979100
1924300
1869600
1391700
1336900
1282100
1227300
__ 1122500
1117700
1063000
1008200
953400
8.236.00 —
3266100
6477400
9633900
12735700
—15222200
18774900
21712300
24594900
27422700
3Q.J.95700
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
i/YEAR i i
2698700
2655100
2611500
2567900
2524200
2480700
2437100
2393500
2349900
2306300
32740900 2026300
35231300 1982700
37666900 1939100
40047700 1895500
_ 42222200 18519QO
44407600
46386700
48311000
50180600
—51225400 _
53387100
54724000
56006100
57233400
-52405200-
59523600
60586600
61594800
62548200
—62446.500 _
1615800
1572200
1528600
1485000
-1441400
1100800
1057200
1013600
970000
-226400
882800
839200
795600
752000
20S4QQ _
567400)
556200)
545000)
533900)
511500)
500300)
489100)
477900)
4662001
518900)
507700)
496500)
485300)
-4241001-
418100)
406900)
395700)
384600)
290900)
279700)
268500)
257300)
2461001
234900)
223800)
212600)
201400)
l_ -1202001-
567400)
1123600)
1668600)
2202500)
_ 22252001
3236700)
3737000)
4226100)
4704000)
512Q2QQ1
5689600)
6197300)
6693800)
7179100)
26522001
8071300)
8478200)
8873900)
9258500)
26212001
9922800!
10202500)
10471000)
10728300)
—102244001
11209300)
11433100)
11645700)
11847100)
L 120222001
TOT 127500 702000 68111800 4665000 63446800
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED 1.69
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 2.49
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 25230000
EQUIVALENT PRESENT WORTH, DOLLARS PER BARREL OF OIL BURNED 0.67
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.99
51409500
1.37
2.02
20682100
0.55
0. 81
( 12037300)
4547900)
-------
Table A-110
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 200 MW. EXISTING OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
7426000
Includes comparison with projected operating cost of low-cost limestone process
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
8
9 7000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
24900
TOTAL
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
*/YEAR
3329200
NET REVENUE,
t/TON
100?
H2S04
8.00
1Q 7QQQ 24900 3259000 8.00_
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 71500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
17800
17800
17800
17800
17800
12400
12400
12400
12400
12422
5300
5300
5300
5300
53.22-
5300
5300
5300
5300
5322
253800
COST, DOLLARS
2890500
2820300
2750100
2679900
2609700
2297200
2227000
2156800
2086600
2016400
1573400
1503200
1433000
1362800
1292600
1222400
1152200
1082000
1011800
24.16.22-
43697700
PER BARREL OF
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
»/YEAR
199200
-122222
142400
142400
142400
142400
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
3130000
2252fl22_.
2748100
2677900
2607700
2537500
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
3130000
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
2794100 (
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSSI
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
t $
335900) < 335900)
61fl2flOO_ 223.21QQ i 327.1Q01 J
8937900
11615800
14223500
16761000
^ 8-00 142400 2467300 19228300
8.00
8.00
8.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5..Q2
OIL BURNED
99200
99200
99200
62000
. 62222-
26500
26500
26500
26500
26522
26500
26500
26500
26500
. 26522
1797COO
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH,
PRESENT WORTH,
AT 10.0? TO
DOLLARS PER
INITIAL YEAR,
BARREL OF OIL
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
2198000
2127800
2057600
2024600
__1254.4.22_.
1546900
1476700
1406500
1336300
1266122 .
1195900
1125700
1055500
985300
21426300
23554100
25611700
27636300
22522222
31137600
32614300
34020800
35357100
2443900 (
2381800
2319800
2257700
2195600_
1947900
1885900
1823800
1761700
1622122- J
1349200
1287100
1225100
1163000
3662320Q - 1100900
37819100
38944800
40000300
40985600
1038900
976800
914700
852700
304200)
296100)
287900)
279800)
__2112221 J
250100)
241900)
233800)
262900)
L 254.1221-]
197700)
1896001
181400)
173300)
1652221
157000)
1489001
140800)
132600)
6636001
967800)
1263900)
1551800)
1831600)
210,33001
2353400)
2595300*
2829100)
3092000)
3346.700)
3544400)
3734000)
3915400)
40887001
42539QQ1
4410900)
4559800)
4700600)
4833200)
215102 4J.2Q21QQ 23Q6DQ I 1245001 i 4957700)
41900700
1.93
2.93
20155600
0.93
1.41
36943000
1.70
2.58
17862000
0.82
1.25
49577001
( 2293600)
to
-------
Table A-111
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 1.0 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
9888000
Includes comparison
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
— 5
6
7
8
9
.10. .
11
12
13
14
15
16
17
18
19
-1Q__
21
22
23
24
25
26
27
28
29
-30 —
with projected operating cost of low-cost limestone process
PRODUCT RATE,
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
70QQ
7000
7000
7000
7000
— 2flflfl__
5000
5000
5000
5000
__5000
3500
3500
3500
3500
EQUIVALENT
TONS/YEAR
100%
H2S04
23600
23600
23600
23600
_ .23600
23600
23600
23600
23600
_2i6fifl
16800
16800
16800
16800
TOTAL
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
4242900
4174300
4105800
4037200
3968700
3900100
3831600
3763000
3694400
36? 5900.
3171300
3102800
3034200
2965700
NET REVENUE,
S/TON
TOTAL
NET
SALES
100% REVENUE,
H2S04
8.00
8.00
8.00
8.00
8«00
8.00
8.00
8. CO
8.00
8.00
5.00
5.00
5.00
5.00
$/YEAR
188800
188800
188800
188800
_iaaaflo__
188800
188800
188800
188800
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
4054100
3985500
3917000
3848400
32222flfl_
3711300
3642800
3574200
3505600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4054100
8039600
11956600
15805000
125a4200
23296200
26939000
30513200
34018800
laaaoo 3437100 37455900
84000
84000
84000
84000
16&QO ?HQ7inn «;-nn B4.nnn
11800
11800
11800
11800
2517900 5.00 59000
2449300
2380700
2312200
— 3500 — 11BQQ 2243600
1500
1500
1500
1500
— LSflfl
1500
1500
1500
1500
-1500
5000
5000
5000
5000
5-QQfl
5000
5000
5000
5000
5QQQ
1705000
1636400
1567900
1499300
1430 7QO
1362200
1293600
1225100
1156500
iflaaooo
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
59000
59000
59000
52000
25000
25000
25000
25000
25000
25000
25000
25000
25000
5-.OQ .. ,,25000^
3087300
3018800
2950200
2881700
40543200
43562000
46512200
49393900
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING
*/YEAR $ $
3886100
3820300
3754500
3688700
3622900
3557100
3491300
3425400
3359600
3293800
2903800
2838000
2772200
2706400
2313100- 522Q2QQQ 26406.00
2458900 54665900 2312200
2390300
2321700
2253200
2134600-
1680000
1611400
1542900
14"74300
14fl52flfl
1337200
1268600
1200100
1131500
57056200
59377900
61631100
2246300
2180500
2114700
63315200 2flA8.9QQ_
65495700
67107100
68650000
70124300
21530000
72867200
74135800
75335900
76467400
1583000
1517200
1451400
1385600
1312aQQ
1253900
1188100
1122300
1056500
1680001
165200)
162500)
159700)
1520001-1
154200)
151500)
1488001
146000)
1433001
1835001
180800)
178000)
175300)
1225001
1467001
144000)
141200)
138500)
135700)
97000)
94200)
91500)
88700)
1 , 859001
83300)
805001
77800)
75000)
168000
333200
495700
655400
812400
966600
1118100
1266900
1412900
1556200
1739700
1920500
2098500
2273800
24>63QO
2593000
2737000
2878200
3016700
31524QO
3249400
3343600
3435100
3523800
_ 36Q22QQ
3693000
3773500
3851300
3926300
_ 106.3000 22530400 22Q2QQ— I 223001.1 3223602
TOT 127500 429000 80383400
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED
EQUIVALENT COST, MILLS PER KILOWATT-HOUR
PRESENT WORTH IF DISCOUNTED AT 10.0% TO INITIAL YEAR,
EQUIVALENT PRESENT WORTH, DOLLARS PER BARREL OF OIL
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR
2853000
DOLLARS
BURNED
77530400
0.85
1.22
31092000
0.34
0.49
73531800
0.80
1.15
29653900
0.32
0.47
3998600)
1438100)
-------
Table A-112
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MM. NEW OIL FIREO POWER PLANT, 2.5 * S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
12439000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
J.O 700(J
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
_20 3500
21 1500
22 1500
23 1500
24 1500
_25 1500
26 1500
27 1500
28 1500
29 1500
30 1500 .
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
58900
58900
58900
58900
5.220.0.
58900
58900
58900
58900
58200
42100
42100
42100
42100
421QO
29400
29400
29400
29400
294QO
12600
12600
12600
12600
12600
12600
12600
12600
12600
__12600
1072500
COST, 'DOLLARS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
5453800
5367600
5281300
5195100
5108900
5022600
4936400
4850200
4763900
4.677700
4066300
3980100
3893900
3807600
3721400
3216000
3129700
3043500
2957200
2fi21QQfl
2158900
2072600
1986400
1900200
1813900
1727700
1641500
1555200
1469000
1382700
103052300
PER BARREL
NET REVENUE,
S/TON
100?
H2S04
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
471200
471200
471200
471200
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4982600
4896400
4810100
4723900
, _ 8,QO 471200 4637700
8.00
8.00
8.00
8.00
8.0Q
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
_5_,.0_Q
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
_5j.flfl
OF OIL BURNED
471200
471200
471200
471200
4212QQ _
210500
210500
210500
210500
_ 21Q5J1Q
147000
147000
147000
147000
„ „ 147000 ..
63000
63000
63000
63000
__63flflfl__
63000
63000
63000
63000
__ fiaflQQ—
7129500
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10.0?
TO INITIAL YEAR
, DOLLARS
, DOLLARS PER BARREL OF OIL BURNED
, MILLS PER
KILOWATT-HOUR
4551400
4465200
4379000
4292700
420650Q
3855800
3769600
3683400
3597100
35J.Q2flfl
3069000
2982700
2896500
2810200
(DECREASE)
IN COST OF
POWER,
$
4982600
9879000
14689100
19413000
24Q5.Q2flQ_
28602100
33067300
37446300
41739000
45^45500.
49801300
53570900
57254300
60851400
643.&23QQ
67431300
70414000
73310500
76120700
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
t/YEAR
4454500 <
4380500 (
4306400 (
4232400 (
415fl3Qfl i
4084300 (
4010200 (
3936200 (
3862100 (
32flfllQfl i
3325700 (
3251600 (
3177600 (
3103500 (
3Q295QQ i
2642700 (
2568700 (
2494600 (
2420600 (
2224Qflfl_ 7_8.fl441QQ 234A5QD. 1
2095900
2009600
1923400
1837200
125fl2flfl
1664700
1578500
1492200
1406000
13122flfl
95922800
1.05
1.50
38313300
0.42
0.60
80940600
82950200
84873600
86710800
flfi4612flfl
90126400
91704900
93197100
94603100
__25222flflfl__
1798300 (
1724200 (
1650200 (
1576100 (
1502100 ,(
1428000 (
1354000 (
1279900 {
1205900 (
113.1&Q.Q— i
84224500 (
0.92
1.32
34007700 (
0.37
0.53
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
t $
528100)
515900)
503700)
491500)
4224QQ1_J
467100)
455000)
442800)
430600)
41840Q)
530100)
518000)
505800)
493600)
4814QQ1
426300)
4140001
401900)
389600)
2225QQ1_J
297600)
285400)
273200)
261100)
24flflQQl_
2367001
224500)
212300)
200100)
1879001
528100)
1044000)
1547700)
2039200)
2518600)
2985700)
3440700)
3883500)
4314100)
4732500 )
5262600)
5780600)
6286400)
6780000)
7261400 )
7687700)
8101700)
8503600)
8893200)
L_ 222Q2QQ1
9568300)
9853700)
10126900)
10388000)
106368QQ1
10873500)
11098000)
11310300)
11510400)
t 11698300)
116983001
4305600)
-------
ON
O
Table A-1 13
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 2.5
S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT: $
12439000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7PPQ.
6 7000
7 7000
8 7000
9 7000
12 1222-
11 5000
12 5000
13 5000
14 5000
15_ 5222-
16 3500
17 3500
18 3500
19 3500
22_ 2502
21 1500
22 1500
23 1500
24 1500
25 150Q
26 1500
27 1500
28 1500
29 1500
3_0 1522
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
58900
58900
58900
58900
-53222
53900
58900
58900
58900
5fl222
42100
42100
42100
42100
42122
29400
29400
29400
29400
-22402
12600
12600
12600
12600
12622
12600
12600
12600
12600
12622
1072500
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY ,
t/YEAR
5453800
5367600
5281300
5195100
512S222
5022600
4936400
4850200
4763900
4611102
4066300
3980100
3893900
3807600
2121422 _
3216000
3129700
3043500
2957200
-2111222
2158900
2072600
1986400
1900200
1311222-
1727700
1641500
1555200
1469000
U8.27QO
103052300
COST, DOLLARS PER BARREL OF
COST, MILLS PER
NET REVENUE,
$/TON
100?
H2S04
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
471200
471200
471200
471200
fi^.22 41120Q
8.00
8.00
8.00
8.00
8..QQ
5.00
5.00
5.00
5.00
5^.22-
5.00
5.00
5.00
5.00
5^.0.0...
5.00
5.00
5.00
5.00
5tOO
5.00
5.00
5.00
5.00
5--OQ
OIL BURNED
471200
471200
471200
471200
-411222.
210500
210500
210500
210500
212502.
147000
147000
147000
147000
141222.
63000
63000
63000
63000
62222.
63000
63000
63000
63000
63000
7129500
KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO
PRESENT WORTH,
PRESENT WORTH,
DOLLARS PER
INITIAL YEAR,
BARREL OF OIL
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
4982600
4896400
4810100
4723900
4622222
4551400
4465200
4379000
4292700
4226522
3855800
3769600
3683400
3597100
2510202
3069000
2982700
2896500
281-0200
2124222—
2095900
2009600
1923400
1837200
1152222
1664700
1578500
1492200
1406000
1212122
95922800
1 .05
1.50
38313300
0.42
0.60
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4982600
9879000
14689100
19413000
-24252122
28602100
33067300
37446300
41739000
_ 45245522
49801300
53570900
57254300
60851400
___6,i262220
67431300
70414000
73310500
76120700
_ 1BS44122
80940600
82950200
84873600
86710800
-M46112Q
90126400
91704900
93197100
94603100
25222S22
ALTERNATIVE
OPERATING ANNUAL
COST FOR NON- SAVINGS
RECOVERY WET- (LOSS)
LIMESTONE USING
PROCESS RECOVERY
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAP
5015800
4955600
4895400
4835200
4115222 .
4714800
4654600
4594400
4534200
4414002-
3712000
3651800
3591600
3531400
2411222
2865100
2804900
2744700
2684600
2624422-
1783400
1723200
1663000
1602800
1542622
1482400
1422200
1362000
1301800
_ -1241622
94255700
1.03
1.48
38632900
0.42
0.61
PROCESS
INSTEAD
OF WFT-
LIMFSTONE
SCRUBBING,
$
33200
59200
85300
111300
121222 __
163400
189400
215400
241500
261520
( 143800)
117800)
91800)
65700)
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
33200
92400
177700
289000
_ -42.6202
589700
779100
994500
1236000
1522522
1359700
1241900
1150100
1084400
i 221221 1044700
203900)
177800)
151800)
125600)
i -226221
312500)
286400)
260400)
234400)
i 2QB2221 J
( 182300)
( 156300)
( 130200)
( 104200)
840800
663000
511200
385600
2fl6202
26500)
312900)
573300)
8077PO)
L 12162201
1198300)
1354600)
1484800)
1589000)
i 1S1221 S 16671001
( 1667100)
319600
-------
Table A-114
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 4.0 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
14568000
Includes comparison with projected operating cost of low-cost limestone process
f
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 70QO
6 7000
7 7000
8 7000
9 7000
10 7000 _
11 5000
12 5000
13 5000
14 5000
_15 SQQfl
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
3Q_ JL5QQ.. _
TOTAL
MFG. COST
>RODUCT RATE, INCLUDING
EQUIVALENT REGULATED
TONS/YEAR ROI FOR
POWER
100% COMPANY,
H2S04 S/YFAR
94200 6489000
94200 6388000
94200 6287000
94200 6186000
24.200 6.Q.a5QQO
94200 5984000
94200 5883000
94200 5782000
94200 5681000
__24.2QO_ 55.8.00.00,
67300 4831400
67300 4730400
67300 4629400
67300 4528400
£2300 4.4.224.20.
47100 3811700
47100 3710700
47100 3609700
47100 3508700
4.21QQ 3102200
20200 2543100
20200 2442100
20200 2341100
20200 2240100
_20209_ 2132100
20200 2038100
20200 1937100
20200 1836100
20200 1735100
2Q20Q _.. 16341QQ _
NET
imestone proce
REVENUE,
$/TON
100?
H2S04
8.00
8.00
8.00
8.00
6*00
8.00
8.00
8.00
8.00
. fimUfl
5.00
5.00
5.00
5.00
5»00
5.00
5.00
5.00
5.0C
5.00
5.00
5.00
5.00
5«.00
5.00
5.00
5.00
5.00
__5*QQ
ss
TOTAL
NET
SALES
REVENUE,
S/YEAR
753600
753600
753600
753600
753600
753600
753600
753600
753600
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$ $
5735400 5735400
5634400 11369800
5533400 16903200
5432400 22335600
5221AQO 226.fi2Q.Qfl
5230400 32897400
5129400 38026800
5028400 43055200
4927400 47982600
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
*/YEAR
4964100 (
4883000 (
4801900 (
4720800 (
4639700 t
4558600 I
4477500 (
4396400 (
4315300 (
253.60.fl 4fl264QQ 52flQ_9_QflQ A234.2QD L.
336500
336500
336500
336500
236.5QQ_
235500
235500
235500
235500
101000
101000
101000
101000
^pl QOQ
101000
101000
101000
101000
__ 1Q1QOQ_
4494900 57303900
4393900 61697800
4292900 65990700
4191900 70182600
4.Q9Q9QO 742J350Q
3576200 77849700
3475200 81324900
3374200 84699100
3273200 87972300
2442100 93586600
2341100 95927700
2240100 98167800
2139100 100306900
2Q3S1QO 102.24.50QQ
1937100 104282100
1836100 106118200
1735100 107853300
1634100 109487400
15321QQ 111Q2Q5QQ _
3703700 (
3622600 (
3541500 (
3460400 (
3322300 L.
2937400 (
2856300 (
2775200 (
2694100 (
1988500 (
1907400 (
1826300 (
1745200 (
16.6.41QO i.
1583000 (
1501900 (
1420800 1
1339700 (
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
$ $
771300)
751400)
731500)
711600)
691700)
671800)
651900)
632000)
612100)
5222001-
7912001
771300)
751400)
731500)
^2116QQJ_
6388001
618900)
599000)
5791001
453600)
433700)
413800)
393900)
354100)
334200)
314300)
294400)
12586DO . L 274500)
771300)
1522700)
2254200)
2965800)
3657500)
4329300)
49812001
5613200)
6225300)
63175QOJ
7608700)
83800001
9131400)
9862900)
I IQ524.50QJ.
11213300)
11832200)
12431200)
13010300)
14023100)
14456800)
14870600)
15264500)
1 5638500 )
15992600)
16326800)
16641100)
16935500)
L_ 1221QQQQ1
TOT 127500 1716000 122426500 11406000 111020500
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED 1.21
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.74
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 44197900
EQUIVALENT PRESENT WORTH» DOLLARS PER BARREL OF OIL BURNED 0.48
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.69
93810500
1.02
1.47
37916800
0.41
0.59
( 17210000)
( 6281100)
-------
OS
Table A-115
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 500 MW. EXISTING OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT: $
13920000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 S/YEAR H2S04 S/YEAR
1
2
3
4 7000
. 5 , _700Q
6 7000
7 7000
8 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
2P 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1.500
TOT 106500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
60200 5997100
60220 saaaao o
60200
60200
60200
60200
6Q2QP
43000
43000
43000
43000
43QQO
30100
30100
30100
30100
3Q1QO
12900
12900
12900
12900
12900
12900
12900
12900
12900
12200
5782600
5675300
5568100
5460800
53.5.3.6OQ
4693300
4586100
4478900
4371600
8.00
8.00
8.00
8.00
8.00
8.00
S*£0 __
8.00
8.00
8.00
5.00
5.00
3714400 5.00
3607200 5.00
3499900 5.00
3392700 5.00
32854PO 5..QQ
2514800
2407600
2300300
2193100
,,2085800 _
1978600
1871300
1764100
1656800
1549600
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
915900 99943200
COST, DOLLARS PER BARREL OF OIL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR,
PRESENT WORTH, DOLLARS PER BARREL OF OIL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
481600
481600
481600
481600
481600
4B16QQ
344000
344000
344000
215000
215.000.
150500
150500
150500
150500
150500
64500
64500
64500
64500
64,500
64500
64500
64500
64500
6230700
DOLLARS
BURNED
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
NET ANNUAL CUMULATIVE INCLUDING
INCREASE NET INCREASE REGULATED
(DECREASE! (DECREASE! ROI FOR
IN COST OF IN COST OF POWER
POWER, POWER, COMPANY,
S S S/YEAR
5515500 5515500 5032800
5.40fl2.0Q 10223.200 422fl20Q
5301000 16224700 4843600
5193700 21418400 4749000
5086500 26504900 4654400
4979200 31484100 4559800
4B.222QQ 3.625_&.lflfl 4465.100
4349300 40705400 3953400
4242100 44947500 3858800
4134900 49082400 3764200
4156600 53239000 3669600
40494.QQ 57288400 3574900
3563900
3456700
3349400
3242200
2124200
2450300
2343100
2235800
2128600
202120fl
1914100
1806800
1699600
1592300
1465.120
93712500
1.20
1.76
40215400
0.51
0.76
60852300
64309000
67658400
70900600
76485800
78828900
81064700
83193300
__S5.2146QQ
87128700
88935500
90635100
92227400
__222125QQ
3143500
3048900
2954300
2859700
2157000
2062400
1967800
1873200
1683900
1589300
1494700
1400100
12Q5.4QQ_
84147500
1.07
1.58
36435400
0.47
0.68
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS! (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF HET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
t S
( 482700!
i 42QQQfll_l
( 4574001
( 444700)
( 432100)
( 419400)
i 4062001—1
( 395900)
( 383300)
( 370700)
( 487000)
i 42450QJ—J
( 420400)
( 4078001
( 395100)
( 3825001
I 3623QQ1_
( 293300)
( 280700)
( 268000)
( 255400)
( 230200)
( 217500)
( 2049001
( 192200)
1 __1222QQl_.
( 9565000)
( 3780000)
4827001
25.21001
1410100)
1854800)
22869001
2706300)
311,32001
3509100)
3892400)
4263100)
4750100)
5645000)
6052800)
6447900)
6830400)
| 22.QQ2QQ1
7493600)
7774300)
80423001
8297700!
S5.405.00J
8770700)
8988200)
9193100)
93853001
L 2565J1QQ1
-------
Table A-116
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 1.0 * S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
14957000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR t/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100* COMPANY, 100? REVENUE,
START KW H2S04 $/YEAR H2S04 S/YEAR
1 7000
2 7000
3 7000
4 7000
5 7QQO
6 7000
7 7000
8 7000
9 7000
10 2fl22
11 5000
12 5000
13 5000
14 5000
15 5222
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500_
26 1500
27 1500
28 1500
29 1500
32 1500 _
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
^ EQUIVALENT
OS
OJ
45500
45500
45500
45500
4552fl
45500
45500
45500
45500
45522
32500
32500
32500
32500
_ 22522
22800
22800
22800
22800
22800
9800
9800
9800
9800
2322
9800
9800
9800
9800
9800
6373300
6269500
6165800
6062100
5958400
5854700
5751000
5647300
5543600
5422222
4735600
4631900
4528200
4424400
4222222
3740300
3636600
3532900
3429200
2225522-
2516500
2412800
2309100
2205400
2121622
1997900
1894200
1790500
1686800
1583100
8.00
8.00
8.00
8.00
8»00
NET ANNUAL
INCREASE
(DECREASEI
IN COST OF
POWER,
$
364000 6009300
364000 5905500
364000 5801800
364000 5698100
364000 5594400
CUMULATIVE
NET INCREASE
(DECREASEI
IN COST OF
POWER,
$
6009300
11914800
17716600
23414700
29009100
8.00 364000 5490700 34499800
8.00 364000 5387000 39886800
8.00 364000 5283300 45170100
8.00 3.64000 5179600 50349700
2*22 264222 5225.222 55425622-.
5.00 162500 4573100 59998700
5.00 162500 4469400 64468100
5.00 162500 4365700 68833800
5.00 162500 4261900 73095700
5.00 1625QO 415B2QO 77253900
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5. Op
5.00
5.00
5.00
5.00
5.00
829500 119868800
COST, DOLLARS PER BARREL OF OIL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR,
PRESENT WORTH, DOLLARS PER BARREL OF OIL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
114000
114000
114000
114000
114222
49000
49000
49000
49000
42222
49000
49000
49000
49000
42222 .
5512500
DOLLARS
BURNED
3626300
3522600
3418900
3315200
. -2211522 .
2467500
2363800
2260100
2156400
2£52622_.
1948900
1845200
1741500
1637800
_ 1534122-.
114356300
0.65
0.90
45980700
0.26
0.36
80880200
84402800
87821700
91136900
3.4243422
96815900
99179700
101439800
103596200
125643222—
107597700
109442900
111184400
112822200
114256222
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS! (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR $ t
5979600 ( 29700) ( 297001
5877300 ( 28200) ( 57900)
5774900 i 26900) ( 84800)
5672500 ( 25600) ( 1104001
5522122 J 243001 1347001
5467700
5365400
5263000
5160600
525fl222__J
4448600
4346200
4243800
4141400
4039000
3530500
3428100
3325700
3223300
2121222
2409700
2307300
2204900
2102500
2222222
1897800
1795400
1693000
1590700
143320.2
23000)
21600)
20300)
19000)
L 122221-J
124500)
123200)
121900)
120500)
L _ 1122221-J
95800)
945001
93200)
91900)
L 225221
578001
56500)
552001
53900)
L 5Z422J
51100)
49800)
48500)
471001
L 4.5BQQ1
112526700 ( 1829600)
0.63
0.88
45517600 ( 463100)
0.26
0.36
1577001
1793001
199600)
218600)
2262221
360800)
484000)
605900)
7264001
8456001
941400)
1035900)
11291001
1221000)
12115221
13693001
1425800)
1481000)
1534900)
1 158730.21
1638400)
1688200)
1736700)
17838001
1 15226221
-------
to
o\
-Pi
Table A-117
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 9&% H2S04 PRODUCTION.
FIXED INVESTMENT:
18888000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
.5 .7000
6 7000
7 7000
8 7000
9 7000
10. LC2Q_
11 5000
12 5000
13 5000
14 5000
100?
H2S04
113900
113900
113900
113900
1 1 3990
113900
113900
113900
113900
1112013
81300
81300
81300
81300
COMPANY,
$/YEAR
8282100
8151100
8020200
7889200
7758300
7627300
7496400
7365400
7234400
7J.0350Q
6139400
6008500
5877500
5746600
15 5.QQQ 81300 5615600
16 3500
17 3500
18 3500
19 3500
56900
56900
56900
56900
4827800
4696800
4565800
4434900
100%
H2S04
8.00
8.00
8.00
8.00
fl*.0_Q
8.00
8.00
8.00
8.00
8«.QO
5.00
5.00
5.00
5.00
REVENUE,
I/YEAR
911200
911200
911200
911200
2112QQ_
911200
911200
911200
911200
911200
406500
406500
406500
406500
ALTERNATIVE
OPERATING
COST FOR NON-
RECOVERY WET-
LIMESTONE
PROCESS
NET ANNUAL CUMULATIVE INCLUDING
INCREASE NET INCREASE REGULATED
(DECREASE) (DECREASE) ROI FOR
IN COST OF IN COST OF POWER
POWER,
$
7370900
7239900
7109000
6978000
68471 00.
6716100
6585200
6454200
6323200
6122.lQ.fl
5732900
5602000
5471000
5340100
POWER,
$
7370900
14610800
21719800
28697800
3.5.5.4.4-2QO.
42261000
48846200
55300400
61623600
_6.2fll.52Q.Q. _
73548800
79150800
S4621800
89961900
COMPANY,
$/YEAR
6890400
6775100
6659800
6544500
642930Q
6314000
6198700
6083400
5968100
«
(
{
(
(
(
(
(
(
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
480500)
4648001
449200)
433500)
4.17800 1
402100)
3865001
370800)
3551001
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
(
(
(
(
(
{
(
(
(
SCRUBBING,
$
480500)
945300)
13945001
1828000)
224.5..SQ.Q.J.
26479001
3034400)
3405200)
3760300)
5_a5_2flafi X 3325DQ1 I 40928001
5120700
5005400
4890100
4774800
(
(
(
(
612200)
596600)
580900)
565300)
(
(
(
(
4712000)
5308600)
5889500)
6454800)
^5»aO_- 4065QO . _ 5209100 _ 951710QO_ _4659500__( 549600) ( 70044(10)
5.00
5.00
5.00
5.00
284500
284500
284500
284500
20. 35flii S&S-ti! 4303900 5.00 284500
21 1500 24400
22 1500
23 1500
24 1500
25 ISQO.
26 1500
27 1500
28 1500
29 15CO
30 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
24400
24400
244uO
24.4.0.Q
24400
244JO
244CO
24400
24.4.0-ii
2074000
COST, DOLLARS
3213400
3082400
2951500
2820500
_26fl25.QO.
2558600
2427600
2296700
2165700
20.3-4_SQfl
155385,400
PER BARREL OF OIL
5.00
5.00
5.00
5.00
_5j.Qfl_
5.00
5.00
5.00
5.00
5«.QD
BURNED
122000
122000
122000
122000
. _122QCQ
122000
122000
122000
122000
1220.Q.Q.
13787000
COST, MILLS PER KILOWATT-HOUR
If DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10.0% TO INITIAL YEAR,
, DOLLARS PER BARREL OF OIL
DOLLARS
BURNED
, MILLS PER KILOWATT-HQUR
4543300
4412300
4281300
4150400
4Q.124fifl
3091400
2960400
2829500
2698500
_25fi25flfi
2436600
2305600
2174700
2043700
99714300
104126600
108407900
112558300
4052800
3937500
3822200
3706900
{
(
(
(
490500)
474800)
459100)
443500)
(
(
(
(
ll&5I22fifl 3591600 I 427800) (
119669100
122629500
125459000
128157500
2745400
2630100
2514900
2399600
(
(
(
(
346000)
330300)
314600)
298900)
(
(
(
I
7494900)
7969700)
8428800)
8872300)
23QfllfiQl
9646100)
9976400)
10291000)
10589900)
12fi225fiQfl_ 22fl43QO 1 2832QQJ i 108731001
133161600
135467200
137641900
139685600
2169000
2053700
1938400
1823100
(
(
(
(
267600)
251900)
236300)
2206001
(
(
(
(
1212flflfi 14.152J24J2Q HfllflQQ I 2Q5QQQ1 1
141598400
0.80
1.11
56611200
0.32
0.44
129543900
0.73
1.02
52482100
0.30
0.41
(
(
12054500)
4129100)
111407001
11392600)
11628900)
11849500)
12fi54_5flfll
-------
Table A-118
MAGNESIA SCHEME A, REGULAlED POWER CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
18888000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 ZQOQ
6 7000
7 7000
8 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500
EQUIVALENT
TONS/YEAR
100*
H2SQ4
113900
113900
113900
113900
113200
113900
113900
113900
113900
-113200
81300
81300
81300
81300
flllQQ
56900
56900
56900
56900
_2Q 3.5.00 5_62QQ__
21 1500
22 1500
23 1500
24 1500
2,5 1500
26 1500
27 1500
28 1500
29 1500
10. 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUI VAL ENT
to
OS
24400
24400
24400
24400
24400
24400
24400
24400
24400
2440Q
2074000
COST, DOLLARS
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
8282100
8151100
8020200
7889200
ZZ5.a3.QQ
7627300
7496400
7365400
7234400
Z1Q15.QJ3
6139400
6008500
5877500
5746600
5.615.6.00
4827800
4696800
4565800
4434900
4203.200
3213400
3082400
2951500
2820500
Z6.fl25.OQ
2558600
2427600
2296700
2165700
2Q34.2Q-Q
155385400
PER BARREL
NET REVENUE,
S/TON
100*
H2S04
8.00
8.00
8.00
8.00
.,, .- 8, go
8.00
8.00
8.00
8.00
3.00
5.00
5.00
5.00
5.00
5.A.QQ
5.00
5.00
5.00
5.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
911200
911200
911200
911200
9112QO
911200
911200
911200
911200
_ 211200 -
406500
406500
406500
406500
406500
284500
284500
284500
284500
NET ANNUAL
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NPN- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
CUMULATIVE INCLUDING PROCESS PROCESS
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
7370900
7239900
7109000
6978000
614Z1QQ
6716100
6585200
6454200
6323200
6122300
5732900
5602000
5471000
5340100
5.2Q21QQ
4543300
4412300
4281300
4150400
(DECREASE)
IN COST OF
POWFR,
$
7370900
14610800
21719800
28697800
3_5.5_442QQ
42261000
48346200
55300400
61623600
6.2215.200
73548800
79150800
84621800
89961900
25J.Z1QQQ
99714300
104126600
108407900
112558300
5^QQ 234500 4012400 11&.52ZZQO
5.00
5.00
5.00
5.00
122000
122000
122000
122000
5,00 122QOO__
5.00
5.00
5.00
5.00
5.00
OF OIL BURNED
122000
122000
122000
122000
122QQQ .
13787000
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10. OS
TO INITIAL YEAR,
, DOLLARS PER BARREL OF OIL
, MILLS PFR
KILOWATT-HOUR
DOLLARS
BURNED
3091400
2960400
2829500
2698500
. _ 256.Z5QQ .
2436600
2305600
2174700
2043700
., 1212flQQ_ .
141598400
0.80
1.11
56611200
0.32
0.44
119669100
122629500
125459000
128157500
. 13.QZ25QQQ_
133161600
135467200
137641900
139685600
. 14.152S4QQ-
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
8261100
8166900
8072700
7978500
Zfi.S43.QQ
7790200
7696000
7601800
7507600
Z413.4QQ
6082300
5988200
5894000
5799800
5.2Q5.6QQ
4656200
4562000
4467900
4373700
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
S
890200
927000
963700
1000500
1Q3.22QQ
1074100
1110800
1147600
1184400
1221100
349400
386200
423000
459700
426500
112900
149700
186600
223300
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
890200
1817200
2780900
3781400
43.1&6QQ
5892700
7003500
8151100
9335500
10556600
10906000
11292200
11715200
12174900
126.21400
12784300
12934000
13120600
13343900
__42Z25_QQ 26J11QQ 13JiQ4QQQ_
2840700
2746500
2652400
2558200
246.4QQQ
2369800
2275600
2181400
2087300
1223.100
154350700
0.87
1.21
63589800
0.36
0.50
( 250700)
( 213900)
( 177100)
( 140300)
i 1Q25QQ1
( 66800)
( 30000)
6700
43600
aQ3.QQ
12752300
6978600
13353300
13139400
12962300
12822000
iznaioa
12651700
12621700
12628400
12672000
12Z5Z3.00
-------
ON
ON
Table A-119
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 4.0 * S IN FUEL, 98? H2 S04 PRODUCTION.
FIXED INVESTMENT:
22046000
Includes comparison
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
EQUIVALENT REGULATED NET REVENUE, TOTAL
TONS/YEAR ROI FOR $/TON NET
POWER SALES
100% COMPANY, 100? REVENUE,
H2S04 $/YEAR H2S04 S/YEAR
182200
182200
182200
182200
182200
6 7000 182200
7 7000 182200
8 7000 182200
9 7000 182200
10 ZOOQ 18,220.0
11 5000 130100
12 5000 130100
13 5000 130100
14 5000 130100
15 5000 130100
16 3500
17 3500
18 3500
19 3500
20 3500_
21 1500
22 1500
23 1500
24 1500
26 1500
27 1500
28 1500
29 1500
30 1500
91100
91100
91100
91100
911,00
39000
39000
39000
39000
39000
9859800
9706900
9554000
9401200
8.00
8.00
8.00
8.00
_8^QO
9095500 8.00
8942600 8.00
8789800 8.00
8636900 8.00
a4B.4QQo a*.oc
7296600 5.00
7143700 5.00
6990900 5.00
6838000 5.00
66.851,00. . _5.00
5720400
5567500
5414700
5261800
-51P89QQ
3778700
3625800
3473000
3320100
3167200
39000 3014400
39000 2861500
39000 2708700
39000 2555800
323.0.0. 24.Q3.OQp
5.00
5.0C
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
1457600
1457600
1457600
1457600
1457600
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
i
8402200
8249300
8096400
7943600
7790700
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
8402200
16651500
24747900
32691500
40482200
1457600 7637900 48120100
1457600 7485000 55605100
1457600 7332200 62937300
1457600 7179300 70116600
145260.0. 20.26.4.00. 22143.000-
650500 6646100 83789100
650500 6493200 90282300
650500 6340400 96622700
650500 6187500 102810200
6.50.50.0. _ M)346flO 105fi4iBQQ
455500
455500
455500
455500
_ 45550.0. .
195000
195000
195000
195000
1250.0.0 .
195000
195000
195000
195000
1250QQ_.
5264900
5112000
4959200
4806300
3583700
3430800
3278000
3125100
. _22222QO _
2819400
2666500
2513700
2360800
220SOOO
114109700
119221700
124180900
128987200
137224300
140655100
143933100
147058200
—150030400-
152849800
155516300
158030000
160390800
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- Of WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
WYEAR $ $
7717900
7591700
7465500
7339300
_ 22131QQ
7086900
6960800
6834600
6708400
5732700
5606500
5480300
5354100
5222200
4527300
4401100
4274900
4148700
4022500
3046900
2920800
2794600
2668400
2542200-
2416000
2289800
2163600
2037400
_ - 1211200-
684300)
657600)
630900)
604300)
5776Q01
551000)
524200)
497600)
4709001
913400)
886700)
860100)
833400)
8.062001-
737600)
710900)
684300)
657600)
63Q20Q1-J
536800)
5100.00)
4834001
456700)
t 4100001-
403400)
376700)
350100)
323400)
L 226flQQl_
684300)
1341900)
19728001
2577100)
21542001
3705700)
4229900)
4727500)
5198400)
1 56426001
6556000)
7442700)
8302800)
9136200)
2242200.1
10680500)
11391400)
12075700)
12733300)
L__JL22642QQ1
13901000)
14411000)
14894400)
15351100)
L 1528.11QQ1
16184500)
16561200)
16911300)
17234700)
L_ 125315001
TOT 127500 3318000 134654800 22056000 162598800
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED 0.92
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.28
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 64717200
EQUIVALENT PRESENT WORTH, DOLLARS PER BARREL OF OIL BURNED 0.37
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.51
145067300
0.82
1.14
58833700
0.33
0.46
( 17531500)
5883500)
-------
Table A-120
MAGNESIA SCHEME A, REGULATED POWER CO. ECONOMICS, 1000 MW. EXISTING OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
20740000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 t/YEAR H2S04 »/YEAR
1
2
3
4 7000
_ 5 7000
6 7000
7 7000
8 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
^15 . 5QQQ_ ._
16 3500
17 3500
18 3500
19 3500
20 3500 _ _
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1500
117800
11780.0
117800
117800
117800
117800
._ _iizap_o_
84100
84100
84100
84100
_ 84100
58900
58900
58900
58900
58900
25200
25200
25200
25200
25202
25200
25200
25200
25200
8979700
8820000
8660200
8500400
8340700
8180900
B.2.21122
6987100
6827300
6667500
6507800
63.48QOO
5498400
5338700
5178900
5019100
__ 485.94QQ
3688700
3529000
3369200
3209400
3.242202
2889900
2730100
2570400
2410600
22528.20-
8.00
8.00
8.00
8.00
8.00
__fl*22__
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5.00
5.00
5.0Q
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5..QQ
942400
242422
942400
942400
942400
942400
242400
672800
672800
672800
420500
__4205flfl
294500
294500
294500
294500
_224.5Qfl
126000
126000
126000
126000
_ _ -126220
126000
126000
126000
126000
126222--
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
8037300
2S_22622
7717800
7558000
7398300
7238500
2225202
6314300
6154500
5994700
6087300
-5222502—
5203900
5044200
4884400
4724600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
8037300
23632700
31190700
38589000
45827500
59220500
65375000
71369700
77457000
-£338.4520
88588400
93632600
98517000
103241600
_LQ2fl065QQ .
3562700 111369200
3403000 114772200
3243200 118015400
3083400 121098800
2223202 124222522—
2763900 126786400
2604100 129390500
2444400 131834900
2284600 134119500
__2124fl22 136244322-.
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR t *
7604800 ( 432500) ( 432500)
2463320- i 414300) ( 846800)
7321900
7180400
7039000
6897500
5942200
5800700
5659200
5517800
5326302 J
4699300
4557800
4416300
4274900
3195900
3054400
2912900
2771500
2630002- J
2488600
2347100
2205600
2064200
_ 1222202 _
395900)
377600)
359300)
341000)
3227001 J
3721001
353800)
335500)
569500)
L 5512001
504600)
486400)
468100)
449700)
431500)
366800)
348600)
330300)
311900)
L 2232221_J
275300)
257000)
238800)
2204001
1242700)
1620300)
1979600)
2320600)
26433221
3015400)
3369200)
3704700)
4274200)
i 4B.254221
53300001
5816400)
6284500)
6734200)
1 21652001
7532500)
7881100)
8211400)
8523300)
I 8.8.122221
9092300)
9349300)
9588100)
9808500)
L_ 122126221
TOT 106500 1791600 148433000 12188700 136244300
EQUIVALENT COST, DOLLARS PER BARREL OF OIL BURNED 0.89
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 1.28
PRESENT WORTH IF DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS 58523000
EQUIVALENT PRESENT WORTH, DOLLARS PER BARREL OF OIL BURNED 0.38
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 0.55
to
OS
126233700
0.82
1.19
54890100
0.36
0.52
( 100106001
3632900)
-------
to
a^
oo
Table A-121
MAGNESIA SCHEME 3, REGULATED POWER CO. ECONOMICS, 200 MW. NEW COAL FIRED POWER PLANT, 3.5 ? S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
$ 11990000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
i -with projected operating cost of low-cost limestone process
TOTAL
PRODUCT RAT?,
EQUIVALENT
TONS/YEAR
iocs;
H2S04
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY ,
I/YEAR
NET REVENUE,
$/TON
100?
H2S04
TOTAL
NET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST COR NON-
RECOVERY WF.T-
LIMFSTONE
CUMULATIVE
NET INCREASE
(DFCRFASE)
IN COST OF
POWER,
$
PROCESS
INCLUDING
REGJLATED
ROI FOR
P3WER
COMPANY,
$/YEAR
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMF.STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING
t
UNIT
START
1
2
3
4
6
7
8
9
12 .
11
12
13
16
17
18
19
22
21
22
23
24
26
27
28
29
KW-HR/
7000
7000
7000
7000
2222
7000
7000
7000
7000
__2222_ _
5000
5000
5000
5000
r>202
loos;
H2S04
45200
45200
45200
45200
45220
45200
45200
45200
45200
45222
32300
32300
32300
32300
32300
3500 22600
3500 22600
3500 22600
3500 22600
_2502 22600
1500
1500
1500
1500
1500
1500
1500
1500
1500
1522 - -
9700
9700
9700
9700
2200
9700
9700
9700
9700
2202
COMPANY ,
I/YEAR
5187000
5103900
5020700
4937600
-48.54500--
4771300
4688200
4605100
4521900
4433220 .
3884900
3801800
3718700
3635500
25524QO—
3088300
3005100
2922000
2338800
-2255200
2092600
2009400
1926300
1843200
1676900
1593700
1510600
1427500
. 1344320—
100?
H2S04
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
2^00
5.00
5.00
5.00
5.00
5*02
5.00
5.00
5.00
5.00
. 5^.00
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
REVENUE,
S/YEAR
361600
361600
361600
361600
261600 .
361600
361600
361600
361600
261600 .
161500
161500
161500
161500
161500
113000
113000
113000
113000
_113QQQ_.
48500
48500
48500
48500
48500
48500
48500
48500
POWER,
$
4825400
4742300
4659100
4576000
4409700
4326600
4243500
4160300
3723400
3640300
3557200
3474000
3222200
2975300
2892100
2809000
2725800
264.2IQO. .
2044100
1960900
1877300
1794700
12115QQ
1628400
1545200
1462100
1379000
POWER,
$
4825400
9567700
14226800
18802800
._ 22225200 _
27705400
32032000
36275500
40435800
48236400
51876700
55433900
58907900
65274100
68166200
70975200
73701000
26343202
78387800
80348700
82226500
84021200
- -8.5Z222QQ
87361100
88906300
90368400
91747400
23Q422QO- .
COMPANY, SCRUBBING, SCRUBBING,
$/YEAR S t
3325400 (
3761700
3698000
3634200
_ 2522500-
3506800
3443000
3379300
3315600
—2251200
2868100
2804400
2740700
2676900
2612200
2288900
2225100
2161400
2097700
2Q332QQ
1567700
1504000
1440200
1376500
1212BQO
1249100
1185300
1121600
1057900
224100
1000000)
980600)
961100)
941800)
2224201
902900)
883600)
864200)
844700)
3253001
855300)
835900)
816500)
797100)
2222001
686400)
667000)
647600)
628100)
476400)
456900)
437600)
418200)
L 2282001
379300)
359900)
340500)
321100)
L— 3012001-
1000000)
1980600)
2941700)
3883500)
4.a059.QQl
5708800)
6592400)
7456600)
8301300)
21266001
9981900)
10817800)
11634300)
12431400)
--1320210.01
13895500)
14562500)
15210100)
15838200)
16923400)
17380300)
17817900)
18236100)
I— ia&.34flQQl
19014100)
19374000)
19714500)
20035600)
i__2022230Ql
TOT 127500 823500 98516700 5473.500 93043200
EQUIVALENT COST, DOLLARS PER TON OF COAL BURNED 9.52
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 3.65
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 37116300
f-'OUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL BURNED 3.80
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HTUR 1.46
72705900
7.44
2.85
29257300
2.99
1.15
( 20337300)
7859000)
-------
Table A-122
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98Z H2S04 PRODUCTION.
FIXED INVESTMENT:
22237000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
YEARS
AFTER
POWER
UNIT
START
ANNUAL
0 P E R A-
TION,
KW-HR/
KW
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2SC4
MFG. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
NET REVENUE,
S/TON
100?
H2S04
TOTAL
NET
SALES
REVENUE,
*/YEAR
NET ANNUAL
INCREASE
(DFCREASE)
IN COST OF
POWFR,
$
ALTERNATIVE
OPERATING
COST POP, NON-
RECOVERY WET-
LIMESTONE
CUMULATIVE
NET INCREASE
(DECREASE)
IN C3ST OF
POWFR,
$
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
S
CUMULATIVE
SAVINGS
(LOSS)
US INS
RECOVERY
PROCESS
INSTEAD
OF KPT-
LIMESTONE
SCRUBBING
$
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
8
9
11
12
13
~16
17
18
19
-20
21
22
23
24
26
27
28
29
3.P
7000
7000
7000
7000
-1002-.
7000
7000
7000
7000
2000
5000
5000
5000
5000
5000 .
3500
3500
3500
3500
2500
1500
1500
1500
1500
1502-
1500
1500
1500
1500
1520—
100?
H2SC4
110400
110400
110400
110400
11Q4QQ
110400
110400
110400
110400
110400
78900
78900
78.900
78900
23200
55200
55200
55200
55200
55222
23700
23700
23700
23700
_ 22222
23700
23700
23700
23700
22222
COMPANY,
S/YEAR
9474700
9320500
9166400
9012200
8703800
8549700
8395500
8241300
aoa2200
7053700
6899500
6745400
6591200
6422000
5581500
5427300
5273100
5118900
4264aOQ
3763700
3609500
3455400
3301200
3142000-
2992900
2838700
2684500
2530300
2226200
100?
H2S04
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
_ 5*20-
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
. 5*20 __
5.00
5.00
5.00
5.00
REVENUE,
*/YEAR
883200
883200
883200
883200
aa22QQ
883200
883200
883200
883200
aa220Q
394500
394500
394500
394500
224522—
276000
276000
276000
276000
-226.222
118500
118500
118500
118500
llflSQQ .
118500
118500
118500
118500
POWFR,
$
8591500
8437300
8283200
8129000
2224aOQ
7820600
7666500
7512300
7358100
2224200
6659200
6505000
6350900
6196700
. 6042500
5305500
5151300
4997100
4842900
3645200
3491000
3336900
3182700
2874400
2720200
2566000
2411800
. 2252222
POWFR,
$
8591500
17028800
25312000
33441000
41415flOO
49236400
56902900
64415200
71773300
22222200
85636500
92141500
98492400
104689100
-11Q2216QQ
116037100
121188400
126185500
131028400
125212202
139362403
142853400
146190300
149373000
-152401500
155275900
157996100
160562100
162973900
1652216QQ _
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR S $
7209600 (
7087400 (
6965200 (
6843000 (
6222200 i
6593700 (
6476500 (
6354300 (
6232100 (
6110002 L
5381100 (
5258930 (
5136700 (
5014500 (
_ _4a224QQ_ 1_.
4283700 (
4158500 I
4036300 (
3914200 (
2222QQQ L
2926100 (
2803900 (
2&81730 (
2559600 I
2422400 i
2315200 (
2193300 (
2070800 (
1948700 I
1381900)
1349900)
1318300)
1286000)
12522001
1221900)
1190000)
1158000)
1126000)
10240221
1278100)
1246100)
1214200)
1182200)
. 11521001
1024800)
992800)
960800)
928700)
719100)
697100) .
655200)
623100)
5211001
559200)
527200)
495200)
463100)
. 4212221
1381900)
2731800)
4049800)
5335800)
65322201
7811600)
9001600)
10159600)
11285600)
122226021
13657700)
14903800)
16118000)
17300200)
19475100)
20467900)
21428700)
22357400)
222542001
23973300)
24660400)
25315600)
25938700)
__ 26522S221
27089000)
27616200)
28111400)
28574500)
L _222Q52Q01
TOT 127500 2011500 178601100 13369500 165231600
EQUIVALENT COST, DOLLARS PER TON OF COAL BURNED 6.91
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 2.59
PRESENT WORTH IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS 65952600
EQUIVALENT PRESENT WORTH, DOLLARS PER TON OF COAL BURNED 2.76
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 1.03
10
ON
136225900
5.70
2.14
54984900
2.30
0.86
( 29005700)
( 10967700)
-------
to
-J
o
Table A-123
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 1 S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
22237000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATF, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER HPERA- TONS/Y
-------
Table A-124
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 1000 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
33838000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100% COMPANY, 100? REVENUE,
START KW H2S04 S/YEAR H2S04 S/YEAR
1 7000
2 7000
3 7000
4 7000
5. _ 2Q2Q_
6 7000
7 7000
8 7000
9 7000
_1,Q 20Q2-
11 5000
12 5000
13 5000
14 5000
15 _50QO
16 3500
17 3500
18 3500
19 3500
20 2520
21 1500
22 1500
23 1500
24 1500
25. L500-
26 1500
27 1500
28 1500
29 1500
3P 150Q
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
to
-j
213500
213500
213500
213500
2125QQ
213500
213500
213500
213500
212520
152500
152500
152500
152500
152500—
106800
106800
106800
106800
45800
45800
45800
45800
45320
45800
45800
45800
45800
45800
14324000
14089400
13854800
13620200
122S56QQ
13151000
12916400
12681800
12447200
12212600
10609200
10374600
10140000
9905400
262QaOQ
8356000
8121400
7886700
7652100
2412500
5603000
5368400
5133800
4899200
4664600-
4430000
4195400
3960800
3726200
34216.QQ
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
_5^QQ
5.00
5.00
5.00
5.00
5^QQ
1708000
1708000
1708000
1708000
1208000
1708000
1708000
1708000
1708000
12QaOQQ
762500
762500
762500
762500
26250Q-.
534000
534000
534000
534000
524QQQ-.
229000
229000
229000
229000
22200Q-.
229000
229000
229000
229000
222Q.QQ .
3889500 268289700 25852500
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS
PRESENT WORTH, DOLLARS PER TON OF COAL BURNED
PRESENT WORTH, MILLS PER KILOWATT-HOUR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWF.R,
$
12616000
12381400
12146800
11912200
11622600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
S
12616000
24997400
37144200
49056400
60734000
11443000 72177000
11208400 83385400
10973800 94359200
10739200 105098400
1Q5Q46QQ 115602000-.
9846700 125449700
9612100 135061800
9377500 144439300
9142900 153582200
___ 8908,30P 162490500
7822000
7587400
7352700
7118100
170312500
177899900
185252600
192370700
199254200
5374000 204628200
5139400 209767600
4904800 214672400
4670200 219342600
4425600 22222a2QO
4201000 227979200
3966400 231945600
3731800 235677400
3497200 239174600
2262600 242437200
242437200
5.25
1.90
96743000
2.09
0.76
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGJLATED INSTEAD INSTEAD
ROI FOR OF WET- OF WFT-
PTWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR S $
11082800
10892700
10702700
10512600
10222500 i
10132500
9942400
9752300
9562200
2222200
8236300
8046200
7856200
7666100
2426002 1
6530600
6340600
6150500
5960400
522Q4QQ
4451700
4261600
4071600
3381500
2621422
3501300
3311300
3121200
2931100
2241100
1533200)
1488700)
1444100)
1399600)
L 12551001 J
1310500)
1266000)
1221500)
1177000)
L 11224001 J
1610400)
1565900)
1521300)
1476800)
L 14222001
1291400)
1246800)
1202200)
1157700)
L 11121221
922300)
877800J
833200)
788700)
L 2442221
699700)
655100)
610600)
566100)
521500)
208272000 ( 34165200)
4.51
1.63
84316100 ( 12426900)
1.82
0.66
1533200)
3021900)
4466000)
5865600)
L 22202001
8531200)
97972001
11018700)
12195700)
L 12223100.1
14938500)
16504400)
18025700)
19502500)
L 20224a2Ql
22226200)
23473000)
24675200)
25832900)
L— 2624600Q1
27868300)
28746100)
29579300)
30368000)
L 211122001
31811900)
32467000)
33077600)
33643700)
L__241652QQ1
-------
to
-J
t-o
Table A-125
MAGNESIA SCHEME 8, REGULATED POWER CO. ECONOMICS, 200 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
6806000
Includes comparison \vith projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TtON, POWER SALES
UNIT KW-HR/ 100* COMPANY, 100% REVENUE,
START KW
1 7000
2 7000
3 7000
4 7000
5 ZQOQ
6 7000
7 7000
8 7000
9 7000
10 ZQOO
11 5000
12 5000
13 5000
14 5000
15 _5QQQ
16 3500
17 3500
18 3500
19 3500
20 2500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
20 1500.
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
H2S04
24100
24100
24100
24100
24100
24100
24100
24100
24100
241QQ
17200
17200
17200
17200
1Z2J3Q
12000
12000
12000
12000
12000
5200
5200
5200
5200
5200
5200
5200
5200
5200
5200 _
439000
COST, DOLLARS
$/YEAR
2982400
2935300
2888100
2840900
2Z22JQQ
2746500
2699300
2652100
2604900
255Z2QQ
2243800
2196600
2149400
2102200
2Q55QQQ
1790000
1742800
1695600
1648400
16Q12QQ _
1217700
1170500
1123400
1076200
_ 1022QQQ
981800
934600
887400
840200
222000 _ _
56979700
PER BARREL OF OIL
H2S04
8.00
8.00
8.00
8.00
fl^-llQ
8.00
8.00
8.00
8.00
£^QQ
5.00
5.00
5.00
5.00
-5*00 _
5.00
5.00
5.00
5.00
5 4.00
5.00
5.00
5.00
5.00
5 00
5.00
5.00
5.00
5.00
5.*.Q Q
BURNED
S/YEAR
192800
192800
192800
192800
. -122BQQ
192800
192800
192800
192800
_ 122300
86000
86000
86000
86000
86000
60000
60000
60000
60000
60000
26000
26000
26000
26000
26.QQQ
26000
26000
26000
26000
26QQQ
2918000
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH,
PRESENT WORTH,
AT 10.0? TO INIT
IAL YEAR,
DOLLARS PER BARREL OF OIL
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PR1CESS RECOVERY RECOVERY
NET ANNUAL CUMULATIVE INCLUDING PROCESS PROCESS
INCREASE NET INCREASE REGULATED INSTEAD INSTEAD
(DECREASE) (DECREASE) ROI FOR OF WET- OF WET-
IN COST OF IN COST OF POWER LIMFSTONF LIMESTONE
POWER, POWER, COMPANY, SCRUBBING, SCRUBBING,
$
2789600
2742500
2695300
2648100
_ 2600200
2553700
2506500
2459300
2412100
22642QQ
2157800
2110600
2063400
2016200
12620QQ
1730000
1682800
1635600
1588400
1541200
1191700
1144500
1097400
1050200
1QQ2QQQ
955800
908600
861400
814200
„ 26ZQQQ- .
54061700
1.44
2.12
21510000
0.57
0.84
t
2789600
5532103
8227400
10875500
12426400 .
16030100
18536600
20995900
23408000
25222200
27930700
30041300
32104700
34120900
26Qfl22QQ
37819900
39502700
41138300
42726700
44262200 .
45459600
46604100
47701500
4R751700
42254ZQQ
50710500
51619100
52480500
53294700
. 54Q61ZQQ- .
S/YEAR
2429700 (
2390200 (
2350700 (
2311100 (
22Z16QQ I
2232100 (
2192600 (
2153100 (
2113500 (
2QZ40QQ L
1826600 (
1787100 (
1747600
1708000
1666500 i
1459000
1419500
1380000
1340400
._ 12QQ2QQ 1
997500
958000
918500
878900 t
222400 i
799900 (
760400 (
720900 (
681300 (
6418.0.Q 1
46352800 (
1.24
1.82
18625500 (
0.50
0.73
S
359900) (
352300) (
344600) (
337000) (
2222QQ.1 i
321600) (
313900) (
306200) (
298600) (
S
359900)
712200)
1056800)
1393800)
1J221QQ1
2044700)
2358600)
2664800)
2963400)
22020°! I 3254300)
331200) (
323500) (
315800) (
308200) (
2005001 i
271000) (
263300) (
255600) (
248000) (
3585500)
3909000)
4224800)
4533000)
42225001
5104500)
5367800)
5623400)
5871400)
24Q2QQ.1 i 6111700)
194200) (
186500) (
178900) (
171300) (
6305900)
6492400)
6671300)
6842600)
1626001 1 ZQQ62QQ1
155900) ( 7162100)
148200) (
140500) (
132900) (
1252Q21 I
7708900 )
2834500)
7310300)
7450800)
7583700)
ZZQa2QQl
-------
Table A-126
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
12561000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 2000- .
6 7000
7 7000
8 7000
9 7000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
58900
58900
58900
58900
53200
58900
58900
58900
58900
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
$/YEAR
5359900
5272800
5185700
5098600
50.1150.0
4924400
4837400
4750300
4663200
NET REVENUE,
*/TON
100?
H2S04
8.00
8.00
8.00
8.00
_ 3.*00
8.00
8.00
8.00
8.00
10 20QQ 58900 4576100 8.00
11 5000
12 5000
13 5000
14 5000
_15 500.0-
16 3500
17 3500
18 3500
19 3500
42100
42100
42100
42100
_ 4.2100
29400
29400
29400
29400
-20. -3.500 224QCL
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
3J1 150.0. —
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
., EQUIVALENT
12600
12600
12600
12600
_ 12600
12600
12600
12600
12600
12600
1072500
4000500
3913400
3826300
3739200
3.&52100
3173100
3086100
2999000
2911900
—2324300
2147600
2060500
1973400
1886300
-122320.0
1712100
1625100
1538000
1450900
J.3638QO
101363200
COST, DOLLARS PER BARREL OF
COST, MILLS PER
5.00
5.00
5.00
5.00
5 0.0
5.00
5.00
5.00
5.00
5,00
5.00
5.00
5.00
5.00
5~&0.0
5.00
5.00
5.00
5.00
5.00
OIL BURNED
TOTAL
NET
SALES
REVENUE,
$/YEAR
471200
471200
471200
471200
421200
471200
471200
471200
471200
4.2120.0
210500
210500
210500
210500
210500
147000
147000
147000
147000
142000
63000
63000
63000
63000
6.200.0.
63000
63000
63000
63000
62000.
7129500
KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO
PRESENT WORTH,
PRESENT WORTH,
DOLLARS PER
INITIAL YEAR,
BARREL OF OIL
DOLLARS
BURNED
MILLS PER KILOWATT-HOUR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
4888700
4801600
4714500
4627400
4540200.
4453200
4366200
4279100
4192000
4104200.
3790000
3702900
3615800
3528700
344160.0
3026100
2939100
2852000
2764900
2622300
2084600
1997500
1910400
1823300
123.6200.
1649100
1562100
1475000
1387900
. 1200300.
94233700
1.03
1.48
37564700
0.41
0.59
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS PFCOVFRY RECOVERY
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4888700
9690300
14404800
19032200
22522500
28025700
32391900
36671000
40863000
44262200...
48757900
52460803
56076600
59605300
63.04620Q
66073000
69012100
71864100
74629000
222fl63flQ_
79391400
81388900
83299300
85122600
36353300
88507900
90070000
91545000
92932900
24222200
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
$/YEAR
4454500
4308500
4306400
4232400
4153200
4084300
4010200
3936200
3862100
22331Q0
3325700
3251600
3177600
3103500
2022500.
2642700
2568700
2494600
2420600
2246500
1798300
1724200
1650200
1576100
1502100
1428000
1354000
1279900
1205900
1121320
84152500
0.92
1.32
33948200
0.37
0.53
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE LIMESTONE
SCRUBBING, SCRUBBING,
S $
( 434200)
( 493100)
( 408100)
( 395000)
I 2320001 J
( 368900)
( 356000)
( 342900)
( 329900)
I 21630Q1_J
( 464300)
( 451300)
( 438200)
( 425200)
L 4121001 J
( 383400)
( 370400)
I 357400)
( 344300)
I 2212001
( 286300)
( 273300)
( 260200)
( 247200)
L 22410QJ.
( 221100)
t 208100)
( 195100)
( 182000)
434200)
927300)
1335400)
1730400)
21124001
2481300)
2837300)
3180200)
3510100)
L 23262001
4291200)
4742500)
5180700)
5605900)
L 60130001
6401400)
6771800)
7129200)
7473500)
L 28043001
8091100)
8364400)
8624600)
8871800)
L 21052001
9327000)
9535100)
9730200)
9912200)
1 1620001 I 10.03120.01.
( 10031200)
( 36165001
-------
to
-0
Table A-127
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
12561000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR $/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 S/YEAR H2S04 */YEAR
1 7000
2 7000
3 7000
4 7000
5_ 2200
6 7000
7 7000
8 7000
9 7000
11 5000
12 5000
13 5000
14 5000
_L5 5222 _
16 3500
17 3500
18 3500
19 3500
20 2500
21 1500
22 1500
23 1500
24 1500
?5 1500
58900
58900
58900
58900
55200
58900
58900
58900
58900
42100
42100
42100
42100
_421QQ__
29400
29400
29400
29400
22422
12600
12600
12600
12600
5359900
5272800
5185700
5098600
_ 5211522
4924400
4837400
4750300
4663200
4000500
3913400
3826300
3739200
36.52102 _
3173100
3086100
2999000
2911900
2147600
2060500
1973400
1886300
1222200-
26 1500 12600 1712100
27 1500 12600 1625100
28 1500 12600 1538000
29 1500 12600 1450900
32 1522 12622 1363B02
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
1072500 101363200
COST, DOLLARS PER BARREL OF OIL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR,
PRESENT WORTH, DOLLARS PER BARREL OF OIL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
471200
471200
471200
471200
121202
471200
471200
471200
471200
421200
210500
210500
210500
210500
210520
147000
147000
147000
147000
142222-
63000
63000
63000
63000
6.3200
63000
63000
63000
63000
62022 _
7129500
DOLLARS
BURNED
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
NET ANNUAL CUMULATIVE INCLUDING PROCESS PROCESS
INCREASE NET INCREASE REGULATED INSTEAD INSTEAD
(DECREASE) (DECREASE) ROI FOR OF WET- OF WET-
IN COST OF IN COST OF PDWER LIMFSTONF LIMESTONE
POWER, POWER, COMPANY, SCRUBBING, SCRUBBING,
$ $ t/YEAR $ $
4888700
4801600
4714500
4627400
4542322
4453200
4366200
4279100
4192000
_ -4104220-
3790000
3702900
3615800
3528700
3441622—
3026100
2939100
2852000
2764900
2622fi2Q
2084600
1997500
1910400
1823300
1236.200
1649100
1562100
1475000
1387900
13QOafl2
94233700
1.03
1.48
37564700
0.41
0.59
4888700
9690300
14404800
19032200
22522522
28025700
32391900
36671000
40863000
44262220
48757900
52460800
56076600
59605300
6.2246222
66073000
69012103
71864100
74629000
22226322
79391400
81388900
83299300
85122600
. fi6a5aaoo
88507900
90070000
91545000
92932900
._ 24232202
5015800
4955600
4895400
4835200
4225QQQ
4714800
4654600
4594400
4534200
4424002
3712000 (
3651800 (
3591600 (
3531400
3421222
2865100 (
2804900 (
2744700 (
2684600 (
2624422 L
1783400 (
1723200 (
1663000 (
1602800 (
1542620 I
1482400 (
1422200 (
1362000 (
1301800 (
1241620 i
94255700
1.03
1.48
38632900
0.42
0.61
127100
154000
180900
207800
261600
288400
315300
342200
362122
78000)
51100)
24200)
2700
22622
161000)
134200)
107300)
80300)
524221
301200)
274300)
247400)
220500)
1226221
166700)
139900)
113000)
86100)
522.221
22000
1068200
127100
281100
462000
669800
204502-
1166100
1454500
1769800
2112000
24S1120
2403100
2352000
2327800
2330500
2260122
2199100
2064900
1957600
1877300
1522200
1522700
1248400
1001000
780500
5869QQ
420200
280300
167300
81200
22022
-------
Table A-128
MAGNESIA SCHEME B, REGULATED POWER CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT:
19126000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KH-HR/ 100? COMPANY, 100? REVENUE,
START KW H2S04 i/YEAR H2S04 S/YEAR
1 7000
2 7000
3 7000
4 7000
5_ _I222_
6 7000
7 7000
8 7000
9 7000
10 2000
11 5000
12 5000
13 5000
14 5900
15 5220
16 3500
17 3500
18 3500
19 3500
_20 3522__.
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 1500_
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
to
-o
113900
113900
113900
113900
1139.0(5
113900
113900
113900
113900
113200
81300
81300
81300
81300
8X3QO
56900
56900
56900
56900
56222-
24400
24400
24400
24400
24422
24400
24400
24400
24400
24402
8115900
7983300
7850700
7718100
25fi5520_
7452900
7320300
7187700
7055100
62225QQ
6022800
5890200
5757600
5625000
5422400
4752400
4619800
4487200
4354600
4222QOQ
3194900
3062300
2929700
2797100
26.6>500
2531900
2399300
2266700
2134100
200150.0
8.00 911200
8.00 911200
8.00 911200
8.00 911200
a*00 _ 911200
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5. 00
5.00
5.00
5.00
5.00
5^Qfl
2074000 152398000
COST, DOLLARS PER BARREL OF OIL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR,
PRESENT WORTH, DOLLARS PER BARREL OF OIL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
911200
911200
911200
911200
211200
406500
406500
406500
406500
406522
284500
284500
284500
284500
2fl4502__
122000
122000
122000
122000
122000-
122000
122000
122000
122000
. _ 12202Q_
13787000
DOLLARS
BURNED
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
S $
7204700
7072100
6939500
6806900
6624322
6541700
6409100
6276500
6143900
6011300
5616300
5483700
5351100
5218500
5025222
7204700
14276800
21216300
28023200
34622520
41239200
47648300
53924800
60068700
66020QQQ
71696300
77180000
82531100
87749600
92835500
4467900 97303400
4335300 101638700
4202700 105841400
4070100 109911500
3232502 113242000--
3072900 116921900
2940300 119862200
2807700 122669900
2675100 125345000
2542500 127887500
2409900
2277300
2144700
2012100
1222500
138611000
0.78
1.09
55284000
0.31
0.43
130297400
132574700
134719400
136731500
133611220
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMFSTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR 3F WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR $ S
6890400 I
6775100 (
6659800 (
6544500 (
6422320 i
6314000 (
6198730 (
6083400 (
5968100 (
5252300 I
5120700 (
5005400 (
4893130 (
4774800 (
4652500 i
4052800 (
3937500 (
3822200 (
3706900 (
3521600 _i
2745400 (
2630100 (
2514900 I
2399600 (
2224300 1
2169000 (
2053700 (
1938400 (
1323100 (
1202300 L
129543900 (
0.73
1.02
52482130 {
0.30
0.41
314300) ( 314300)
297000) ( 611300)
279700) ( 891000)
262400) ( 1153400)
2452221 i 1398400)
227700) (
2104001 (
193100) (
175800) (
1525001 I
495600) (
478300) (
461000) (
443700) (
4264021 I
415100) (
397800) (
380500) (
363200) (
3452221 I
327500) (
310200) (
292800) (
275500) (
2522001 i
240900) (
223600) (
206300) (
189000) (
1212001 i
9067100)
2801900)
1626100)
1836500)
2029603)
2205400)
.__23_63_2QQ1
2859500)
3337800)
3798800)
4242500)
46622001
5084000)
5481800)
5862300)
6225500)
&.5Z14221
6898900)
7209100)
7501900)
7777400)
22356021
8276500)
8500100)
8706400)
8895400)
22621221
-------
to
-J
Table A-129
SCHEME C, REGULATED POwEK CO. ECONOMICS, 200 MM. NEw COAL FIRED POWER PLANT, 3.5 :« S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
9923000
Includes comparison
with projected operating cost of low-cost limestone process
TOTAL
MFG. CUST
PRODUCT RATE, INCLUDING
YfcAKS
Af-TtK
HonER.
UNIT
bTART
i
/
3
4
5
6
7
8
9
1£
11
1^;
13
14
]__^
16
n
lb
19
_zc
ti
<-Z
^3
2t
^5
it
27
2o
i9
MlNilUAL
UPtkA-
T1GN,
KB — hk /
KB
7ULQ
7GCl>
7CGu
7GGO
2G.G.Q.
7COu
7 GOO
7 JOG
70Uu
2ilL.fi
5GGG
5GGO
icCG
5CCO
6CCQ
25GO
35CU
35GJ
: bCO
EQUIVALENT
TONS/YEAR
100*
H?S04
38700
38700
36700
3670J
"fi2Cii
3670C
38700
38700
36700
3 6700
277GO
£7700
27700
2770G
'22QQ
1 9400
194CO
194PO
19400
REGULATED NET
ROI FOR
POWER
COMPANY,
$/YEAR
4421800
4353000
4284200
4215400
4.14. 6.6QQ
4G778CO
4008900
3940100
3871300
3.aG.25Qa
3312800
3244000
3175200
310b4"0
2C3.260.C
262900C
2560200
2491400
2422600
REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
.a*.aa
8.00
8.00
8.00
8.00
5.00
5.00
5.00
5.00
5*-iiQ
5.00
5.00
5.00
5.00
TOTAL
NET
SALES
REVENUE,
*/YEAR
309600
309600
309600
309600
_3.C26.aa
309600
309600
309600
309600
3.Q96. Q_a
133500
138500
133500
138500
lli5D-2
97000
97000
97000
97000
JtT ANNUAL
INCREASE
(DECREASE)
IN COST OF
POMES,
$
4112200
4043400
3974600
39C58CO
3.a22aQQ
3763200
3699300
3630500
3561,700
^4.9 ^2ao_
3174300
3105500
30367PO
2967900
2SS.2.LQ.Q
2532000
2463200
2394400
23256^0
ALTERNATIVE
OPERATING ANNUAL
C3ST FOR N3N- SAVINGS
RECOVERY MET- (L3SS)
LIMESTONE USING
PROCESS RECOVERY
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
PJMER,
i
4112200
8155600
12130200
16036000
12323.0.0.0.
?3641200
27340500
30971000
34532700
a u r. 75500
41199900
44305400
473421 00
503' 0000
S3.229.10.Q.
55741100
58204300
6159«700
02974300
_.i5LQ _ 134CQ 2153.6.0.0. 5*0.0. 2700.0. 22565QO _ 65131100
15GG
ibCG
iSCO
J5CO
' ^GU
liOO
1500
150u
1501'
8300
b?00
8300
830G
6300
&30G
8300
8300
1769900
1701000
1632200
1563400
i 49460O
14256CO
1357uGO
1288200
1219400
5.00
5.00
5.00
5.00
5.M.QQ
5. 00
5.00
5.00
5.00
41500
41 500
4150C
4\500
^i 5aa
41500
41.500
41500
41500
1728400
16595CO
159^700
1521900
_ 14.5_3_iaO.
J3643CO
1315500
1246700
1177900
6690950^
68569000
70159700
71681 600
2213.4.200
745190QO
7583450^
77031 200
78P59100
INCLUDING PROCESS
REGULATED INSTEAD
RGI FOR OF MET-
POMER LIMESTONE
COMPANY, SCRUBBING,
S/YEAR t
3825400
3761700
3698000
3634200
3.5.23523
3506800
3443000
3379300
3315600
12512QQ
7663100
28H4400
2740700
2676900
2&1 -iiQ2
2288900
22255.00
2161400
2097700
-) 0^3900
'567700
1504000
1440200
1370500
1312. JiOO
1249100
1185300
1 J 21600
1057900
286800)
281700)
276600)
271600)
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
(
(
(
(
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
t
286800)
568500)
845100)
1116700)
_ 266.5231 L 13.32200.1
261400)
256300)
251200)
246100)
2410.221
306200)
3011001
29oOOO)
291000)
(
(
(
(
1644600)
1900900)
2152100)
2398200)
t 2639200)
(
(
(
(
2945400)
3246500)
3542500)
3833500)
2as.22ai t 4119^001
243100)
238100)
2330001
2279DO)
(
(
(
(
4362500)
460O600)
4833600)
5061500)
2222221 i s?fl44noi
160700) (
155500)
150500)
145400)
(
(
(
5445100)
5600600)
57511001
5896500)
L 14.0.2231 i AO^A.Bnr»
135200)
130200)
1?5130I
120000)
( 617200,01
(
(
(
6302200)
6427300)
6547300)
i£_ iiau_ _ — siLQ__ — ii5i}6.ai/_ — 5.32 __ _ 41533 _ -112210.0. 2226.a2aa 224iaa__i ussiiai i 6.6623001
TOT li7i>C'G 7C55.00 84056,700 4688500 79363200
EwUlVALENT COST, DOLLARS PER TUN UF CJAL BURNED 3.12
tvUlVALtNT COST, MILLS PLR KILUWATT-HUUR 3.U
huKTH IF DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS 31679000
LuOlVALENT PRESENT wOKTH, DOLLARS PER TUN OF COAL BURNED 3.24
EQUIVALENT PRtSEKT wOKTH, MILLS PER KILOMATT-HOUR 1.24
72705900
7.44
2.85
29257300
2.99
1.15
666230C)
242)70O)
-------
Table A-130
MA&Nfc.SIA SCHEME C, REGULATED POWER CO. ECONOMICS, 500 MW.
COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
18111000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE. TOTAL
AFTER OPERA- TONS/YEAR ROI FOR $/TON NET
POWER. TlUN, POWER SALES
UNIT Kw-HK/ 100* COMPANY, 100* KEVENUE,
SIART K» H2S04 WYEAR H2S04 $/YEAR
1 7000
2 7000
3 7000
4 7000
6 7000
7 7000
fa 700U
9 7000
11 50CG
12 5000
13 5000
14 iCOO
15. _ _5.UOU
16 3500
17 3500
18 550u
19 3500
21 15CO
22 1500
23 1500
24 1500
_25. IStii
2o 1500
27 1500
28 1500
29 1500
TOT 127500
fcwUlVALENT
PRESENT WORTH
EQUIVALENT
94700
94700
94700
94700
94700
7979000
7853400
7727600
7602300
7476700
94700 7351100
922_
2926100
2803900
2681700
2559600
2422402
2315200
2193000
2070800
1948700
136225900
5.70
2.14
54984900
2.30
0.86
(
(
(
(
(
(
1
(
(
(
(
(
(
(
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
t
11800) 11800)
8400) 20200)
5000) 25200)
1700) 26900)
Ifi22 1 25100)
5200
8500
11900
15300
13222
220600)
217200)
213900)
210500)
2222221
168000)
164600)
1611001
15.23221
107900)
104500)
101200)
97700)
-242221
90900)
87600)
84200)
80700)
224221
2783900)
545400)
19900)
11400)
500
15800
186100)
403300)
617200)
827700)
1206000)
1374000)
1538600)
1699700)
1965400)
2069900)
2171100)
2268800)
L 23.6.21Q21
2454000)
2541600)
I 2625800)
( 2706500)
-------
Table A-131
MAGNESIA SCHEME C, REGULATED POWER CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUFL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT:
18111000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT OFGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEA0 ROI FOR $/TON NFT
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
_5_ ZQflQ
6 7000
7 7000
8 7000
9 7000
_lfl _ZQ.O_Q_
11 5000
12 5000
13 5000
14 5000
15- _5.QQQ
16 3500
17 3500
18 3500
19 3500
20. 3.5_j20__
21 1500
22 1500
23 1500
24 1500
25. 15QQ
26 1500
27 1500
28 1500
29 1500
3Q -15.0.0.
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
1002
H2S04
94700
94700
94700
94700
2.4Z.CQ
94700
94700
94700
94700
24ZQJ1
67600
67600
f 7600
67600
. _ 6.2&.QO. _
47300
47300
47300
47300
4Z3.QQ _
20300
20300
20300
20300
20.3.QQ _
20300
20300
2030C
20300
2Q3.QQ
1724500
COST, HOLLARS
POWER
COMPANY,
S/YEAR
7979000
7853400
7727800
7602300
Z4.16.ZQ.Q
7351100
7225600
7100000
6974400
6348200.
5939700
5814100
5688600
5563000
5411405
4688500
4563000
4437400
4311800
4136.3.00.
3135500
3009900
2884400
2758800
26.322QQ
2507600
2382100
2256500
2130900
. 2Q05400
150473300
100?
H2SD4
8.00
8.00
8.00
8.00
SiQfl
8.00
8.00
3.00
8.00
8. OQ
5.00
5.00
5.00
5.00
5_*P_0_
5.00
5.00
5.00
5.00
5_^aa
5.00
5.00
5.00
5.00
^QQ _
5.00
5.00
5.00
5.00
s^aa
SALES
REVENUE ,
$/YFAR
757600
757600
757600
757600
_Z5.Z6_QO.
757600
757600
757600
757600
15.Z6.0.0.
338000
338000
338000
338000
22flQQQ_
236500
236500
236500
236500
23.6.5J20.__
101500
101500
101500
101500
101500
101500
101500
101500
101500
_lflliflfl_
11463500
PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
4T 10.0* TO INIT
, DOLLARS PER TON
IAL YEAR
OF COAL
, DOLLARS
BURNED
, MILLS PER KILOWATT-HOUR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASF)
IN COST OF IN COST OF
POWER,
$
7221400
7095800
6970200
6844700
6.Z12.1QQ
6593500
6468000
6342400
6216800
6.Q213.QQ
5601 700
5476100
5350600
5225000
POWER,
$
7221400
14317200
21287-400
28132100
3.4a5_12£Q
41444.700
47912700
54255100
60471900
6.6.5.63.2Q.O.
72164900
77641000
82991600
88216600
5.Q224J1Q 93316000
4452000
4326500
4200900
4075300
3.24230.2
3034000
2908400
2782900
2657300
97768000
102094500
106295400
110370700
.1143.2Q5.flQ
117354500
120262900
123045800
125703100
25_3.1ZOJ2 12B2348QO
2406100
2280600
2155000
2029400
190.3,2.0.0.
139009800
5.81
2.18
55530300
2.32
0.87
130640900
132921500
135076500
137105900
122flI22fl22
ALTERNAT IVF
OPERATING
COST FO» NON-
RECOVERY WET-
LIMESTONE
PROCESS
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YFAP.
9115900
9016300
8916700
8817100
BZlZfcQQ
8618000
8518400
8418800
8319200
B2126.QQ
6719600
6620000
6520400
6420800
6.2212QQ
5139500
5039900
4940300
4840700
4Z411QQ
3114300
3014700
2915100
2815500
2Z152QQ
2616400
2516800
2417200
2317600
2213QQQ
170642600
7.14
2.68
70296800
2.94
1.10
ANNUAL CUMULATIVE
SAVINGS SAVINGS
(LOSS) (LOSS)
USING USING
RECOVERY RECOVERY
PROCESS PROCESS
INSTEAD INSTEAD
OF WET- OF WET-
LIMESTONE
SCRUBBING,
$
1894500
1920500
1946500
1972400
122a£QQ
2024500
2050400
2076400
2102400
212a3.QQ
1117900
1143900
1169800
1195800
1221fi2fl
687500
713400
739400
765400
Z211QQ
80300
106300
132200
158200
lfl42QQ
210300
236200
262200
288200
3.141P.Q,
31632800
14766500
LTMESTONE
SCRUBBING,
$
1894500
3815000
5761500
7733900
_2Z3.24QQ
11756900
13807300
15383700
17986100
2Q1144QC
21232300
22376200
23546000
24741800
25.26.26.QQ-
26651100
27364500
28103900
28869300
226.6_0_6.0_P.
29740900
29847200
29979400
30137600
1Q3.21B.O.Q
30532100
30768300
31030500
31318700
3.163.2flQQ
-------
Table A-132
MAGNESIA SCHEME C, REC.ULATED POWER CO. ECONOMICS, 1000 Mw. NEW COAL FIRED PO^EK PLANT, 3.5 t S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT:
27540000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER. uPERA-
PfjHER. TIUN,
UNIT KW-HR/
START Kh
1 7000
2 7000
3 7000
4 7000
. b ?UQG
6 7CGv
7 7000
B 7000
9 7000
^^ 2iiC_u
11 5000
12 50UO
13 5000
14 5000
ib 5QGQ
16 3500
17 3500
io 3500
19 350U
2.L '"ikil
<.l 1500
<.i 1UUO
23 15CO
<.t 1 SOD
<:5. liO-U
2o 15CO
^7 1500
2d 1500
is. 1500
,iC litQ
TuT Ii7500
EQUIVALENT
EQUIVALENT
PRESENT «OKTH
EQUIVALENT
EQUIVALENT
-j
MD
TONS/YEAR
100%
H2SU4
183000
183000
\83000
183000
JU3-Q22
1830CO
183COO
183COO
163000
Lfiiflfla
130700
130700
13C700
330700
120.230.
91500
91500
91500
91500
215. aa
39?00
39.200
39200
39200
3.2zaa
39200
39200
39200
39200
3.2222
3333000
CGST, DOLLARS
ROI FUR
POWER
COMPANY,
S/YEAR
12058100
11867200
11676200
11485300
.112243.22 _
11103400
10912500
10721500
10530600
-^1033.9600
8929600
8738600
8547700
8356700
fllfc5.flO.fl _
7015400
6824400
6633500
6442500
6.25.1fcfla
4663000
4472100
4281200
4090200
3.a223.£2_
3708300
35174CO
3326400
3135500
22445.o.a
2259324^0
PER TON UF COAL
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
NET
SALES
REVENUE,
i/YEAR
1464000
1464000
1464000
1464000
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST UF
POWER,
$
10594100
1 C^0??00
1021??00
10021300
fl«.aa 146.400Q 2fl3^3QQ
8.00
8.00
8.00
8.00
1464000
1464000
1464000
1464000
9639400
9448500
92575TO
9066600
(DECREASE)
IN COST OF
POWER,
$
10594100
20997300
31209500
412 30800
5.1C.6.HCO.
60700500
70149000
79406500
88473100
fl^ia 1464Q3Q fial5&QQ 213AS1QQ
5.00
5.00
5.00
5.00
5*flQ
5.00
5.00
5. CO
5.00
653500
653500
653500
653500
6.5.25.Qa__
457500
457500
457500
457500
8276100
8085100
7894200
77C3200
25.1?3.0.a
6557900
6366900
6176000
59b5000
5»flQ __ -45.15QQ 5124LQQ
5.00
5.00
5.00
5.00
5.&QQ_
5.00
5.00
5.00
5.00
5*0.0
BURNED
196000
196000
196000
196000
126-aaa
196000
196000
196000
196000
i2&ao.a
22155000
COST, MILLS PER .U LOWATT-HOUR
IF DISCOUNTED
PRESENT WORTH
PRESENT WORTH
AT 10. 0* TO INITIAL YEAR
, DOLLARS PER TON
OF COAL
, DOLLARS
BURNED
, MILLS PER KILOWATT-HOUR
4467000
4276100
4085200
3894700
3_2C2.1fla_
3512300
3321400
3130400
2939500
224, 8.5.QQ
203777400
<-.41
1.60
813B3500
1.76
0. 64
105624300
113709900
121604100
129307300
I3.&ai24aa
143377500
149744400
155920400
161905400
_L&26.225.0_0._
172166500
176442600
180527800
184422000
iaai25.3.aa
191637oOO
194959000
198089400
201028900
7 9.3.7.JX4.0.0.
ALTERNATIVE
OPERATING ANNUAL
COST FOR NON- SAVINGS
RECOVERY WET- (LOSS)
LIMESTONE USING
PROCESS RECOVERY
INCLUDING PROCESS
REGULATED INSTEAD
ROI FOR
POWER
COMPANY,
S/YE4R
11 082800
10392700
10702700
105J2600
123.225.Qfl
1013.?500
9942400
9752300
9562200
23.222Qa
8236300
8046200
7856200
7666100
24.26.aaa
6530600
6340600
0150500
5960400
OF WET-
LIMESTONE
SCRUBBING,
$
488700
489500
490500
491300
422233
493100
493900
494800
495600
4.26.6.afl
( 39800)
( 38900)
< 38000)
( 37100)
i 3.&3-O.Q.1
27300)
?6300)
25500)
24600)
CUMULATIVE
SAVINGS
(LOSSI
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
t
488700
978200
1468700
1960000
2452220.
2945300
3439200
3934000
4429600
4226222
4886400
4847500
4809500,
4772400
4726102
4708800
4682500
4657000
4632400
5.22fliQQ L 231D01 4608700
4451700
4261600
4071600
3881500
3.6.214.fla
3501300
3311300
3121200
2931100
224^1Qa
208272000
4.51
1.63
84316100
1.82
0.66
15300)
14500)
( 13600)
( 127001
t ii2aai
( 11000)
( 10100)
( 9200)
( 8400)
i 24.aai
4494600
2932600
4593400
4578900
4565300
4552600
4542122
4529700
4519600
4510400
4502000
44946.22
-------
Table A-133
MAGNESIA SCHEME A,
NONREGULATED CO. ECONOMICS, 200 MW. NEW COAL FIRED POWER PLANT, 3.5 1 S IN FUEL, 98% H2S04 PRODUCTION.
FIXER INVESTMENT t 11685000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 7.4?
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
a
9
11
12
13
14
_15___
16
17
18
19
_20
22
23
24
25
26
27
28
29
30
ANNUAL
OPERA-
TIONt
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
45200
45200
45200
45200
TOTAL
MFG.
COST,
t/YEAR
3468400
3468400
3468400
3468400
34^fl4nn
45200 3468400
45200 3468400
45200 3468400
45200 3468400
32300 1846700
32300 1846700
32300 1846700
32300 1846700
37^nn 1 R46700
3500 22600
3500 22600
3500 22600
3500 22600
__3520 22620
1500 9700
1500 9700
1500 9700
1500 9700
1500 9700
1500
1500
1500
1500
., 1502 ..
9700
9700
9700
9700
_ 2200
1480900
1480900
1480900
1480900
1480900
923700
923700
923700
923700
9,23700
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
3825400 ( 357000)
3761700 ( 2933001
3698000 ( 229600)
3634200 ( 1658001
3.520.5.02 i 1221001-
3506800 ( 38400)
3443000 25400
3379300 89100
3315600 152800
3251200 216500
2868100
2804400
2740700
2676900
2613200 J
2288900
2225100
2161400
2097700
2033900
1567700
1504000
1440200
1376500
1312800
923700 1249100
923700 1185300
923700 1121600
923700 1057900
. , ..,.,923700 924100
1021400)
957700)
894000)
830200)
L 1665QQ1
3468400
3468400
3468400
3468400
2468420-
3468400
3468400
3468400
3468400
3468400— _
1846700
1846700
1846700
1846700
1846700
8080001 1480900
744200) 1480900
6805001 1480900
6168001 1480900
[ 5110021 14 80900
6440001 923700
580300) 923700
516500) 923700
4528001 923700
L_ 3821001 _ -9Z2IOQ
325400)
2616001
1979001
134200)
L 704QO)
923700
923700
923700
923700
923700
NET REVENUE,
t/TON
100%
H2S04
8.00
8.00
8.00
8.00
8.00
8.00
8.00
a. oo
8..0Q
5.00
5.00
5.00
5.00
TOTAL
NET
SALES
REVENUE,
*/YEAR
361600
361600
361600
361600
361600—
361600
361600
361600
361600
3616flfl
161500
161500
161500
161500
161502
5.00 113000
5.00 113000
5.00 113000
5.00 113000
5..0C 113000
5.00 48500
5.00 48500
5.00 48500
5.00 48500
— 5..QO 48500
5.00
5.00
5.00
5.00
5..QO
48500
48500
48500
48500
._ _ 485QO
823500
72705900 (
12146900)
5473500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
10 -
11
12
13
14
15
16
17
18
19
20 _
21
22
23
24
26
27
28
29
TOT
280
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
718600 ( 3106800) 359300 ( 1553400)
654900 ( 3106800) 327450 ( 15534001
591200 ( 31068001 295600 ( 15534001
527400 ( 31068001 263700 ( 15534001
463200—1 31068001 _ -231852— i 15534201—
400000 ( 31068001 200000 ( 15534001
336200 ( 3106800) 168100 I 1553400)
272500 ( 3106800) 136250 ( 1553400)
208800 ( 3106800) 104400 ( 15534001
. -14510.0 1 -31268221 22550 _1 15534001—
1182900 ( 16852001 591450 ( 842600)
1119200 ( 16852001 559600 ( 842600)
1055500 ( 1685200) 527750 ( 8426001
991700 ( 1685200) 495850 ( 842600)
928000 ( 1685200) 464000 1 8426001
92)000 ( 1367900) 460500 ( 683950)
857200 ( 1367900) 428600 ( 683950)
793500 ( 13679001 396750 ( 683950)
729800 ( 1367900) 364900 ( 6839501
666002—1 13622flfll 333200—1 6832501
692500 ( 875200) 346250 ( 437600)
628800 ( 875200) 314400 ( 437600)
565000 ( 875200) 282500 ( 4376001
501300 ( 8752001 250650 ( 4376001
_ 432600—1 8252001 21880Q— i_ 4326001
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YEAR t I
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1527800 ( 3849001 1527800 ( 384900) 3.00
1495950 ( 3849001 1023750 ( 769800) 2.74
1464100 ( 3849001 4487850 ( 1154700) 2.47
1432200 ( 384900) 5920050 ( 1539600) 2.20
_ -1400350 1 3842001 1320400 1 12245001 1..24
1368500 ( 384900) 8688900 ( 23094001 1.67
1336600 ( 3849001 10025500 ( 2694300) 1.40
1304750 ( 384900) 11330250 ( 3079200) 1.14
1272900 ( 334900) 12603150 ( 34641001 0.87
1241050 1 3842001 13844200 1 33.420.001. Q&61
591450 ( 8426001 14435650 ( 4691600) 4.97
559600 ( 8426001 14995250 ( 5534200) 4.70
527750 I 8426001 15523000 ( 63768001 4.43
495850 ( 842600) 16018850 ( 7219400) 4.17
46.4000. i Q426QQ1 1648285.0 i 80620001 3a.9.0
460500 ( 683950) 16943350 ( 8745950) 3.88
428600 ( 683950) 17371950 ( 9429900) 3.62
396750 ( 683950) 17768700 ( 10113850) 3.35
364900 ( 6839501 18133600 ( 107978001 3.08
333020 i 6832521 18466600. 1 114812501 2t81
346250 ( 437600) 18812850 ( 11919350) 2.94
314400 ( 4376001 19127250 < 12356950) 2.67
282500 ( 437600) 19409750 ( 12794550) 2.40
250650 ( 4376COI 19660400 ( 132321501 2.13
218800 t 4176nnl iqfi7q?nn I ll^AQ7Rni 1-flA
373900 I 8752001 186950 ( 437600) 186950 ( 437600) 20066150 ( 141073501 1.59
310100 ( 8752001 155050 ( 4376001 155050 ( 437600) 20221200 ( 14544950) 1.32
246400 ( 875200) 123200 ( 437600) 123200 ( 437600) 20344400 ( 14982550) 1.05
182700 ( 875200) 91350 ( 4376001 91350 ( 437600) 20435750 ( 154201501 0.78
U822Q__i .8152021 5.2450— i 4326001 53450—1 4316021 2a425200__l__ 158522521 SU.5B
17620400 ( 550855001 8810200 ( 27542750) 20495200 ( 158577501 AVG=> 2.49
-------
Table A-134
MAGNESIA SCHEME A, NONRESULATED CO. ECONOMICS, 200 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FJEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT ( 11685000
OVERALL INTEREST RATE OF RETURN KITH PAYMENT 11.Ot
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWFR
UNIT
START
1
2
3
4
5-
6
7
8
9
12
11
12
13
14
15
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
1222
5000
5000
5000
5000
5Q2D.
16 3500
17 3500
18 3500
19 3500
22 152Q
21
22
23
24
~26
27
28
29
-22—
1500
1500
1500
1500
1500
1500
1500
1500
1500
-1522^
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
45200
45200
45200
45200
45200
45200
45200
45200
45200
45222
32300
32300
32300
32300
22222
22600
22600
22600
22600
22600
9700
9700
9700
9700
2122
9700
9700
9700
9700
9700
TOTAL
MFG.
COST,
t/YEAR
3468400
3468400
3468400
3468400
3468400
3468400
3468400
3468400
2463422
1846700
1846700
1846700
1846700
1480900
1480900
1480900
1480900
1432222
923700
923700
923700
923700
_ -222122
923700
923700
923700
923700
9,2.3700
ALTERNATIVE
MONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
I/YFAR
4388700 (
4338300 1
4288000 (
4237700 (
4137000 1
4086700 I
4036300 1
3986000 1
1225122 i
3252900 1
3202600 (
3152200 (
3101900 (
3051600 I
2508100 (
2457800 1
2407500 1
2357100 I
2226322 i
1550300 (
1499900 I
1449600 1
1399300 (
1243322 1
1298600 (
1248200 1
1197900 (
1147600 (
_ _ 1221222 1_.
NET
•WITH
PAYMENT
920300)
869900)
819600)
769300)
1132221
668600)
618300)
567900)
517600)
4613221
1406200)
1355900)
1305500)
1255200)
12242221
1027200)
976900)
926600)
876200)
3252221
6266001
576200)
525900)
475600)
4252221
3749001
324500)
274200)
223900)
. —1135221
MFG. COST,
»/YEAR
WITHOUT
PAYMENT
3468400
3468400
3468400
3468400
3463422
3468400
3468400
3468400
3468400
3463422
1846700
1846700
1846700
1846700
1346122
1480900
1480900
1480900
1480900
1432222
923700
923700
923700
923700
223122
NET REVENUE,
t/TON
100%
H2S04
8.00
8.00
8.00
8.00
Ba.0.2
8.00
8.00
8.00
8.00
- - 3*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5.QQ
T3TAL
NET
SALES
REVENUE,
J/YEAR
361600
361600
361600
361600
361622
361600
361600
361600
361600
361622
161500
161500
161500
161500
161522
113000
113000
113000
113000
112222
48500
48500
48500
48500
48.522
923700 5.00 48500
923700 5.00 48500
923700 5.00 48500
923700 5.00 48500
.222122 5*22 43522
157500
82657700 (
22098700)
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
PHWER
UNIT
START
1
2
3
4
_5
6
7
8
9
12
GROSS INCOME,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1281900
1231500
1181200
1130900
1.QB.2522
1030200
979900
929500
879200
azaaoo
11 1567700
12 1517400
13 1467000
14 1416700
15 1266422—
16 1140200
17 1C89900
18 1039600
19 989200
22 938900
21
22
23
24
25
26
27
28
29
30
675100
624700
574400
524100
413122
423400
373000
322700
272400
222222 _J
3106800)
3106800)
3106800)
31068001
2126.8.221
3106800)
3106800)
3106800)
310680(0)
31265221-.
1685200)
1685200)
1685200)
1685200)
-16552221 .
1367900)
1367900)
1367900)
13679001
12612221
875200)
8752001
875200)
8752001
£152221
875200)
875200)
875200)
875200)
k 8.152221 .
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
640950
615750
590600
565450
54P250
515100
489950
464750
439600
414452
783850
758700
733500
708350
683200
570100
544950
519800
494600
469450
337550
312350
287200
262050
226B52--J
211700
186500
161350
136200
11100Q
1553400)
1553400)
1553400)
1553400)
L 15524221
1553400)
15534001
1553400)
1553400)
L_ 15524221 _
842600)
8426001
842600)
842600)
L B426221
683950)
683950)
6839501
6839501
L 6B22521
437600)
437600)
437600)
437600)
L 4216221
4376001
4376001
437600)
437600)
L 4216221—
CASH FLOW,
i/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1809450
178425CT
1759100
1733950
112flI52 J
1683600
1658450
1633250
1608100
- 15B2250- J
783850
758700
733500
708350
6B3222 J
570100
544950
519800
494600
462452 J
337550
312350
287200
262050
226352 J
211700
186500
161350
136200
-_ 111222— J
384900)
384900)
384900)
384900)
394300)
CUMULATIVE CASH FLOW,
$
WITH WITHOUT
PAYMENT PAYMENT
1809450
3593700
5352800
7086750
8795500
384900) 10479100
3849001 12137550
384900) 13770800
384900) 15378900
3345001 16961850
842600)
842600)
842600)
842600)
B426221
683950)
683950)
683950)
683950)
6332521—
437600)
437600)
437600)
437600)
4216221
437600)
437600)
437600)
4376001
L 4.316221—
17745700
18504400
19237900
19946250
—22622452—
21199550
21744500
22264300
22758900
— 2.3223352—
23565900
23878250
24165450
24427500
—24664352—
24876050
25062550
25223900
25360100
—25411122—
384900)
769800)
1154700)
1539600)
12245221.
2309400)
2694300)
3079200)
3464100)
23422221.
46916001
5534200)
63768001
7219400)
32622221.
8745950)
9429900)
10113850)
10797800)
—114311521.
11919350)
12356950)
12794550)
13232150)
—126621521.
14107350)
14544950)
14982550)
15420150)
L— 153511521
INITIAL INVESTMENT,
X
WITH WITHOUT
PAYMENT PAYMENT
5.36
5.15
4.94
4.73
4*51
4.30
4.09
3.88
3.67
3*46-
6. 58
6.37
6.16
5.95
— 5*14
4.81
4.60
4.38
4.17
. _ 3*26
2.87
2.65
2.44
2.22
2*21
1.80
1.58
1.37
1.16
. -2*24
27572200 ( 55085500)
13786100 1 27542750)
25471100 I 15857750)
3.90
281
-------
Table A-135
MAGNESIA SCHEME A, NQNREGULATEO CO. ECONOMICS, 200 MM. EXISTING COAL FIRED POWER PLANT, 3.5 1 S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT t 13083000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT (,„(,*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC,
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
e
9
-12
11
12
13
14
-15
16
17
18
19
21
22
23
24
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HP/
KW
7000
5000
5000
5000
5000
3500
3500
3500
3500
3522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
loot
H2S04
46600
33300
33300
33300
33300
23300
21300
23300
23300
? 3 3 n n
1500 10000
15CO 10000
1500 10000
1500 10000
15QQ_ 10022
TOTAL
MFGo
COST,
S/YEAR
3746400
3246422
3274600
3274600
3274600
3274600
3274620
2892200
2892200
2892200
1583900
1533222
998000
998COO
998000
998000
998000
1500 10000 998000
1500 10000 998000
1500 10000 998000
1500 10000 999000
-1522 —12222- _ _ -223222
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
$/YEAR
4276000 (
4122522 i
3741100 (
3644600 {
3548)00 (
3451600 (
3355122 i
2979200 (
2882700
2786200
2689700 I
2593100 (
2064200 (
1967700 (
1871200 (
1774700 (
1623222 1
1581700 (
1485200 (
1388600 (
1292100 (
1125622-J
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
529600)
4331221-
466500)
370000)
2735001
177000)
325221
870001
9500
106000
1105800)
12122221
10662001
9697001
8732001
7767001
6322221- _
583700)
4872001
3906001
294100)
-1226221-
3746400
3246422
3274600
3P74600
3274600
3274600
3224602-
2892200
2892200
2892200
1583900
158.3222
998000
998000
998000
998000
228222
998000
998000
998000
998000
_ 223(202
NET REVENUE,
t/TON
lOOt
H2S04
3.00
a.»22
8.00
8.00
8.00
8.00
_ S..22
8.00
8.00
8.00
5.00
5*22
5.0C
5.00
5.00
5.00
5^22 _.
TOTAL
NET
SALES
REVENUE,
t/YEAR
372800
. 3228.Q2
266400
266400
266400
266400
266422
186400
186400
186400
116500
50000
50000
50000
50000
52220
5.00 50000
5.00 50000
5.00 50000
5. 00 50000
_5»22 52222
56426100 (
1369800
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
Nn PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS GROSS INCOME, NFT INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
AFTFP $/YEAR S/YEAR S/YEAR $ *
POWER
UNIT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
START PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1
2
3
4
_5 _
6
7
8
9 902400 ( 33736001 451200 ( 1686800) 1759500 ( 3785001 1759500 1 1785001 3.37
10 __ 3U59QO. i 3373600) 4Q2950 ( 1686B01I 1211250 f 37flRnni ->47n7-;n i 7«Tnnm •». ni
11 732900 ( 30082001 366450 ( 1504100) 1674750
12 636400 ( 3006200) 318200 ( 15041001 1626500
13 539900 ( 30082001 269950 ( 15041001 1578250
14 443400 I 30082001 221700 ( 15041001 le'0000
15 . _ 3469DO. ( 30082001 173450 1 15r|4\Q0.1 1531150 J
16 273400 ( 2705800) 136700 ( 13529001 1445000
17 176900 I 27053001 88450 ( 13529001 1396750
18 80400 ( 27058001 40200 ( 1352900) 1348500
19 1222300 ( 1467400) 611150 1 7337001 611150
_22 1125222- i_ 14.6.2420.1 562S.52 i 2232221 5.6.28.5.2 J
21 1116200 ( 94SOOO) 558100 ( 4740001 558100
22 1019700 ( 948000) 509850 ( 4740001 509850
23 923200 ( 948000) 461600 ( 474000) 461600
24 826700 ( 9480CO) 413)50 ( 47*0001 413350
_25 212222 _i 2432221 _365122 1 4142201 365120 J
26 633700 ( 948000) 316850 ( 474000) 316850
27 517200 ( 948000) 268600 ( 4740001 268600
28 440600 ( 948000) 220300 ( 4740001 220300
29 344100 ( 9480001 172050 I 474000) 172050
3fl_ 242622- i_ 24B2221 123.B.2C. i- 4242221 123H20 L
1958001 5145500 ( 9528001 2.75
195800) 6772000 ( 11486001 2.39
195800) 8350250 ( 1344400) 2.03
1958001 9P80250 I 1540200) 1.67
1353221 113.6,2222 1 12362221 1..32
446001 12807000 ( 17806001 1.03
44600) 14203750 ( 1825200) 0.67
446001 15^52250 ( 1R69800I 0.30
733700) 161634PO ( 26035001 4.61
L 233.2221 162267t>0_ i ^3322221 4t2£
4740001 17284350 ( 38112001 4.23
4740001 17794200 ( 42852001 3.87
474000) 18255800 ( 4759200) 3.50
474000) 18669150 ( 5233200) 3.14
L 4242221 1223425Q i 52222221 2*12
4740001 1935110P ( 61812001 2.40
4740001 19619700 ( 6655?OOI 2.04
474000) J9S40000 ( 71292001 1.67
474000) 20012050 ( 76032001 1.31
4740001 20135P50 ( 80772001 0.94
TOT 14)05700 ( 42320400) 7052850 ( 211602001 20135850 ( 8077200) AVG= 2.43
282
-------
Table A-136
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS, 500 MM. NEW COAL FIRED POWER PLANT, 2.0 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT ( 18788000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 9.5%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
e
9
.10
11
12
13
14
15
16
17
18
19
.20
21
22
23
24
_25_
26
27
28
29
3C
PRODUCT RATE,
ANNUAL EQUIVALENT
OPFRA- TONS/YEAR
T10N,
KW-HR/ 100*
KW H2S04
7000 63100
7000 63100
7000 63100
7000 63100
. 7000 61100
7000
7300
7000
7000
2222-
5000
5000
5000
5300
3500
3500
3500
3500
3522-
1500
? 500
1503
l 500
1500
1500
1500
1500
1522—
63100
63100
63100
63100
63122
TOTAL
MFG.
COST,
t/YEAR
5276300
5276300
5276300
5276300
57J63QB
5276300
5276300
5276300
5276300
5276300
45100 2714000
45100 27)4000
45100 2714000
451CT 2714000
45122 2714QOO
31600
31600
31600
31600
31622
13500
13500
13500
13500
13502
1 3500
13500
13500
13500
13522
2166600
2166600
2166600
21 66600
2166622
1346200
1346200
1346200
1346200
1346200
1346200
1346200
1346200
1346222
ALTERNATIVE
NONPECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
6483500 (
6371300 (
6259200 (
6147100 (
6234322 I
5922800 (
5810700 (
5698500 (
5586400 (
5424322 i.
4840900 (
4728800 (
4616700 (
4504500 (
4322422 i
1207200)
10950001
982900)
8708001
7586001
646500)
534400)
4222001
310100)
-1230221-
21269001
2014800)
1902700)
1790500)
16784001
3858100 ( 1691500)
3746000 ( 15794001
3633800 ( 1467200)
3521700 ( 13551001
3422622 I_ 1243QQH1
2651800 (
2539.700 (
2427600 (
2315400 (
2223300 i
2091200 (
1979000 (
'866900 (
1754800 (
1642602 1-
1305600)
11935001
10814001
969200)
3521221
7450001
632800)
520700)
4086001
- - -2264221-
5276300
5276300
5276300
5276300
5226322
5276300
5276300
5276300
5276300
52763QO
2714000
2714000
2714000
2714000
2714000
2166600
2166600
2166600
2166600
2166600
1346200
1346200
1346200
1346200
1346200-
1346200
1346200
1346200
1346200
- 1346222
NET REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
TOTAL
NET
SALES
REVENUE,
t/YEAR
504800
504800
504800
504800
524900
8.00 504800
8.00 504800
8.00 504800
8.00 504800
3*00 524322 _
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5..20
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5*02
225500
225500
225500
225500
225500
158000
158000
158000
158000
67500
67500
67500
67500
62502
67500
67500
67500
67500
61500
122513500 (
31885500)
90628000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
7.4
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
STAPT
1
2
3
4
C
6
7
a
9
1£
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
GROSS INCOME, NET INCOME AFTER TAXES,
I/YEA'S t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
1712000
1599800
1 487700
1375600
1263422-
115) 300
1039200
927000
P 14900
122JJ22
2352400
2240300
2128200
2016000
12J3202-
1849500
1737400
1625230
1513100
14212UQ
1373100
1261000
1148900
1 036.700
924600
26 812500
27 700 300
28 TB8200
29 476100
_32 363222-
(
(
(
(
(
(
(
(
(
I
(
(
(
(
i
4771500)
4771500)
4771500)
47715001
42115221
47715001
47715001
4771500)
47715001
41115221
24885001
24B8500I
24885001
24885001
24SE53Q1
( 2008600)
( 20086001
( 2008600)
( 200P(.OPI
.1 222B6221
( 12767001
( 1278700)
( 12787001
( 1278700)
1 127tJ7Q£il
(
(
(
(
1
1278700)
12787001
1278700)
1278700)
. 1218.1221
856000
799900
743850
687800
631222
575650
519600
463500
407450
351422
1176200
1120150
1064100
1008000
251252
924750
868700
812600
756550
222522
686550
630500
574450
518350
46232Q
406250
350150
294100
238350
-lfl.1252 J
23857501
2385750)
2385750)
2385750)
_ 23S52521
2365750)
2385750)
23857501
23857501
23£52521
12442501
1244250)
1244250)
12442501
12442521 _ _
10043001
10043001
10043001
1004300)
12243C21
639350)
6393501
639350)
639350)
6323521 __
6393501
639350)
639350)
639350)
L 6323521
CASH FLOW,
t/YEAR
W)TH WITHOUT
PAYMENT PAYMENT
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
$ T
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
2734800 ( 5069501 2734800 ( 5069501 4.46
2678700 ( 506950) 5413500 ( 1013900) 4.17
2622650 ( 506950) 8036150 ( 1520850) 3.87
2566600 ( 506950) 10602750 ( 2027800) 3.58
_2512522_-i- -5262521- -13113252 i 25342521 3»22
2454450 ( 506950) 15567700 ( 3041700) 3.00
2398400 ( 506950) 17956100 ( 3548650) 2.71
2342300 ( 5069501 20308400 ( 40556001 2.41
2286250 ( 5069501 22594650 < 4562550) 2.12
-2232222 i_ 5262521 24424150- 1 50625221 1..8.2
1176200 I 1244250) 26001050 ( 63137501 6.16
1120150 ( 12442501 27121200 < 75580001 5.86
1064100 ( 12442501 28185300 ( 8802250) 5.57
1008000 ( 1244250) 29193300 ( 10046500) 5.28
—251252 -i -12442521— 32145250- 1- L1220J501 __ 4t3fl
924750 ( 10043001 31070000 < 12295050) 4.86
868700 ( 10043001 31938700 ,r 13299350) 4.56
812600 ( 10043001 32751300 ( 143036501 4.27
756550 ( 10043001 33507850 ( 153079501 3.98
-222522 i 12043021 34208.250 1 163122521 2«.6.fl
686550 ( 6393501 34894900 ( 16951600) 3.63
630500 I 639350) 35525400 ( 175909501 3.33
574450 ( 6393501 36099850 ( 182303001 3.04
518350 ( 6393501 36618200 ( 18869650) 2.74
-462300- L -6323501 312B2522 _I__125Q22QQi 2..44
406250 ( 6393501 37486750 ( 201483501 2.15
350150 ( 6393501 37836900 ( 20787700) 1.85
294100 ( 6393501 38131000 ( 21427050) 1.55
238050 ( 639350) 38369050 ( 220664001 1.26
—131250 i 6323521 — 3a551022— i— 22IQ515Q1 Q».9Ji
39526000 ( B29P7500I
19763000 ( 414937501
38551000 ( 227057501
AVG-
3.48
283
-------
Table A-137
MAGNESIA SCHEME A, NONRE&ULATED CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT $ 21732000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 8,8*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEC
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
10
11
12
13
1*
_15
16
17
18
19
2Q
21
22
23
24
_25
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2iH)0__
7000
7000
7000
7000
7000
5000
5000
5000
5000
5220—
3500
3500
3500
3500
2522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
loo*
H2S04
110400
110400
110400
! 10400
1104.00
1.10400
110400
110400
110400
110400
78900
78900
78900
78900
232G2
55200
5520J
55200
55200
55200
TOTAL
MFG.
COST,
»/YEAR
6306400
6306400
6306400
6306400
6.3.26.4.20.
6306400
6306400
6306400
6306400
6306400 .
3286000
3286000
3286000
3286000
3286000
2610400
2610400
2610400
2610400
2610400
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
*S PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
7209600 (
7087400 (
6965200 <
6843000 (
6720900 1
6598700 (
6476500 (
6354300 (
6232100
6112222_
5381100 (
5258900 (
5136700 (
5014500 (
4222422 J.
4280700 (
4158500 (
4036300 (
3914200 (
3792000 1
NET MFC, COST, NET REVENUE,
t/YEAR t/TON
WITH WITHOUT 100%
PAYMENT PAYMENT H2S04
903200)
781000)
6588001
536600)
4145221-.
2923001
170100)
47900)
74300
-126422 .
2095100)
1972900)
1850700)
1728500)
-16.26.40.2)
1670300)
1548100)
1425900)
13038001
11816001
1500 2^700 1603800 2926100 ( 13223001
1500 23700 1603800 2803900 ( 12001001
1500 23700 1603800 2681700 ( 1077900)
1500 23700 1603800 2559600 ( 9558001
15.0.2 22.20.0. 16.0.3.20.0. 2422422-J 2226221-.
1500 23700 1603800 2315200 ( 711400)
1500 23700 1603800 2193000 ( 589200)
1500 23700 1603800 2070800 ( 467000)
1500 23700 1603800 1948700 ( 3449001
_152fl _ 22222 16.0.28.22 1226522_i 2222221-.
6306400 8.00
6306400 8.00
6306400 8.00
6306400 8.00
. 6226.402- _ _ —8^.22
6306400 8.00
6306400 8.00
6306400 8.00
6306400 8.00
6.3.26.40.0 3..2C
3286000 5.0C
3286000 5.00
3286000 5.00
3286000 5.00
2236222 5»Qfl
2610400 5.00
2610400 5.00
2610400 5.00
2610400 5.00
2612422 5»22
1603800 5.00
1603800 5.00
1603800 5.00
1603800 5.00
16228.0,Q_ S..22
1603800 5.00
1603800 5.00
1603800 5.00
1603800 5.00
1603802 , 5.0C . .
TOTAL
NET
SALES
REVENUE,
$/YEAR
883200
883200
883200
883200
aai2Qfl
883200
883200
883200
883200
ttfl32QQ
394500
394500
394500
394500
2345flQ
276000
276000
276000
276000
22620.Q
118500
118500
118500
118500
112522-
118500
118500
118500
118500
112222
108584000
136225900 (
27641900)
108584000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
GROSS INCOME,
t/YEAR
NET INCOME AFTER TAXES,
t/YEAR
CASH FLOW,
t/YEAR
CUMULATIVE CASH FLOW,
t
ANNUAL RETURN ON
INITIAL INVESTMENT,
UNIT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
START PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1 1786400
2 1664200
3 1542000
4 141980C
5 _ 1297700_
6 1175500
7 1053300
8 911100
9 808900
10 __6ie>8ao_
11 2489600
12 2367400
13 2245?00
14 2123000
_15 2020.20.2—
16 1 946300
17 1824100
18 1701900
19 1579800
_22 1452622—
21 1440800
22 1318600
23 1196400
24 1074100
-25 -252122
26 829900
27 707700
28 535500
29 461400
22 241202- J
5423200) 893200 ( 27116001 3066400 ( 538400) 3066400 ( 5384001 4.02
54232001 832100 I 27116001 3005300 1 5384001 6C71700 ( 1076800) 3.74
5423200) 771000 ( 27116001 2944200 I 538400) 9015900 ( 1615200) 3.47
54Z3200I 709900 < 2711600) 2883100 < 538400) 11899000 ( 21536001 3.19
-54222221 642252 i 21116221- 2322252 i 5324221 14221252 1 2622Q221 2.. "2
54212001 587750 ( 2711600) 2760950 ( 538400) 17482000 ( 32304001 2.64
54232001 526650 ( 271)6001 2699850 ( 53140P) 20181850 ( 37688001 2.37
54232001 465550 ( 2711600) 2638750 ( 5384001 22820600 ( 4307200) 2.09
5421?00> 404450 1 2711600) 2577650 ( 5384001 25398250 ( 484560P) 1.82
54222221 242422 1 22116221- _ 2516622 i 5224221 22214352 i 52240.0.0-1 1»54
28"1500) 1244800 ( 14457501 1244800 1 1445750) 29159650 l~ ~6829750I 5.63
2891500) M83700 ( 1445753) 1183700 ( 1445750) 30343350 ( 82755001 5.35
28915001 1122600 ( 14457501 1122600 ( 14457501 31465950 ( 9721250) 5.07
2»')1500) 1061500 ( 1445750) 1061500 ( 1445750) 3252745O ( 11167000) 4.80
- 2fl.215ilil _122fl452_ i -14452521 1222452 1- 14452521 22522222 1 126122521 4»52
2334400) 973150 ( 1167200) 973150 ( 11672001 34501050 ( 13779950) 4.42
2334400) 912050 ( 1167200) 912050 ( 1167200) 35413100 ( 14947150) 4.14
2334430) 050950 ( 11672001 R50950 ( 1167200) 36264050 ( 1H1435Q) 3.86
2334400) 719900 ( 11672001 789900 ( 1167200) 37053950 ( 17281550) 3. =9
22244221- 223322 I 11622221 -222202 1 11622221 2222225Q. 1 134432521 2..21
1485300) 720400 ( 742650) 720400 ( 742650) ?«503150 I 19191400)" "3. 29
14853001 659300 ( 7426501 659300 ( 7426501 39162450 ( 19°34050I 3.01
1485300) 598200 ( 742650) 598200 1 742650) 39760650 ( '06767001 2.73
14H5300I 537150 ( 7426501 537150 ( 742650) 41?97BOO ( 214193501 2.45
14252QU1 426252 i 2A265Q.1 426252 i 242650.1 422222^0 1 22162C.Q.21 2 12
14853001 414950 ( 7426501 414950 ( 742650) 41188800 ( 2'904650I U90
1485300) 353850 ( 742650) 353850 ( 742650) 41542650 ( 2*647100) 1.62
14853001 292750 ( 7426501 292750 { 7426501 41835400 ( 241B9950I 1.34
14853001 231700 ( 7426501 2M700 1 742650) 42067100 ( 2513'600I 1.06
L —14252221 1226E2- 1 _ 1426521 122622- 1 74265Q1 42237700 ( ?5n7S5sni n.7n
TOT 4lnil4nri ( 95214500) 20505700 ( 47607250) 47217700 I 25H75250) AVG* 1 12
284
-------
MAGNESIA SCHEME A,
Table A-138
NONREGUL4TEO CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 X S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT $ 21732000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 14.9%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
—5
6
7
8
9
12
11
12
13
14
-15—
16
17
18
19
22
21
22
23
24
-25—
26
27
28
29
22
ANNUAL
OPERA-
TION,
KH-HR/
KW
7000
7000
7000
7000
1222
7000
7000
7000
7000
-1222
5000
5000
5000
5000
5.222
3500
3500
3500
3500
2.5.22
1500
1500
1500
1500
1522
1500
1500
1500
1500
1522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
110400
110400
110400
110400
110400
110400
110400
110400
110400
110400
78900
78900
78900
78900
12222
55200
55200
55200
55200
55222
23700
23700
23700
23700
23700
23700
23700
23700
23700
22122
TOTAL
MFG.
COST,
t/YEAR
6306400
6306400
6306400
6306400
6226422-
6306400
6306400
6306400
6306400
6306400
3286000
3286000
3286000
3286000
3226222—
2610400
2610400
2610400
2610400
-2612422
1603800
1603800
1603800
1603800
\6Q3800
1603800
1603800
1603800
1603800
1603800
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
J/YEAR PAYMENT PAYMENT
9115900
9016300
8916700
8817100
£111632 J
8618000
8518400
8418800
8319200
22.19.622-J
6719600
6620000
6520400
6420800
6221222 J
5139500
5039900
4940300
4840700
4 7411 OQ
3114300
3014700
2915100
2815500
2115222 J
2616400
2516800
2417200
2317600
. 22ia22Q_J
2809500)
2709900)
2610300)
2510700)
I 241120.21
2311600)
2212000)
2112400)
2012800)
L_ 12132221-
34336001
3334000)
3234400)
3134800)
22352021
2529100)
2429500)
2329900)
22303001
21201221
1510500)
1410900)
13113001
1211700)
.11121221
1012600)
9130001
8134001
713800)
6142221
6306400
6306400
6306400
6306400
6226422
6306400
6306400-
6306400
6306400
- -6226422
3286000
3286000
3286000
3286000
2226222
2610400
2610400
2610400
2610400
2612422
1603800
1603800
1603800
1603800
1622222
1603800
1603800
1603800
1603800
1622200
NET REVFNUE,
I/TON
loot
H2S04
8.00
8.00
8.00
8.00
2*22
8.00
8.00
8.00
8.00
2*00
5.00
5.00
5.00
5.00
5*22
TOTAL
NET
SALES
REVENUE,
I/YEAR
883200
883200
883200
883200
232222
883200
883200
883200
883200
222222
394500
394500
394500
394500
394500
5.00 276000
5.00 276000
5.00 276000
5.00 276000
5*22 2162Q2
5.00 118500
5.00 118500
5.00 118500
5.00 118500
5*20 118500
5.00
5.00
5.00
5.00
- _ 5*22
118500
118500
118500
118500
- 112522 —
127500
108584000
108584000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTFP
POWER
UNIT
START
1
2
3
4
£
6
7
8
9
12
11
12
13
14
15.
16
17
18
19
22
21
22
23
24
25.
26
27
28
29
_22
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/YFAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
3692700 1
3593100 (
3493500 (
3393900 1
3294400 I
3194800 (
3095200 (
2995600 (
2896000 (
7796400 (
5423200)
5423200)
5423200)
54232001
54222221
5423200)
5423200)
5423200)
5423200)
5423200)
3828100 ( 2891500)
3728500 ( 2891500)
3628900 ( 28915001
3529300 ( 28915001
2422122 1 2B915QQ1
2805100 I
2705500 (
2605900 (
2506300 (
2426122 i
1629000 (
1529400 I
1429800 I
1330200 I
1222622 1
1131100 1
1031500 (
931900 1
832300 (
—122122 1-
23344001
2334400)
2334400)
23344001
22244221
1485300)
1485300)
1485300)
1485300)
14.25300)
14853001
1485300)
14853001
1485300)
14253221
1846350
1796550
1746750
1696950
1647200
1597400
1547600
1497800
1448000
1322222 J
1914050
1864250
1814450
1764650
1714850
1402550
1352750
1302950
1253150
1222252 J
814500
764700
714900
665100
&15300
565550
515750
465950
416150
-366252 _J
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2711600) 4019550
2711600) 3969750
2711600) 3919950
2711600) 3870150
1 22116221 2220420--
2711600) 3770600
2711600) 3720800
27116001 3671000
2711600) 3621200
L 2111622JL 35714QQ
1445750)
14457501
1445750)
1445750)
L 14451521
11672001
1167200)
1167200)
1167200)
U612221
742650)
742650)
7426501
742650)
L 2426521
742650)
742650)
742650)
742650)
1426521- .
1914050
1864250
1814450
1764650
..1114252
1402550
1352750
1302950
1253150
1222252 -
814500
764700
714900
665100
615222
565550
515750
465950
416150
-366252— J
CUMULATIVE CASH FLOW,
I
WITH WITHOUT
PAYMENT PAYMENT
538400) 4019550 (
5384001 7989300 I
538400) 11909250 (
538400) 15779400 I
5324221 12522202—1—
5384001 23370400 (
538400) 27091200 (
538400) 30762200 I
538400) 34383400 {
5324221 31954BQQ 1 .
1445750)
1445750)
1445750)
14457501
— 14451521
1167200)
1167200)
1167200)
11672001
_ 11612221 -
7426501
742650)
7426501
742650)
1426521
742650)
742650)
742650)
742650)
74265Q)
538400)
1076800)
16152001
2153600)
- 26222221
3230400)
3768800)
4307200)
4845600)
. 5384D2Q)
ANNUAL RETURN ON
INITIAL INVESTMENT,
%
WITH WITHOUT
PAYMENT PAYMENT
8.30
8.08
7.85
7.63
1*41
7.18
6.96
6.74
6.51
6*23
39868850 ( 68297501 8.65
41733100 ( 8275500) 8.43
43547550 ( 9721250) 8.20
45312200 ( 11167000) 7.98
— 42222252—1—126.121521 1*15
48429600 1 13779950) 6.37
49782350 I 14947150) 6.14
51085300 ( 161143501 5.91
52338450 I 17281550) 5.69
5.254120.2- 1 124421521 5*46.
54356300 ( 19191400)
55121000 ( 19934050)
55835900 ( 20676700)
56501000 I 21419350)
— 5I1162Q2 L— 2216220.01.
57681850 t 22904650)
58197600 ( 23647300)
58663550 ( 24389950)
59079700 ( 25132600)
— 52446252—1 252252521.
3.72
3.49
3.27
3.04
— 2*21
2.58
2.36
2.13
1.90
1*61
75428100 ( 952145001
37714050 I 47607250)
59446050 I 25875250)
AVG= 5.74
285
-------
Table A-139
MAGNESIA SCHEME A, NONRFGULATED CO, ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 5.0
$
S IN FUEL, 98? H2S04 PRODUCTION.
FIXED INVESTMENT $ 24275000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 3. SI
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NFG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
a
9
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
-SO..
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7300
7QOQ
7000
7000
7000
7303
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
I SOn
1500
1500
1500
1500
1500
— 152fl
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
130?
H2SU4
157800
157800
157800
157830
157800
157800
157800
157800
112700
112700
3 12700
112700
112222
78900
78900
78900
78900
28.222
33800
33800
33803
33800
22S20
33800
3'800
33800
33800
ALTERNATIVE
NONRECOVFRY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
TOTAL PANY FOR AIR t/YEAP
MFG.
COST,
t/YEAR
7232500
7232500
7232500
7232500
-1222522
7232500
7232500
7232500
7232500
22225"2
3806900
3806900
3806900
3806900
2326222
3013000
301.3000
3013000
3013000
2212222
1835800
1835800
1835800
1835800
1325322
1835800
1835800
1835800
1.835800
22320 -1.325322
POLLUTION
CONTROL, WITH
t/YEAR PAYMENT
7863100 ( 6306001
7731900 1 499400)
7600700 ( 368200)
7469400 ( 236900)
2223222 i -1252221 —
7207000 25500
7075800 156700
6944500 288000
6813300 419230
6682100 550400
5865300 ( 2058400)
5734000 ( 1927100)
5602800
5471600
- 5242322-
4657600
4526400
4395200
4263900
412^200 J
3168900
3037700
2906400
2775200
2644222 J
2512700
2381500
2250300
2)19100
17959001
16647001
. 15234221-
1644600)
1513400)
13822001
1250900)
i 11122221
1333100)
1201900)
1070600)
9394001
L 3232221 - -
676900)
545700)
4145001
?83300)
. 12a2a2Q_i _ 1522221
WITHOUT
PAYMENT
7232500
7232500
7232500
7232500
.-2222500. .
7232500
7232500
7232500
7232500
. 222250.2—
3806900
3806900
3806900
3806900
—23069.02-.
3013000
3013000
3013000
3013000
2212200—
1835800
1835800
1835800
1835800
_18_25aOO_.
1835800
1835800
1835800
1835800
. 1325aO_0__
NET REVENUE,
J/TON
100?
H2S04
8.00
8.00
8.00
8.00
g.Ofl
9.00
8.00
9.00
8.00
2*. 00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.-02-
5.00
5.00
5.00
5.00
5.213
5.00
5.00
5.00
5.00
5.22
TOTAL
NET
SALES
REVENUE,
t/YEAR
1262400
1262400
1262400
1262400
1262422
1262400
1262400
1262400
1262400
1262420
563500
563500
563500
563500
563522 __
394500
394500
394500
394500
324522 __
169000
169000
169000
169000
162222-
169000
169000
169000
169000
163222
127500
12478250C
148499400 (
237169001
124782500
19104000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS GROSS INCOME,
AFTER t/YEAR
POWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1 1893000 ( 59701001
2 1761800 ( 5970TOO)
3 1630600 ( 59701001
4 1499300 ( 59701001
_ 5_ 13681.00 ( "97010CI
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
946500
890900
815300
749650
6340,50
6 1236900 ( 5970100) 618450
7 1105700 ( 59701001 552850
8 974400 ( 59701001 487200
9 843200 ( 5970100) 421600
_12 212220 i 52221021 356000— J
11 2621900 ( 3243'00) 1310950
12 2490600 ( 3243430) 1245300
13 2359400 ( 3243400) 1179700
14 2228200 < 32434001 1114100
15. _ 3096900 1 . 32434001 1048450 J
16 2C39100 I 26185001 1019550
17 1907900 ( 2618500) 953950
18 1776700 ( 26185001 888350
19 1645400 ( 2618500) 822700
_22 1514220—1 26135021 252122— J
21 1502100 ( 1666800) 751050
22 1370900 ( 16568001 685450
23 1239600 ( 16669001 619800
24 H08400 ( 1666800) 554200
_25 32220.2 -i 16663021 4fl£iQfl J
26 845900 ( 1666800)
27 71470C ( 1666WO)
28 583500 ( 1666800)
29 452300 ( 1666800)
-32— _3210QO__ 1 16.6.630.21-
TOT 42820900 ( 1056785001
286
422950
357350
291750
226150
160520 i
2985050)
2985050)
29850501
29850501
_22£52521 -
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
I/YEAR t %
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
3374000 ( ^575501 3374000 ( 5575501 3.81
3308400 ( 5575501 6682400 { 11151001 3.54
3242800 ( 5575501 9925200 ( 16726501 3.28
3177150 ( 5575501 13102350 ( 22302001 3.01
3111550 ( 5575501 16713900 ( 77S7750I 7.7";
2985050) 3045950 ( 557550) 19259850 ( 3345300) 2.49
2985050) 2980350 ( 5575501 22240200 ( 3902850) 2.22
2985050) 2914700 ( 557550) 25154900 ( 44604001 1.96
29850501 2849100 ( 5575501 29004000 ( 50179501 1.70
22352521 2233500—1- 5525521 3Q.7_ai5QQ i 5575500) 1.43
16217001
1621700)
16217001
1671700)
L 16212221—
13092501
1309250)
1309250)
1309250)
12222501—
833400)
8334001
833400)
833400)
L £334221-
1310950 ( 1621700) 32098450 ( 7197200) 5.30
1245300 I 1621700) 33343750 ( 88189001 5.04
1179700 1 16217001 34523450 ( 104406001 4.77
1114100 ( 1621700) 35637550 ( 120623001 4.51
1043452 1 16212221 26636222 1 126342221 4 24
1019550 ( 1309750) 37705550 1 14993250) 4.14
953950 ( 1309250) 38659500 ( 163025001 3.87
898350 ( 1309250) 39547850 ( 17611750) 3.61
822700 1 13092501 4037055Q ( 189210001 3.34
252122—1—13022521 41122650—1— 222322521 2.2S
751050 ( 833400) 41878700 ( 210636501 ~3.07
685450 ( 833400) 42564150 t 21897050) 2.80
619800 ( 833400) 43183950 ( 227304501 2.53
554200 ( 833400) 43738150 ( 235638501 2.27
488600 I 8334001 447767SD f 74^Q79Rni t nn
833400) 422950 1 8334001 44649700 ( 252306501 1.7J
833400) 357350 ( 8334001 4C007050 ( 260640501 1.46
833400) 291750 ( 8334001 45298800 1 26897450) 1 19
8334001 226150 ( 833400) 45524950 ( 27730850) 0.92
fl33.4QQ± 160500 ( B33400I 45<,8S4«;n 1 To m ->cr, i „ .,
21410450 ( 528392501
45685450 I 28564250) AV6= J>92
-------
Table A- 140
MAGNESIA SCHEME A, NONRFGULATED CO. ECONOMICS, 500 MW. EXISTING COAL FIRED POWER PLANT, 3.5 t S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
q
11
12
13
14
_15_
16
1.7
18
19
-22
21
22
23
24
_25
26
27
28
29
.30
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
7000
r-roo
5330
5000
5000
. -5220—
3500
3500
1500
3500
-3522—
1500
1500
1500
1500
1522
1500
1500
' 500
1500
. 1522—
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
loos
H2S04
1) 2900
112222
112900
112900
112900
112900
112200
80600
8u600
B0600
80600
20602
56400
56400
56400
56400
56402
24200
242PO
242JO
24200
24222
24200
24200
24203
24200
24220 - -
ALTERNATIVE
NONRECOVEPY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
TOTAL PANY FOR AIR
MFG. POLLUTION
COST, CONTROL,
I/YEAR t/YEAR
6879300
6212220
6879300
6879300
6879300
6879300
6312300
5991400
5991400
5991400
3526300
2526300
2815500
2815500
2815500
2815500
2215502
1753300
1750300
1750300
1750300
175030g
1750300
1750300
1750303
1750300
7979600 (
1821622 1-
7675700 (
7523300 (
7371900 (
7220000 (
106.3220 i
6270500 (
6118600 (
5966700
5814700 (
~4988600~(~
4836700 (
4684700 (
4532800, (
4222202 i-
3432400 I
3280500 (
3128500 (
2976600 (
282470.0 (
2672800 (
2520800 (
2368900 <
22)7000 I
—2265100-1-
NFT MFGo
WITH
PAYMENT
1100300)
2423001-
796400)
6445001
4926001
340700)
laaiooi
279100)
1272001
24700
2287900)
21360001
21731001
20212001
1369700)
1717300)
15^5.4201
16821001
1530200)
1378200)
122630")
12144201
9225001
770500)
618600)
4667001
314B201
COST,
WITHOUT
PAYMENT
6879300
6312320
6879300
6879300
6879300
6879300
6212222-
5991400
5991400
5991400
3526300
352iflQO
2815500
2815500
2815500
2815500
2215500
1750300
1750300
1750300
1750300
1750300
NFT REVENUE,
t/TON
100?
H2S04
8.00
3..00-
8.00
8.00
8.00
8.00
2»OQ
8.00
8.00
8.00
5.00
5..Q2
5.00
5.00
5.00
5.00
- 5..0E. _
5.00
5.00
5.00
5.00
5.00
TOTAL
NET
SALES
REVENUE,
t/YEAR
903200
203200
903200
903200
903200
903200
203222
644800
644800
644800
403000
403000
282000
282000
282000
282000
232000-
121000
121000
121000
121000
121000
1750300 5.00 121000
1750300 5.00 121000
1750300 5.00 121000
1750300 5.00 121000
115Q30Q 5..QQ 121000
TOT
104763400
133410900 (
104763400
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
70'f
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
3
9
-10
11
12
13
14
15
16
17
18
19
20
21
22
73
24
_25
26
27
28
29
30— .
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PSYrtENT
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
20035CO ( f.9761001 1001750 ( 2988C50)
1251522 1 5 9161021 925150 i 29fla0501
16996DO ( 59761001
1547703 < 5976100)
ISWOn ( 5976)00)
! 243910 ( 5°76100)
Ijj21222 1 52161221
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YEAR $ %
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
3466350 ( 52345CI 3466350 ( 5234501 3.98
3330350 i 5234501 6356102 1 12469Q01 3.63
849800 ( 2988050) 3314400 ( 5734501 10171100 ( 157O350I 3.37
773850 ( 29880501 37JR450 ( 5234501 13409550 ( 20938001 3.07
697900 ( 29880501 3162500 ( 52345C) 16572050 ( 2617750) 2.77
621950 ( 2963050) 3086550 ( 5234501 1965.R600 I 31407001 2.47
545250 i 22220501 3Q1Q55Q i 5224501 226621*Q_ I 36641501 2*11
923900 ( 53466001 461950 ( 2673300)
772JOO { 53466001 386100 ( 26733001
620100 ( 53466001 310050 ( 26733001
2690900 ( 3173ROCI 1345450 ( 1561900)
25_i2202 1 2122fl001 1262502 1 15612201 _
2455100 ( 25°3500) 1227550 ( J266750)
2303200 ( 75335001 1151600 ( 12667501
215120C ( 753^500) 1075600 ( 1266750)
iqoqini ( 25135001 9S1650 ( 12667501
1241402 1 25235021- 322120 i 12661521
1=103100 ( 16293001
1651203 ( 16703001
1-.99'0& ( 1679300)
1347330 ( U29300I
1125402 i 16223221
1043500 ( 1629300)
891500 ( 16293001
739600 ( 16293001
587700 ( 1679300)
_ 425fl20—l_ 16223001
901550 ( 814650)
825600 ( 8146501
749600 ( 814650)
673650 I 814650)
521100 i 2146501-
521750 ( 8146501
445750 ( 6146501
369800 ( 8146501
293850 ( 3146*0)
211200 i- ai4t521—
2926550 ( 203700) 75595700 ( 3872150) 1.84
28*0630 ( 2037001 23446300 ( 4031550) 1.54
2774650 ( 7037001 31270950 ( 4200250) 1.24
1345450 ( 1561900) 32566400 ( 53*21*01 5.37
_ 1262500- 1 -15612001 32235200 I 1414(1501 5i21
1227550 ( 12667501 35063450 ( 8680800) 4.92
11*1600 ( 12667501 36215050 ( 9947*501 4.61
1075630 ( 12667501 37290650 ( 112143001 4.31
999650 ( 12667501 38290300 ( 124R1050I 4.00
223122 1 12661521 222140.0.0- i__ U74.28.Q.Q1 _3»10
901550 ( H14650) 4011555Q ( 14562450) 3.63
825600 ( R14650) 409411*0 ( 15377)00) 3.33
749600 ( ,314650) 41&OQ750 ( 16101750) 3,02
673650 ( B14650I 47364400 ( 170064001 2.71
521100 L 3146501 _ 42262100 i 113212501 2»41
5217*0 ( 8146501 43433350 ( 1R635700I 2.10
445750 ( R14650) 43079^00 ( 194503*0) 1.30
369800 ( 814650) 44299403 ( 20765000) 1.49
793850 1 8146501 44593250 I 21079650) 1,18
211202—1 B146521 44211152 -1 -212242201 Q».ae_
40330300 ( 930R060CI
20165150 ( 465403COI
44811150 ( 21894300)
AVG= 3.01
287
-------
Table A-141
MAGNESIA SCHFMF A.
NONREGULATED CO, ECONOMICS, 1000 MW. NEW COAL FIRFO POWER PLANT, 3.5 f S IN FUFL, 98? H2S04 PRODUCTION.
t 33118000
NEG
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
10
11
12
13
14
15
16
17
18
19
22
21
22
23
25
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HR/
KW
70CO
7000
7000
7000
7000
7000
7000
7000
1000
5000
5000
5000
?000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1.5CO
1500
1500
15JO
-1520 .
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
213500
213500
213500
213500
713500
213500
213500
213500
212500
152500
152500
152500
1*2500
152500
106800
106800
106800
106800
106300
4S800
45800
45800
45800
4530Q
45800
45800
45800
4580?
45300
TOTAL
MFG.
COST,
t/YEAR
9508800
9508800
9508800
9508800
9508800
9508800
9508800
9508800
2503BQQ
4880200
4880200
4880200
4880200
4330200
3841300
3841300
3841300
3841300
2341200
232MOO
2323100
23231"0
2323100
2323100
2323100
2373100
2323100
732310D
2222122
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHFMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAP
11082800 (
10892700 (
10702700 (
10512600 (
10^2250.0 i
10132500 (
9942400 (
9752300 (
9562200 (
2312200
8236300 (
8046200 (
7856200 (
7666100 (
7476000 (
6530600 (
6340600 I
6150500 (
5960400 (
5112400 i
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1574000)
13839001
11939001
1003800)
3121221
6237001
433600)
243500)
53400)
136602 _.
3356100)
31660001
29760001
2785900)
25253001
26893001
2499300)
23092001
2119100)
1 929100)
4451700 ( 21286001
4261600 1 19385001
4071600 ( 1748500)
3881500 ( 1558400)
3411420 L. 1^633001
3501300 ( 1178200)
3311300 ( 9882001
3121200 ( 7981001
2931100 ( 608000)
2141102-i 41B020J
9508300
9508800
9508800
9508800
9508800
95C8800
9508800
9508800
2503300
4880200
4880200
4880200
4830200
4322200 .
3841300
3841300
3841300
3841300
3341300
2323100
2323100
2373100
2323100
2322100
7323100
2323100
2323100
2323100
2322120 .
NET REVENUE,
t/TON
100*
H2S04
8.00
R.OO
8,00
8.00
3..0.Q
8,00
8.00
8.00
8.00
3..0Q
5.00
5.00
5.00
5.00
5..02
5.00
5.00
5.00
5.00
5..20
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5»00
TOTAL
NET
SALES
REVENUE,
t/YEAR
1708000
1708000
1708000
1708000
1223220
1708000
1708000
1708000
1708000
1123000
762500
762500
762500
762500
162522
534000
534000
534000
534000
-524002
229000
229000
229000
229000
222QQO
229000
229000
229000
229000
223200
161926500
208272000 (
463455001
161976500
25852500
YEARS REQUIFEO FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
7,1
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
3282000 (
3091900 <
2901900 (
2711800 (
252170Q I
6 2331700 (
7 2141600 (
8 1951500 (
9 1761400 (
-10 15114Q2__i.
11 4118600 (
12 3928500 (
13 3738500 (
14 3548400 (
15 3252200 1.
16
17
18
19
-20
21
22
23
?4
75
3223300 (
3033300 (
2843200 (
26*3'00 (
—2462100 1
7800800)
7830800)
78008001
78003001
1B2QSOQ1
7800X00)
7800800)
7800800)
78P0300I
13023001
4)177001
41177001
4117700)
4117700)
41111201
33073001
3307300)
3307300)
33073COI
. 33Q23QQ1 .
2357600 ( 2094100)
2167500 ( 20941001
1977500 ( 7094100)
1787400 < 20941001
15.971 QO i 20341001 .
26 1407200 (
27 1217200 (
28 1027100 I
29 837000 (
20 647000 1
TOT
288
72198000 (
20941001
20941JO)
2094100)
2094100)
. 20241221
136074COOI
1641000 (
1545950 (
1450950 (
1355900 (
1260352--1-
1165850 (
1070800 (
975750 (
880700 (
1B51QQ i
3900400)
39004001
3900400)
39004001
22Q04QQ1
39004001
39004001
39004001
3900^00)
3SOD40QJ
2059300 ( 205X8501
1964250 ( 2058850)
1869250 ( 2058850)
1774200 ( 2058B50I
- -1612150 I- 20533501
1611650 (
1516650 (
1421600 (
1326550 (
1221550 -i
1178300 (
1083750 (
988750 (
893700 (
123650 i
1653650)
1653650)
16536501
1653650)
- 16536501
1047050)
1047050)
1047050)
10470501
1Q42Q50J
703600 ( 1047050)
608600 ( 10470501
513550 ( 1047050)
418500 ( 1047050)
. _222500__i 10410501 _.
36099000 (
680370001
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
4952800
4857750
4762750
4667700
4512650
4477650
4382600
4287550
4192500
4031522
2059300
1964250
1869250
1774200
1612150
1611650
1516650
1421600
1326550
1221550
1178800
1083750
988750
893700
233650
703600
608600
513550
418500
. 222500-
69217000
1
5886001
588600)
588600)
588600)
5336001
588600)
588600)
588600)
5886001
588600)
( 2058850)
( 2058850)
( 2058850)
( 2053950)
-i 20533501
( 1653650)
( 1653650)
( 1653650)
1 1653650)
I 16526501
( 10470501
( 1047050)
( 1047050)
( 1047050)
-i— 10420501
( 1047050)
( 10470501
( 1047050)
( 1047050)
i 10410501
34919000)
ANNUAL RETURN ON
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
I t
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
4952800
9810550
14573300
19241000
22312650-
28291300
32673900
36961450
41153950
45251452-,
47310750
49275000
51144250
52918450
545.21622-
56209250
577259QO
59147500
60474050
f>2884400~
63968150
64956900
65850600
£6643250-
67352850
67961450
68475000
68893500
.622UQ22-
(
(
I
(
I
i
(
<
(
-i_.
(
(
(
(
-i_.
(
(
(
(
-1—
(
(
(
(
-i_.
(
(
(
(
|
5886001
11772001
17658001
23544001
._22i22221
35316001
4120200)
47088001
5297400)
-53362201
7944650)
10003700)
12062550)
14121400)
.161322521
17833900)
19487550)
21141200)
22794850)
.244435201
254955501
265426001
275896501
286367001
.224321501
30730800)
317778501
328249001
338719501
242120221
AVG*
4.84
4.S6
4.28
4.00
2*22
3.44
3.16
2.88
2.60
6.11
5.83
5.55
5.27
4.80
4.52
4.24
3.95
3. 54
3.25
2.97
2.68
.2.42 .
2.11
1.83
1.54
1.26
0.97
3.61
-------
Table A-142
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS, 1000 MW. NEW COAL FIRED POWER PLANT, 3.5 I S IN FUEL, 98X H2S04 PRODUCTION.
FIXED INVESTMENT = t 33118000
OVERALL INTEREST RATF OF RETURN WITH PAYMENT 18.11
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
12 „
11
12
13
14
-15
16
17
18
19
_22
21
22
23
24
25
26
27
28
29
-22
PRODUCT RATE,
ANNUAL EQUIVALENT
OPERA- TONS/YEAR
TION,
KW-HR/ 100%
KW H2S04
7000
7000
7000
7000
1222.
7000
7000
7000
7000
1222.
o o o o o
0 0 0 0 Q
00000
ir\ i^ in u> in
3500
3500
3500
3500
3522
1500
1500
1500
1500
1522
1500
1500
1500
1500
-1522.
213500
213500
213500
213500
213522
213500
213500
213500
213500
. 213522
152500
152500
152500
152500
152522
106800
106800
106800
106800
126822
45800
45800
45800
45800
45822
45800
45800
45800
45800
.•tSBQQ
TOTAL
MFG.
COST,
J/YEAR
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST, NET REVENUE,
PANY FOR AIR »/YEAR t/TON
POLLUTION
CONTROL, WITH WITHOUT 100*
I/YEAR PAYMENT PAYMENT H2S04
9508800 15208800
9508800 15053700
9508800 14898600
9508800 14743500
950880Q 14588400
9508800
9508800
9506800
9508800
9508,390.^
4880200
4880200
4880200
4880200
4880200
3841300
3841300
3841300
3841300
_2fl41222
2323100
2323100
2323100
2323100
2323100
2323100
2323100
2323100
2323100
2323100
14433200
14278100
14123000
13967900
13J12B22-J
11154900
10999800
10844700
10689600
12534522-J
8458700
8303600
8148500
7993400
1828222 J
5007900
4852800
4697700
4542500
4281422 J
4232300
4077200
3922100
3767000
3611322-J
5700000)
55449001
53898001
5234700)
1_ 52126221
4924400)
4769300)
46142001
4459100)
L 42242221 _
62747001
6119600)
5964500)
5809400)
L 56542221
4617400)
4462300)
43072001
41521001
L 22212221
2684800)
2529700)
23746001
2219400)
L_ 22642221
1909200)
1754100)
1599000)
1443900)
L_ _i2aaa22i_ .
9508800
9508800
9508800
9508800
2528822
9508800
9508800
9508800
9508800
2528822 .
4880200
4880200
4880200
4880200
4322222
3841300
3841300
3841300
3841300
2841222
2323100
2323100
2323100
2323100
2322122
8.00
8.00
8.00
8.00
8*0.2
TOTAL
NET
SALES
REVENUE,
J/YEAR
1708000
1708000
1708000
1708000
1708000
8.00 1708000
8.00 1708000
8.00 1708000
8.00 1708000
3*22 1223222
5.00 762500
5.00 762500
5.0^ 762500
5.00 762500
5*22 162522
5.00 534000
5.00 S34000
5.00 534000
5.00 534000
5*22 534000
5.00
5.00
5.00
5.00
5.0Q
2323100 5.00
2323100 5.00
2323100 5.00
2323100 5.00
2222122 5.Q2
229000
229000
229000
229000
222222
229000
229000
229000
229000
222222
3889500
161926500
283172800 ( 1212463001
161926500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS G&OSS INCOME,
AFTER I/YEAR
PHWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
NET INCOME AFTER TAXES,
J/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1 7408000 ( 7800800) 3704000 ( 3900400)
2 7252900 ( 7800300) 3626450 I 3900400)
3 7097800 ( 7800800) 3548900 1 39004001
4 6942700 ( 7800800) 3471350 ( 39004001
* 61316.22 L 15228221 3393800 1 3900400)
6 6632400 1 78008001
7 6477300 ( 7800800)
8 6322200 ( 78008001
9 6167100 I 7800800)
10 6212222 1 ia223221
11 7037200 ( 4117700)
12 6882100 ( 4117700)
13 6727000 ( 4117700)
14 6571900 ( 4117700)
15 6416822— i 41111221-
16 5151400 ( 3307300)
17 4996300 ( 3307300)
IB 4841200 ( 33073001
19 4686100 ( 33073001
-22 4531222—1 22212221-
21 2913800 I 20941001
22 2758700 ( 2094100)
23 2603600 ( 2094100)
24 2448400 ( 20941001
25 2223322 i 22241221-
26 2138200 ( 2094100)
27 1983100 ( 2094100)
28 1828000 ( 2094100)
29 1672900 I 2094100)
in 1517800 1 2Q341221
3316200 I 3900400)
3238650 1 39004001
3161100 ( 39004001
3083550 1 39004001
2226222—i J2224221
3518600 I 2058850)
3441050 ( 20588501
3363500 1 2058850)
3285950 ( 2058850)
22aa4fl2__i 22588521
2575700 1 16536501
2498150 ( 1653650)
2420600 ( 1653650)
2343050 ( 1653650)
_2265522__ i 1652652J
1456900 ( 10470501
1379350 ( 1047050)
1301800 ( 1047050)
1224200 ( 10470501
1146652 L 12412521
1069100 ( 1047050)
991550 ( 1047050)
914000 ( 10470501
836450 ( 10470501
— 758900. | 12472501..
ANNUAL RETURN ON
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
I/YEAR t %
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
7015800
6938250
6860700
6783150
6125622
6628000
6550450
6472900
6395350
6311822—
3518600
3441050
3363500
3285950
3223422—
2575700
2498150
2420600
2343050
2265522
1456900
1379350
1301800
1224200
1146652—
1069100
991550
914000
836450
151222 _J
588600) 7015800
5886001 13954050
5886001 20814750
5886001 27597900
5836221 24222522 _J
588600) 40931500
5886001 47481950
5886001 53954850
588600) 60350200
-5136221 _666&aa02 J
20588501 70186600
20568501 73627650
2058850) 76991150
2058850) 80277100
—.22525521 a24a5522__J
16536501 86061200
1653650) 88559350
1653650) 90979950
1653650) 93323000
16526521 35538522 J
1047050) 97045400
1047050) 98424750
1047050) 99726550
10470501 100950750
12412521 122221422— J
10470501 103166500
1047050) 104158050
1047050) 105072050
1047050) 105908500
L_ -12412521 -1Q6661422 J
588600) 10.93
11772001 10.70
1765800) 10.48
23544001 10.25
- 22422221 12*22
3531600) 9.79
41202001 9.56
4708800) 9.33
5297400) 9.10
L 58362221 fl*81
7944850) 10.44
100037001 10.21
12062550) 9.98
14121400) 9.75
L— 161822521 2*52
17833900) 7.68
19487550) 7.45
21141200) 7.21
22794650) 6.98
--244485221 6*15
25495550) 4.37
26542600) 4.14
27589650) 3.90
28636700) 3.67
L 236822521 2*44
30730800) 3.21
31777850) 2.97
32824900) 2.74
33671950) 2.51
1 342122221 2. 28
147098800
1360740001
73549400 ( 68037000) 106667400 ( 34919000)
289
-------
Table A-143
MAGNESIA SCHEME A. NONREGULATEO CO. ECONOMICS, 1000 MW. EXISTING COAL F.REO POKER PLANT, 3.5 « S IN FUEL, 98* H2S04 PRODUCTION.
$
FIXED INVESTMENT
OVERALL INTEREST RATE Of RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
3663*000
9.6?
NEC
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
3
4
—5
6
7
8
9
12
13
-15—
16
17
18
19
20
21
22
23
24
26
27
28
29
30
PRODUCT RATE
ANNUAL EQUIVALENT
OPERA- TONS/YEAR
TION,
KW-HR/
KH
""
7000
2 220
7000
7000
7000
7000
5000
5000
5000
^500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
—1502—
100*
H2S04
220900
220900
220900
220900
220900
157800
157800
157800
157800
152322
110400
110400
110400
110400
112422
47300
47300
47300
47300
42222
47300
47300
47300
47300
42222—
TOTAL
MFG.
COST,
t/YEAR
10185100
10185100
10185100
10185100
10185100
8818400
8818400
8818400
5155000
5155222
4074400
4074400
4074400
4074400
407440.0.
2488700
2488700
2488700
2488700
2438200
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
12063000 (
—11324222-1—
11606700 (
11378600 (
11150400 (
10922200 (
12694100 I
9432700 (
9204600 (
8976400 I
8748300 (
7467500 1
7239300 (
7011100 (
6783000 (
_6554322_i—
5098000 <
4869800 (
4641700 (
4413500 (
4185400 I
2488700 3957200 (
2488700
2488700
2488700
3729100 (
3500900 (
3272700 (
2488700 3044600 (
NET MFG. COST,
t/YEAR
WITH
PAYMENT
1877900)
1642B22J
1421600)
1193500)
965300)
737100)
5222021
614300)
386200)
158000)
3593300)
2265122J
3393100)
3164900)
2936700)
27086001
WITHOUT
PAYMENT
10185100
12135122-
10185100
10185100
10185100
10185100
. -12135.122-
8818400
8818400
8818400
5155000
_ 51550.22-
4074400
4074400
4074400
4074400
NET REVENUE,
*/TON
100T
H2S04
8.00
a*02
8.00
8.00
8.00
8.00
fl*22
8.00
8.00
8.00
5.00
5.22
5.00
5.00
5.00
5.00
. — 2432422J 4224422 5*22
2609300)
2381100)
21530001
19248001
1696700)
1468500)
1240400)
1012200)
784000)
5552221
2488700
2488700
2488700
2488700
. -2433220
2488700
2488700
2488700
2488700
. _ 2431202 -
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
TOTAL
NET
REVENUE,
t/YEAR
1767200
1262222.
1767200
1767200
1767200
1767200
_17672QQ
1262400
1262400
1262400
7B9000
232222
552000
552000
552000
552000
552222
236500
236500
236500
236500
226522
236500
236500
236500
236500
5*22 226522
3360300
153319900
200300600 (
46980700)
153319900
22860600
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS GROSS INCOME, NET INCOME AFTER TAXES,
AFTER t/YEAR t/YEAR
POWER
UNIT WITH WITHOUT WITH WITHOUT
START PAYMENT PAYMENT PAYMENT PAYMENT
1
2
3
4 3645100 ( 8417900) 1822550 ( 4208950)
_5 _ 3412222 I .34122221 1223522 1 42232521
6 3188800 ( 8417900) 1594400 ( 4208950)
7 2960700 ( 8417900) 1430350 I 4208950)
8 2732500 ( 8417900) 1366250 ( 4208950)
9 2504300 ( 8417900) 1252150 ( 4208950)
10 2?76200 ( 84179001 11331QQ i 4.ZDB9_5.0J.
11 1876700 ( 7556000) 938350 ( 3778000)
12 1648600 ( 7556000) 824300 I 37780001
13 1420400 ( 7556000) 710200 ( 3778000)
14 4382300 ( 4365000) 2191150 ( 2183000)
,.15 4154122—1—42660221 2222252— i— 21322221
16 3945100 ( 3522400) 1972550 ( 1761200)
17 3716900 ( 3522400) 1958450 ( 1761200)
18 3488700 1 3522400) 1744350 ( 1761200)
19 3260600 ( 3522400) 1630300 ( 17612001
20 - -2222422—1 25224221 1516222— i 12612.221
21 2845800 ( 2252200) 1422900 1 11261001
22 2617600 ( 2252200) 1308800 ( 11261001
23 2389500 ( 2252200) 1194750 ( 1126100)
24 2161300 ( 22522001 1080650 ( 1126100)
.25 , 1933200 i 22522001 266632 1 11261221
26 1705000 1 22522001 852500 ( 1126100)
27 1476900 ( 2252200) 738450 ( 1126100)
28 1248700 ( 2252200) 624350 ( 1126100)
29 1020500 ( 2252200) 510250 ( 1126100)
-22 -222422—1 -22522221 226222 L 11261221
TOT 69841300 ( 130459300) 34920650 ( 652296501
290
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YEAR t «
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
5485950 ( 5455501 5435950 ( 545550) 4.87
5221222- 1 5455521 12252352 1 12211221 4*56
5257800 ( 545550) 16115650 ( 1636650) 4.26
5143750 ( 5455501 21259400 ( 21822001 3.96
5029650 ( 545550) 26289050 ( 2727750) 3.65
4915550 ( 545550) 31204600 ( 3273300) 3.35
43.21522 1 5455521 26126122- 1 28133.5.21 2*24
4601750 ( 114600) 40607850 ( 39334501 2.52
4487700 ( 1146001 45095550 ( 40480501 2.21
4373600 I 114600) 49469150 ( 4162650) 1.91
2191150 I 2183000) 51660300 ( 63456501 5.88
2222252 1 21322221 52222252 1 35236521 5*58
1972550 1 17612001 55709900 1 102898501 5.32
1858450 ( 1761200) 57568350 ( 12051050) 5,01
1744350 ( 1761200) 59312700 ( 138122501 4.70
1630300 I 1761200) 60943000 ( 15573450) 4.40
1516222 1 12612221 62459^22 1 122246521 4*22
1422900 ( 11261001 63882100 I 184607501 3.86
1308800 ( 11261001 65190900 ( 19586850) 3.55
1194750 ( 1126100) 6638S650 ( 20712950) 3.24
1080650 I 1126100) 67466300 ( 218390501 2.93
B52500 ( 1126100) 69285400 ( 240912501 2.31
738450 ( 1126100) 70023850 ( 252173501 2.00
624350 ( 1126100) 70648200 ( 263.43450) 1.69
510250 ( 11261001 71158450 ( 27469550) 1.38
396200 ( 11261001 21554652 1 295956501 1*2,7.
71554650 ( 28595650) AVG= 3.51
-------
Table A-144
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS,
200 MM. NEW OIL FIRED POWER PLANT, 1.0 % S IN FUEL, 98t H2S04 PRODUCTION.
I
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
5146000
11. 8*
NEG
Payment equivalent to projected operating cost of low-cost limestone process
PRODUCT RATE,
YEARS
AFTER
POMER
UNIT
START
1
2
3
4
6
7
8
9
10
11
12
13
14
15
16
17
18
19
21
22
23
24
25
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HR/
KM
7000
7000
7000
7000
1Q20_
7000
7000
7000
7000
70QO
5000
5000
5000
5000
5222
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
-1520
EQUIVALENT
TONS/YEAR
100*
H2S04
9600
9600
9600
9600
2622
9600
9600
9600
9600
2622
6900
6900
6900
6900
6222
4800
4800
4800
4800
4800
2100
2100
2100
2100
2122
2100
2100
2100
2100
2122
TOTAL
MFG.
COST,
t/YEAR
1547200
1547200
1547200
1547200
15472QQ
1547200
1547200
1547200
1547200
1547200
835700
635700
835700
835700
335.100
674800
674800
674800
674800
6748QQ
426800
426800
426800
426800
-426BQfl
426800
426800
426800
426800
_ 426322
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG
. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH
t/YEAR PAYMENT
2114800 ( 5676001
2080300 I 533100)
2045800 ( 4986001
2011300 ( 464100)
12161flfl 1 _ 422522J
1942200 ( 3950001
1907700 ( 3605001
1673200 ( 3260001
1838600 ( 291400)
1804100 < 2569001
1592500 ( 756800)
1557900 ( 722200)
1523400 ( 667700)
1488900 ( 6532001
14544flfl i 6131021-
1274200 ( 599400)
1239700 ( 564900)
1205200 ( 5304001
1170600 ( 495800)
_ ,1136.100 1 _ 461300)
874300 ( 447500)
839800 ( 413000)
805200 1 3784001
770700 ( 3439001
136222 L- 3224021
701600 ( 274800)
667100 I 240300)
632600 ( 205600)
598100 ( 171300)
563522-1 136102J
WITHOUT
PAYMENT
1547200
1547200
1547200
1547200
1547200
1547200
1547200
1547200
1547200
1547200
835700
835700
835700
835700
835700
674800
674800
674600
674800
-614B22
426800
426800
426800
426800
426322
426600
426800
426800
426800
426800
NET REVENUE,
t/TON
'00*
H2S04
8.00
8.00
8.00
6.00
8. t Q2
8.00
8.00
8.00
3.00
B..02
5.00
5.00
5.00
5.00
5..2fl _.
5.00
5.00
5.00
5.00
_5«.22_
5.00
5.00
5.00
5.00
5..20
5.00
5.00
5.00
5.00
5..02
TOTAL
NET
SALES
REVENUE,
t/YEAR
76800
76800
76800
76800
16BQC
76800
76600
76800
76800
16322-
34500
34500
34500
34500
34520--
24000
24000
24000
24000
24QOQ
10500
10500
10500
10500
1250.2
10500
10500
10500
10500
125Q2
127500
175500
40426700 (
13134200)
27292500
116,5500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
?Q
21
22
23
24
-25_
26
27
28
29
30 _
GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW,
t/YEAR t/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
644400 ( 14704001 322200 ( 735200)
609900 ( 14704001 304950 ( 735200)
575400 < 1470400) 287700 ( 735200)
540900 ( 14704001 270450 ( 735200)
_lfl63.Cfl--i 14.124221 __ 253152__i 1352221-- _
471800 ( 14704001 235900 ( 735200)
437300 ( 1470400) 218650 ( 735200)
402800 ( 14704001 201400 ( 7352001
368200 ( 14704001 184100 ( 7352001
33310.2- i 141fl4flfll 166B.5.2 i 13520.21
791300 ( 8012001 395650 ( 4006001
756700 ( 6012001 378350 ( 400600)
722200 ( 801200) 361100 ( 400600)
687700 ( 601200) 343850 ( 4006001
653200 1 flfllZQfll 3.26620 i 4flQ6Qfll
623400 ( 6508001 311700 I 3254001
588900 ( 650600) 294450 ( 325400)
554400 ( 6508001 277200 ( 3254001
519800 ( 650800) 259900 ( 325400)
435322- 1 652B221 242fi5fl i 32540.0.1
458000 ( 4163001 229000 ( 2081501
423500 1 4163001 211750 ( 208150)
388900 ( 416300) 194450 < 208150)
354400 ( 416300) 177200 ( 208150)
31220_2_-i- - _41fi3.fl0.1 152252--1 20B1521
285300 ( 4163001 142650 ( 208150)
250800 ( 4163001 125400 ( 2061501
216300 I 416300) 108150 ( 2081501
181800 < 416300) 90900 ( 2061501
141222-- 1 4163221 13622 _1 2231521
837000
819750
802500
765250
_16125.2_-
750700
733450
716200
698900
-6B1652-
395650
378350
361100
343850
-326620 _
311700
294450
277200
259900
-242652—
229000
211750
194450
177200
-152252--
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t %
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
220400) 837000 1 220400) 6.11
220400) 1656750 ( 440800) 5.78
2204001 2459250 ( 6612001 5.46
2204001 3244500 ( 881600) 5.13
2224Q21 421245Q--1 110200.01 4»flfl
220400) 4763150 ( 13224001 4.47
2204001 5496600 ( 1542800) 4.15
2204001 6212800 ( 17632001 3.82
220400) 6911700 ( 1983600) 3.49
22Q40Q1 7593350 I 22040001 3.16
4006001
400600)
400600)
400600)
4flfl6221
7989000 ( 26046001 7.54
8367350 ( 3005200) 7.21
8728450 I 34058001 6.88
9072300 ( 38064001 6.55
232S2QQ i 42070001 6.22
325400) 9710600 ( 45324001 5.97
325400) 10005050 ( 4857800) 5.64
325400) 10282250 ( 5183200) 5.30
325400) 10542150 ( 5508600) 4.97
3.25400.1 10ja4aQO__l 56.340.021 S..64
206150) 11013800 ( 6042150) 4.41
208150) 11225550 ( 6250300) 4.08
2081501 11420000 { 6458450) 3.75
201150) 11597200 I 6666600) 3.41
L 22B1521 11157150 1 61141501 3.08
142650 ( 208150) 11699800 ( 7082900) 2.75
125400 I 208150) 12025200 1 7291050) 2.42
108150 ( 208150) 12133350 ( 7409200) 2.08
90900 ( 208150) 12224250 ( 7707350) 1.75
__1362fl__i _ 2081521 12291fl5fl 1 1915500.1 1..42
TOT
14299700 ( 26127000)
7149850 ( 13063500)
12297850 ( 79155001
4.59
291
-------
Table A-145
MAGNESIA SCHEME At MONREGULATED CO. ECONOMICS, 200 MM. NEW OIL FIRED POWER PLANT
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT •
2.5 3! S IN FUEL, 98* H2S04 PRODUCTION.
« 6690000
8.81!
NFG
Payment equivalent to projected operating cost of low-cost limestone process
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
TOTAL
MFG.
COST,
t/YEAR
ALTERNATIVE
NONPECOVfRY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
*/YEAR
NET MFG. COST,
t/YEAR
WITH
PAYMENT
WITHOUT
PAYMENT
NET REVENUE,
»/TON
100*
H2S04
TOTAL
NET
SALES
REVENUE,
t/YEAR
TOT
2072500
2072500
2072500
2072500
-2022500
2072500
2072500
2072500
2072500
-2222502
1130100
1130100
1130100
1130100
1130122
908400
908400
908400
908400
.223420
568000
568000
568000
568000
563202
568000
568000
568000
568000
563000
36597500
2429700 <
2390200 (
2350704 I
23111CO «
22216Qfl_l—
2232100 (
2192600 (
2153100 <
2113500 (
2024000-i—
18266CO (
1787100 (
1747600 (
1708000 (
1662502- J—
1459000 (
1419500 (
1380000 (
1340400 (
13QQ202-1—
997500 t
958000 (
91S5CO (
878900 (
332400-1—
799900 (
760400 (
720900 (
681300 (
46352800 (
3572001
3177001
2782001
238600>
1221221--
1596001
120100)
806001
410001
15201—
6965001
6570001
6175001
5779001
533422J
550600)
511100)
4716001
432000)
322.5001—
429500)
3900001
3505001
3109001
2214001—
2319001
192400)
1529001
1133001
23302J
9755300)
2072500
2072500
2072500
2072500
_2272SQQ
2072500
2072500
2072500
2072500
-2022502—
1130100
1130100
1130100
1130100
908400
908400
908400
908400
223400
568000
568030
568000
568000
563020
568000
568000
568000
568000
545(122
8.00
8.00
8.00
8.00
3*02
8.00
8.00
8.00
3.00
3..02
5.00
5.00
5.00
5.00
5a22
5.00
5.00
5.00
5.00
5»20
5.00
5.00
5.00
5.00
5*00
5.00
5.00
"i.OO
5.00
5..QQ
192800
192800
192800
192800
122300
192800
192800
192800
192800
122302
86000
86000
86000
86000
36220
60000
60000
60000
60000
62002
26000
26000
26000
26000
26020
26000
26000
26000
26000
26000
2918000
YEARS REOUIREO FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
7.6
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
11
12
13
14
_15
16
17
18
19
21
22
23
24
_25
26
27
28
29
30
TOT
292
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
550000 (
510500 (
471000 (
431400 (
391900 1
352400 (
312900 (
273400 (
233800 I
-124302—1.
782500 (
743000 (
703500 (
663900 (
624420—1.
610600 (
571100 (
53)600 (
492000 (
_4525QO_-1.
187070QI
1879700)
18797001
1879700)
10212221
1879700)
1879700)
18797001
1879700)
13222221-
1044100)
10441001
1044100)
1044100)
10441QD1
275000 (
255250 (
235500 (
215700 1.
125250 L
176200 (
156450 I
136700 (
116900 (
22150—1—
391250 (
371500 1
351750 (
331950 I
3122QQ I
939850)
9398501
939850)
9398501
2323501
939850)
9398501
9398501
9398501
—2323501—
522050)
5220501
522050)
5220501
5220501
8484001 305300 ( 4242001
848400) 285550 ( 424200)
848400) 265800 ( 424200)
848400) 246000 ( 4242001
B4B40Q1 226250 _1 4242021—
455500 ( 542000) 227750 ( 2710001
416000 ( 542000) 208000 ( 2710001
376500 1 542000) 188250 ( 2710001
336900 ( 5420001 168450 ( 271000)
-222402 1 5420221 143200—1 2210001
257900 (
218400 (
17B900 (
139300 (
22322 1.
12673300 (
5420001
542000)
5420001
542000)
—5420001
33679500)
128950 ( 2710001
109200 ( 271000)
89450 ( 271000)
69650 I 271000)
— -42200 1 271000)
6336650 (
16839750)
CASH FLOW,
I/YEAR
WITH WITHOUT
PAYMENT PAYMENT
944000
924250
904500
884700
364250—
845200
625450
805700
785900
266150—
391250
371500
351750
331950
312222
305300
285550
265800
246000
226252—
227750
208000
188250
168450
143202
128950
109200
89450
69650
42200
13026650
270850)
2708501
2708501
270850)
2203501
2708501
270850)
270850)
270850)
- - 2223521
522050)
522050)
5220501
5220501
5222501
4242001
4242001
4242001
4242001
4242201
271000)
2710001
2710001
2710001
2212221
271000)
271000)
2710001
271000)
L 2212021
101497501
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t t
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
944000
1868250
2772750
3657450
4522400
5367600
6193050
6998750
7784650
..3550300
8942050
9313550
9665300
9997250
.10322450—
10614750
10900300
11166100
11412100
-116ja350__
11866100
12074100
12262350
12430800
12522500
12708450
12817650
12907100
12976750
2708501
541700)
8125501
10834001
13542521
1625100)
1895950)
21668001
24376501
2Ifla5221
4.01
3.72
3.43
3.14
2.57
2.28
1.99
1.70
1-47
32305501 5.73
3752600) 5.44
42746501 5.15
4796700) 4.86
, 53132501 S»52
57429501 4.49
6167150) 4.20
65913501 3.91
70155501 3.62
24322521 3«.33
7710750) 3.37
79817501 3.08
S252750I 2.79
85237501 2.50
90657501 1.91
9336750) 1.62
96Q77501 1.33
98787501 1.03
L— 101422501 0*24
AVG- 3.13
—
-------
MAGNESIA SCHEME A, NONREGULATFD CO. ECONOMICS,
Table A-146
200 MW. NEW OIL FIRED POKER PLANT,
FIXED INVESTMENT
OVERALL INTEREST RATS OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
2.5 * S IN FUFL, 98Z H2S04 PRODUCTION.
$ 6690000
9.9%
NfG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
12
11
12
13
16
17
18
19
22
21
22
23
24
.25
26
27
28
29
12
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2222
7000
7000
7000
7000
1222
5000
5000
5000
5000
5222
3500
3500
s50d
350J
1522
1500
1500
1500
1500
1522
1500
1500
1500
1500
1522
PRODUCT RATE,
EQUIVALENT
TONS/YFAR
loot
H2S04
TOTAL
MFG.
COST,
S/YEAR
24100 2072500
24100 2072500
24100 2072500
24100 2072500
24122 2072500
24100
24100
24100
24100
24122
17200
17200
17200
17200
12000
12000
12000
12000
._ 12222
5200
5200
5200
5200
5222
5200
5200
5200
5200
5222
2072500
2072500
2072500
2072500
2222522
1130100
1130100
1130100
1H0100
1112122
908400
908400
908400
908400
223422 _-
568000
568000
568000
568000
563222-
568000
568000
563000
SbSOOO
568000
ALTERNATIVE
NONFECOVFRY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
J/YEAP
2514300 (
2483200 1
2452000 I
2420900 1
2^32222 i
2358600 (
2327400 1
2296200 (
2265100 (
2211222 i
1875000 {
1843800 1
1812600 (
1781500 (
1252122 1
1460900 (
1429700 (
1398600 1
1367400 1
1116222 i
927600 1
89o400 (
865300 I
834100 (
322222-1
771800 (
740600 1
709500 I
678300 (
. _ 641222 1
NFT
WITH
PAYMENT
441300)
410700)
379500)
3484001
1112221
286100)
254900)
2237001
192600)
1614221
744900)
713700)
682500)
o51400)
6222221
552500)
521300)
490200)
459000)
—4213221
359600)
328400)
297300)
266100)
-2142221
2038001
172600)
141500)
110300)
222221
MFG. COST,
I/YEAR
WITHOUT
PAYMENT
2072500
20725/00
2072500
2072500
2212522
2072500
2072500
2072500
2072500
2212522
1130100
1130100
1130100
1130100
1112122
908400
908400
908400
90U400
- S2J3422
568000
568000
568000
568000
563222
568000
568000
563000
568000
563222—
NET REVENUE,
t/TON
loot
H2SQ4
8.00
8.00
8.00
3*22-
8.00
3.00
3.00
8.00
3*22 .
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
- - - 5*22
5.00
5.00
5.00
5.00
5*22 _ -
5.00
5.00
5.00
5.00
-- — 5*22
TOTAL
NET
SALES
REVENUE,
•$/YFAR
192800
192800
192800
192800
- 122S22- .
192800
192800
192800
192800
122222 —
86000
86000
86000
86000
36222
60000
60000
60000
60000
62222
26000
26000
26000
26000
26222 _
26000
26000
26000
26000
26222
47671000 I
2918000
YFARS RE8UIRFD FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
12
11
12
13
14
15
16
17
18
19
22
21
22
23
24
25
26
27
28
29
12
GROSS INCOME,
4/YFAK
WITH WITHOUT
PAYMENT PAYMENT
634600
603500
572300
541200
512222
478900
447700
416500
385400
154222
330900
799700
76d'iOU
737400
126222
6U500
581300
550200
519000
431322
385600
354400
323300
292100
262222
229800
198600
167500
136300
125222 .
1
1
I
I
-i.
I
I
I
(
I
I
1
1
1
I
I
I
[
1879700)
1879700)
1879700)
1879700)
13111221
1879700)
1879700)
18797001
1379700)
13121221 .
1044100)
10441001
1044100)
104410DI
12441221 .
84d400l
848400)
84:3400)
8414001
3434221-.
542000)
542000)
542000)
542000)
5422221
542000)
542000)
542000)
542000)
_ 5422221
NFT INCOME AFTER TAXES,
t/YFAR
WITH WITHOUT
PAYMFNT PAYMENT
317300 1
301750 (
286150 {
270600 (
255222 1
239450 (
223850 (
203250 (
192700 (
. _ 111122 I
415450 (
399350 (
384250 (
3oo70J (
151122— i
30o250 (
290650 I
275100 (
259500 1
241222— i
192300 (
177200 (
161650 (
146050 (
112452 i
114900 (
99300 (
33750 (
68150 I
52622 1
CASH FLO/J,
t/YFAR
WITH WITHOUT
PAYMENT PAYMFNT
939850) 9B6300
939850) 970750
9398501 955150
939850) 939600
9.122521 2240UQ
939850)
939850)
9398501
9398501
2123521
522050)
522050)
522050)
522050)
5222521
424200)
424200)
4242001
4242001
4242221-
271000)
271000)
271000)
271000)
2212221
271000)
2710001
271000)
271000)
2112221-
908450
892850
877250
861700
246122 .
415450
399850
384250
368700
151122 .
306250
290650
275100
259500
241222 .
192800
177200
161650
146050
112452
I
(
I
(
(
1
(
I
I
.1—
(
(
[
(
-1—
I
1
{
(
1
(
(
(
(
(
270850)
270350)
270d50)
270350)
2123521
270850)
270850)
2703501
270350)
—2122521—
522050)
5220501
5220501
522050)
—5222521—
424200)
4242001
424200)
4242001
4242221
271000)
2710001
271000)
271000)
2212221
114900 ( 2710001
99300 I 271000)
83750 ( 2710001
68150 I 2710001
52622 1 Z112221
CUMULATIVE CASH FLOW,
$
WITH WITHOUT
PAYMFNT PAYMENT
936300
1957050
2912200
3851800
-4215322 -
5684250
6577100
7454350
8316050
2162152—
9577600
9977450
10361700
10730400
11221522 _
11389750
11680400
11955500
12215000
12453222-
12651700
12828900
12990550
13136600
—11261252—
13381950
13481250
13565000
13633150
11625152
ANNUAL RETURN ON
INITIAL INVESTMENT,
X
WITH WITHOUT
PAYMENT PAYMENT
270S50) 4.62
541700) 4.40
812550) 4.17
10834001 3.94
- -11542521 3.72
1625100)
1895950)
21C6800I
2437650)
21225221
3.49
3.26
3.03
2.81
3230550) 6.09
3752600) 5.86
4274650) 5.63
4796700) 5.40
51131521 5.17
5742950)
6167150)
6591350)
7015550)
14122521
4.51
4.28
4.05
3.82
3.59
77107501 2.86
7981750) 2.63
8252750) 2.40
8523750) 2.16
—32242521 1*21 ,_
90657501 1.70
9336750) 1.47
9607750) 1.24
9873750) 1.01
L- 121422521 2*13
13991500 I 33679500)
6995750 I 16839750)
AVG= 3.46
293
-------
Table A-147
MAGNESIA SCHEME A, NPNREGULATED COc ECONOMICS, 200 MM. NEW OIL FIRFD POWER PLANT, 4.0 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT $ 7903000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 7.7*
OVFRALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
e
12
11
12
13
14
15
16
17
IB
19
ANNUAL
OPERA-
TION,
KW-HR/
KW
7COO
7000
7000
7 COO
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
38500
38500
36500
38500
7000 38500
7000
7000
7000
7002
5000
5000
5000
5000
^222
3500
3500
3500
3500
38500
38500
38500
27500
27500
27500
27500
?1500
19300
19300
19300
19300
TOTAL
MFG.
COST,
t/YEAR
2476100
2476100
2476100
2476100
ALTERNATIVE
NONRECOVERY
WET-LI1ESTONF
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
$/YEAR
2698700 (
7655100 (
2611500 (
2567900 (
2476100 2480700 (
2476100
2476100
2476100
24761QQ
1352300
1352300
1352300
1352300
1252222
1082300
1082300
1082300
1082300
2fl_ 2500 13202 1222220
21
22
23
24
25
26
27
28
29
_22_-
1500
1500
1500
1500
J 50.0
1500
1500
1500
1500
1522
8300
8300
8300
8300
2222
8300
8300
8300
8300
671400
671400
671400
671400
(,71400
671400
671400
671400
671400
2437100
2393500
2349900
2326322
2026300 (
1982700 (
1939100 <
1895500 (
1251302-1
1615800 (
1572200 {
1528600 (
1485000 (
NET MFG. COST,
*/YEAR
WITH
PAYMENT
2226001
179000)
135400)
91800)
422221
46001
39000
82600
126200
162220
674000)
630400)
586800)
5432001
4956001
533500)
489900)
446300)
402700)
1441422.1 252122J
1100800 (
1057200 I
1013600 I
970000 (
-------
Table A-148
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS, 200 MW. EXISTING OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98* H2S04 PRODUCTION.
t 7426000
8.0*
NEG
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
6
5
6
7
8
9
10
11
12
13
14
_15
16
17
18
19
_22
21
22
23
24
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7QOO
5000
5000
5000
5000
5220
3500
3500
3500
3500
2502
1500
1500
1500
1500
-1522-
1500
1500
1500
1500
1522_
PRODUCT RATE,
EQUIVALENT
TONS/YEAR TOTAL
MFG.
100* COST,
H2S04 t/YEAR
24900
24222
17800
17800
17800
17800
12320—
12400
12400
12400
12400
12400
5300
5300
5300
5300
5222
5300
5300
5300
5300
_ .5200-
2241000
2741000
ALTERNATIVE
NONRECOVF.RY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FDR AIR
POLLUTION
CONTROL,
t/YEAR
2794100 (
2732100 (
1951500 2443900 (
1951500 2381800 (
1951500 2319800 (
1951500 2257700 (
1251522 2135620.i
1716400 1947900 1
1716400 1885900 (
1716400 1823800 (
973800 1761700 (
973BOO 1699700 (
612100
612100
612100
612100
612100
612100
612100
612100
612100
.. .612102
1349200 (
1287100 (
1225100 (
1163000 (
11Q0900 (
1038900 (
976800 (
914700 (
852700 (
790600 (
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
553100)
4911001
492400)
430300)
368300)
3062001
,24,41001
2315001
1695001
107400)
787900)
725900)
737100)
675000)
613000)
550900)
4888001
426800)
3647001
302600)
2406001
-1185021-
2241000
2241000
1951500
1951500
1951500
1951500
1251522 —
1716400
1716400
1716400
973800
322822
NET REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
5.00
5..QQ
612100 5.00
612100 5.00
612100 5.00
612100 5.00
612122 5«QO
612100
612100
612100
612100
612102
5.00
5.00
5.00
5.00
5«.Qfl
TOTAL
NET
SALES
REVENUE,
t/YEAR
199200
133222 _
142400
142400
142400
142400
142422
99200
99200
99200
62000
^ _ .... 62000 T-
26500 '
76500
26500
26500
26500
26500
26500
26500
26500
26500
27457300
1797000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
6
7
a
9 752300 I 2041800) 376150
10- 622322—i 22413221 345152--
11 634800 1809100) 317400
12 572700 18091001 286350
13 510700 1809100) 255350
14 448600 1809100) 224300
_15 386500 18091001 _ . 193250
16
17
18
19
20
21
22
23
24
,25 .,
330700
•>68700
206600
849900
232222- i
1617200)
1617200)
1617200)
9118001
SllflQOl
763600 ( 5856001
701500 ( 585600)
639500 ( 585600)
577400 1 5856001
515322 _i 5356001-
165350
134350
103300
424950
223252--
381800
350750
319750
288700
251652--
26 453300 ( 585600) 226650
27 391200 ( 5856001 195600
28 329100 I 585600) 164550
29 267100 ( 585600) 133550
_22 225222 i 5355.221 102522--J
1020900)
L 12202221
904550)
904550)
9045501
904550)
2245521
8086001
8086001
808600)
4559001
4552221
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1118750
128.125Q-.
1060000
1028950
997950
966900
. —225350—
907950
876950
845900
424950
233250 .
(
I
(
(
1
(
.1—
(
(
(
(
(
278300)
-2132221-
161950)
1619501
161950)
161950)
- 1612521—
CUMULATIVE CASH FLOW,
t
WITH WITHOUT
PAYMENT PAYMENT
INITIAL INVESTMENT,
%
WITH WITHOUT
PAYMENT PAYMENT
1118750 ( 2783001 4.94
2206.500 1 5566221 4»54
3266500 ( 7185501 4.19
4295450 ( 8805001 3.78
5293400 ( 10424501 3.37
6260300 ( 12044001 2.96
1126150 1 13663501 2.55
66000) 8104100 (
66000) 8981050 1
660001 9826950 (
455900) 10251900 (
4552001 _10645fl5Q_ 1 .
292800) 381800 I 292800)
292800) 350750 ( 2928001
2928001 319750 ( 2928001
2028001 288700 ( 2928001
2222221 251650--1 2323221--
11027650 (
11378400 (
11698150 (
11986850 (
- 12244500—1
1432350)
1498350)
1564350)
20202501
—24161501
2768950)
30617501
3354550)
36473501
. 22401501.
2.19
1.78
1.37
5.64
S..23 ^
5.10
4.68
4.27
3.86
3.44
2928001 226650 ( 2928001 12471150 ( 4232950) 3.03
292800) 195600 ( 2928001 12666750 ( 45257501 2.61
2928001 164550 ( 292800) 12831300 1 4818550) 2.20
292800) 133550 ( 292800) 12964850 ( 5111350) 1.78
I 2223021 122522--1 2223221 12062352--! 54241521 1..31_
11282700 I 256603001
5641350 ( !2830150)
13067350 ( 5404150)
AVG*
3.42
295
-------
Table A-149
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS, 500 MM. NEW OIL FIRED POWER PLANT, 1.0 * S IN FUEL, 98? H2S04 PRODUCTION.
i
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT =
9B88000
11.5%
NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
it
6
7
8
9
_12 —
11
12
13
14
16
17
IB
19
70
21
22
23
24
26
27
28
29
-32—
PRODUCT RATE,
ANNUAL EQUIVALENT
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
15QQ
1500
1500
1500
1500
1522
TONS/YEAR
100*
H2S04
23600
23600
23600
23600
23600
23600
23600
23600
16800
16800
16800
16800
11800
11800
11800
11800
11222
5000
5000
5000
5000
5Q2Q
5000
5000
5000
5000
5222
TOTAL
MFG.
COST,
»/YEAR
2875200
2875200
2875200
2875200
2B152QQ
2875200
2875200
2875200
2875200
1511900
1511900
1511900
1511900
15 119QO
1210500
1210500
1210500
1210500
1212522
754600
754600
754600
754600
75.4622
754600
754600
754600
754600
154622—
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
3886100 (
3820300 (
3754500 (
3688700 (
3^22222 L
3557100 (
3491300 (
3425400 (
3359600 <
2903800 (
2838000 (
2772200 (
2706400 (
26.42622 t
2312200 (
2246300 (
2180500 (
2114700 <
2fl42222 i
1583000 (
1517200 I
1451400 (
1385600 (
1319800 I
1253900 (
1188100 (
1122300 <
1056500 (
NET MFG.
COST,
«/YEAR
WITH
PAYMENT
1010900)
9451001
8793001
813500)
1411221
681900)
616100)
5502001
484400)
1391900)
1326100)
1260300)
11945001
11231221-
1101700)
10358001
970000)
904200)
__ 2324Q21
828400)
762600)
6968001
6310001
56.520.01
499300)
4335001
367700)
301900)
WITHOUT
PAYMENT
2875200
2875200
2875200
2875200
2315222- —
2875200
2875200
2875200
2875200
28.752CQ
1511900
1511900
1511900
1511900
1511222
1210500
1210500
1210500
1210500
. _1212522
754600
754600
754600
754600
154622
754600
754600
754600
754600
NET REVENUE,
100*
H2S04
8.00
8.00
8.00
8.00
3^22 —
8.00
8.00
8.00
8.00
fl«.QC
5.00
5.00
5.00
5.00
5*22—
5.00
5.00
5.00
5.00
5»22
5.00
5.00
5.00
5.00
5»22
5.00
5.00
5.00
5.00
TOTAL
REVENUE,
188800
186800
188800
188800
133fl2fl_
188800
188800
188800
188800
lafifl.22
84000
84000
84000
84000
84000
59000
59000
59000
59000
522.22-
Z5000
25000
25000
25000
-2522.2
25000
25000
25000
25000
222122-.I 2261221 154422 S..22 25222 —
429000
49910000
73531800 I
23621800)
49910000
2853000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
606
ANNUAL RE1URN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
12
GROSS INCOME,
J/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1199700 ( 26864001
1133900 ( 2686400)
1068100 ( 2686400)
1002300 ( 2686400)
.216.522 1 —26264221-
870700 ( 26864001
804900 ( 26864001
739000 ( 2686400)
673200 ( 2686400)
-621422 1 26S64Q21
NET INCOME AFTER TAXES, CASH FLOW,
«/YEAR I/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
599850 ( 1343200) 1588650
566950 1 13432001 1555750
534050 ( 13432001 1522850
501150 ( 13432001 1489950
463252—1 13.43.2221 1451252—
435350 ( 13432001 1424150
402450 < 13432001 1391250
369500 ( 1343200) 1358300
336600 ( 13432001 1325400
- 323122 I 13432001 1232502
11 1475900 ( 14279001 737950 ( 713950) 737950
12 1410100 ( 14279001 705050 ( 7139501 705050
13 1344300 I 1427900) 672150 ( 7139501 672150
14 1278500 ( 14279001 639250 ( 713950) 639250
_15 121212 2__i 14212221 626352—1 113.2521 626352..
16 1160700 ( 1151500) 580350 ( 575750) 580350
17 1094800 ( 1151500) 547400 ( 575750) 547400
18 1029000 ( 11515001 514500 1 575750) 514500
19 963200 ( 1151500) 481600 ( 5757501 481600
_2U 321422- 1 11515221 443122—1— 5152521 44B12Q
21
22
23
24
25
2h
27
28
?9
-23-
TOT
296
853400 ( 7296001
787600 ( 729600)
721800 ( 729600)
656000 ( 7296001
59.02QO ( _729_6.221
524300 ( 729600)
458500 ( 7296001
392700 ( 7296001
326900 ( 729600)
261122 1 12262C1-
26^74800 ( 47057000)
426700 ( 3648001 426700
393800 ( 364800) 393800
360900 ( 364800) 360900
328000 ( 364800) 328000
225122 1 3.643221 2S5122
262150 ( 3648001 262150
229250 1 364600) 229250
196350 ( 3648001 196350
163450 1 364800) 163450
13255X1 1_ 3.643221 132552
354400)
354400)
354400)
354400)
3544221-
3544001
354400)
3544001
354400)
3544221-
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t *
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
1588650
3144400
4667250
6157200
1614252—
9038400
10429650
11787950
13113350
1440_Sa5Q_
713950) 15143800
7139501 15848850
713950) 16521000
7139501 17160250
1132521 11166622—
575750) 18346950
575750) 18894350
575750) 19408850
575750) 19890450
5151521 20J32150
3648001
3648001
364800)
3648001
3642221
364800)
364800)
3648001
364800)
3^4flnni
13237400 ( 235285001 23125400 ( 13640500)
20765850
21159650
21520550
21848550
2214.36.5.0
22405800
22635050
22831400
22994850
23125402
354400) 5.93
708800) 5.60
1063200) 5.28
1417600) 4.95
11122221 4*.63
21264001 4.30
2480800) 3.98
28352001 3.65
31896001 3.33
35442221- _3«.fl2
4257950) 7.33
4971900) 7.00
56858501 6.68
6399800) 6.35
11131521 6»fl2
7689500) 5.79
82652501 5.46
8841000) 5.13
9416750) 4.80
22225221 4»4B
103573001 4.28
10722100) 3.95
11086900) 3.62
114517001 3.29
— Iiai65221 2*26
12181300) 2.63
12546100) 2.30
129109001 1.97
132757001 1.64
L— 126425221 la.31
AVG= 4.43
-------
Table A-150
MAGNESIA SCHEME A, NONRFGULATEO CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 985! H2 S04 PRODUCTION.
FIXED INVESTMENT $ 12439000
OVERALL INTEREST P4TF OF RETURN WITH PAYMENT 9.8*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT MEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
12
11
12
13
14
16
17
18
19
-2.Q -
21
22
23
24
25
26
27
28
29
30
PRODUCT RATE,
ANNUAL EQUIVALENT
OPERA- TONS/YEAR
TION,
KW-HR/ 100%
KW H2S04
7000
7000
7000
7000
7000
58900
58900
58900
58900
5
-------
Table A-151
MAGNESIA SCHEME A,
NONREGULATED CO. ECONOMICS, 500 MW. NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 12439000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 13.0%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTE^
POWER
UNIT
bTAKT
1
2
3
4
- 5_
6
7
8
9
12
11
12
13
14
16
17
18
19
ANNUAL
OPERA-
TION,
KW-HS/
KW
7000
7000
7000
7000
7000
7000
7000
7000
2222
5000
5000
500J
5000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
lOOf
H2SU4
58900
53900
58900
ALTERNATIVE
N1NPECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
TOTAL
MFG.
COST,
»/YEAR
3730800
373J800
3730800
58900 3730800
58900 3730800
53900
58900
56900
5£200
42100
42100
42100
42100
S020 42122
1500 29400
1500
3500
J500
29400
29400
29400
3730800
3730800
3730300
32328.02
197f200
1977200
1977200
1977200
1977200
1570400
1570400
1570400
1570400
21 1500 12600 962900
22
23
24
25
26
27
28
29
32
1500
1500
1500
1522
1500
15^0
1500
1500
1522 _
12600
12600
12600
12600
12600
12600
12600
12622
962900
962900
962900
962900
962900
962900
962900
962900
__ 262200- -
PANY FOR AIR i/YFAR
POLLUTION
CONTROL, WITH
i/YEAR PAYMENT
5015800
4955600
4895400
4835200
4225200
4714800
4654600
4594400
4534200
4424200
3712000
3651800
3591600
3531400
3421202
2865100
2804900
2744700
2684600
2624400
1783400
1723200
1663000
1602800
1542622
1482400
1422200
1362000
1301800
12B5000I
12248001
1164600)
11044001
12442221
984000)
923800)
863600)
803400)
2432201
1734800)
16746001
1614400)
1554200)
14242221
1294700)
1234500)
1174300)
1114200)
12542221
820500)
760300)
700100)
639900)
5222201
519500)
4593001
3991001
336900)
1241622 1 . - 22S2221
WITHOUT
PAYMENT
3730800
3730800
3730800
3730300
3230500-
3730800
3730800
3730800
3730800
3220222
1977200
1977200
1977200
1977200
1222200
1570400
1570400
1570400
1570400
1520400
962900
962900
962900
962900
262222
962900
962900
962900
962900
262222-
MET REVENUE,
100*
H2S04
3.00
8.00
8.00
8.00
3x22
8.00
3.00
8.00
3.00
_ __ 3x20-
5.00
5.00
5.00
5.00
5x00- — —
5.00
5.00
5.00
5.00
5x22
5.00
5.00
5.00
5.00
_ 5x00
5.00
5.00
5.00
5.00
5x02-
TOTAL
REVENUE,
J/YFAR
47 1200
—421200
471200
_ 421200- .
210500
210500
210500
210500
—210500
147000
147000
147000
147000
_ 142000
63000
63000
63000
63000
„ 63202
63000
63000
63000
63000
630QO ..
64675JOO
94255700 [
7129500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYHUT WITHOUT PAYMENT
6.1
YEARS
AFTFh
PCWER
NET INC'IMC AFTFR TAXES,
CASH FLUH,
t/YEAR
CUMULATIVE CASH FLOW,
ANNUAL RETURN ON
INITIAL INVESTMENT,
UNIT
START
WITH WITHOUT WITH
PAYMFNT PAYMf-NT PAYMf-NT
1 1756200 (
2 1090000 (
3 1635BOO [
4 1575600 (
5 _ 1515422 1 .
6
7
a
9
10 .
11
12
13
14
15
16
17
IB
19
22
21
22
23
24
25
26
27
28
29
30
1455200 (
1395000 (
1334000 (
1274600 I
. 1214420 i -
1945JOO (
1835100 1
1624900 [
1764700 I
1224522 1
1441700 I
1331500 1
1321300 (
1261200 (
. 1201202 i .
883500 (
623300 1
703100 I
702900 I
642222 1
582500 I
522300 1
462100 I
4J1900 [
341222 i
3259600)
3259000)
3259000)
3259600)
.-32526201
3T59600)
3259600)
3259600)
3259600)
-32526221
1 760700)
1766700)
1766700)
1 766700)
12662221
1423400)
14234001
14234001
14234001
. 14214221
899900)
899900 )
899900)
899900)
£222221
878100
64810J
8179DU
707800
252200—
727000
697500
667400
637300
622222-.
972o50
942550
912450
882^50
£52252
720850
690750
660650
030600
441750~~
411650
381550
351450
321350 .
WITHOUT
PAYMENT
1 16296001
( 1629800)
( 1629800)
( 1629800)
1 1.6222001
I 1629800)
( 1629800)
( 1629800)
( 1629800)
J. 16222201
( 8833501
( 883350)
I 383350)
[ 883350)
i ££31501
( 711700)
( 7117001
( 711700)
( 711700)
i 2112001
( 449950)
I 449950)
[ 449950)
! 4499501
_i 44295.Q1
899900) 291250 I 449950)
8999001 261150 I 449950)
'199900) 231050 ( 449950)
399900) 20u950 1 4499501
. £222221 122£50 i_ 4422521
WITH
PAYMENT
21220'OQ 1
2091930 (
2061800 1
2031700 I
2001620 I
1971500 (
1941400 1
1911300 1
1881200 (
1£51122 1
972650 (
942550 (
912450 (
882350 (
£52252 1
720850 (
690750 [
660650 (
610600 (
-602520 I
441750 I
411650 I
381550 (
351450 (
221350 i
291250 (
261150 (
231050 1
200950 (
-1228.52— J.
WITHOUT
PAYMENT
WITH WITHOUT
PAYMENT PAYMENT
385900) 2122000
385900) 4213900
3859001 6275700
385900) 8307400
2£522Q1 _ 1030.2002 i
?B5900)
3859001
385900)
385900)
28.52221
883350)
883350)
883350)
883350)
££33501
711700)
711700)
711700)
711700)
2112221
449950 1
4499501
449950)
4499501
4422501
449950 1
449950)
449950)
449950)
4422501
12280500
14221900
16133200
18014400
12865502 J
20838150
21780700
22693150
23575500
24422252 J
25148600
25839350
26500000
27130600
—22231100— J
2B172850
23584500
28966050
29317500
22622250—
29930100
30191250
30422300
30623250
— 20224122
3859001
7718001
11577001
1543600)
12225021
2315400)
2701300)
3087200)
3473100)
22520001
4742350)
5625730)
6509050)
7392400)
22252501
8987450)
9699150)
10410850)
11122550)
—112242501—
12284200)
12734150)
13184100)
13634050)
14533950)
14983900)
15433850)
158838001
L 163337501
WITH WITHOUT
PAYMENT PAYMENT
6
6
6
6
•j
5
5
5
5
4.
.89
.65
.42
.18
x25
.71
.47
.24
.00
. 76
7.67
7.44
7.20
6.96
6x22
5.71
5.47
5.24
5.00
—4x26
3.52
3.28
3.04
2.80
—2x56
2.32
2.08
1.84
1.60
1 . 36
36710200 I 575455001
18355100 I 28772750)
30794100 ( 163337501
298
-------
Table A-1 52
MAGNESIA SCHEME A, NONREGULATEO CO. ECONOMICS, 500 MM. NEW OIL FIRED POWER PLANT, 4.0
FIXED INVESTMENT $
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
S IN FUEL, 98* H2S04 PRODUCTION.
14568000
9.0*
NEC
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
-12
11
12
13
14
15
16
17
18
19
_20_
21
22
23
24
25
26
27
28
29
22_
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2120
7000
7000
7000
7000
_2220
5000
5000
5000
5000
-5000
3500
3500
3500
3500
1500
1500
1500
1500
150Q
1500
1500
1500
1500
... 1500.
PRODUCT RATE,
EOUIVALENT
TONS/YFAR
100*
H2S04
94200
94200
94200
94200
94200
94200
94200
94200
94200
24222
67300
67300
67300
67300
47100
47100
47100
47100
42122
20200
20200
20200
20200
20200
20200
20200
70200
20220
TOTAL
MFG.
COST,
t/YEAR
4469000
4469000
4469000
4469000
4462022
4469000
4469000
4469000
4469000
-4462222
2383400
2383400
2383400
2383400
2232402
1883700
1883700
1883700
1883700
1883700
1142500
1142500
1142500
1142500
1142500
1142500
1142500
1142500
1142500
1142502
ALTERNATIVE
NONRECQVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
4964100 (
4883000 (
4801900 (
4720800 (
4639700 I
4558600 (
4477500 (
4396400
4315300
4224222
3703700 (
3622600 (
3541500 (
3460400 (
3222200 I
2937400 (
2856300 (
2775200 <
2694100 (
2612000 i_
1988500 (
1907400" (
1826300 (
1745200 (
166412Q_i_
1583000 (
1501900 (
1420800 (
1339700 (
1253622-1
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
495100)
4140001
3329001
251800)
1202001
896001
8500)
72600
153700
224302
1320300)
1239200)
1158100)
1077000)
2252221-
10537001
972600)
8915001
810400)
22.33QQ1
4469000
4469000
4469000
4469000
4469000
4469000
4469000
4469000
4469000
4462000
2383400
2383400
2313400
2383400
22134Q2
1883700
1883700
1 883700
1883700
1883700
NET REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
3*00
8.00
8.00
8.00
8.00
—3*00 -
5.00
5.00
5.00
5.00
5*02 -_
5.00
5.00
5.00
5.00
5..QO
TOTAL
NET
SALES
REVENUE,
t/YEAR
753600
753600
753600
753600
252602
753600
753600
753600
753600
252622
336500
336500
336500
336500
336500
235500
235500
235500
235500
235500
846000) 1142500 5.00 101000
764900) 1142500 5.00 101000
683800) 1142500 5.00 101000
6027001 1142500 5.00 101000
—5216021 1142500 5*00 101200
4405001 1142500 5.00 131000
359400) 1142500 5.00 101000
2783001 1142500 5.00 101000
197200) 1142500 5.00 101000
_ —1161201 1142500 _ 5*00 101222 _
1716000
77450500
93810500 (
11406000
YFARS REOUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
7.5
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
GROSS INCOME,
t/YFAR
WITH WITHOUT
PAYMENT PAYMENT
1248700 ( 37154001
1167600 ( 37154001
1086500 ( 3715400)
1005400 ( 3715400)
924300 ( 3715400)
6 843200
7 762100
8 681000
9 599900
_12 513820—
11 1656800
12 1575700
13 1494600
14 14135CO
_15 133240.2
16
17
18
19
20
21
22
23
24
26~
27
28
?9
_32__
1289200
1208100
1127000
1345900
264300— J
947000
865900
784800
703700
622600 -J
541500
460400
379300
298200
. 212100— J
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
624350
583800
543250
502700
462150
1
1
1
1857700)
1857700)
18577001
1857700)
1357.2001
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2081150
2040600
2000050
1959500
1313250 .
CUMULATIVE CASH FLOW,
t
WITH WITHOUT
PAYMENT PAYMENT
( 4009001 2081150
( 4009001 4121750
( 4009001 6121800
( 4009001 8081300
.1 4QQ2QC1 10000250
3715400) 421600 ( 1857700) 1878400 ( 4009001
3715400) 381050 ( 18577001 1837850 ( 4009001
37)5400) 340500 ( 1857700) 1797300 ( 400900)
37154001 299950 ( 18577001 1756750 ( 400900)
L 32154021 252422— i 13522001 1216200—1 4QQ2QQ1—
2046900) 828400 ( 1023450) 828400 ( 1023450)
2046900) 787850 ( 1023450) 787850 ( 10234501
20469001 747300 ( 10234501 747300 ( 1023450)
2046900) 706750 ( 1023450) 706750 ( 10234501
t -20462001 666200 i 1Q2345Q1 6.662QQ i 10234501
1648200)
16482001
16482001
164»200)
L— 164B20Q1-.
10415001
1041500)
1041500)
10415001
L 12415QQ1-.
10415001
10415001
1041500)
1041500)
. -1Q4150Q1-.
644600 ( 8241001
604050 ( 824100)
563500 ( 824100)
522950 ( 824100)
432400—1 3241001—
473500
432950
392400
351850
311302.
270750
230200
189650
149100
123552.
-i
I
520750)
520750)
520750)
5207501
5202501
5207501
520750)
5207501
520750)
—5202501 _
644600
604050
563500
522950
4B240Q-.
473500
432950
392400
351850
211200
270750
230200
189650
149100
1QB55Q .
( 824100)
( 824100)
( 824100)
( 824100)
.1 3241001—
( 520750)
( 520750)
( 520750)
( 520750)
.1 5202501—
( 5207501
( 520750)
( 520750)
( 520750)
.1 5202501—
11878650
13716500
15513800
17270550
—19.286250-
19815150
20603000
21350300
22057050
—22222252.
23367850
23971900
24535400
25058350
—25540250-
26014250
26447200
26839600
27191450
—22502250.
27773500
28003700
28193350
J8342450
_ 2B451QOQ.
( 400900)
( 8018001
( 12027001
( 1603600)
-i 20045001.
( 2405400)
( 2806300)
I 32072001
I 36081001
1 - 40020021
INITIAL
WITH
PAYMENT
*. 18
3.91
3.64
3.36
3*02
2.82
2.55
2.28
2.01
1*24
INVESTMENT,
WITHOUT
PAYMENT
( 5032450) 5.58
( 605500CI 5.30
( 7079350) 5.03
( 8102800) 4.76
_I 21262521 4*43
( 995035P) 4.36
( 10774450) 4.09
( 115985501 3.81
( 12422650) 3.54
-1—122462501 3*26
( 137675PO) 3.22
t 14288250) 2.95
( 14809000) 2.67
( 15329750) 2.40
—1—153505001 2*12
( 16371250) 1.84
( 16892000) 1.57
( 17412750) 1.29
( 179335001 1.02
. 1— 1B4542501 0*24—
27766000 ( 66044500)
13883000 ( 33022250)
28451000 ( 184542501
299
-------
MAGNESIA SCHEME o,
Table A-153
NONREGULATED CO. ECONOMICS, 500 MW. EXISTING OIL FIRED POWER PLANT, 2.5 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 13920000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.0%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT N&G
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
I
—5.
6
7
8
9
10
ANNUAL
OPERA-
TION,
KU-HR/
KW
PRODUCT RATE,
EQUIVALENT
TONS/YEAR TOTAL
MFG.
100* COST,
H2S04 WYEAR
7000 60200
1000 60220—
7000 60200
7000 60200
7000 60200
7000 60200
7000 6n?no
11 5000
12 5000
13 5000
14 5000
_15 5.022—
16 3500
17 3500
18 3500
19 3500
21
22
23
24
25
26
27
28
29
-30 .
1500
1500
1500
1500
1503
1500
1500
1500
1500
. _1522
4044800
4044800
4044800
4044800
4044800
4044800
43000 3508100
43000 3508100
43000 3508100
43000 2116100
30100 1666400
30100 1666400
30100 1686400
30100 1666400
22120 lAR^tnn
12900
J.2900
12900
12900
\2900
12900
12900
12900
12900
12222 .
1042600
1042600
1042600
1042600
1042600
1042600
1042600
1042600
1042600
. _ _1042600
ALTERNATIVE
NONRFCOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
$/YEAR PAYMENT PAYMENT
5032800 ( 988000)
4936200 i 893400)
4843600
4749000
4654400
4559800
4465100 .
3953400
3858800
3764200
3669600
2514220-
3143500
3048900
2954300
2859700
2165220
2157000
2062400
1967800
1673200
1113500
1683900
1569300
1494700
1400100
13.25.400-.
7968001
704200)
609600)
5150001
[ .-4222221
4044800
4244300-
4044800
4044800
4044800
4044800
445300) 3508100
350700) 3508100
256100) 3508100
15535001 2116100
1458800) 2116100
1457100)
1362500)
1267900)
11733001
10786001
1114400)
10198001
9252001
830600)
I Z252QQJ.
6413001
546700)
452100)
357500)
L 2623221
1666400
1686400
1686400
1686400
1636402
1042600
1042600
1042600
1042600
1042600
1042600
1042600
1042600
1042600
1242622
NET REVENUE,
t/TON
100*
H2S04
TOTAL
NET
SALES
REVENUE,
t/YEAR
8.00 481600
„ B..Q2 _ 4316C2
8.00
8.00
8.00
8.00
8.00
8.00
8.00
5.00
5»22
5.00
5.00
5.00
5.00
5.00
5.00
5.00
5.00
„ 5..Q2
5.00
5.00
5.00
5.00
5..20 -
481600
481600
481600
481600
431600
344000
344000
344000
215000
— 2150Q2
150500
150500
150500
150500
152502
64500
64500
64500
64500
64500
64500
64500
64500
64500
64522
106500
915900
84147500 (
22219400)
61928100
6230700
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
7.0
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_5
f-
7
8
9
_12_
11
12
13
14
-15
16
17
18
19
20
21
22
23
24
,2.5
26
27
28
29
-22
GROSS INCOME,
t/YE»R
WITH WITHOUT
PAYMENT PAYMENT
1469600 ( 3563200)
1215202 _i- 25622221
1280400 ( 3563200)
1185800 ( 3563200)
1091200 ( 35632001
996600 ( 3563200)
_221222 _1 256222J1
789300 ( 3164100)
694700 ( 3164100)
600100 ( 3164100)
1.768500 ( 19011001
1612320 1 12211221
1607600 I 1535900)
1513000 ( 15359001
1418400 ( ) 535900)
1323800 ( 15351001
12221J2—1- -15253.021
1178900 ( 978100)
1084300 ( 978100)
989700 ( 978100)
895100 ( 9761001
__a£Q402 _i, _21fll221
705800 ( 9791001
611200 ( 978100)
516600 I 9781001
422000 ( 9781001
_2212Qfl i 21JUQ21
NET INCOME AFTER TAXES,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
734800 ( 17816001
6fl.15.22 I 12316221 _
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YEAR t 1
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
2126800 ( 369600) 2126800 ( 389600) 5.16
2019500 ( 3896001 4706300 ( 779Pfinl 4- ft 4
640200 1781600) 2032200 ( 3896001 6238500 ( 11688001 4.49
592900 1781600) 1984900 ( 389600) 8223400 ( 15584001 4.16
545600 1781600) 1937600 ( 389600) 10161000 ( 1948000) 3.83
498300 1781600) 1890300 ( 3896001 12051300 ( 2337600) 3.50
452252— i 11316221 1242252--! 2B26221 12324250 i —21212221 2..11
394650 15820501 1786650 ( 190050) 15680900 ( 2917250) 2.79
347350 15620501 1739350 ( 190050) 17420250 ( 3107300) 2.45
300050 1562050) 1692050 < 1900501 19112300 ( 32973501 2.12
884250 9505501 884250 ( 950550) 19996550 ( 42479001 6.24
£26222 i 2525521 836900 ( 95nssni ?n«^34sn i moa^nt K at
803800 7679501
756500 767950)
709200 767950)
661900 767950)
— 614552—i— 2612501—
589450 ( 489050)
542150 ( 4890501
494850 1 4890501
447550 ( 489050)
422222 L 4322521
352900 ( 469050)
305600 ( 4690501
258300 < 489050)
211000 I 489050)
162652 -i -4322521—
803800 ( 7679501 21637250 ( 5966400) "" 5.70
756500 ( 767950) 22393750 ( 6734350) 5.36
709200 ( 767950) 23102950 ( 7502300) 5.03
661900 ( 7679501 23754850 ( 82702501 4.69
614552 i 1612521 24212422- I 22232221 4 25
589450 ( 489050) 24968850 ( 9527250) 4.20
542150 ( 4890501 25511000 ( 10016300) 3.87
494350 ( 4890501 26005650 ( 105053501 3.53
447550 ( 4890501 26453400 1 109944001 3.19
422222 i 4322521 26352622 1 114,33.4521 2 35
352900 ( 4890501 27206500 ( 11972500) 2.52
305600 ( 489050) 27512100 ( 12461550) 2.18
258300 ( 469050) 27770400 ( 12950600) 1.84
211000 ( 469050) 27981400 ( 134396501 1.50
162652_-i_ _432252i 23145252 I 122281001 1.17
TOT 28450100 (
300
14225050 ( 27648700)
28145050 I 139287001
AVG*
3.76
-------
Table A-154
M4GNESI4 SCHEME A, NONREGULATED CO. ECONOMICS,
1000 MW. NEW OIL FIRED POWER PLANT, 1.0 X S IN FUEL, 16f H2S04 PRODUCTION.
» 14957000
NEG
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
12-
11
12
13
1*
15
16
17
18
19
?0-
21
22
23
2*
25
26
27
2B
29
-22
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2222
7000
7000
7000
7000
2200
5000
5000
5000
5000
5002
3500
3500
3C00
3500
2522
1500
1500
1500
1500
1500
1500
1500
1500
1500
—1522
PRODUCT RATE
EQUIVALENT
TONS/YEAR
loot
H2S04
45500
45500
45500
45500
45522
45500
45500
45500
45500
455.22
32500
32500
32500
32500
22520 _
22800
22800
2?800
22800
2'BOQ
TOTAL
MFG.
COST,
t/YEAR
4306000
4306000
4306000
43G6000
4324222
4306000
4306000
4306003
4306000
4306022
2227600
2227600
2227600
2227600
_ 2221622
1765100
1765100
1765100
1.765100
1I6510Q
3600 1080900
9800 10S0900
9800 10B0900
9800 1080900
2222 1022222—
9800 1080900
9800 1080900
9800 1080900
0800 10B0900
_ __ 2200 1222222—
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY F0» AIR
POLLUTION
CONTROL,
$/YEAR
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
5979600 ( 16736001
5877300 ( 1571300)
5774900 ( 14689001
5672500 ( 13665001
5522122 1_ 1264100)
5467700 (
5365400 (
5263000 (
5160600 (
5058200 (
4448600 (
4346200 (
4243800 I
4141400 (
4222222 1
3530500 (
3428100 (
3325700 (
3223300 (
3121000. (
11617001
10594001
9570001
854600)
1522221
22210001
21186001
20162001
19138001
12114221
17654001
1663000)
15606001
14582001
13559001
2409700 ( 1328800)
2307300 ( 1226400)
2204900 ( 1124000)
2102500 ( 10216001
2£22222_i 2122201
1P97800 ( 8169001
1795400 ( 714500)
1693000 ( 6121001
15907TO ( 5098001
-. . 1486200 i 4074001
4306000
4306000
4306000
4306000
4226222
4306000
4306000
4306000
4306000
43.2&.aaa
2227600
2227600
2227600
2227600
-2221622 .
1765100
1765100
1765100
1765100
-1165120- .
1080900
1080900
1080900
1080900
-1020222-
1080900
1080900
1080900
1080900
1222202 .
NET REVENUE,
t/TDN
100*
H2SD4
8.00
8.00
8.00
8.00
8...QO .
8.00
8.00
8.00
8.00
B..OO
5.00
5.00
5.00
5.00
. _ 5»00 -
5.00
5.00
5.00
5.00
5..0Q-
5.00
5.00
5. no
5.00
5..0Q.
5.00
5.00
5.00
5.00
5..QQ
TOTAL
NET
SALES
REVENUE,
t/YEAR
364000
364000
364000
364000
. 264222
364000
364000
364000
364000
-264200
162500
162500
162500
162500
—162522
114000
114000
114000
114000
114Q22
49000
49000
49000
49000
42222
49000
49000
49000
49000
. -42222
127500
112526700
38694200)
5512500
YEARS REQUIRED FOR PAYPUT WITH PAYMENT: 6,3
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
_5
6
7
8
9
10
11
12
13
14
16
17
18
19
-22
GROSS INCOME,
t/YEAP
WITH WITHOUT
PAYMENT PAYMENT
2037600 (
1935300 (
1B32900 (
1730500 (
1622100 L
1525700 (
1423400 (
1321000 (
1218600 (
1116220 -1
39420001
3942000)
3942000)
39420001
22422201-
39420001
3942COO)
39420001
39420001
32420201
2383500 1 20651001
228110C ( 2065100)
2178700 ( ?0<>5110I
2076300 ( 20651001
1212202 1 - 22651221
1879400 ( 16511001
1777000 ( 1651100)
1674'00 ( 16511001
1572200 ( 16511001
-1462320- 1—16511021
21 13778DO (
22 1275400 (
23 1173000 (
24 1070600 (
_25 262202—1
26 B65900 (
27 763500 (
28 661100 (
29 558803 (
32 456422 _1
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1018800
967650
916450
865250
214050
762850
711700
660500
609300
552120
1191750
1140550
10B9350
1038150
326252
939700
8B8500
837300
786100
224252—
(
(
(
(
(
(
(
(
(
I
(
(
(
(
(
I
(
(
I
1971000)
19710001
1971000)
1971000)
- 12112221
19710001
19710001
19710001
1971000)
12112201
10325501
1032550)
10325501
1032550)
12225521
CASH FLOW,
t/YFAR
WITH WITHOUT
PAYMENT PAYMENT
2514500
2463350
2412150
2360950
2222250
2258550
2207400
2156200
2105000
2252202.
1191750
1140550
10E9350
1038150
9B6950
( 475300)
( 4753001
( 4753001
( 4753001
.1 4152021
( 475300)
( 4753001
( 475300)
( 4753001
.1 4152021. __
CUMULATIVE CASH FLOW,
t
WITH WITHOUT
PAYMENT PAYMENT
2514500
4977850
7390000
9750950
.12260120
14319250
16526650
18682850
20737850
.22241650.
( 1032550) 24033400
( 10325501 25173950
( 10325501 26263300
( 10325501 27301450
i 103255Q1 28238400
8255501 939700 ( 8255501
825550) 68B500 ( 8255501
825550) B37300 ( 8255501
8255501 786100 ( R25550I
-2255501 -224250—1 _. 2255501
29228100
30116600
30953900
31740000
.32414250.
1031900) 688900 ( 5159501 688900 1 5159501 35163B50
1031900) 637700 ( 515950) 637700 ( 515950) 33B01550
1031900) 586500 ( 5159501 586500 ( 51595PI 34388050
10319001 535300 ( 515950) 535300 ( 5159501 34923350
12212221 424150—1 5152521 424152—1 5152521 25421502.
1031900) 432950 ( 5159501 432950 ( 515950) 35840450
1031900) 3B1750 ( 5159501 381750 ( 5159501 36222200
1031900) 330550 ( 515950) 330550 ( 5159501 36552750
1031900) 279400 ( 515950) 279400 ( 515950) 368321^0
10212001 „ 222222—1 5152521 222200 1 5152501- 21060350.
INITIAL INVESTMENT
f
WITH WITHOUT
PAYMENT PAYMENT
( 475300) 6.66
( 950600) 6.33
( 14259001 5.99
( 1901200) 5.66
1 22265001 5.32
( 28518001
( 3327100)
( 38024001
( 42777001
- 1 41530021
( 57855501
( 681S100)
( 78506501
( 8B83200I
1 22152521
( 10741300)
( 115668501
( 1239240CI
( 13217950)
—1—140435001
( 145594501
( 150754001
( 155913501
( 16107300)
—1—166222521
( 17139200)
( 17655150)
I 181711001
1 192030001
4.99
4.65
4.32
3.98
7.83
7.49
7.16
6.82
6^42
6.20
5. 86
5.52
5.19
-4«.25
4.57
4.23
3.89
3.55
3..21
2.87
2.53
2.19
1.85
1. 51
44206700 ( 683200001
22103350 ( 34160000)
37060350 I 192030001
301
-------
Table A-155
MAGNESIA SCHEME A
NONRFGULATFQ CO. ECONOMICS, 1000 MW, NEW OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 98* H2S04 PRODUCTION.
$ 18898000
NEG
FIXER INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
2
3
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
H'900
113900
11 3900
4 7000 113900
_5_ -7220 113220
6 7000 113900
7
B
9
-10-
11
12
13
14
7000
7000
7000
_-2i!22
5000
5000
5000
5000
16 3500
17
18
19
2fl
21
22
23
24
25
26
27
28
29
22
3500
3500
3500
2520
1500
1500
1500
1 500
1522
1500
1500
1500
1.500
152J-
113900
113900
113900
112202
31300
81300
81300
81300
TOTAL
MFG.
COST,
»/YEAR
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666622
2968900
2968900
2968900
2968903
? otoqnn
5!>900 2331200
56900
5690C
56900
24400
24400
24400
24400
24422
24400
24400
24400
24400
24422
2331200
2331200
2331200
2221222
1399700
1399700
1399700
1399700
1222222
1399700
1399700
1399700
1399700
_ 1322222__
ALTERNATIVE
NONRECOVEPY
WET-LIMFSTONE
PROCESS COST
4S PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
;ONTROL,
$/YFAR
6890400 (
6775100 (
6659800 (
6544500 (
6422220 L
6314000 (
6198700 (
6083400 (
5968100 (
5120700 (
5005400 (
4690100 I
4774800 (
4.6595QQ 1
4052800 (
3937500 I
3822200 (
3706900 (
2521602 I _ .
2745400 (
2630100 (
2514900 (
2399600 (
2234320 I .
2169000 (
2053700 (
1938400 (
1823100 (
17.02 8.02-1— .
NET MFG. COST,
S/YEAR
WITH
PAYMENT
1223800)
1108500)
9932001
8779001
2622221
6474001
532100)
416800)
301500)
. 1362221
21518001
2036500)
1921200)
1805900)
16226221
1721600)
1636300)
1491000)
1375700)
. 12624201 _ .
1345700)
12304001
1115200)
999900)
WITHOUT
PAYMENT
5666600
5666600
5666600
5666600
-5666622—
5666600
5666600
5666600
NET REVENUE,
S/TON
100*
H2S04
8.00
8.00
8.00
TOTAL
NET
REVENUE,
t/YFAR
911200
911200
8J.2.C- 2112Q2
8.00
8.00
8.00
5666600 8.00
5666622 3«.22_ —
2968900
2966900
2968900
2966900
2966900
2331200
2331200
2331200
2331200
. 2331202 .
1399700
1399700
1399700
1399700
5.00
5.00
5.00
5.00
S..22-
5.00
5.00
5.00
5.00
5..02
5.00
5.00
5.00
5.00
. aa46021_ _ 1322222 5..20
7693001
6540CO)
538700)
4234001
. 2231221
1399700
1399700
1399700
1399700
—1322222 .
5.00
5.00
5.00
5.00
911200
911200
211222
406500
406500
406500
._ 426522
284500
284500
284500
284500
234522
122000
122000
122000
122000
1222U2-
122000
122000
122000
122000
S..22 L22222 —
97163503
129543900 (
YEARS REQUIRED FOR PAYOUT WITH PAYMENT: 6,,
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
-15 _
16
17
18
19
20
21
22
23
24
26
27
28
29
GROSS INCOME, NET INCOME AFTER TAXES,
$/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
2135000
2019700
1904400
1789100
1623200 .
1558600
1443300
l'2flOOO
1212730
-1222422
2558300
2443000
2327700
2212400
2022102
1
(
1
I
2006100 (
1890800 (
1775500 (
1660200 (
1544222. 1-
1467700
1352400
1237200
1121900
1026602
(
(
891300 (
776000 (
660700 <
545400 I
. _420122 1.
4755400)
4755400)
47554001
4755400)
._ 42554021
4755400)
4755400)
47554UO)
47554001
._ 42554221
2562400)
2562400)
25624001
._ 25624221
2046700)
20467001
2046700)
20467001
— 22462021 _
12777001
1 2777001
1277700)
12777001
— 12222221
1277700)
12777001
1277700)
12777001
— 12222021
1C67500
1009650
952200
894550
326252
779300
721650
664000
606350
543222
1279150
1221500
1163850
1136200
1243552
1003050
945400
887750
R30100
222452
733850
676200
618600
560950
502322
445650
388000
330350
272700
215D_52
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
S/YEAR t t
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
( 23777001 2956300
( 23777001 2698650
( 23777001 2841000
( 23777001 2783350
1 22222221 27257SO
( 2377700)
( 23777001
( 23777001
( 23777001
_i 22222221
( 12812001
( 12812001
( 12612001
( 1281200)
-1 12312221 _.
( 1023350)
( 10233501
( 1023350)
( 10233501
i 10222521
( 638650)
( 6368501
( 6388501
( 6388501
i 6233521
( 6388501
( 636650)
( 6368501
( 6388501
i 6233521 -.
2666100
2610450
2552800
2495150
2432522
1279150
12215HQ
1163850
1106200
. 1043550
1003050
945400
887750
830100
222450
[
1
1
(
4889001 2956300
488900) 5854950
488900) 869595Q
4889001 11479300
4332221 14225250
488900) 16873150
488900) 19483600
488900) 22036400
4889001 24531550
4332221 26262050-
1281200) 28248200
1281200) 29469700
12812001 30633550
12812001 31739750
.-12312221 22233322
1023350) 33791350
1023350) 34736750
10233501 35624500
1023350) 36454600
10233501 37??7nsn
733650 ( 6388501 37960900
676200 ( 638850) 38637100
618600 ( 638850) 39255700
560950 ( 638850) 39816650
5033QO i 6333521 40212252-
445650 ( 6386501 40765600
388000 I 638850) 41153600
330350 ( 6388501 41483950
272700 ( 6388501 41756650
215052__i __ 6333521 __ 41221222
(
(
(
(
-1-
(
(
(
(
-i_
(
1
(
(
i
4889001
977800)
14667001
1955600)
—24445221
29334001
3422300)
3911200)
44001001
43322221
61702001
7451400)
8732600)
100138001
ii295nnni
5.52
5.22
4.92
4.62
4*22
4.03
3.73
3.43
3.13
2&34
6.65
6.35
6.05
5.75
5.45
( 17318350) 5.24
( 13341700) 4.94
( 14365050) 4.63
( 15388400) 4.33
-1—164112521 4»22
( 17050600) 3.86
< 17689450) 3.55
( 18328300) 3.25
( 189671501 2.95
-1—126 262221 2»65
< 20244850) 2.34
( 20883700) 2.04
t 21522550) 1.74
( 221614001 1.43
-1—223222521- _1..12
TOT 46167400 (
302
83376500)
23083700 ( 416882501
41971700 ( 22800250)
4VG= 4.04
-------
Table A-156
MAGNESIA SCHFME A, NONRFGULATED CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 2.5 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 1BB88000
OVERALL INTEREST RATF OF RETURN WITH PAYMENT 15.dZ
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTFR
POWER
UNIT
START
ANNUAL
OPERA-
TION,
KW-HR/
M<
1 7000
2 7000
3 7000
4 7000
5 IflflQ
6
7
8
9
-1Q
11
12
13
1*
15
PRODUCT RATE,
EQUIVALENT
TONS/YEAR TOTAL
MFG.
100* COST,
H2S04 t/YCAR
113900
113900
113900
113900
113900
7000 113900
7000 113900
7000 113900
7000 113900
2222 113900
5000
5000
5000
5000
5222
16 3500
17 3500
18 3500
19 3500
-22- 2522
21
22
23
24
25
26
27
28
29
22
1500
1500
1500
1500
15QO
81300
81300
81300
H1300
-.3.13.22
56900
56900
56900
56900
14222
24400
24400
24400
24400
24400
1500 24*00
1500 24400
1500 24400
1500 24400
- _1522_ _ _-24422
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
2968900
2968900
2968900
2968900
2968900
2331200
2331200
2331200
2331200
222120Q
1399700
1399700
1399700
1399700
13997TQ
1399700
1199700
1399700
1399700
. _ --1222222-
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHFMICAL COM- NET MFG. COST,
PANY FOR AIP t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
J/YEAR PAYMENT PAYMENT
8261100
8166900
8072700
7978500
2.B..842.22
7790200
7696000
7601800
7507600
2411422
6082300
5988200
5894000
5799800
5125422
4656200
4562000
4467900
4373700
4222522-
2840700
2746500
2652400
2558200
2464222-
2369800
2275600
2181400
2087300
_ _ 1222122-J
2594500)
2500300)
24061001
2311900)
22122221
2123600)
2029400)
1935200)
1841000)
1246..B.221
3113400)
3019300)
2925100)
2830900)
22.3.6.2221
2325000)
22308001
2136700)
2042500)
1348.2221
1441000)
1346800)
1252700)
1156500)
12642221
970100)
875900)
781700)
6876001
L - 5224221
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5666600
5466622
2968900
2968900
2968900
2968900
2365222
2331200
2331200
2331200
2331200
2221222 _
1399700
13997UO
1399700
1399700
1222222
NET REVENUE,
J/TON
urn
H2S04
8.00
3.00
e.oo
8.00
a*22_
8.00
8.00
S.OO
8.00
3.»22
TOTAL
NET
SALES
REVENUE,
t/YEAR
911200
911200
911200
911200
211222 -
911200
911200
911200
911200
211222
5.00 406500
5.00 406500
5.00 406500
5,00 406500
5*22 - 426522^.
5.00
5.00
5.00
5.00
. 5*22 .
5.00
5.00
5.00
5.00
5, DO
1399700 5.00
1399700 5.00
1399700 5.00
1399700 5.00
.- 1232222— 5*22
284500
284500
284500
284500
--224522- -
122000
122000
122000
122000
122222
122000
122000
122000
122000
_ 122222-
97163500
154350700 (
57187200)
97163500
YEARS PEOUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS GROSS INCOME,
AFTER t/YEAR
POWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1 1505700
2 3411500
3 3317300
4 3223100
_5- - 2122222
6 3034BOO
7 2940600
8 2446400
9 2/52200
12 2656222 J
11 3519900
12 3425800
13 3331600
14 3237400
15 2142252 J
16 2609500
17 2515300
18 2421200
19 2327000
22 2222B22 J
21 1503000
22 1468800
23 1374700
24 1280500
25_ 1126222 J
26 1092100
27 997900
28 903700
29 809600
_22 _ _215422_ J
4755400)
4755400)
4755400)
4755400)
L 42554221-.
47554001
4755400)
4755400)
',7554001
L 42554221 .
2562400)
2562400)
2562400)
2562400)
L Z5U24D21
2046700)
2046700)
2046700)
2046700)
L 22462221
1277700)
1277700)
1277700)
1277700)
t 12222221
1277700)
12777001
1277700)
1277700)
12222221—
NFT INCOME AFTER TAXFS,
t/YTAR
WITH WITHOUT
PAYMENT PAYMENT
ANNUAL RETURN ON
CASH FLOW, CUMULATIVE CASH FLnw, INITIAL INVFSTMENT,
t/YEAR I t
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1752850 1 2377700) 3641650
1705750 ( 2377700) 3594550
1658650 ( 2377700) 3547450
1611550 ( 2377700) 3500350
1564452—i 212222S1 2452252— J
1517400 ( 2377700) 3406200
1470300 ( 2377700) 3359100
1421200 ( 23777001 3312000
137A1?11 I _>~<77700) 3^64900
1222222 _i 22222221 2212802
1759950 ( 1281200)
1712900 ( 1281200)
1665800 ( 1261200)
1618700 ( 1281200)
1521iil2 i -128.12221
1304750 ( 1023350)
1257650 ( 10233501
1210600 ( 1023350)
1163500 ( 1021?50)
1116400 ( 1023350)
781500 ( 630B50)
734400 I 638850)
687350 1 638850)
640250 ( 6388501
522152 i 628_a521
546050 ( 638850)
498950 ( 638850)
451850 ( 638850)
404800 1 638850)
252222__i— 6228.521 _
1759950
1712900
1665800
1618700
1521622 .
1304750
1257650
1210600
1163500
1116422—
781500
734400
687350
640250
522152 -
546050
498950
451850
404800
252222 J
488900) 3641650 ( 4889001 9.06
488900) 7236200 ( 9778001 8.81
488900) 10783650 1 14667001 8.57
488900) 14284000 ( 1955600) 8.33
L 43S2221 12222252 1 24445221 2*2S_
488900) 21143450 ( 29334001 7.84
488900) 24502550 ( 3422300) 7.60
488900) 27814550 ( 39112001 7.35
438900) 31079450 ( 4400100) 7.11
L 48.8.2221 24222Z52 1 4-tiiQuJl 6*22
1281200) 36057200 I 6170200) 9.15
1281200) 37770100 ( 7451400) 8.90
1281200) 39435900 1 8732600) 8.66
1281200) 41054600 ( 10013800) 8.41
1281200) 42626200 1 11295000) 8.17
1023350) 43930950 ( 12318350) 6.81
1023350) 45188600 1 13341700) 6.57
1023350) 46399200 ( 143650501 6.32
1023350) 47562700 ( 153884001 6.07
I 12222521 4&622122 1 164112521 5*.S2
638850) 49460600 ( 17050600) 4.11
638850) 50195000 ( 17689450) 3.86
638850) 50882350 ( 18323300) 3.61
638850) 51522600 ( 18967150) 3.36
L 6222521 52115252- i 1262621121 2*12
638850) 52661800 ( 20244850) 2.87
638850) 53160750 ( 20883700) 2.62
6388501 53612600 ( 21522550) 2.37
638850) 54017400 I 22161400) 2.13
L 62B.a5.21- _ 54225122 X -22E222521 __l*£fi
70974200 ( B3376500)
35487100 ( 41688250)
54375100 ( 22800250)
303
-------
Table A-157
MAGNESIA SCHEME A, NONREGULATED C(l. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 4.0 X S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 22046000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.5*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
_I5
16
17
18
19
21
22
23
24
_25
26
27
28
29
.32
PRODUCT RATE,
ANNUAL EOUIVALENT
OPFRA- TONS/YEAR TOTAL
TION, MFG.
KW--HR/ 100? COST,
KW H2S04 t/YEAR
7000
7000
7000
7000
70. CO
7000
7000
7000
7000
ZQDQ
5000
•5000
5000
5000
5QOQ
3500
3500
3500
3500
2522
1500
1500
1500
1500
150Q
1500
1500
1500
1500
-1522- _
182200
182200
182200
132200
1B2222
182200
182200
182200
182200
1B2202
130100
130100
130100
130100
1.22122
91100
91100
91100
91100
glLOQ
39000
39000
39000
39000
12222
39000
39000
39000
39000
32222.
6802800
6802800
6802800
6802800
6802800
6802800
6802800
6802800
6802800
6807800
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
VYEAR
NET MFG. COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
7717900 ( 9151001
7591700 ( 788900)
7465500 ( 6627001
7339300 ( 536500»
1213122.1. 410322J
7086900 (
6960800 (
6834600 (
6708400
658220Q
3593300 5732700 (
3593300 5606500 (
3593300 5480300 1
3593300 5354100 (
2522322 5221222-i-
2804700 4527300 (
2804700 4401100 (
2804700 4274900 <
2804700 4148700 (
2524122 4022500 i
1661400
1661400
1661400
1661400
1661400
1661400
1661400
1661400
1661400
_ 16.61422
284100)
158000)
31800)
94400
220622
21394001
20132001
1887000)
1760800)
16346H21.
1722600)
15964001
1470200)
1344000)
1J17800)
3046900 ( 13855001
2920800 ( 1259400)
2794600 ( 1133200)
2668400 ( 1007000)
25.42222 i_ aaaaaoi
2416000 ( 7546001
2289800 ( 628400)
2163600 ( 5022001
2037400 ( 376000)
1211222 i 242B.22J
6802800
6802800
6802800
6802800
_ 6ao2ao2_
6802800
6802800
6802800
6802800
_68J12a2Q_
3593300
3593300
3593300
3593300
3523200.. _.
2804700
2804700
2804700
2804700
.-28.24100
1661400
1661400
1661400
1661400
X66X4QQ
NET REVENUE, TOTAL
J/TON NET
SALES
100% REVENUE,
H2S04 */YE»R
8.00 1457600
8.00 1457600
8.00 1457600
8.00 1457600
a»OQ 145.1622—.
8.00 1457600
8.00 1457600
8.00 1457600
8.00 1457600
fl.,22 145J.6QO.
5.00 650500
5.00 650500
5.00 650500
5.00 650500
5..QQ 6505QJ}
5.00 455500
5.00 455500
5.00 455500
5.00 455500
5»Q2 __455502
5.00 195000
5.00 195000
5.00 195000
5.00 195000
5.20. 1250.02
1661400 5.00 195000
1661400 5.00 195000
1661400 5.00 195000
1661400 5.00 195000
_ 166140.0_ _ 5..00 12520.2...
TOT
127500
3318000
116632000
145067300 (
28435300)
116632000
22056000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
GROSS INCOME,
t/YEAR
NET INCOME AFTER TAXES,
t/YEAR
CASH FLOW,
t/YFAR
CUMULATIVE CASH FLOW,
t
ANNUAL RETURN ON
INITIAL INVESTMENT,
WITH
PAYMENT
WITHOUT
PAYMENT
WITH
PAYMENT
WITHOUT
PAYMENT
WITH
PAYMENT
WITHOUT
PAYMENT
WITH
PAYMENT
2372700 (
2246500 (
2120300 (
1994100 (
1741700 (
1615600 (
1439400 (
1363200 (
L231202—1.
2789900 (
2663700 (
2537500 (
2411300 (
2205122—1
2178100 (
2051900
1925700
1799500
1612222.
1580500
1454400
1328200
1202000
12158.22—i
949600 (
823400 (
697200 (
571000 (
444322—1
5345200)
53452001
53452001
5345200)
-53452221-
5345200)
53t5200l
53452001
5345200)
—52452221-
29428001
29428001
2942800)
29428001
-2242flfl01-
2349200)
23492001
2349200)
23492001
-2.2422221.
14664001
1466400)
14664001
1466400)
—1466.4021-
14664001
1466400)
1466400)
1466400)
—14664221.
1186350 (
1123250 (
1060150 (
997050 (
233252—1_.
870850 (
807800 (
744700 (
681600 (
61£522—i..
1394950 (
1331850 (
1268750 (
1205650 (
__1142552__i_.
1089050 (
1025950 (
962850 (
899750 (
8_36652__i_.
790250 (
727200 (
664100 (
601000 (
521222 L_.
474800 (
411700 (
348600 (
285500 (
222420__i_.
2672600)
26726001
2672600)
2672600)
.-26126021.
2672600)
2672600)
2672600)
2672600)
.-26126221-
1471400)
1471400)
14714001
1471400)
..14114221.
1174600)
1174600)
11746001
11746001
..11146021.
733200)
7332001
733200)
733200)
—1232221.
7332001
733200)
733200)
733200)
—1222221.
3390950
3327850
3264750
3201650
21235.52-
3075450
3012400
2949300
2886200
2223122.
1394950
1331850
1268750
1205650
1142552.
1089050
1025950
962850
899750
B266.52.
790250
727200
664100
601000
521200.
474800
411700
348600
285500
222422-
( 468000)
( 468000)
( 4680001
( 468000)
.1 46B2221
( 468000)
( 468000)
( 468000)
( 468000)
.1 46B2021
( 14714001
( 1471400)
( 1471400)
I 1471400)
.1 14114221
( 1174600)
( 11746001
( 1174600)
( 1174600)
.1 11146221
( 733200)
I 733200)
( 733200)
I 7332001
.1 1332221
( 733200)
( 7332001
( 733200)
I 7332001
-i 1322Q21
3390950 (
6718800 (
9983550 (
13185200 (
-16222I50__i_.
19399200 (
22411600 (
25360900 (
28247100 (
-31212222__i_.
32465150 (
33797000 I
35065750 (
36271400 (
—31413250—1..
38503000 (
39528950 (
40491800 (
41391550 (
-4222a2Q.O__i_.
43018450 <
43745650 (
44409750 (
45010750 (
-4554fl650-_l_.
46023450 (
46435150 (
46783750 (
47069250 (
—41221652—L-.
5C491300 ( 94576000) 25245650 ( 47288000) 47291650 ( 25242000)
WITHOUT
PAYMENT
46800oT"
9360001
1404000)
18720001
—22402201..
2608000)
3276000)
3744000)
42120001
—46322021-.
6151400)
76228001
9094200)
10565600)
-122310201..
132116001
143862001
155608001
16735400)
-112122Q01--
18643200)
193764001
201096001
20842800)
-215162201--
22309200)
230424001
2377.5600)
24508800)
.252420221—
AV6=
WITH
PAYMENT
4.97
4.69
4.41
-4..13 ___
3.85
3.57
3.29
3.01
-2..I3 ___
6.21
5.92
5.64
5.36
WITHOUT
PAYMENT
4.87
4.59
4.30
4.02
-3^24
3.56
3.27
2.99
2.71
.2^42
2.14
1.85
1.57
1.29
.1*0.0
3.79
-------
Table A-158
MAGNESIA SCHEME A, NONREGULATED CO. ECONOMICS, 1000 MM. EXISTING OIL FIRED POWER PLANT, 2.5 % S IN FUEL, 99% H2S04 PRODUCTION.
FIXED INVESTMENT $ 20740000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.9*
OVERALL INTEREST PATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POHER
UNIT
START
1
2
3
4
6
7
9
9
11
12
13
14
li
16
17
18
19
20
21
22
23
24
-25
26
27
28
29
30. .
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
7000
7000
2222_
5000
5000
5000
5000
5000
3500
3500
3500
3500
3.522_
1500
1500
1500
1500
1500
1500
1500
1500
1500
1522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
117800
112222
117800
117800
117900
117800
112220.
84100
84100
84100
B4100
24122
58900
58900
58900
58900
5.2220.
25200
25200
25200
25200
25222
25200
25200
25200
25200
- _ .25.222
TOTAL
MFG.
COST,
t/YEAR
6070600
60706.Q2
6070600
6070600
6070600
6070600
607060P
5221800
5221800
5221900
3147800
3-142222
2478200
2478200
2478200
2478200
2422222
1497000
1497000
1497000
1497000
_ 1421222
1497000
1497000
1497000
1497000
_1422222
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEA'l
POLLUTION
CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
7604800 ( 1534200)
246.3.3.22 J 13927001
7321900
7190400
7039000
6897500
625.6222 J
5942200
5800700
5659200
5517800
5376300
4699300
4557800
4416300
4274900
413.3.422-J
3195900
3054400
2912900
2771500
26.3.0.222 J
2498600
2347100
2205600
2064200
-1222 22 a J
12513001
1109800)
968400)
826900)
L_ 6254221
720400)
5789001
437400)
23700001
L 22225221
22211001
2079600)
1938100)
1796700)
L 16552221
16989001
15574001
14159001
1274500)
L_ 113.3. aaai
991600)
8501001
7086001
5672001
4252221 —
6070600
6222620.
6070600
6070600
6070600
6070600
62226 aa
5221800
5221800
5221800
3147800
3.142220—
2478200
2478200
2478200
2478200
2478209
NET REVENUE,
$/TON
1 00*
H2S04
8.00
8j.ao_
8.00
8.00
8.00
8.00
2*22
8.00
8.00
8.00
5.00
5*22
5.00
5.00
5.00
5.00
5»Q3
1497000 5.00
1497000 5.00
1497000 5.00
1497000 5.00
. -1422222 5*22
1497000
1497000
1497000
1497000
. —1422022
5.00
5.00
5.00
5.00
5*22-
TOTAL
NET
SALES
REVENUE,
t/YEAR
942400
-242422
942400
942400
942400
942400
242422
672800
672800
672900
420500
422522
294500
294500
294500
294500
224522
126000
126000
126000
126000
1262Q2
126000
126000
126000
126000
_ 126222 _
TOT
106500
126233700 (
344175001
12188700
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
AFTER t/YEAR t/YEAR t/YFAR t T
POWER
UNIT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
START PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1
2
3
4 2476600 ( 5128200) 1238300 ( 2564100) 3312300 ( 490100) 3312300 ( 490100) 5.83
5_ 2225122- S 51292001 1167550 ( 25641QQ1 32415SQ i 4901D01 6513850 1 980200J 5.50
6 2193700
7 2052200
8 1910800
9 1769300
10 1627800
11 1393200
12 1251700
13 1110200
14 2790500
_15 2M2102— J
16 2515600
17 2374100
18 2232600
19 2091200
20 194970Q
21 1824900
22 1683400
23 1541900
24 1400500
25 1252122
26 1117600
27 976100
28 834600
29 693200
30 551IDO
51282001 1096850 ( 25641001 3170850 ( 490100) 9724700 ( 14703001 5.17
51282001 1026100 ( 2564100) 3100100 ( 4901001 12824800 ( 19604001 4.83
5128200) 955400 ( 2564100) 3029400 ( 490100) 15854200 ( 2450500) 4.50
5129200) 884650 ( 25641001 2958650 ( 4901001 18812850 ( 29406001 4.17
L 51222221 212222 1 25641221 2222222 1 -4221221 2120.0_25Q_ 1 3.43.22221 2*22
45^9000) 696600 ( 2274500) 2770600 ( 200500) 24471350 ( 3631200) 3.30
45490001 625850 ( 2274500) 2699850 ( 200500) 27171200 ( 3831700) 2.96
4549000) 555100 ( 2274500) 2629130 ( 200500) 29800300 ( 4032200) 2.63
27273001 1395250 ( 13636501 1395250 ( 1363650) 31195550 ( 53958501 6.61
L 22222221 1224522 i 12626521 122450.2 i -12636521 _ 22522252 _i 62525221 6*22
2183700) 1257800 ( 10918501 1257800 ( 1091850) 33777850 ( 79513501 5.98
2183700) 1187050 ( 1091850) 1187050 ( 1091850) 34954900 ( 89432001 5.65
2183700) 1116300 ( 1091850) 1116300 ( 1091850) 36091200 ( 10035050) 5.31
21837001 1045600 ( 1091850) 1C45600 ( 1091850) 37126800 ( 111269001 4.97
L 21222221 224252 i 12212521 224252 i 12212521 28J.2165J1 1 122122521 4*64
1371000) 912450 ( 685500) 912450 ( 6855001 39014100 ( 129042501 4.37
1371000) 841700 ( 6855001 841700 ( 6955001 39855800 ( 13589750) 4.03
1371000) 770950 ( 685500) 770950 ( 685500) 40626750 ( 142752501 3.69
1371000) 700250 ( 6855001 700250 ( 685500) 41327000 ( 14960750) 3.35
L 12212221 622522 L _ 6255221- 622522 i -6255221 4125,6522 i 156462521 2»Q1
1371000) 559800 ( 685500) 558800 ( 6855001 42515300 ( 163317501 2.68
1371000) 488050 ( 685500) 488050 ( 6855001 43003350 ( 170172501 2.34
1371000) 417300 ( 685500) 417300 ( 685500) 43420650 1 17-702750) 2.00
1371000) 346600 ( 685500) 346600 ( 685500) 43767250 1 183882501 1.66
13I1QQQ1 225252 t 6255221 225252— i 6255221 44243100 i 19073750) 1.3?
TOT 4660620O ( 79627500) 23303100 1 398137501 44043100 ( 190737501 AVG= 4.13
305
-------
Table A-159
MAGNESIA SCHEMF B, NONREGULATFD CO. ECONOMICS, 200 MW. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98% H2S34 PRODUCTION.
FIXED INVESTMENT $ 11990000
OVERALL INTEREST RATE OF RFTURN WITH PAYMENT 6.9?
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
PRODUCT RATE,
YEARS ANNUAL EQUIVALENT
AFTER OPERA- TONS/YEAR TOTAL
POWER TION, MFG.
UNIT KW-HR/ 100* COST,
START KM M2S04 t/YEAR
*
7000
7000
7000
7000
45200 3528400
45200 3528400
45200 3528400
45200 3528400
6 7000 45200 352B400
7 7000 45200 3528400
8 7000 45200 3528400
9 7000 45200 3528400
J.O 7000 45200 3528400
11 50C3 32300 1872400
12 5000 32300 1872400
13 5000 32300 1872400
14 5000 32300 1872400
15 ^nnn i?^nn ifl7?4no
16
17
18
19
20
3500 22600 1502600
3500 22600 1502600
!500 22600 1502600
3500 22600 1502600
3500 22600 1502600
21 1500
22 1500
23 1500
24 1500
-25 1500
26 1500
27 1500
28 1500
?9 1500
.20 1520
9700 939700
9700 939700
9700 939700
9700 939700
2100 232100
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
S/YFA" PAYMENT PAYMENT
3825400 ( 297000)
3761700 ( 233300)
3698000 ( 169600)
3634200 ( 105800)
3510500 1 421201
3506800 21600
3443000 85400
3379300 149100
3315600 212800
3251200 276500
2868100
2804400
2740700
2676900
26132QD J
2288900
2225100
2161400
2097700
2023200 J
1567700
1504000
1440200
1376500
1312800
9700 939700 1249100
9700 939700 1185300
9700 939700 1121600
9700 939700 1057900
2122 232100— - 224122-J
995700)
932000)
868300)
804500)
1403001
786300)
722500)
658800)
595100)
5213021
628000]
564300)
500500)
436800)
3131021 -
309400)
245600)
181900)
118200)
L -544001 --.
3528400
3528400
3528400
3528400
352B400
3528400
3528400
3528400
3528400
352B400-
1872400
1872400
1872400
1872400
1312420
1502600
1502600
1502600
1502600
1502602
939700
939700
939700
939700
232122
939700
939700
939700
939700
--.332122
NET REVENUE
J/TON
100*
H2S04
8.00
8.00
8.00
H.OO
8.00
fl.OO
8.00
8.00
. ..3x20 .
5.00
5.00
5.00
5.00
5x00
5.00
5.00
5.00
5.00
5x00
, TOTAL
NET
SALES
REVENUE,
i/YEAR
361600
361600
361600
361600
26160Q...
361600
361600
361600
361600
. . 261622 .
161500
161500
161500
161500
161500
113000
113000
113000
113000
113QQQ
5.00 48500
5.00 48500
5.00 48500
5.00 48500
5x02 4B5QO
5.00 48500
5.00 48500
5.00 48500
5.00 48500
. . -- 5x00 . 4B500
72705900 (
111499001
61556000
YEARS REQUIRED FOR PAYC1UT WITH PAY1FNT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YFARS
AFTER
POWER
UNIT
START
1
2
3
4
- 5 .
6
7
8
9
12 .
11
12
13
14
-IS .
16
17
18
19
22 .
21
22
23
24
25 .
26
27
28
29
32 .
TOT
306
GROSS INCOME,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
NET INCOME AFTFR TAXFS,
J/YFAR
WITH WITHOUT
PAYMENT PAYMENT
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YFAR l %
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
658600 ( 3166800) 329300 ( 1583400) 1528300 I
594900 ( 31668001 297450 I 1583400) 1496450 (
531200 1 3166800) 265600 ( 15834001 1464600 1
467400 ( 31668001 233700 ( 1583400) 1432700 (
423122—1—31663221 201350— i 15334001 14QQB5Q. I
340000 [ 3166800) 170000 ( 1583400) 1369000 1
276200 ( 3166800) 130100 ( 1583400) 1337100 I
212500 [ 3166800) 106250 ( 1583400) 1305250 (
148800 I 3166800) 74400 ( 1583400) 1273400 (
25102 -1 21663021 4255Q i 15B34.M1 1241550 I
1157200 (
1093500 1
1079800 (
966000 (
222202 1
899300 (
835500 (
771800 1
708100 I
644320 i
676500 I
612800 (
549000 I
485300 (
421602 i-
: 57900 (
294100 (
230400 (
166700 (
122222 1
16623400 (
1710900)
1710900)
1710900)
1710900)
11122201.
1389600)
1389600)
1389600)
1389600)
12226001.
891200)
891200)
8912001
891200)
3212201
578600 ( 8554501 578600 (
546750 ( 855450) 546750 (
514900 ( 855450) 514900 (
483000 ( 855450) 483000 (
451152—1 H554521 451150— i
449650 ( 694800) 449650 (
417750 ( 694800) 417750 (
385900 ( 694BOO) 385900 [
354050 ( 694800) 354050 (
3221-iJ— i 6243221 322152 1
338250 ( 445600) 338250 (
306400 ( 4456001 306400 I
274500 ( 4456001 274500 1
242650 ( 445600) 242650 (
21QBQO ( 4456001 Plonnn ,
891200] 178950
8912001 147050
8912001 115200
8912001 83350
.3212001. —51452-
56082500)
8311700
1 445600)
( 4456001
( 4456001
( 445600)
I _ 4456001
( 28041250)
178950 (
147050 (
115200 (
83350 (
20301700 (
3844001 1528300
384400) 3024750
3844001 4489350
3844001 5922050
3344201 1222202
384400) 8691900
3844001 10029000
384400) 11334250
384400) 12607650
855450) 14427ROO
855450) 14974550
8554501 15489450
855450) 15972450
694800) 16873250
6948001 17291000
6948001 176,76900
694800) 18030950
i2i3221 13253100.
445600) 18691350
445600) 18997750
445600) 19272250
4456001 19514900
4456221 12125100
445600) 19904650
445600) 20051700
445600) 20166900
445600) 20250250
4456001 202Q11QU J
16051250)
384400)
763800)
1153200)
1537600)
12220201—
2306400]
2690800)
3075200)
3459600)
4699450)
5554900)
6410350)
7265800)
31212501 —
8816050)
9510850)
10205650)
10900450)
-.115252501 —
120408501
124864501
129320501
13277650)
--138232501..
1426S850)
14714450)
1516005D)
15605650)
L__1625U5Q1 —
AVG =
2.68
2.42
2.16
1.90
~~U38
1.12
O.B7
0.61
—0x25
4.74
4.48
4.22
3.95
__3x62
3.70
3.43
3.17
2.91
— 2x65
2.80
2.54
2.27
2.01
— 1x14
1.48
1.22
0.95
0.69
— 0x43
2.29
-------
Table A-160
MAGNESIA SCHEME B, NONREGULATED CO. ECONOMICS, 200 MM. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 98* H2SD4 PRODUCTION.
FIXED INVESTMENT * 11990000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.5*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NE3
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
it
5
6
7
8
9
-10
11
12
13
14
-15 _
16
17
18
19
20
PRODUCT RATE,
ANNUAL EQUIVALENT
OP^RA- TONS/YEAR
TlflN,
KW-HR/ 100*
KW H2S04
TOTAL
MFG.
COST,
$/YEAR
7000 45200 3528400
7000 45200 3528400
7000 45200 3528400
7000 45200 3528400
_ 2002 45222 352fl4flO
7000 45200
7000 45200
7000 45200
7000 45200
2000 45222
5000 32300
5000 32300
5000 32300
5000 32300
5022 323.00
3500
3500
3500
3500
1500
21 1500
22 1500
23 1500
24 1500
-25 15. QQ
26 1500
27 1500
28 1500
29 1500
-22 1522
22600
22600
22600
22600
22600-
9700
9700
9700
9700
2200 _
9700
9700
9700
9700
, 2222
3528400
3528400
3528400
3528400
352.fl4.Qfl
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET MFG. COST,
PANY FOR A'lR I/YEAR
POLLUT ION
CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
4388700
4338300
4288000
4237700
4122222
4137000
4086700
4036300
3986000
3935700
1872400 3252900
1872400 3202600
1872400 3152200
1872400 3101900
-_lflI242Q 3251622-
1502600 2508100
1502600 2457800
1502600 2407500
1502600 2357100
. 15Q26.Qa 2306800
939700
939700
939700
939700
939100
1550300
1499900
1449600
1399300
13.48900 1
860300)
809900)
759600)
7093001
6.5.820.0,1
608600)
5583001
507900)
457600)
4223021
13805001
1330200)
1279800)
1229500)
11222021
10055001
955200)
904900)
854500)
B242221
610600)
560200)
• 509900)
459600)
L 409200J
939700 1298600 ( 3589001
939700 1248200 ( 3085001
939700 1197900 ( 2582001
939700 11*7600 ( 207900)
939700 1097200 ( 1575001
3528400
3528400
3528400
3528400
3522422
3528400
3528400
3528400
3528400
. 3522402- .
1872400
1872400
1872400
1872400
1222420
1502600
1502600
1502600
1502600
- 1522622
939700
939700
939700
939700
232222-
939700
939700
939700
939700
. -- 232222 „
NET REVENUE,
$/TON
100*
42S04
8.00
8.00
8.00
8.00
2*22
8.00
8.00
8.00
8.00
.2*22
5.00
5.00
5.00
5.00
5.2B
5.00
5.00
5.00
5.00
5*22
TOTAL
NET
SALES
REVENUE,
J/YEAR
361600
361600
361600
361600
3616Q2
361600
361600
361600
361600
. 361602
161500
161500
161500
161500
161522
113000
113000
113000
113000
113000
5.00 48500
5.00 48500
5.00 48500
5.00 48500
5»20 42522
5.00 48500
5.00 48500
5.00 48500
5.00 48500
- 5.22 42522 „
127500
61556000
82657700 (
5473500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_5
6
7
8
9
12
11
12
13
14
15
16
17
18
19
20
GROSS INCOME,
$/YF»R
WITH WITHOUT
PAYMENT PAYMENT
1221900 ( 3166800)
1171500 ( 31668001
1121200 ( 3166800)
1070900 ( 3166800)
1222522 1 31662221-.
970200 ( 3166800)
919900 ( 3166800)
869500 ( 3166800)
819200 ( 3166800)
262222 1 31662201—
1542000 ( 1710900)
1491700 ( 1710900)
1441300 ( 17109001
1391000 ( 1710900)
1240200 1 121Q2QQ1 .
1118500 1 1389600)
1068200 ( 1389600)
1017900 ( 1389600)
967500 ( 1389600)
917700 ( 13896001
NFT INCOME AFTER TAXES,
I/YEAR
WITH WITHOUT
PAYMENT PAYMENT
610950
585750
560600
535450
510250
485100
459950
434750
409600
224452
771000
745850
720650
695500
. - 620352—
559250
534100
508950
483750
4586.00
(
(
(
I
i_
I
I
1_
I
{
21 659100 ( 891200) 329550 (
22 608700 I 891200) 304350 (
23 558400 ( 891200) 279200 (
24 508100 ( 891200) 254050 (
25 452222—1 2212221 222252 — L_
26 407400 ( 891200) 203700 (
27 357000 I 891200) 178500 1
28 106700 ( 891200) 153350 (
29 256400 ( 891200) 128200 (
30 206222—1- 2212221— _ 123202—1-
1583400)
15834001
1583400)
15834001
15234221
1583400)
15834001
1583400)
1583400)
15234201
855450)
855450)
855450)
8554501
-2554521—
6948001
694800)
694800)
694800)
6242201
445600)
445600)
4456001
445600)
-4456221-
4456001
445600)
445600)
445600)
4456221—
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1809950
1784750
1759600
1734450
1223252
1684100
1658950
1633750
1608600
1523452
771000
745850
720650
695500
622350
559250
534100
508950
483750
452622-
329550
304350
279200
254050
222252-
203700
178500
1533DO
128200
123222 J
CUMULATIVE
WITH
PAYMENT
3844001 1809950
3844001 3594700
384400) 5354300
384400) 7088750
L 3244221 2222020
3844001 10482100
384400) 12141050
384400) 13774800
384400) 15383400
L 2244221 1696.6fl.5Q
855450)
855450)
855450)
8554501
L 2554521—
694800)
694800)
6948001
694800)
L- -6242221
445600)
445600)
445600)
445600)
L 4456001 —
445600)
445600)
445600)
445600)
L 4456.221—
17737850
18483700
19204350
19899850
— 22520.222—
21129450
21663550
22172500
22656250
—22114252—
23444400
23748750
24027950
24282000
—24510250—
24714550
24893050
25046400
25174600
—252226.22—
$
I
1
(
1
1
1
I
I
1
1
1
CASH FLOW,
WITHOUT
PAYMENT
384400)
768800)
1153200)
1537600)
12222221-
2306400)
2690800)
3075200)
34596001
3244QQ21
4699450)
5554900)
6410350)
7265830)
— 21212521.
88160501
9510850)
10205650)
1090D450I
115252521
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH WITHOUT
PAYMENT PAYMENT
1 1
I I
U1'J1U1C7>C7>ILJl>>UJUJ'^l*>.f.F>.r.f
4
4
4
3
3
12040R50) 2
124864501 Z
129320501 2
13377650) 2
-.132232521 1
142688501 1
147144501 1
151600501 1
156056501 1
—162512521 2
.98
.77
.57
.36
.95
.75
.54
.34
.31
.11
.90
.69
»42_
.60
.39
.18
.98
.73
.52
.31
.10
.69
.48
.27
.06
26575200 ( 56082500)
13287600 I 28041250)
25277600 ( 16051250)
AVG= 3.66
307
-------
MAGNESIA SCHEME B,
Table A-161
NONREGULATED CO. ECONOMICS, 500 MW. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98* H2S34 PRODUCTION.
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
22237000
8.4*
NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS ANNUAL
AFTER DPFRA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
it 7000
6 7000
7 7000
8 7000
9 7000
11 5000
12 5000
13 5000
14 bOOO
15 5222
16 3500
17 3500
18 3500
19 3500
_22 1520
21 1500
22 1500
23 1500
24 1500
-25 1522
26 1500
27 1500
28 1500
29 1500
_3.Q 1500
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
110400
110400
110400
110400
110400
110400
110400
110400
110.40.0.
78900
78900
78900
78900
2220.0
55200
55200
55200
55200
5520.0,
23700
23700
23700
23700
2.3.7.20.
TOTAL
MFG.
COST,
t/YEAR
6404400
6404400
6404400
6404400
6404400
6404400
6404400
6404400
6.4044D.2
3326700
3326700
3326700
3326700
3.326700
2645500
2645500
2645500
2645500
2645500
1629000
1629000
1629000
1629000
1629QQQ
23700 1629000
23700 1629000
23700 1629000
23700 1629000
2210.2 16.220.0,2 _.
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
7209600 I
7087400 (
6965200 (
6843000 (
6.120.30.0. i
6598700 (
6476500 (
6354300
6232100
6110022
5381100 (
5258900 I
5136700 (
5014500 I
40.22422 i
4280700 (
4158500 (
4035300 (
3914200 1
3122000 I
2926100 (
2803900 (
2681700 (
2559600 (
2421402 1
2315200 (
2193000 (
2070800 (
1943700 (
1B2652Q i
NET
WITH
PAYMENT
805200)
683000)
560800)
438600)
216.5QQ1
194300)
72100)
50100
172300
224402
2054400)
19322001
1810000)
1687800)
156.52221
1635200)
1513000)
13908001
1268700)
11465001
1297100)
11749001
1052700)
930600)
2034021
686200)
564000)
441800)
319700)
1325021
MFG. COST,
$/YEAR
WITHOUT
PAYMENT
6404400
6404400
6404400
6404400
6.40.440.0.- _.
6404400
6404400
6404400
6404400
_ -6.404400. -
3326700
3326700
3326700
3326700
- 3326100
2645500
2645500
2645500
2645500
2645500
1629000
1629000
1629000
1629000
16.23000
1629000
1629000
1629000
1629000
16.23000
NET REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
3*00 -
8.00
8.00
8.00
8.00
--3*00
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
--5*00—
5.00
5.00
5.00
5.00
5*02—
5.00
5.00
5.00
5.00
- -5*02
TOTAL
NET
SALES
REVENUE,
$/YEAR
883200
883200
883200
883200
88320,0..
883200
883200
883200
883200
882200-
394500
394500
394500
394500
324500
276000
276000
276000
276000
2I6.QQQ
118500
118500
118500
118500
uasoo— .
118500
118500
118500
118500
11850.2.-.
110195000
136225900 (
26030900)
110195000
13369503
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
STA3T
1
2
3
4
GROSS INCOME,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1608400
1566200
1444000
1321800
1199100
6 1077500
7 955300
8 833100
9 710900
_iQ iaaao2_-
11 2448900
12 2326700
13 2^04500
14 2082300
15 1262222
16
17
18
19
-2Q _
21
22
23
24
-25 _
26
27
28
29
3.0.
TOT
308
1911200
1789000
1666800
1544700
_ 1422500 -
1415600
1293400
1171200
1049100
_ -226222__
304700
68^500
560300
438200
3.16.QQ2 -
5521200)
55212001
55212001
55212001
—55212221-
5521200)
5521200)
5521200)
5521200)
55212201
NET INCOME AFTER TAXFS,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
ANNUAL RETURN ON
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/YEAR $ j
WITH WITHOUT WITH WITHOUT ^ITH WITHOJT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
844200 ( 27606001 3067900
783100 ( 2760600) 3006800
722000 ( 2760600) 2945700
660900 I 27606001 2884600
522352 i 2160.6.221 2823550
538750 ( 27606001
477650 ( 2760600)
416550 ( 2760600)
355450 ( 2760600)
224400 i 2760600)
2932200) 1224450 I 1466100)
29322001 1163350 < 1466100)
2932200) 1102250 ( 1466100)
2932200) 1041150 ( 1466100)
- 22222001 -232120. i 1466100)
2369500)
23695001
2369500)
23695001
- 226250.01-
1510500)
1510500)
1510500)
1510500)
15105021-
1510500)
15105001
15105001
( 1510500)
i. -15105.221
39400400 [ 968255001
955600 1 1184750)
894500 ( 1184750)
833400 ( 1184750)
772350 ( 1184750)
111250. 1 11B41521
707800 ( 755250)
646700 ( 7552501
585600 I 7552501
524550 ( 755250)
46.2452 i _ 1552521
402350 ( 755250)
341250 ( 7552501
280150 ( 755250)
219100 ( 7552501
15B222 i 1552521
19700200 ( 484127501
2762450
2701350
2640250
2579150
2518100—
1224450
1163350
1102250
1041150
2B0100
955600
894500
833400
772350
111250
707800
646700
585600
524550
46.2450
402350
341250
280150
219100
41937200
536900) 3067900 I 536900) 3.71
536900) 6074700 ( 1073800) 3.44
5369001 9020400 ( 1610700) 3.17
536900) 11905000 ( 2147600) 2.91
536900) 17491000 ( 32214001 2*37
536900) 20192350 I 3758300) 2.10
536900) 22832600 ( 4295200) 1.83
5359001 25411750 ( 4S32100) 1.56
14661001 29154300 ( 6835100) 5.41~
1466100) 30317650 ( 8301200) 5.14
1466100) 31419900 ( 9767300) 4.87
1466100) 32461050 ( 11233400) 4.60
1184750) 34396750 ( 13884250) 4.24
1184750) 35291250 ( 150690001 3.97
11847501 36124650 ( 16253750) 3.70
1184750) 36897000 ( 17438500) 3.43
L— 11841501 316.08250 i — 18.6222501 2*1$
755250) 38316050 I 19378500) 3.16
755250) 38962750 ( 201337501 2.89
755250) 39548350 1 20889000) 2.61
755250) 40072900 I 21644250) 2.34
L 1552501 40536.250— i — 222325001 2*02
755250) 40938700 ( 23154750) 1.80
755250) 41279950 ( 23910000) 1.52
7552501 41560100 ( 24665250) 1.25
7552501 41779200 ( 254205001 0.98
L I5525Q1 41221222— L— 26,1152521 Q*ll
26175750) 4VG= 2.93
-------
Table A-162
MAGNESIA SCHEME 8, NONREGULATED CO. ECONOMICS, 500 MM. NEW COAL FIRED POWER PLANT, 3.5 * S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 22237000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 14.4*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS ANNUAL
AFTER OPERA-
POHER TION,
UNIT KH-HR/
START KW
1 7000
2 7000
3 7000
4 7000
. ,5 2022- _
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
110400
110400
110400
110400
110400.
6 7000 110*00
7 7000 110400
8 7000 110400
9 7000 110400
-ID 2220 112400
11 5000
12 5000
13 5000
14 5000
-15 5000—
16 3500
17 3500
18 3500
19 3500
22 3520
21 1500
22 1500
23 1500
24 1500
25 1520
78900
78900
78900
78900
23202
55200
55200
55200
55200
5.5.2.0.2
23700
23700
23700
23700
Z32QQ
26 1500 23700
27 1500 23700
28 1500 23700
29 1500 23700
-30- 1522- - — 23220
TOTAL
MFG.
COST,
t/YEAR
6404400
6404400
6404400
6404400
- -6424422 .
6404400
6404400
6404400
6404400
,,6404400
3326700
3326700
3326700
3326700
1326122 _
2645500
2645500
2645500
2645500
2645502 _
1629000
1629000
1629000
1629000
1622202- -
1629000
1629000
1629000
1629000
1622000
ALTERNATIVE
NONRECOVERY
HET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
9115900 (
9016300 I
8916700 (
8817100 1
3212622 i
8618000 I
8518400 (
8418800 (
8319200 (
. 3212600 i
6719600 (
6620000 (
6520400 (
6420800 (
6321220 i
5139500 (
5039900 (
4940300 (
4840700 (
4241122 1
3114300 (
3014700 (
2915100 (
2815500 (
2215320 i
2616400 (
2516800 I
2417200 (
2317600 (
2213022-1
NET
WITH
PAYMENT
27115001
2611900)
2512300)
2412700)
-23132221
2213600)
2114000)
20144001
1914800)
18152021
3392900)
3293300)
3193700)
30941001
239450.21
2494000)
2394400)
2294800)
21952001
20.356221
14853001
1385700)
1286100)
1186500)
12363221
987400)
887800)
788200)
6886001
-.5220021
MFG. COST,
t/YEAR
WITHOUT
PAYMENT
6404400
6404400
6404400
6404400
6404422.
6404400
6404400
6404400
6404400
6424422
3326700
3326700
3326700
3326700
3326222
2645500
2645500
2645500
2645500
2645520
1629000
1629000
1629000
1629000
1622222-
1629000
1629000
1629000
1629000
- - - 1623220
NET REVENUE,
I/TON
100*
H2S04
8.00
8.00
8.00
8.00
B..22
8.00
8.00
8.00
8.00
a»02
5.00
5.00
5.00
5.00
5.20
5.00
5.00
5.00
5.00
5.20
5.00
5.00
5.00
5.00
. 5.02
5.00
5.00
5.00
5.00
S.OC
TOTAL
NET
SALES
REVENUE,
I/YEAR
883200
883200
883200
883200
283222
883200
883200
883200
883200
- - 333222
394500
394500
394500
394500
3345Q2
276000
276000
276000
276000
226222
118500
118500
118500
118500
113520 -
118500
118500
118500
118500
113520
110195000
170642600 (
13369500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5.
6
7
8
9
—10
11
12
13
14
-15
16
17
18
19
-22—.
21
22
23
24
25
26
27
28
29
-32 -.
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3594700 ( 55212001
3495100 ( 5521200)
3395500 ( 55212001
3295900 ( 5521200)
3126422 J 5521200)
3096800
2997200
2897600
2798000
2632422
3787400
3687800
3588200
3488600
3332222—
2770000
2670400
2570800
2471200
2321622
1603800
1504200
1404600
1305000
1225422
1105900
1006300
906700
807100
202522 J
55212001
5521200)
5521200)
5521200)
L 55212221
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1797350
1747550
1697750
1647950
1598200
1548400
1498600
1448800
1399000
1349200
2932200) 1893700
2932200) 1843900
2932200) 1794100
2932200) 1744300
22322221 1624522.
2369500) 1385000
2369500) 1335200
23695001 1285400
2369500) 1235600
23625221 11R5BOO
15105001
15105001
1510500)
1510500)
15125221
1510500)
1510500)
1510500)
1510500)
L— 15105001
( 2760600)
I 2760600)
( 2760600)
( 2760600)
_1 22626021—
1 2760600)
( 27606001
I 2760600)
( 2760600)
i 226Q6QQ1
( 1466100)
( 1466100)
( 1466100)
( 1466100)
_1 14661021—
( 1184750)
( 1184750)
( 1184750)
( 1184750)
I 1184750)
801900 ( 7552501
752100 ( 755250)
702300 ( 755250)
652500 ( 755250)
602200 1 2552501
552950
503150
453350
403550
353252-
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
4021050
3971250
3921450
3871650
3321320
3772100
3722300
3672500
3622700
3522300
1893700
1843900
1794100
1744300
1624520
1385000
1335200
1285400
1235600
1135322-.
801900
752100
702300
652500
60.2202 .
CUMULATIVE CASH FLOW,
t
WITH WITH3UT
PAYMENT PAYMENT
I 536900) 4021050
( 536900) 7992300
( 5369001 11913750
( 5369001 15785400
1 5362021 12&Q23.Q.D.
( 536900)
( 536900)
( 536900)
( 536900)
1 5363201—
I 14661001
( 1466100)
I 1466100)
( 1466100)
i 14661221
( 11847501
( 1184750)
( 1184750)
( 1184750)
.1- 11242501 -
( 755250)
( 7552501
( 7552501
( 755250)
.1 2552501—
23379400
27101700
30774200
34396900
32262220
39863500
41707400
43501500
45245800
— 46342322—
48325300
49660500
50945900
52181500
—53362300—
54169200
54921300
55623630
56276100
56222222 _
( 755250) 552950 I 755250) 57431750
( 7552501 503150 1 755250) 57934900
I 755250) 453350 ( 755250) 58388250
( 755250) 403550 I 755250) 58791800
i -2552521 353252- i 2552521- - 52145552- J
ANNUAL RETURN ON
INITIAL INVESTMENT
*
WITH WITHOUT
PAYMENT PAYMENT
•
536900) 7.90
1073800) 7.68
1610700) 7.46
2147600) 7.24
26345221, 2.22
3221400)
3758300)
4295200)
4832100)
53622221.
6835100)
8301200)
9767300)
112334001
126235001.
13884250)
150690001
16253750)
17438500)
—126232521.
6.81
6.59
6.37
6.15
5.33
8.37
8.15
7.93
7.71
2.43
6.15
5.92
5.70
5.48
—5.26
—
19378500) 3.58
20133750) 3.36
20889000) 3.14
21644250) 2.91
—223225201 2.63
23154750) 2.47
23910000) 2.25
246652501 2.02
25420500) 1.80
L— 261252521 1.53
73817100 ( 96825500)
36908550 ( 484127501
59145550 ( 26175750)
5.49
309
-------
MAGNESIA SCHEME B
Table A-163
NONRESULATED CO. ECONOMICS, 1000 MM. NEW COAL FIRED POWER PUNT, 3.5 * S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT * 33838000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 9.6%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
-12—
11
12
13
14
-15-
16
17
18
19
22
21
22
23
24
25
26
27
28
29
-32 .
ANNUAL
OPF RA-
TION,
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
-1222
5000
5000
5000
5000
3500
3500
3500
1500
2522
1500
1500
1500
1500
1522
1500
1500
1500
1500
- -1522 -
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100S5
H2S04
213500
213500
213500
213500
213500
213500
213500
213500
152500
152500
152500
152500
106800
106800
106800
106800
126222
45800
45800
45800
45800
45822
45800
45800
45800
45800
. --.45222
TOTAL
MFG.
COST,
S/YEAR
9657200
9657200
9657200
9657200
2652222
9657200
9657200
9657200
9657200
4943300
4943300
4943300
4943300
3893900
3893900
3893900
3893900
- 2223222
2359100
2359100
2359100
2359100
2359100
2359100
2359100
2359100
2359100
235212D -
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHFMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
S/YEAR
11082800 (
10892700 1
10702700 (
10512600 (
12322522 1
10132500 <
9942400 (
9752300 (
9562200
2222222
8236300 (
8046200 (
7856200 (
7666100 (
2426222 1
6530600 (
6340600 (
6150500 (
5960400 (
5222422-1 -
4451700 1
4261600 (
4071600 (
3881500 (
3621422-1
3501300 (
3311300 (
3121200 (
2931100 (
2241122-1— -
NET MFG. COST,
WITH
PAYMENT
1425600)
1235500)
1045500)
855400)
6653221
475300)
285200)
951001
95000
285222
3293000)
3102900)
2912900)
2722800)
25322221
2636700)
2446700)
2256600)
2066500)
—18265221
2092600)
19025001
1712500)
1522400)
-13323221
1142200)
952200)
7621001
572000)
. 3222221
S/YEAR
WITHOUT
PAYMENT
9657200
9657200
9657200
9657200
2652222-
9657200
9657200
9657200
9657200
—2652222-
4943300
4943300
4943300
4943300
4243322
3893900
3893900
3893900
3893900
. 2223222.
2359100
2359100
2359100
2359100
2352122.
2359100
2359100
2359100
2359100
2252122.
NFT REVENUE
100*
H2S04
8.00
8.00
8.00
8.00
.3*22
8.00
8.00
8.00
8.00
8*22
5.00
5.00
5.00
5.00
5.22—
5.00
5.00
5.00
5.00
, TOTAL
REVENUE,
t/YEAR
1708000
1708000
1708000
1708000
1708000
1708000
1708000
1708000
1222200
762500
762500
762500
762500
2625BB —
534000
534000
534000
534000
.5*22 524flQfl—
5.00
5.00
5.00
5.00
5*22—
5.00
5.00
5.00
5.00
-—5*22—
229000
229000
229000
229000
22222B
229000
229000
229000
229000
222Bfla
127500
208272000 I
43923000)
164349000
25852500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
c;
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3133600
2943500
2753500
2563400
23.233.22
6 2183300
7 1993200
8 1803100
9 1613000
_12 1423222—
11 4055500
12 3065400
13 3675400
14 3485300
15 3295200
16
17
18
19
20 _
21
22
23
24
25 .
26
27
28
29
an .
TOT
310
3170700
2980700
2790600
2600500
2412522
2321600
2131500
1941500
1751400
- -1561322
1371200
1181200
991100
801000
611222
7949200)
7949200)
7949200)
7949200)
L 12422221
NET INCOME AFTER TAXES,
»/YEAR
WITH WITHOUT
PAYMENT PAYMENT
ANNUAL RETURN ON
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
S/YEAR S t
WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
1566800 ( 39746001 4950600
1471750 ( 39746001 4855550
1376750 ( 39746001 4760550
1281700 ( 3974600) 4665500
1186650 I 3974600) 4570450
7949200) 1091650 1 3974600) 4475450
7949200) 996600 ( 3974600) 4380400
7949200) 901550 ( 3974600) 4285350
7949200) 806500 ( 3974600) 4190300
L— 22422221 211522— .1 32146221 4225122—
4180800) 2027750 ( 2090400) 2027750
41808001 1932700 ( 2090400) 1932700
4180800) 1837700 1 2090400) 1837700
4180800) 1742650 ( 20904001 1742650
41228.221 1647AOD i 2090400) 1647600
3359900)
33599001
3359900)
3359900)
L 33.522221
2130100)
2130100)
2130100)
2130100)
L 21321221
2130100)
2130100)
2130100)
21301001
L 213210.01
69775500 I 133496500)
1585350 ( 1679950)
1490350 ( 1679950)
1395300 ( 1679950)
1300250 ( 1679950)
1225252 i 16222521
1160800 ( 1065050)
1065750 ( 10650501
970750 I 10650501
875700 ( 1065050)
780650 1 1Q6.525D1
685600 1 1065050)
590600 1 1065050)
495550 ( 1065050)
400500 I 1065050)
. _ 30.5522 _i. 12652521
34887750 ( 69248250)
1585350
1490350
1395300
1300250
1225252
1160800
1065750
970750
875700
18.2652
685600
590600
495550
400500
3.Q5500
590800) 4950600 ( 590800) 4.53
590800) 9806150 ( 1181600) 4.25
590800) 14566700 ( 1772400) 3.98
5908001 19232200 ( 2363200) 3.70
5228.221- 23222652 i 22542221 3*43
590800) 28278100 [ 3544800) 3.15
590800) 32658500 ( 4135600) 2.88
590800) 36943850 ( 47264001 2.60
590800) 41134150 ( 5317200) 2.33
522B221 — 45222452 -1—52282221 2*Bfi
2090400) 47257200 ( 7998400) 5.89
2090400) 49189900 ( 10088800) 5.61
2090400) 51027600 ( 12179200) 5.34
20904001 52770250 ( 142696001 5.06
16799501 56003200 ( 18039950) 4.62
16799501 57493550 ( 19719900) 4.35
1679950) 58888850 ( 21399850) 4.07
1679950) 60189100 ( 230798001 3.79
16222521 61324352—1—242522521 2*52
1065050) 62555150 ( 258248001 3.41
1065050) 63620900 ( 26889850) 3.13
1065050) 64591650 ( 27954900) 2.85
1065050) 65467350 ( 29019950) 2.57
1065050) 66933600 ( 311500501 2.01
10650501 67524200 ( 32215100) 1.73
10650501 68019750 ( 33280150) 1.45
1065050) 68420250 ( 343452001 1.18
68725750 ( 35410250) AVG = 3.41
-------
MAGNESIA SCHEME o,
Table A-164
NONREGULATEO CO. ECONOMICS, 1000 MW. NEW COAL FIRED POWER PLANT, 3.5 % S IN FUEL, 983; H2S04 PRODUCTION.
FIXED INVESTMENT t 33838000
OVERALL INTERFST RATE OF RETURN WITH PAYMENT 17.6*
OVERALL INTERFST RATE OF RETURN WITHOUT PAYMENT ' NFS
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION,
KW-HR/
KW
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
1 7000 213500
2 7000 213500
3 7000 213500
4 7000 213500
5 1QQ2- - 21352Q
6 7000
7 7000
8 7000
9 7000
1C IflflQ
11
12
13
1*.
-15
5000
5000
5000
5000
- 5220 _
213500
213500
213500
213500
2135Q2-
152500
152500
152500
152500
152502
16 3500 106800
17 2500 106800
18 3500 106800
19 3500 106800
-20 — 35QQ —106202
21
22
23
24
-25
26
27
28
29
-3.0.
1500
1500
1500
1500
- 1500 _ .
1500
1500
1500
1500
. 15.QQ
TOTAL
MFG.
COST,
t/YEAR
9657200
9657200
9657200
9657200
26522QO--
9657200
9657200
9657200
9657200
26522QQ
4943300
4943300
4943300
4943300
4243302
3893900
3893900
3893900
3893900
3flS3.aQU
45800 2359100
45300 2359100
45800 2359100
45800 2359100
— - -45B22 _ _23521QQ
45800
45800
45800
45800
. — 45fiQQ
2359100
2359100
2359100
2359100
2353100--
ALTERNATIVF
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
$/YEAR
15208800 (
15053700 (
14898600 I
14743500 (
- - 145Ba4.QQ 1
1-4433200 (
14278100 (
14123000 1
13967900 1
13812£QQ 1
11154900 (
10999800 (
10844700 (
10689600 <
1Q5345QO 1
8458700 (
8303600 (
8148500 (
7993400 (
2838300 i
5007900 (
4852800 (
4697700 (
4542500 (
-4382400 i
4232300 (
4077200 {
3922100 (
3767000 (
3611222-1—-
NET
WITH
PAYMENT
5551600)
53965001
52414001
5086300)
42312221
4776000)
4620900)
4465800)
4310700)
41556001
6211600)
60565001
59014001
5746300)
55212QQ1
45648001
4409700)
4254600)
4099500)
32444001
2648800)
2493700)
2338600)
2183400)
20283001
1873200)
1718100)
1563000)
1407900)
- 12528001
MFG. COST,
t/YEAR
WITHOUT
PAYMENT
965T200
9657200
9657200
9657200
2652200
9657200
9657200
9657200
9657200
2652202
4943300
4943300
4943300
4943300
42433QQ
3893900
3893900
3893900
3893900
3B232QQ
2359100
2359100
2359100
2359100
23521QO
2359100
2359100
2359100
2359100
2352120 —
NET REVENUE,
J/TON
100?
H2S04
8.00
8.00
8.00
8.00
a*QQ
8.00
8.00
8.00
8.00
a»22
5.00
5.00
5.00
5.00
5.QD
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5*QO
5.00
5.00
5.00
5.00
5*QO
TOTAL
NET
SALES
REVENUE,
t/YEAR
1708000
1708000
1708000
1708000
-17.0800.0
1708000
1708000
1708000
1708000
I22a222
762500
762500
762500
762500
262522
534000
534000
534000
534000
534Q2Q -_
229000
229000
229000
229000
_ 222000
229000
229000
229000
229000
2.22222
164349000
283172800 I 118823800)
YEARS REQUIRED FDR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
_iO_
GROSS INCOME,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
7259600
7104500
6949400
6794300
66322QQ
6484000
6328900
6173800
6018700
5363.600
(
(
(
(
1
I
(
(
(
1
6974100 (
6019000 (
6663900 (
6508800 (
63522QQ— i.
5098800 (
4943700 (
4788600 1
4633500 (
4423422 I
2877800
2722700
2567600
2412400
2252300
2102200
1947100
1792000
1636900
14.81802—
(
I
(
(
f
(
(
(
(
1
NFT INCOME AFTFR TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
79492001 3629800
79492001 3552250
7949200) 3474700
7949200) 3397150
22422QQ1 33196.QQ
7949200)
79492001
7949200)
7949200)
22422QQ1
4180800)
41808001
41808001
4180800)
4iaoaooi
3359900)
3359900)
33599001
3359900)
335220.21
2130100)
21301001
2130100)
2130100)
21321021
2130100)
21301001
21301001
2130100)
21321001
3242000
3164450
3086900
3009350
2231322
3487050
3409500
3331950
3254400
31 76850
2549400
2471850
2394300
2316750
2232202
1438900
1361350
1283800
1206200
112.3650
1051100
973550
896000
818450
14Q2QQ J
CASH FLOW,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3974600) 7013600
3974600) 6936050
39746001 6858500
3974600) 6780950
32246221 67.Q34QQ
39T4600)
3974600)
3974600)
3974600)
32246021
2090400)
20904001
2090400)
2090400)
2Q2Q40Q1—
1679950)
1679950)
1679950)
1679950)
16222521
6625800
6548250
6470700
6393150
6315620
3487050
3409500
3331950
3254400
3126S5Q
2549400
2471850
2394300
2316750
2239200
10650501 1438900
1065050) 1361350
1065050) 1283800
1065050) 1206200
1Q65Q5Q1 1128650
1065050)
1065050)
1065050)
10t5050)
L -1Q65Q5Q1—
1051100
973550
896000
818450
24Q9.QQ-
CUMULATIVE CASH FLOW,
$
WITH WITHOUT
PAYMENT PAYMENT
( 590800) 7013600
( 5908001 13949650
( 590800) 20808150
( 590800) 27589100
i 5228001- 3.42S25QQ
( 590800)
( 590800)
I 590800)
( 590800)
i 52aaooi-.
( 2090400)
( 20904001
( 2090400)
( 20904001
i 2Q2Q4QQ1
( 16799501
( 1679950)
( 1679950)
( 1679950)
1 -16222501 -
( 1065050)
( 1065050)
( 1065050)
( 1065050)
1 1Q6505Q1 -
( 1065050)
( 1065050)
( 10650501
( 1065050)
1 126525.21-.
40918300
47466550
53937250
60330400
466.46.0.22
70133050
73542550
76874500
80128900
—33325252—
85855150
88327000
90721300
93038050
.—25222252—
96716150
98077500
99361300
100567500
.-121626152—
102747250
103720800
104616800
105435250
.-126.114150 _
5908001
1181600)
1772400)
2363200)
22542201.
3544800)
4135600)
4726400)
53172001
52232001.
7998400)
10088800)
12179200)
14269600)
143621221
18039950)
19719900)
21399850)
23079800)
— 242522521.
25824800)
268898501
27954900)
29019950)
320350201
ANNUAL RETURN ON
INITIAL INVESTMENT,
«
WITH WITHOUT
PAYMENT PAYMENT
10.49
10.26
10.04
9.82
2*52
9.37
9.14
8.92
8.69
fl»42 .
10.13
9.90
9.68
9.45
2»23
7.44
7.21
6.98
6.76
—6*53
4.22
4.00
3.77
3.54
3*31
31150050) 3.09
32215100) 2.86
332801501 2.63
34345200) 2.40
L—35.4102501 2*12
144676300 ( 136496500)
72338150 ( 69248250) 106176150 ( 35410250)
7.08
31]
-------
Table A-165
MAGNESIA SCHEME 8, NONREGULATED CO. ECONOMICS, 200 MW. NEW OIL FIRED POWER PLANT, 2.5 * S IN FUFL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 6806000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 9.11
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
ANNUAL
OPERA-
T ION,
KW-HR/
KW
7000
7000
7000
7000
?nnn
6 7000
7 7000
8 7000
9 7000
-1Q 2222—
11 5000
12 5000
13 5000
14 5000
15 5nno
16
17
18
19
22
21
22
23
24
25
3500
3500
3500
3500
3522
1500
1500
1500
1500
1500
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
24100
24100
24100
24100
24100
24100
24100
24100
24100
24.1QP ;
17200
17200
17200
17200
_ _ --12222
12000
12000
12000
12000
12000
5200
5200
5200
5200
5200
TOTAL
MFG.
COST,
i/YEAR
2039700
2039700
2039700
2039700
223.22flfl
2039700
2039700
2039700
2039700
£03230.2
1100200
1100200
1100200
1100200
1122222
888800
888800
388800
388800
flflflaQQ
562400
562400
562400
562400
5624QO
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
2429700 (
2390200 (
2350700 (
2311100 (
22.7.1622 X
2232100 (
2192600 1
2153100 (
2113500 (
2224222 I
1826600 (
1767100 (
1747600 (
1708000 (
1668522 i
1459000 (
1419500 (
1380000 (
1340400 (
1322222 i
997500 (
953000 (
918500 I
378900 (
339400 i
26 1500 5200 562400 799900 (
27 1500 5200 562400 760400 (
28 1500 5200 562400 720900 (
29 1500 5200 562400 681300 (
M 1522 - _ 5222 5424.0.0. 641322-1. _
NET MFG. COST,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
390000)
3505001
311000)
271400)
2312221
192400)
152900)
1134001
73800)
3.4.322.1
726400)
6869001
647400)
6078001
5623.221
5702001
530700)
4912001
451600)
4121221
435100)
395600)
3561001
316500)
21I22Q1
237500)
198000)
158500)
118900)
-2242.fl.L-
2039700
2039700
2039700
2039700
2222122-
2039700
2039700
2039700
2039700
2232222
1100200
1100200
1100200
1100200
1122222
888800
888800
888800
838800
fi.flB.a2Q.
562400
562400
562400
562400
562422
562400
562400
562400
562400
562422
NET REVENUE,
I/TON
100Z
H2S04
8.00
8.00
8.00
8.00
. a*22 .
8.00
8.00
8.00
8.00
. - a*22
5.00
5.00
5.00
5.00
5*22—-
5.00
5.00
5.00
5.00
-5*22-
5.00
5.00
5.00
5.00
-5*22-
5.00
5.00
5.00
5.00
— 5*22—
THTAL
NET
SALES
REVENUE,
t/YEAR
192800
192800
192800
192800
-122B.22--
192800
192800
192800
192800
-122E22 .
86000
86000
86000
86000
36222...
60000
60000
60000
60000
6222Q-
26000
26000
26000
26000
2622Q
26000
26000
26000
26000
26222 .-
46352800 (
2918000
YEARS REOUIREO FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
GROSS INCOME,
$/YEAR
NET INCOME AFTER TAXES,
t/YEAR
CASH FLOW,
t/YEAR
CUMULATIVE CASH FLOW,
ANNUAL RETURN ON
INITIAL INVESTMENT,
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1 582800
2 543300
3 503800
4 464200
_5 424222
6
7
8
9
in
11
12
13
14
15
16
17
18
19
?Q
21
22
23
24
_Z5._
26
27
28
29
in
TOT
312
385200
345700
306200
266600
-221122 -
812400
772900
733400
693800
6543.22
630200
590700
551200
511600
422122—
461100
421600
382100
342500
223222
263500
224000
184500
144900
125422— J
13304800
1846900)
1846900)
1846900)
1346900)
_ 1B462221 _
1846900)
1846900)
18469001
1846900)
L_ 1B462221-
1014200)
1014200)
1014200)
1014200)
_ 12142221 _
828800)
828800)
828800)
828800)
a2flB221_
536400)
536400)
5364001
536400)
5364221
5364001
5364001
536400)
5364001
L 5364221
330480001
WITH
PAYMENT
291400 (
271650 (
251900 (
232100 (
- -212352__l-_
192600
172850
153100
133300
113552-
406200
336450
366700
346900
327150
WITHOUT
PAYMENT
923450)
923450)
923450)
9234501
2234521
WITH
PAYMENT
972000 (
952250 (
932500 (
912700 (
. -E22252 _i
WITHOUT
PAYMENT
2428501
242850)
242850)
242850)
242B.521
< 923450) 873200 ( 242850)
( 923450) 853450 ( 2423501
1 923450) 833700 ( 2428501
( 923450) 813900 ( 242850)
-i 2234521 224152 .i _ 2423521
I 507100) 406200 ( 5071001
I 507100) 386450 ( 507100)
( 507100) 366700 < 507100)
( 507100) 346900 ( 507100)
1 5071001 327150 1 5r>7inr>l
315100 (
295350 (
275600 (
255800 (
216252 -1 _
230550 (
210300
191050
171250
151500
131750
112000
92250
72450
52Z22 L—
6652400 (
4144001
414400)
414400)
414400)
-4144221
268200)
268200)
2682001
2682001
2632221
315100 (
295350 1
275600 (
255800 1
-226Q52 i
230550 (
210800 (
191050 (
171250 (
151522 i
WITH
PAYMENT
972000
1924250
2356750
3769450
4662422
5535600
6389050
7222750
8036650
.aai2a22.
9237000
9623450
9990150
10337050
(
(
(
(
(
(
(
(
(
(
(
(
(
(
414400) 10979300 (
4144001 11274650 (
414400) 11550250 (
4144001 11806050 (
4144221 12242122—i.
2682001 12272650 (
2682001 12483450 (
2682001 12674500 (
2682001 12845750 (
268200) l?99775n i
268200) 131750 ( 268200) 13129000 (
268200) 112000 ( 268200) 13241000 (
268200) 92250 ( 268200) 13333250 (
268200) 72450 ( 2632001 13405700 (
_26a2Q21 52222—1 26B22Q1 13453122— i_
165240001 13458400 ( 9718000)
WITHOUT
PAYMENT
242850)
485700)
7235501
9714001
12142521
1457100)
1699950)
1942800)
2185650)
24215221
29356001
3442700)
3949800)
4456900)
5378400)
57928001
62072001
6621600)
7304200)
75724001
78406001
81 088001
8645230)
8913400)
9181600)
9449800)
- 221B2221-
AVG
WITH WITHOUT
PAYMENT PAYMENT
4.18
3.90
3.61
3.33
3*25
2.76
2.48
2.20
1.91
1*6.3.
5.86
5.57
5.29
5.00
— 4*12
4.56
4.28
3.99
3.70
3.36
3.07
2.78
2.49
1.92
1.63
1.34
1.06
- 2*22
= 3.23
-------
Table A-166
MAGNESIA SCHEME B, MONREGULATEO CO. ECONOMICS, 200 MM. NEW OIL FIRED POWER PLANT, 2.5 * S IN FUEL, 98T H2S04 P°onilCT I ON,
FtXFD INVESTMFNT t 6806000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.1?
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_ 5- .
6
7
8
9
11
12
13
15 .
16
17
18
19
-20 .
21
22
24
25 -
26
27
28
29
30 .
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2QQQ__
7000
7000
7000
7000
2000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
- - 1500-
1500
1500
1500
1500
- - 1500
PRODUCT RATE,
EQUIVALENT
TONS/YEAR TOTAL
MFG.
100% COST,
H2S04 4/YEAR
24100
24100
24100
24100
24100
24100
24100
24100
24100
- 24100
17200
17200
17200
17200
12200
2039700
2039700
2039700
2039700
_ 2022200
2039700
2039700
2039700
2039700
_2033200 .
1100200
1100200
1100200
1100200
1100200 .
12000 888800
12000 888800
12000 888800
12000 888800
12000- BflflBOQ .
5200
5200
5200
5200
- 5200
5200
5200
5200
5200
52QQ-
562400
562400
562400
562400
562400
562400
562400
562400
562400
ALTERNATIVE
NONRECOVFRY
WET-LIMESTONE
PROCESS COST
AS PAYMFNT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YFAR
2514300 (
2483200 1
2452000 (
2420900 (
23B2200 i
2358600 (
2327400 (
2296200 (
2265100 (
2222300 1
1875000 (
1843800 (
1812600 (
1781500 (
1250300 i
1460900 (
1429700 (
1398600 (
1367400 I
1226200 1
927600 (
896400 (
865300 (
834100 I
B023QQ L
771800 (
740600 (
709500 1
678300 1
64J2QQ 1
NFT
WITH
PAYMENT
474600)
443500)
4123001
3812001
3500001
318900)
287700)
2565001
225400)
1242QQ1
7748001
743600)
712400)
6813001
6501001
5721001
5409001
509800)
478600)
4424001
365230)
334033)
302900)
2717001
24Q5Q01
209400]
178200)
1471001
115900)
_-fl4flD.Ql
MFG. COST,
t/YFAB
WITHOUT
PAYMENT
2039700
2039700
2039700
2039700
2022100
2039700
2039700
2039700
2039700
2022200
1100200
1100200
1100200
1100200
1100200
888800
888800
888800
883300
BSflflQQ
562400
562400
562400
562400
562400
562400
562400
562400
562400
562400
NFT REVENUE,
t/THN
H2S04
3.00
8.00
8.00
8.00
BxQQ
3.00
8.00
8.00
8.00
BxQQ
5.00
5.00
5.00
5.00
5x00
5.00
5.00
5.00
5.00
5xQQ
5. no
5.00
5.30
5. no
5xDD
5.00
5.00
5.00
5. on
5xQQ -- _ .
TOTAL
NFT
S1LFS
t/YFAR
19?800
192300
197300
197300
192BQQ
192800
192100
197300
19280n
122200
86000
86000
1)6000
36000
36202
60300
60000
60003
60903
6.3.QQQ
76000
26000
26300
26000
26000
26000
26000
'6003
26300
. . 263QO -.
47671000 (
35966000
YEARS REQUIRED FOR PAYOUT WITH PAYMFNT:
NO PAYOUT WITHOUT PAYMFNT
YEARS
AFTER
POWER
GROSS INCOME,
t/YEAU
NFT INCOME AFTER TAXES,
t/YEAR
CASH FLOW,
t/YEAR
CUMULATIVF "ASH FLPW,
$
ANNUAL RFTUON ON
INITIAL INVESTMENT,
UNIT WITH WITHOUT
START PAYMFNT PAYMENT
1
2
3
4
5
6
7
8
9
10
11
12
13
14
1 5
16
17
18
19
20.
21
22
23
24
-25
26
27
28
29
30
667400 (
636300 (
605100 (
574030 (
542BOQ i
511700 (
480500 (
449300 (
418200 (
3S2QQO I
860800 (
829600 (
798400 (
767300 (
126100 1
632100 (
&00900 (
569800 (
538600 (
502400 I
391200 (
360000 I
328900 1
297700 I
266500 i
235400 (
204200 (
173100 I
141900 (
110BOO 1 .
WITH HTTHOUT
PAYMENT PAYMENT
1846900) 333700 ( 9234501
1846900) 318150 ( 923450)
1846900) 302550 1 923450)
1846900) 287000 ( 923450)
1B469D.O) ?714.Q9 1 923450)
18469001 255850 ( 9234501
1846900) 240250 ( 923450)
1846900) 224650 ( 923450)
18469001 209100 ( 9234501
13462001 193500 I 9P3450I
1014200)
1014200)
1014200]
1014200)
10142001
828800)
828800)
828800)
828800)
fl2BB001
536400)
536400)
536400)
536400)
5264001
430400 ( 507100)
414800 ( 507100)
399200 ( 507100)
383650 ( 507100)
3.6,8050 ( 5011001
316050 ( 4144001
300450 ( 4144001
284900 ( 4144001
269300 I 414400)
252200 I 4144001
195600 ( 268200]
180000 1 2682001
164450 ( 26B200I
148850 ( 2682001
133750 ( 76370D 1
5364001 117700 I 268200)
5364001 102100 ( 268200)
5364001 86550 1 268200]
5364001 70950 ( 2682001
. 5364001 554DJ] I 26.fl.2QQl
WITH
PAYMENT
1014300
998750
983150
967600
252000
936450
920850
905250
889700
H241QO.
430400
414800
399200
383650
26BQ5Q
316050
300450
284900
269300
252200
195600
1BOOOO
164450
148850
12225.0
117700
102100
86550
70950
55400.
WITHOUT
PAYMENT
( 242850)
( 242850)
( 2428501
( 2428501
1 242B5Q1
( 2428501
( 242850)
( 2428501
( 242850)
1 2i2B5Ql
( 507100)
( 5071001
I 5071031
I 5071001
1 5021001
WITH
PAYMENT
1014300 (
2013050 (
2996200 (
3963800 (
4215BOO i
5852250 (
6773100 (
7678350 (
8568050 (
2442150- I
9872550 (
10287350 (
10686550 I
11070700 I
11438250 i
I 4144001 11754300 (
( 4144001 12054750 (
I 4144001 12339650 (
I 4144001 12608950 {
1 4144001 12B6265Q i
( 2682001
( 268200)
( 260200)
( 268200!
i 26B20Q1
13058250 (
13238250 (
13402700 (
13551550 (
136B43QQ 1
WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMFNT
242850)
4837001
7235501
9714001
12142501
14571001
1699950)
1942800)
2185650)
.24235001
29356001
3442730)
39498301
4456900)
42640201
5373400)
5792800)
62072001
66216001
.20260001 _
7304200)
7572400)
7840600)
81033001
-33.ZZQQC1-
{ 2682001 13802500 1 3643230)
( 268200) 13904600 ( 8913400)
( 268200) 13991150 ( 918160C)
( 268200) 14062100 ( 9449830)
. 1 _ 26S2QQ1 14111500 i .221BDQQ1 .
4.79
4.56
4.34
4.12
3.67
3.45
3.22
3.00
2.IS--
6.20
5.98
5.75
5.53
5x21
4.57
4.35
4.12
3.93
3x41
'.85
2.62
2.4"
7. 17
1.71
1.49
1.J6
1.03
QxSl _ . - _
14623000 ( 33048000)
7311500 I 165240001
14117500 (
AVG= 3.55
313
-------
Table A-167
MAGNESIA SCHEME B, NONRFGULATED CO. ECONOMICS, 500 MM. NEW OIL FIRED POWER PLANT, 2.5 J S IN FUEL, 98* H2S04 P"HDUCTI ON.
FIXED INVESTMENT $ 12561000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 10.3%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEG
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
—5
6
7
8
9
11
12
13
14
15
16
17
18
19
22
21
22
23
2*
25
26
27
28
29
32,
ANNUAL
OPERA-
TION,
KH-HR/
KM
7000
7000
7000
7000
— 2222
7000
7000
7000
7000
— 2222
5000
5000
5000
5000
—5.222
3500
3500
3500
3500
3522
1500
1500
1500
1500
I 5.0Q
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
58900
58900
58900
58900
58900
58900
58900
58900
5B222
42100
42100
42100
42100
42120
29400
29400
29400
29400
22422
12600
12600
12600
12600
12600
TOTAL
MFG.
COST,
$/YEAR
3625100
3625100
3625100
3625100
36251QQ
3625100
3625100
3625100
3625100
3625.122
1894600
1894600
1894600
1894600
1894600
1514100
1514100
1514100
1514100
1514122
941100
941100
941100
941100
941100
ALTERNATIVE
NONRECOVFRY
HET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NET
PANY FOR AIR
POLLUTION
CONTROL, WITH
$/YEAR PAYMENT
4454500
4308500
4306400
4232400
4158.322 J
4084300
4010200
3936200
3862100
3JBS122 J
3325700
3251600
3177600
3103500
3222522 J
2642700
2568700
2494600
2420600
23.4.6522-.!
1798300
1724200
1650200
1576100
1SD210D J
1500 12600 9*1100 1428000
1500 12600 941100 1354000
1500 12600 941100 1279900
1500 12600 941100 1205900
1520. - 12622 2411C2 1131822 1
8294001
6834001
6813001
607300)
5332221
459200)
385100)
311100)
237000)
1632221
14311001
13570001
1283000)
12089001
1134.20.21
1128600)
1054600)
9805001
906500)
— - -3324.0.21
857200)
7831001
7091001
6350001
- 5612221
486900)
4129001
3388001
264800)
L 12Q2Q01
MFG. COST,
t/YEAR
WITHOUT
PAYMENT
3625100
3625100
3625100
3625100
3625102
3625100
3625100
3625100
3625100
'625100
1894600
1894600
1894600
1894600
1824620
1514100
1514100
1514100
1514100
1514100 __
941100
941100
941100
941100
241100
NFT REVENUE,
t/TON
100Z
H2S04
8.00
8.00
8.00
3.00
3*0.2
8.00
8.00
8.00
8.00
B. 22
5.00
5.00
5.00
5.00
— -5*02
5.00
5.00
5.00
5.00
-5*00 -_ .
5.00
5.00
5.00
5.00
. 5*22
941100 5.00
941100 5.00
941100 5.00
941100 5.00
241100 - 5*00 - .
TOTAL
NFT
SALES
PEVFNUE,
$/YFAR
471200
471200
471200
471200
-421220
471200
471200
471200
471200
421200
210500
210500
210500
210500
21Q5Q2
147000
147000
147000
147000
142222
63000
63003
63000
63000
_ 62200 —
63000
63000
63000
63000
63000 .
127500
1072500
84152500 (
7129500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO P4YOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_5
D vD CO -g o-
11
12
13
14
_15_
16
17
18
19
22 .
21
22
23
24
25
26
27
28
29
30
TOT
314
GROSS INCOME, NET INCOME AFTER TAXES,
S/YEAR S/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
1300600
1154600
1152500
1078500
1J24422-
(
(
(
(
(
930400 [
856300 1
782300 (
708200 (
6.2420.2 i -
1641600
1567500
1493500
1419400
1345422
1275600
1201600
1127500
1053500
222422
(
(
[
(
(
(
[
(
1
1
3153900)
3153900)
3153900)
3153900)
. 31532Q21
3153900)
3153900)
3153900)
3153900)
- 21532221
1684100)
16841001
1684100)
16841001
. 168410.21
1367100)
13671001
1367100)
1367100)
. 13611QQ1
920200 I B78100I
846100 ( 8781001
772100 ( 878100)
698000 ( 878100)
624222 i 328.1221 -
549900
475900
401800
327800
253222
28576500
I
(
(
I
_i-
(
8781001
878100)
8781001
878100)
. B.2B1QD1 -
55576000)
650300
577300
576250
539250
522222 .
465200
428150
391150
354100
212122-.
820800
783750
746750
709700
6.22Z22-.
637800
600800
563750
526750
48.2220
( 1576950)
( 1576950)
( 1576950)
( 1576950)
-i 15262521-
1 15769501
( 1576950)
( 1576950)
( 1576950)
_i L5262521—
( 84205D)
( 8420501
( 842050)
1 8420501
-i _ E422521
I 6835501
1 683550)
( 6835501
( 683550)
_i 6.3.35501
460100 1 4390501
423050 ( 4390501
386050 I 439050)
349000 I 439050)
312220. i 4320.521
274950
237950
200900
163900
1268.52
14288250
( 439050)
( 4390501
( 4390501
( 439050)
1 4320.521
( 27788000)
CASH FLOW,
t/YFAR
WITH WITHOUT
PAYMENT PAYMENT
1906400
1833400
1832350
1795350
1258.322
1721300
1684250
1647250
1610200
-1523222
820800
783750
746750
709700
612200-
637800
600800
563750
526750
-482200
(
(
1
(
(
(
I
(
(
1
(
(
(
(
1
(
(
(
(
I
320850)
3203501
320350)
320850)
- 3228.521- -
320850)
320850)
3208501
320R50I
-- 2228.521
8420501
8420501
8420501
8420501
S4205Q1
6835501
683550)
6835501
683550)
683550)
460100 ( 4390501
423050 ( 439050)
386050 ( 439050)
349000 ( 439050)
212220— i 4222501—
274950 ( 439050)
237950 ( 439050)
200900 ( 4390501
163900 ( 439050)
126.850 ' 439050 i
26849250
(
15227000)
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
S J
WITH WITHOUT «ITH WITHOJT
PAYMENT PAYMENT PAYMENT PAYMENT
1906400 ( 320850)
3739800 ( 641700)
5572150 [ 9625501
7367500 ( 1283400)
- 21258.02 I UQ42?0)
10847100
12531350
14178600
15788800
-1226200.2-
18182800
18966550
19713300
20423000
21225220
21733500
22334300
22898050
23424800
-22214500-
24374600
24797650
25183700
25532700
-25B442QQ-
26119650
26357600
26558500
26722400
26.fl4.225Q
( 19251001
< 2245950)
( 2566800]
( ?817650I
I 32235.0.01
I 4050550)
I 48926001
( 57346501
( 6576700)
1 24132521
( 8102300)
( 3785850)
1 94694001
I 10152950)
1 123265001
( 112755501
( 11714600)
( 121536501
( 12592700)
I 120312521
5.06
4.49
4.48
4.?0
3*21
3.62
3.33
3.04
2.76
2*42
6.42
6.13
5.84
5.55
-5*26
5.01
4.7?
4.4'
4.14
^*85
3.64
3. ^4
3.05
2.76
?.47
( 13470300) 2.17
( 139098501 l.Bfl
1 14348900) 1.59
( 14787950) 1.30
.-1—152222021 1*00
AVG= 5.76
-------
MAGNESIA SCHEME B, NONREGULATED CO. ECONOMICS,
Table A-168
500 MW. NEM OIL FIRED POWER PLANT, 2.5
t
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
S IN FUFL, 98* H2SH4 PRODUCTION.
12561000
13.5*
NEG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
— 5.
6
7
8
9
10
ANNUAL
OPERA-
TION,
KW-HR/
KW
rooo
7000
7000
7000
2000
7000
7000
7000
7000
IDQO
11 5000
12 5000
13 5000
14 5000
-15. 5202
16 3500
17 3500
18 3500
19 3500
20 350D
21
22
23
24
25.
26
27
28
29
20.
1500
1500
1500
1500
-1500
1500
1500
1500
1500
_ 150.0.
PRODUCT RATE,
EQUIVALENT
TOMS/YEAR
100*
H2S04
TOTAL
MFG.
COST,
*/YEAR
58900 3625100
58900 3625100
58900 3625100
58900 3625100
52200 3625100
58900
58900
58900
58900
52222
42100
42100
42100
42100
42100
29400
29400
29400
29400
29400
12600
12600
12600
12600
_ 12620
12600
12600
12600
12600
- - 126.2C _-
3625100
3625100
3625100
3625100
2623100
1894600
1894600
1894600
1894600
1224.6flfl_ .
1514100
1514100
1514100
1514100
L5.14.lflC
941100
941100
941100
941100
941100
941100
941100
9*1100
941100
941100
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
J/YEAR
5015800 (
4955600 I
4895400 (
4835200 I
4.125.20.0. i
4714800 <
4654600 (
4594400 I
4534200 I
-4.4.7.4.000-1
3712000 (
3651800 (
3591600 (
3531400 (
. 2421200 1
2865100 (
2804900 (
2744700 (
2684600 (
2624420-1
1783400 (
1723200 1
1663000 (
1602800 (
1542600-1
1482400 I
1422200 (
1362000 (
1301800 (
. -124.160.0 i -
NET
WITH
PAYMENT
1390700)
1330500)
1270300)
1210100)
11422001
1089700)
1029500)
969300)
909100)
- 3422021
18174001
1757200)
16970001
16368001
15.26.6001
1351000)
1290800)
1230600)
11 705001
11122001
842300)
7821001
7219001
661700)
6.215.00.1
5413001
481100)
420900)
3607001
— 3005021
MFG. COST,
$/Yf AR
WITHOUT
PAYMENT
3625100
3625100
3625100
3625100
1625100
3625100
3625100
3625100
3625100
3625100
1894600
1894600
1894600
1894600
12246.02
1514100
1514100
1514100
1514100
1514100
941100
941100
941100
941100
241122-
941100
941100
941100
941100
.— _. 241100
NFT PEVFNUE,
S/THN
100?
H2S04
8.00
8.00
8.00
S.OO
8.00
8.00
8.00
8.00
a*2C
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
5*00
5.00
5.00
5.00
5.00
_ -5*00 -
5.00
5.00
5.00
5.00
-- - 5*00 -
TOTAL
NTT
SHIES
REVEMUC,
S/YFAR
471200
471200
471200
471200
---421200...
471200
471200
471200
471200
4212.QQ
210500
210500
210500
210503
210502
147000
147000
147000
147000
141000
63000
63000
( 3000
63000
62000
63000
'3000
63000
6?000
62020
62705500
94255700 (
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
AFTER $/YEAR S/YEAR $/YEAR $ 11
POWER
UNIT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHDUT WITH WITHnyT
START PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMFNT P(lYufSIT
1 1861900
2 1801700
3 1741500
4 1681300
5 -1621100
6 1560900
7 1500700
8 1440500
9 1380300
-lfl_ 13.22100—
11 2027900
12 1967700
13 1907500
14 1847300
-15 122Z122
16 1498000
17 1437800
18 1377600
19 1317500
-22 1252220—
21 905300
22 845100
23 784900
24 724700
-25 664500—
26 604300
27 544100
28 483900
29. 423700
_22_ 262520 i
31539001 930950 1 1576950) 2187050 ( 320850) 2187050 ( 320850) 7.24
31539001 900850 ( 1576950) 2156950 [ 3208501 4344000 ( 6417301 7.01
3153900) 870750 ( 1576950) 2126850 ( 320850) 6470850 ( 96?550) 6.73
3153900) 840650 ( 15769501 2096750 ( 3208501 8567600 1 12834001 fj.54
3153900) 810.550 i 15769501 2066650 ( 320850) 10634250 1 1604250) 6.31
3153900) 780450 ( 1576950) 2036550 I 3208501 12670800 ( 1925130) 6.07
3153900) 750350 t 1576950) 2006450 1 320850) 14677250 ( 2245950) 5.R4
3153900) 720250 ( 15769501 1976350 ( 320850) 16653600 ( 25668001 5.60
3153900) 690150 ( 1576950) 1946250 1 3208501 18599850 I 28876501 5.37
_ 21522021 642fl5Q i 15262301 1216152- 1 2202521 22516222 _I 22025001. - 5*14
1684100) 1013950 ( 842050) 1013950 ( 842050) 21529950 ( 4350550] 7.93
16841001 983850 ( 842050) 983850 ( 8420501 22513800 ( 4R92600) 7.69
16841001 953750 I 842050) 953750 1 842050) 23467550 ( 5734650] 7.46
16841001 923650 I 842050) 923650 ( 8420501 24391200 ( 65767001 7.22
162410.21 232552 I 242050.1 222550 i 2420521 25224250 _i 24132521 fi*29
1367100) 749000 ( 683550) 749000 ( 6835501 26033750 ( 8102300] 5.88
1367100) 718900 ( 683550) 718900 ( 6835501 26752650 ( 87B5850I 5.65
1367100) 688800 ( 6835501 688800 I 683550) 27441450 1 9469400] 5.41
1367100) 658750 ( 6835501 653750 ( 6835501 28100200 ( J0152950I 5.17
12621201 622650 i 6225501 622650 1 -6225501 22222252 l_-lQa265201-_ 4*24 _
8781001 452650 1 439050) 452650 ( 4390501 29181500 ( 11275550) 3.58
878100) 422550 I 439050) 422550 ( 439050) 29604050 ( 11714600) 3.34
878100) 392450 ( 439050) 392450 ( 439050) 29996500 ( 12153650) 3.10
878100) 362350 1 439050] 362350 ( 439050) 30358850 ( 12592700) 2.B6
2221201 222252 i 4222501 222250 1 - 4220521 20621120 i. 122212521 2*63.
878100) 302150 ( 439050) 302150 ( 439050) 30993250 ( 13470800) 2.39
878100) 272050 I 439050) 272050 ( 439050) 31265300 ( 13900850) ?.15
8781001 241950 ( 439050) 241950 [ 4390501 31507250 ( 14343900] 1.91
878100) 211850 ( 439050) 211850 ( 439050) 31719100 ( 14787950) 1.67
878100) 181750 1 4390501 18115.0. I 422Q5Q1 21200250 1 15222QQQ1 1*44
TOT 38679700 ( 55576000) 19339850 ( 27788000) 31900850 ( 15227000) AVG= 5.09
315
-------
Table A-1 69
MAGNESIA SCHEME 8, NONREGUL ATED CO. ECONOMICS, 1000 HH. NEW OIL FIRED POWER PLANT, 2.5
$
S IN FUEL, 98? H2SO*, PRODUCTION.
FIXED INVESTMENT $ 19126000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 11.5*
OVFRALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC-
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
in
11
12
13
15
16
17
18
19
22
21
22
23
24
-25
26
27
28
29
ANNUAL
OPERA-
TION,
K.W-HR/
KW
7000
7000
7000
7000
2022
7000
7000
7000
7000
2200
5000
5000
5000
5000
5QQQ
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
113900
113900
113900
113900
113300
113900
113900
113900
113900
113202^
81300
81300
81300
81300
81300
56900
56900
56900
56900
56222
24400
24400
24400
24400
24400
1500 24400
1500 24400
1500 24400
1500 24400
1522- — —24400
TOTAL
MFG.
COST,
$/YEAR
5477000
5477000
5477000
5477000
5422200
5477000
5477000
5477000
5477000
5422022
2819200
2819200
2819200
2819200
2819200
2229100
2229100
2229100
2229100
2222100
1360300
1360300
1360300
1360300
U 6.0320
1360300
1360300
1360300
1360300
ALTERNATIVE
NONRECOVERY
WET-LIMESTONF
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
$/YEAR
6890400 (
6775100 (
6659800 (
6544500 (
6422320 1
6314000 (
6198700 I
6083400 (
5968100 1
5252BQQ i
5120700 (
5005400 (
4890100 (
4774800 {
4652520 i
4052800 (
3937500 (
3822200 (
3706900 1
3521600 i
2745400 (
2630100 (
2514900 (
2399600 (
2224300 i_
2169000 (
2053700 (
1938400 I
1823100 (
-1202800 i
NET MFG. COST,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1413400)
1298100)
1182800)
1067500)
2523021
837000)
721700)
606400)
491100)
3252021
2301500)
2186200)
20709001
1955600)
124.23QQ1
1823700)
1708400)
15931001
14778001
13625221
1385100)
1269800)
1154600)
1039300)
2242221
808700)
693400)
5781001
4628001
—3425021
5477000
5477000
5477000
5477000
5422002-
5477000
5477000
5477000
5477000
5422022 -
2819200
2819200
2819200
2819200
2212222
2229100
2229100
2229100
2229100
-2222102
1360300
1360300
1360300
1360300
136Q3QQ -
1360300
1360300
1360300
1360300
136Q2QQ
NFT REVENUE,
I/TON
100%
H2S04
8.00
8.00
8.00
8.00
. . 2x00-
8.00
B.OO
8.00
3.00
BxQC
5.00
5.00
5.00
5.00
5x22
5.00
5.00
5.00
5.00
5x02
5.00
5.00
5.00
5.00
5x22
5.00
5.00
5.00
5.00
- _ -5x20
TOTAL
NFT
SALES
REVENUE,
$/YcAR
911200
911200
911200
911200
211200 —
911200
911200
911200
911200
211202—
406500
406500
406500
406500
4Q65QQ
234500
284500
284500
2B4500
224502
122000
122000
122000
122000
1222QQ — .
122000
122000
122000
12?000
122Q2Q- -
2074000
129543900 I
93614500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT: 6.6
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWFR
UNIT
START
1
2
3
4
5
6
7
8
9
10
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2324600 ( 4565800)
2209300 ( 45658001
2094000 ( 4565800)
1978700 ( 4565800)
1263500 1 45658.221
1748200 I 4565800)
1632900 ( 45658001
1517600 ( 4565800)
1402300 ( 45658001
1PS7000 ( 45658001
11 2708000 ( 24127001
12 2592700 ( 2412700)
13 2477400 ( 2412700)
14 2362100 ( 24127001
15 2246800 i 24122021
16
17
18
19
20
21
22
23
24
25
26
27
28
29
3.P
TOT
316
2103200 ( 19446001
1992900 ( 19446001
1877600 ( 19446001
1762300 ( 19446001
1642QQQ i 12446001
1507100 ( 12383001
1391800 1 12383001
1276600 ! 12383001
1161300 ( 12383001
_1246QQQ i 122B.3Q21
930700 ( 1238300)
815400 I 1238300)
700100 I 1238300)
584800 ( 1238300)
46252Q 1 12323221-
49716400 I 798275001
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1162300 1 2282900)
1104650 1 2282900)
1047000 1 22829001
989350 ( 22829001
_ 23i250-_x -228.22001 .
874100
816450
758800
701150
6.4350.2 _
1354000
1296350
1238700
1181050
1123422-
1054100
996450
938800
881150
223500
753550
695900
638300
580650
523002
465350
407700
350050
292400
234252 i
2282900)
2282900)
2282900)
22829001
-22222001
1206350)
1206350)
1206350)
1206350)
-12263501 .
972300)
972300)
972300)
972300)
2223201-
619150)
619150)
619150)
619150)
6121521-.
619150)
6191501
619150)
619150)
L 6131501 .
24858200 ( 399137501
CASH FLOW, CUMULATIVE CASH FLOW,
t/YEAR $
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
3074900
3017250
2959600
2901950
._ 2244352
2786700
2729050
2671400
2613750
2556122—
1354000
1296350
1238700
1181050
1123400
1054100
996450
938800
881150
22.3500
753550
695900
638300
580650
523022-
465350
407700
350050
292400
234250
3703001 3074900 ( 3703001
3703001 6092150 ( 7406001
370300) 9051750 ( 11109001
370300) 11953700 ( 1481200)
_ -3203221 14228.25.2 i- -13515021
3703001 17584750 ( 2221800)
370300) 20313800 ( 2592100)
370300) 22985200 ( 2962400)
3703001 25598950 C 33327001
3203001 2fl.15.5Q5Q 1 31Q3QQQ1
1206350) 29509050 I 4909350)
1206350) 30805400 I 6115700)
1206350) 32044100 ( 7322050)
12063501 33225150 ( 85284001
12Q625.Q1 - 34343550 1 22342501
972300) 35402650 < 107070501
972300) 36399100 1 116793501
9723001 37337900 ( 126516501
9723001 38219050 ( 136239501
2223021 3.2Q4255Q I 14526.2501
6191501 39796100 ( 15215400)
6191501 40492000 ( 15834550)
6191501 41130300 ( 16453730)
6191501 41710950 ( 17072850)
61215Q1 42231252 1 1I622Q221
6191501 42699300 ( 183111501
619150) 43107000 ( 189303001
6191501 43457050 ( 19549450)
619150) 43749450 I 20168600)
L 619150) 43984200 I 20787750)
43984200 I 20787750) AVf
INITIAL INVESTMENT,
*
WITH WITHO'JT
PAYMF\'T PAYMENT
5.94
5.65
5.35
5.06
4x26
4.47
4.17
3.88
3. 58
— 3x22
6.96
6.66
6.36
6.07
5x12
5.44
5.14
4.B4
4.55
. — 4x25
3.91
3.61
3.31
3.01
2x22
2.42
2.12
1.02
1.5?
1x22
4.30
-------
Table A-170
MAGNESIA SCHEME B, NONREGULATED CO. ECONOMICS, 1000 MW. NEW OIL FIRED POWER PLANT, 2.5
t
S IN FUEL, 9 HI H2S04 PRODUCTION.
FIXED INVESTMENT t 19126000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 16.2?
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NFG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS ANNUAL
AFTER OPFRA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
_5
6
7
8
9
-12
11
12
13
14
15.
16
17
18
19
22_
21
22
23
24
25
26
27
28
29
in
7000
7000
7000
7000
2200
7000
7000
7000
7000
-1200-
5000
5000
5000
5000
5000
3500
3500
3500
3500
3502 _
1500
1500
1500
1500
1500
1500
1500
1500
1500
1522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
113900
113900
113900
113900
112200
113900
113900
113900
113900
113220
81300
81300
81300
81300
B.13.0Q
56900
56900
56900
56900
. 56222
24400
24400
24400
24400
24422
24400
24400
24400
24400
24.42Q-
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
TOTAL PANY FOR AIR
MFG. POLLUTION
COST, CONTROL,
$/YEAR WYEAR
5477000
5477000
5477000
5477000
5.477POO
5477000
5477000
5477000
5477000
5422202-
2819200
2819200
2819200
2819200
2819200
2229100
2229100
2229100
2229100
2222122 .
1360300
1360300
1360300
1360300
13.6Q3.flfl
1360300
1360300
1360300
1360300
13623.211 _-.
8261100 (
8166900 (
8072700 (
7978500 (
28.34.3.1)2 I
7790200 (
7696000 (
7601800 (
7507600 I
1411420-1 -
6082300 (
5988200 I
5894000 (
5799800 (
510.5.6.0.0. i
4656200 (
4562000 1
4467900 (
4373700 (
- 4222522-1 -.
2840700 (
2746500 1
2652400 (
2558200 (
-246.40.0.0. 1
2369800 I
2275600 I
2181400 (
2087300 1
122110.0. 1 .
NET MFG. COST,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2784100)
26899001
25957001
2501500)
24223221
23132001
22190001
2124800)
20306001
123.64001
3263100)
3169000)
3074800)
2980600)
28.8.640.21
2427100)
2332900)
2233800)
2144600)
. 20504001 - .
14804001
1386200)
12921001
1197900)
11032001 —
1009500)
915300)
821100)
7270001
6.3.220.0.1
5477000
5477000
5477000
5477000
54ZZ22Q
5477000
5477000
5477000
5477000
5422220-
2819200
2819200
2819200
2819200
28.1220.0.
2229100
2229100
2229100
2229100
22221QQ _ -.
1360300
1360300
1360300
1360300
13.60302
1360300
1360300
1360300
1360300
126Q3QQ . .
NET RFVFNUE,
t/TON
100%
H2S04
8.00
8.00
8.00
8.00
a*.QQ
8.00
8.00
8.00
8.00
. 8. 00 — _ .
5.00
5.00
5.00
5.00
5. 1.0,2
5.00
5.00
5.00
5.00
. _ _ 5*00 -
5.00
5.00
5.00
5.00
__ 5*02
5.00
5.00
5.00
5.00
.. -- 5»OQ__ — .
TOTAL
NCT
SALES
OEVENUE,
S/YEAR
911200
911200
911200
911200
-21122Q -
911200
911200
911200
911200
_ _2112QQ -
406^00
406500
406500
406500
4.265QQ
2S4500
2R4500
284500
234500
.- — 234502
122000
122000
122000
122000
1222Q2
122000
122000
122000
122000
. . 122002- _
154350700 (
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL PFTURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
GROSS INCOME,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3695300
3601100
3506900
3412700
221fl5QQ
6 3224400
7 3130200
8 3036000
9 2941800
_1Q 224.Z6QO—
11 3669600
12 3575500
13 3481300
14 3387100
15 2222200
16
17
18
19
-20
21
22
23
24
-25 —
26
27
28
29
-22
2711600
2617400
2523300
2429100
2224202
1602400
1508200
1414100
1319900
1225222
1131500
1037300
943100
849000
—254802 J
45658001
45658001
4565800)
4565800)
45658.221-
45658001
4565800)
45658001
4565800)
45652001-
2412700)
2412700)
24127001
2412700)
24122021
1944600]
1944600)
1944600)
1944600)
12446201
1238300)
1238300)
1238300)
1238300)
122fl2Q01_
1238300)
1238300)
1238300)
1238300)
.__ 12223021-
NET INCOME AFTER TAXES,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1847650 I 2282900)
1800550 ( 22829001
1753450 < 2282900)
1706350 ( 2282900)
1652252 L 22B22221
1612200 ( 2282900)
1565100 ( 22829001
1518000 ( 2282900)
1470900 1 2282900)
1423BOQ 1 22B2900)
CASH FLOW,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3760250 (
3713150 (
3666050 (
3618950 [
- 35218.50 i -
3524800 (
3477700 (
3430600 (
3383500 (
2336400 1
1834800 1 1206350] 1834800 (
1787750 ( 1206350) 1787750 (
1740650 ( 1206350) 1740650 (
1693550 ( 1206350) 1693550 (
1646450 1 1206350) 164.6450 L _
1355800 ( 972300)
1308700 1 972300)
1261650 ( 972300)
1214550 ( 9723001
1162452 L 2222221
801200 ( 619150)
754100 I 6191501
707050 ( 619150)
659950 ( 619150)
612fl52__i 6121521
565750 ( 619150)
518650 ( 619150)
471550 ( 619150)
424500 ( 619150)
222422__i- 6121521-
1355800 (
1308700 (
1261650 (
1214550 (
-1162450 1-
801200 (
754100 (
707050 I
659950 (
612252- i
565750 (
518650 (
471550 (
424500 (
212422 i
CUMULATIVE CASH FLOW,
s
WITH WITHOUT
PAYMENT PAYMENT
370300) 3760250 ( 3703001
370300) 7473400 ( 740600)
370300) 11139450 ( 1110900)
370300) 14758400 [ 14812001
3222221 12222250 1 11515.0.21
3703001 21855050 ( 2221800)
370300) 25332750 ( 25921001
3703001 28763350 I 29624001
370300] 32146850 I 1332700)
- 2222201 25482252 1 22222Q21
12063501 37318050 ( 49093501
1206350) 39105800 ( 6115700)
1206350) 40846450 ( 7322050)
12063501 42540000 ( B528400)
12062501- — 4412645Q 1 22242501.
972300)
9723001
972300)
972300)
2222001
619150)
619150)
619150)
619150)
- 6121521 -
45542250 ( 107070501
46850950 ( 11679350)
48112600 ( 12651650]
49327150 ( 13623950)
—52424620—1—145262501.
51295800 ( 152154001
52049900 I 158345501
52756950 ( 164537DO)
53416900 ( 170728501
54222250 1 1Z622Q201.
6191501 54595500 ( 18311150)
619150)- 55114150 ( 18930300)
6191501 55585700 1 19549450)
6191501 56010200 ( 201686001
6121521 562BI622 I 22282Z521
INITIAL INVESTMENT,
1!
JITH WITHOUT
nAYMENT PAYMENT
9 . 44
9.20
8.72
2*43
8.24
B.OO
7. 76
7.52
9.43
9. 10
a. 94
8.70
- 2*46
7.00
6.75
6.51
6.27
6*22
4.16
3.92
3.67
3.43
2.94
2.69
2.45
2.20
- -1*26 .
74523200 ( 798275001
37261600 ( 39913750)
56387600 ( 20787750]
AVG= 6.45
317
-------
Table A-171
MAGNESIA SCHEME C, NONREGULATED C1. ECDNOMICSi
20C MM. NEW COAL FIRED POWER PLANT, 3.5 I
$
S IN FUEL, 981! H2S04 PRODUCTION.
FIXER INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST PATE OF RETURN WITHOUT PAYMENT
9923000
10.71
NEG
Payment equivalent to projected operating cost of low-cost limestone process
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
TOTAL
MFG.
COST,
t/YEAR
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOP AIR
POLLUTION
CONTROL,
$/YEAP
NET MFG. COST,
t/YEAR
WITH
PAYMENT
WITHOUT
PAYMENT
NET REVENUE,
t/TON
1009;
H2S04
TOTAL
NET
SALES
REVENUE,
t/YEAR
3044600
3044600
3044600
3044600
2244602
3044600
3044600
3044600
3044600
2244622
1643900
1643900
1643900
1643900
L642222
1314200
1314200
1314200
1314200
;14222
814400
814400
814400
814400
8.14422
B14400
814400
814400
814400
814.420
53380500
3825400 (
3761700 (
3698000 (
3634200 (
—2522522-J
3506800 (
3443000 (
3379300 <
3315600 (
—2251222-i
2863100 (
2R04400 (
2740700 (
2676900 (
—2612222-4
2288900 (
2225100 (
2161400 <
2097700 (
—20.3.2220.-.1
1567700 (
1504000 (
1440200 (
1376500 (
_-1212fl22_.l
1249100 (
1185300 (
1121600 (
1057900 (
224122-1
72705900 (
780flOOI
7171001
653400)
589600)
5252221—
4622001
398400)
3347001
2710001
2222221—
12242001
1160500)
1096800)
1033000)
262.222J
9747001
910900)
847200)
783500)
1121221—
7533001
689600)
625800)
5621001
42B.4.221--
4347001
3709001
3072001
2435001
122I22J
193254001
3044603
3044600
3044600
3044600
—2244622
3044600
3044600
3044600
3044600
—2244620
1643900
1643900
1643900
1643900
—1642212
1314200
1314200
1314200
1314200
U1420.2
814400
814400
814400
814400
S14422
814400
814400
814400
814400
8J.4422
53380500
8.00
8.00
8.00
8.00
Sj.22-
8.00
8.0C
8.00
8.00
S..22-
5.00
5.00
5.00
5.00
5 ..22-
5.PO
5.00
5.00
5.00
5..00-
5.00
5.00
5.00
5.00
5»20._
5.00
5.00
5.00
5.00
5..20-
309600
309600
309600
309600
30.240.2--
309600
309600
309600
309600
2026C2—
138500
138500
138500
138500
12B.500.—
97000
97000
97000
97000
22202—
41500
41500
41500
41500
41522—
41500
41500
41500
41500
41520.
4688500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
-15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
TOT
318
GROSS INCOME,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1090400 ( 2735000)
1026700 ( 2735000)
963000 < 2735000)
899200 ( 2735000)
835500 i 22252221
771800 ( 2735000)
708000 ( 27350001
644300 ( 2735000)
5806CO ( 27350001
-516222 1 22252221
1362700
129=000
1235300
1171500
~1071. 700
1007900
944200
8805GO
B1612Q
( 15054001
( 15054001
( 15054001
( 15054001
1 15254221
( 12172001
( 12!7?00)
( 1217200)
( 1217200)
1 12172001
794800 ( 772900)
731100 ( 7729001
667300 ( 772900)
603600 ( 7729001
-522222 I 2222201—
476200
412400
348700
285000
'2J.200.
24013900
( 7729001
( 772°00>
( 772900)
( 772900)
1— 2222221 _
( 486920001
NET INCOME AFTER TAXES,
*/YEAR
WITH WITHOUT
PAYMENT PAYMENT
545200
513350
481500
449600
412252
385900
354000
322150
290300
—253450—
681350
649500
617650
585750
552222
535850
503950
472100
440250
-42B250-.
397400
365550
333650
301800
262250—
( 13675001
( 13675001
( 13675001
( 1367500)
.1 12625021
( 1367500)
( 1367500)
I 13675001
( 13675001
.1 1262522J
.1-
i
7527001
7527001
7527001
7527COI
2522221
608600)
6086001
6086001
6C8600I
6QfliQQl
( 3864501
( 3864501
( 3864501
( 3864501
.1 2B64521
238100 ( 386450)
206200 ( 386450)
174350 ( 386450)
142500 ( 386450)
112620— i 2364521
12006950
'
243460001
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1537500
1505650
1473800
1441900
1412252
1378200
1346300
1314450
1282600
—1252252
681350
649500
617650
585750
552220
535850
503950
472100
44C250
_ -42B252
397400
365550
333650
301800
262252-
( 3752001
( 3752001
( 3752001
( 3752001
-i 2252221
1 375200)
( 375200)
( 375200)
( 375200)
i _ 2252221
I
i
i
238100 (
206200 (
174350 (
142500 (
112622— i
21929950
7527001
752700)
7527001
7527001
2522221
6086001
6086001
6086001
6086001
60B6001
3864501
386450)
386450)
386450)
-2B64521
386450)
3864501
3864501
3864501
-2364501
( 14423000)
CUMULATIVE CA«:H FLOW,
$
WITH WITHOUT
PAYMENT PAYMENT
1537500 (
3043150 (
4516950 (
59588*0 (
2263220 i
8747100 (
10093400 (
11407850 (
12690450 (
-12141222— i_
14622550 (
15272050 (
15889700 (
16475450 (
.12022250—1.
17565200 (
18069150 1
18541250 {
18981500 (
._ii2a2a5.o__i-
19787250 (
20152800 (
20486450 (
20788250 (
.-21053222—1-
21296300 (
21502500 (
21676850 (
21819350 (
. 21222252 -1-
375200)
7504001
1)25600)
15008001
13260021
22512001
26264001
3001600)
J376800I
—22522201-
4504700)
5257400)
6010100)
67628001
—25155221.
81241001
8732700)
9341300)
99499001
105535201
109449501
113314001
11717850)
12104300)
-124222521-
12877200)
132636501
13650100)
140365501
-144222201-
AVG
INITIAL INVESTMENT,
WITH WITHOUT
PAYMENT PAYMENT
5.36
5.05
4.73
4.42
4*11
3.79
3.48
3.17
2.85
2»54
6.73
6.42
6.10
5.79
5.32
5.00
4.69
4.37
3.97
3.65
3.33
3.02
- 2..2Q
2.38
2.06
1.74
1.42
* 4.00
-------
Table A-1 72
MAGNESIA SCHEME C, NONRtGULATED CO. ECONOMICS, 200 MW . NEW COAL FIRED POWER PLANT, 3.5 ? S IN FUFL, 98* H2SD4 PRODUCTION.
FIXED INVESTMENT
OVERALL INTEREST RATE OF RETURN WITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
12
11
12
13
-15
16
17
18
19
22
21
22
23
24
_25
26
27
28
29
12
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
1222
7000
7000
7000
7000
1222
5000
5000
5000
5000
5QOO
PRODUCT RATE,
EQUIVALENT
TONS/YEAR TOTAL
MFG.
100'J COST,
H2SD4 i/YEAR
38700 3044600
38700 3044600
38700 3044600
30700 3044600
33700 3044600
38700 3044600
38700 3044600
33700 3044600
33700 3044600
1JJ122 1244622
27700 1643900
27700 1643900
27700 1643900
27700 1643900
27700 1643900
3500 19400 1314200
3500 19400 1314200
3500 19400 1314200
_J500 19400 1314200
-1522 13422 1J.1422O
1500
1500
1500
1500
1522
1500
1500
1500
1500
1522
8300 814400
3300 814400
8300 814400
3300 814400
3122 314422
U300 814400
3300 814400
d300 814400
330J 814400
3322 _- -114422
ALTERNATIVE
NONRECOVERY
WET-LIMESTONF
PROCESS COST
AS PAYMENT TO
CHEMICAL COM- NFT MFG. COST,
PANY FOR AIR t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
4388700
4338300
4283000
4237700
4131122 J
4137000
4086700
4036300
3986000
1215122
3252900
3202600
3152200
3101900
1251622
1344100)
1293700)
1243400)
1193100)
L 11421221
10924001
1042100)
991700)
941400)
I 3211221
1609000)
1558700)
1508300)
1458000)
1407700)
2508100 1 1193900)
2457800 ( 1143600)
2407500 ( 1093300)
2357100 1 1042900)
2326322 1 2226221
1550300 1 735900)
1499900 I 685500)
1449600 I 635200)
1399300 ( 584900)
1143222 i 5145221
1298600 ( 484210)
1248200 ( 433800)
1197900 ( 383500)
1147600 ( 3332001
1C212£0 1 2323221
3044600
3044600
3044600
3044600
1244622
3044600
3044600
3044600
3044600
1244622
1643900
1643900
1643900
1643900
1641222
1314200
1314200
1314200
1314200
1214222
NET REVENUE,
$/TON
100*
H2S04
8.00
3.00
3.00
3.00
3*22
3.00
8.00
8.00
3.00
2*£2
5.00
5.00
5.00
5.00
5*22 _
5.00
5.00
5.00
5.00
5*22
314400 5.00
814400 5.00
814400 5.00
314400 5.00
-—£14422 5*22—
814400 5.00
814400 5.00
014400 5.00
814400 5.00
- 314422 5*Q2
TOTAL
NET
SALES
REVENUE,
$/YEAR
309600
309600
309600
309600
222622 —
309600
309600
309600
309600
222622 -
138500
138500
138500
138500
113522
97000
97000
97000
97000
21222
41500
41500
41500
41500
41522
41500
41500
41500
41500
41522
82657/00 (
4638500
YEARS OFOUIRED FOP PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
—5
6
7
8
9
12
11
12
13
14
16
17
18
19
22
21
22
23
24
25
26
27
28
29
3.2
GPOSS IfJCOMF,
I/YEAR
y, ITH rt I THHUT
PAYMENT PAYMENT
1653700 27350001
160J3UO 2735000)
1553000 2735000)
1502700 27?5000)
1452122 i 21252221
NCT INCOMF AFTCo TAXES,
t/YFAR
«ITH WITHOUT
PAYMENT PAYMENT
826850
801650
776500
751350
7261511
1402000 2735000) 701000
1351700 2735000) 675350
1301300 2735000) 650650
1251000 2735000) 625500
1222122 1 21252221 -622352
1747500 ( 1505400)
1697200 ( 1505400)
1646800 ( 1505400)
1596500 ( 1505400)
1546222 1 15254221 .
1290900 ( 1217200)
1240600 ( 1/172001
1190300 ( 1217200)
1139900 ( 1217200)
1-232.6.22 1 12112221 _
777400 ( 7729JO)
727000 ( 772900)
676700 [ 772900]
626400 ( 772900)
516222 1 1122221
873750
848600
023400
798250
112122
645450
620300
595150
56995')
544322
338700
363500
338350
313200
525700 ( 7729001 262850
475^00 ! 772900) 237650
4?50oO ( 772900) 212500
374700 ( 772'JOO) 187350
224222 I 1122221 ; 6.2152
1
I
I
I
1
1
(
1
1
(
1
I
1
1367500)
1367500]
1367500)
13675001
12615221
1367500)
1367500)
1367500)
1367500)
12612221
752700)
752700)
752700)
752700)
1521221
608600)
60H600I
6066001
6086001
-6226221
386450]
3864501
386450)
3864501
2364521
386450)
386450)
386450)
386450)
2364521 _
CASH FLOW,
£/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1819150
1793950
1768800
1743650
1113452
1693300
1668150
1642950
1617800
8737,->0
843600
823400
798250
112122
645450
620300
595150
559950
544322-
388700
363500
338350
-13200
233222
262350
237650
212500
187350
162152 .
I
I
1
(
I
(
I
1
1
1
I
I
375200)
375200)
3752001
375200)
3152221
375200)
375200)
375200)
375200)
2152221
CUMULATIVE
WITH
PAYMENT
C
i
1819150 [
3613100 [
5381900 (
7125550 (
3344222 I
10537300
12205450
1384B400
15466200
1105_8050
752700) 17932600
752700) 13781200
752700) 19604600
752700) 20402850
1521221 21115252
608600) 21821400
608600) 22441700
6086001 23036850
608600) 23606800
-6236221 24151620
386450)
386450)
3864501
386450)
2364521
24540300
24903800
25242150
25555350
25843350
386450) 26106200
336450) 26343850
3864501 26556350
386450) 26743700
2364521 26225352
I
1
I
(
1
I
I
(
1
I-
I
I
1
1
ASH FLOW,
WITHOUT
PAYMENT
375200]
7504001
1125600)
1500800)
— 13142Q21-
22512001
26264001
30016001
33768001
21522221
t504700l
5257400)
6010100)
6762800)
15155221
3124100)
87327001
9341300]
9949900)
125535221
10944950)
11331400)
11717850)
12104300)
124221521
12877200)
132636501
13650100)
14036550)
144222221
INITIAL INVESTMENT,
WITH WITHOUT
PAYMENT PAYMENT
8.13
7.88
7.63
7.38
1*14
6.89
6.64
6.39
6.15
5*32
8.63
8.39
8.14
7.89
1*64
6.41
6.16
5.91
5.66
5*41
3.88
3.63
3.38
3.13
2*33
2.63
2.37
2.12
1.87
1*62
3J965700 ( 4P.692JOO)
169J2850 I 24346000]
26905850 ( 14423000)
AVG= 5.66
319
-------
Table A-173
MAGNESIA SCHEMF C, NONREGULATED CO. ECONOMICS, 50C MM. NEW COAL FIRED POWER PLAMT, 3.5 * S IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT t l»111000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 12.5*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NEC
Payment equivalent to projected operating cost of low-cost limestone process
YEARS
AFTER
POMER
UNIT
START
1
2
3
4
5
6
7
8
9
-12 __
11
12
13
14
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
122Q_
7000
7000
7000
7000
—1222
5000
5000
•5000
5000
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
94700
94700
94700
04700
24.za.fl
94700
94700
94700
94700
24122
67600
67600
67600
67600
TOTAL
MFG.
COST,
t/YEAR
5469100
5469100
5469100
5469100
54.6.2122
5469100
5469100
5469100
5469100
5462122
2897400
2897400
2897400
2897400
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
$/YEAR
7209600 (
7087400 (
6965200 (
6843000 (
£12.2322 i
6598700 (
6476500 (
6354300 (
6232100 (
6112220 1 _
5381100 (
5258900 (
5136700 (
5014500 (
NET MFC
o COST,
t/YEAR
WITH
PAYMENT
1740500)
16183001
1496100)
1373900)
12513021
1129600)
10074001
8852001
7630001
— 6.42202.1
24837001
2361500)
2239300)
21171001
.15 51222 61602 2321402 4.322420-.1 1225202J
16
17
18
19
22_
21
22
23
24
25
26
27
28
29
1500
3500
3500
3500
250.0.
1500
1500
1500
1500
150.2
1500
1500
1500
1500
_22 _ ..1522. .
47300
47300
47300
47300
4.7.3.Q.0
20300
20300
20300
20300
2.0.3.00
20300
20300
20300
203DO
2292500
2292500
2292500
2292500
22.22522
1394600
1394600
1394600
1394600
1394600
1394600
1394600
1394600
1394600
2.0.122 _1234622
4280700 (
4158500 {
4036300 (
3914200 (
2122QOQ-I
2926100 (
2803900 (
2681700 (
2559600 (
2421422 i_
2315200 I
2193000 (
2070800 (
1948700 (
1B.2650Q..1
1988200)
18660001
17438001
1621700)
14995QQ1_
15315001
1409300)
12871001
1165000)
10423221
920600)
798400)
6762001
554100)
4212221
WITHOUT
PAYMENT
5469100
5469100
5469100
5469100
5462120- -
5469100
5469100
5469100
5469100
5469J.2.Q_
2897400
2897400
2897400
2897400
NET REVENUE,
t/TON
100*
H2S04
8.00
8.00
8.00
8.00
a«.ao
8.00
8.00
8.00
8.00
3.22
5.00
5.00
5.00
5.00
TOTAL
NET
SALE$
REVENUE,
t/YEAR
757600
757600
757600
757600
151600-.
757600
757600
757600
757600
151600 .
338000
338000
338000
338000
2fl 214Q2 5*22 222202..
2292500
2292500
2292500
2292500
2222522- .
1394600
) 394600
1394600
1394600
1224622
1394600
1394600
1394600
1394600
1224600
5.00
5.00
5.00
5.00
5..QQ
5.00
5.00
5.00
5.00
5..2C
5.00
5.00
5.00
5.00
. _ _ — 5*00
236500
236500
236500
236500
2265Q2-.
101500
101500
101500
101500
101522
101500
101500
101500
101500
_ 101522 .
TOT
127500
1724500
94586500
136225900 (
41639400)
11463500
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
GROSS INCOME,
t/YEA«
NET INC01E AFTER TAXES,
«/YE4R
CASH FLOW,
t/YEAR
CUMULATIVE CASH FLOW,
t
ANNUAL RETURN ON
INITIAL INVESTMENT,
UNIT
START
1
2
3
4
5
6
7
8
9
11
12
13
14
15
16
17
18
19
20
21
22
23
24
_25
26
27
28
29
WITH
PAYMENT
2498100 (
2375900 (
2253700 (
2131500 (
2022400 1
1887200 (
1765000 (
1642800 (
1520600 (
1223500 L
2821700 (
2699500 (
2577300 (
245510D I
2222022 1
WITHOUT
PAYMENT
4711500)
47115001
4711500)
4711500)
41115001
4711500)
4711500)
4711500)
4711500)
41115001
2559400)
25594001
25594001
2559400)
2S59400L
2224700 ( 2056000)
2102500 ( 20560001
19H0300 ( 2056000)
1858200 ( 20560001
1126202 1 2Q562001
1633000 (
1510800 (
1388600 (
1266500 (
1144202 1
1322100 (
899900 (
777700 (
655600 (
. 522402 L
1293100)
1293100)
1293100)
12931001
12221021
12931001
12931001
1293100)
12931001
-12221221-
WITH
PAYMENT
1249050
1187950
1126850
1065750
1204100
WITHOUT
PAYMENT
( 2355750)
( 2355750)
( 2355750)
( 2355750)
( 235515Q1
943600 ( 2355750)
882500 ( 2355750)
821400 ( 2355750)
760300 ( 2^55750)
622252 1 22551521-
141C850 ( 1279700)
1349750 ( 1279700)
1288650 ( 1279700)
1227550 ( 1279700)
1166520 t 121210C1
1112350
1051250
990150
929100
363000
( 1023000)
( 1028000)
( 1028000)
( 1028000)
L 102B0021
816500 ( 646550)
755400 ( 646550)
694300 ( 646550)
633250 ( 6465501
512150 1 6465501
5)1050 ( 6465501
449950 ( 646550)
388850 ( 646550)
327800 < 6465501
266122—1 .6465521—
WITH
PAYMENT
3060150 (
2999050 (
2937950 (
2876850 (
2315300 i
2754700
2693600
2632500
2571400
2510250
1410850
1349750
1288650
1227550
1166502-
1112350
1051250
990150
929100
- - 363222
816500
755400
694300
633250
512152
511050
449950
388850
327800
266122-
(
(
(
(
I
(
(
(
(
(
(
(
(
(
(
(
(
(
(
(
I
(
(
(
1
WITHOUT
PAYMENT
WITH
PAYMENT
5446501 3060150
544650) 6059200
544650) 8997150
544650) 11874000
5446501 14689800
5446501
5446501
5446501
544650)
5446521
17444500
2013810C
22770600
25342000
27852350
1279700) 29263200
12797001 30612950
1279700) 31901600
12797001 33129150
—12121001 34295650
1028000)
10280001
1023000)
1028000)
102BQQ01
646550)
646550)
646550)
646550)
6465501
646550)
6465501
646550)
646550)
6465501.
35408000
36459250
37449400
38378500
22246520-
40063000
40818400
41512700
42145950
42113120
43229150
43679100
44067950
44395750
4466.2450-
(
(
(
(
(
(
(
(
(
(
(
(
(
~(
(
(
(
_i
(
(
<
_1
(
(
(
(
1
WITHOUT
PAYMENT
544650)
10893PO)
1633950)
2178600)
22222501
3267900)
3812550)
4357200)
4901850)
54465021
6726200)
8005900)
9285600)
10565300)
113452001
12873000)
13901000)
14929000)
159570001
162350.021
17631550)
18278100)
18924650)
19571200)
212111501
208643001
21510850)
22157400)
228039501
2245Q5QQ1
WITH WITHOUT
PAYMENT PAYMENT
6.73
6.40
6.07
5.74
5.41
5.08
4.75
4. 43
4.10
7.64
7.31
6.98
6.65
6.22
6.05
5.72
5.39
5.06
4*22
4.47
4.14
3.80
3.47
2.12
2.80
2.47
2.13
1.80
—1.46
TOT
320
53102900 ( 83123000)
26551450 ( 41561500)
44662450 I 234505001
AVG= 4.85
-------
Table A-174
MAGNESIA SCHEME C, NONkCGULATED CO. ECONOMICS, 500 MW. NFW COIL FIRED POWER PLANT, 3.5 % S IN FUEL, 98* H2S04 PRODUCTION.
FIXED INVESTMENT t 18111000
OVEPALL INTEREST RATE OF RETURN WITH PAYMENT 19.2*
OVERALL INTEREST PATE OF RETURN WITHOUT PAYMENT NEC
Payment equivalent to projected operating cost of high-cost limestone process
YEARS
AFTER
POWER
UNIT
START
PRODUCT RATE
ANNUAL EQUIVALENT
OPERA- T INJ/YEAR
T I ON ,
KW-HR/ 1004
K. H2S04
1 7000
2 fOOO
? 7000
4 7000
-5- 2222
6
7
8
9
-12 _
11
12
13
14
15 _
16
17
18
19
-22_
21
22
23
24
25
26
27
28
29
. 30
7000
7000
700J
7000
2222
5000
500.1
5000
500.1
5222
3500
S500
3500
1500
.15132
1500
1500
1500
1500
1522
94700
94700
94700
94700
.—24222—
94700
94703
94700
94700
24222
67600
67600
67600
f 7600
47300
47300
47300
'.7JOO
42i22
2J300
20300
20300
20300
70^00
1 ->CO ^0300
1500 20300
1V30 20300
1500 20300
152J 2212U—
TOTAL
MFG.
COST,
I/YEAR
5469100
54(-9100
5469100
5469100
5.4.6.210.0.
5469100
5469100
5469100
5469100
5.4.6.2120.
2897400
2897400
2897400
2897400
232242 2_
2292500
2292500
2292500
2292500
2222522
1394600
1394600
1394600
1394600
1.3.24.6.U J]
1394600
1394600
1)94600
1594600
_ 1J94600
ALTERNATIVE
NONRFCOVERY
WET-L IMESTON5
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
NET MFG. COST,
$/YEAP
WITH WITHOUT
PAYMENT PAYMENT
9115900 ( 3646800)
9016300 ( 3547200)
8916700 ( 3447600)
8817100 ( 33480001
-3212622 i 324HSQ01
8618000 (
8518400 I
8418800 (
8319200 (
£212622-1-
6719600 1
6620000 (
6520400 (
6420800 (
6121222 I_
5139500 (
5039900 (
4940300 (
4640700 (
4241122 1
3114300 (
3014700 (
2915100 I
2815500 (
2215222 1
2616400 I
2516HOO 1
2417200 (
2317600 I
. - -221S.222 i
31489001
3049300)
2949700)
2850100)
22525221
3822200)
3722600)
3623000)
3523400)
342130.21
2847000)
27474001
2647800)
25482001
244.86.221
1719700)
16201001
1520500)
1420900)
13213221
1221300)
1122200)
1022600)
923000)
8.214221
5469100
5469100
54o9100
5469100
54.6.210.2
5469100
5469100
5469100
546°100
5.4.6.2122
2897400
2B97400
2897400
2897400
232Z422
2292500
2292500
2292500
2212500
2222522
1394600
1394600
1394600
1394600
1394^22
1394600
1394600
1394600
1394600
13.946.22
NET REVENUE,
I/TON
100*
H2S04
3.00
9.00
n.OO
3.00
2*22
8.00
8.00
8.00
n.OO
3*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
TOTAL
NET
SALES
RFVENUE,
f/YEAR
757600
757600
757600
?57600
Z5.Z6.22 _.
757600
757600
757600
757600
— 252622
338000
338000
336000
338000
313222
236500
236500
236500
236500
236522 -
101500
101500
101500
101500
121522
101500
101500
101500
101500
_ 121522 -_
170642600 (
Yl IRS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS I.KUSS INCOME,
AFTER $/YfAR
POWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1
2
3
4
—5
6
7
8
9
_L2
11
12
13
14
-15
16
17
18
19
-22
21
22
23
24
26
27
28
29
3U
4404-iOO
4304400
4105600
40061 00
^906500
3b06900
3707^00
3607700
152iilV2
I
1
I
(
(
1
(
(
1
4160 '00 (
40'jOOOO 1
1261322 1
2033^00 I
ze -34)00 I
2744700 I
2635120 (
1 vj 2 1 2 J U
1721603
16220JC
1522400
14.223J2
1323300
1223700
1174103
1024500
(
(
(
(
(
1
(
4711300)
4711500)
4711500)
4711500)
42115221
47115001
4711500)
4711=00)
47115001
42115221-
2559400)
7559400)
25594001
2559400)
25.59.40.0.1
20560001
2056000)
'056000)
135oOOO)
22562221
1293100)
1293100)
1293100)
1293100)
12211221
1293100)
129ilOOI
1293100)
129310GI
- 12231221-
N>-T INCOME AI-TR TAXES,
t/YEAR
WITH WITHOUT
PAYMbNT PAYMENT
2202200 (
2152400 (
2102600 (
2052800 (
2221252 1
1053750 I
1903450 (
1B53650 (
1803050 I
1254252 L
2355750)
23557501
2355750)
2355750)
21552521
23557501
23557501
2355750)
2355750)
2030130 ( 1279700)
2030300 I 1279700)
1930530 ( 1279700)
19?0700 I 1279700)
1332222 i 122S2221 .
1541750 (
1401J50 I
1442150 (
1392350 I
1142552— i_
910600 (
S6U100 (
811)00 I
761200 I
211422 i
661650 1
611350 (
562050 1
512250 (
462452 I
1028000)
1028000)
1078000)
1028000)
__12232221_.
646550)
6465501
6465501
646550)
6465521 .
646550)
646550)
646550)
646550)
_ 6465521 .
CASH FLOW,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
4013300
3963500
3913700
3863900
1314152
3764350
3714550
3664750
3614950
._ 1565152.
2080100
2030300
1980500
1930700
1332222
1541750
1491950
1442150
1392350
1142552
1
1
1
I
1
i .
1
. i .
910600 (
860800 (
811000 1
76 1 2 0 0 (
. _ 211422 1 _
661650
611850
562050
512250
462452.
I
1
. 1 .
544650)
544650)
544650)
544650)
5446521
5440501
5446501
544650)
544650)
.-5446521
1279700)
12797001
12797001
12797001
.12222221- .
1020000)
1028000)
1020000)
1028000)
.1228.2231 _.
646550)
646550)
646550)
6465501
. 6465521- .
646550)
6465501
646550)
646550)
. 6465521- .
CUMULATIVE CASH FLOW,
f
WITH WITHOUT
PAYMENT PAYMENT
4013300
7976100
11890500
15754400
-12563552 1
23332900
27047450
30712200
34327150
. 12B.22122
39972400
42002700
43983200
45913900
—42224322—
49336550
50823500
52270650
53663000
.-55225552—
55916150
56776950
57587950
58349150
—52262552—
59722200
60334050
60896100
61438350
. 61222320 .
544650)
1089300)
1633950)
2173600)
1 22212521-
32679001
3812550)
4357200)
4901850)
_ 54465221
6726700)
8005900)
9285600)
10565300)
—113452221-
128730001
139010001
149290001
159570001
162352221
17631550)
18274100)
18924650)
19571200)
—222122521-
20864300)
21510850)
27157400)
22903950)
L 23.4525221-
INITIAL INVESTMENT,
i
WITH WITHOUT
PAYMENT PAYMENT
11.86
11.60
11.33
11.06
12*22
10.52
10.26
9.99
9.72
2*45
11.27
11.00
10.73
10.46
12*12
8.39
8.12
7.85
7.58
2*11
4.99
4.72
4.44
4.17
3*22
3.63
3.35
3.03
2.11
- 2*51
87519600 ( 63123000)
4375'JbOO ( 415615001
61870800 I 234535001
7.99
321
-------
Table A-175
M»GNESIA SCHEME C, NONRFGULATEO CO. ECONOMICS, 1000 MW, NEW COAL FIRED POWER PLANT, 3.5 % 5 IN FUEL, 98% H2S04 PRODUCTION.
FIXED INVESTMENT $ 27640000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 13.6%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NES
Payment equivalent to projected operating cost of low-cost limestone process
YFARS
AFTER
POWER
UNIT
START
1
2
3
4
6
7
8
9
11
12
13
14
15
16
17
18
19
2C
21
22
24
~26
27
28
29
.32..
ANNUAL
OPERA-
TION,
KW--HP/
KW
700P
7300
7000
7000
70CO
7000
7000
7000
7000
5000
50CO
5300
5000
5000
3500
3500
3500
3500
2522
1500
1 500
1500
1530
' 500
1500
1500
'.500
1503
._ 1522
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
183000
S83000
1 83000
183000
L83000
183000
183000
183000
132222
130700
) 30700
130700
133700
122122
91500
91500
91500
91500
21522
39200
39200
39200
39200
2220.2
39200
39200
39200
39200
2i222__
TOTAL
MFG.
COST,
$/YEAR
8245100
8245100
8245100
8245100
8245100
8245100
8245100
8245100
8245100
4307500
4307530
4307500
4307500
4227522
3375900
3375900
3375900
3375900
^215222
2019300
2019300
2019300
2019300
2212200
ALTERNATIVE
NONRECOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL COM-
PANY FOR AIR
POLLUTION
CONTROL,
t/YEAR
11C82800 (
10692700 (
107P2700 (
10512600 (
10132500 (
9942400 (
9752300 (
9562200 (
2212222 1
NET WFGo COST,
*/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2837700)
26476001
2457600)
2267500)
221140.2 J
18874001
16973001
1507200)
1317100)
11271QQ1
8236300 ( 3928800)
8C'6200 < 3738700)
7856200 ( 3548700)
7666100 ( 3358600)
1416.222 i 3 168 53 0.1
6530600 (
6340600 (
6150500 (
5960400 (
5112422 J
4451700 (
426)600 (
4C71600 (
3881500 (
3691400 <
2019300 350)300 (
20193DO 3311300 (
2019300 3121200 (
2019300 2931130 (
2212222 - 2141122 I
3154700)
29647001
27746001
25345001
2224.5221
2432400)
22423001
20523001
1862200)
16121221
14820001
1292000)
1101900)
9118001
I2iaaai
82^5100
8245100
82^5100
8245100
2245122
8245100
8245100
8245100
8245100
5245102
4307500
4307500
4307500
43075PO
—4.201522 -.
3375900
3375900
3375900
3375900
2215222
2019300
2019300
2019300
2019300
2212222—
2019300
2319300
2019300
2019300
2212220 _.
NET REVENUE,
t/TON
100%
H2S04
8. OP
8000
8.00
8.00
TOTAL
NET
SALES
REVENUE,
$/YEAR
1464000
1464000
1464000
1464000
.146.4220.
8.PO 1464000
8.00 1464000
8.0P 1464000
8.00 1464000
3*02 146.40.0.2.
5.00
5.00
5.00
5.PO
5*22
5.00
5.00
5.00
5. OP
5.00
5.00
5.00
5.00
. 5*22
5. OP
5.00
5. CO
5.00
5*22
653500
653500
653500
653500
— fc.52522
457500
457500
457500
457500
—451522
196000
196000
196000
196000
. 126.2Q.2
196000
196000
196000
196000
—126222
141061000
208272000 (
67211000)
141061000
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS SROSS INCOME,
AFTER t/YEAB
POWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1
3
4
6
7
q
-10 - -
11
12
13
14
_15
16
17
18
19
22
21
22
23
24
-25
26
27
28
29
22 _
43C1730 (
4111600 (
392)600 (
373)500 (
2541422— 1 —
3351400 I
3161303 (
2971200 (
2781100 (
2521122—1
4582300 (
4392230 (
4202200 (
4 •! 1 2 1 3 0 (
3&T2200 (
3422200 (
3232100 (
334JTOO (
2',J8400 (
243P300 (
2'4», VV) (
167HOOO (
143^0'JJ I
129790" (
11 07800 (
aiiaoo i
TOT 89366000 { 11
322
67M 100)
6781130)
67611001
6.73'. 101)
67811001
6781100)
67H1 1001
3654^00)
36543301
3654000)
3654'. OCI
2V1».400I
291.8400)
29134PPI
29) 84POI
11233001
1823300)
1823 1001
18 '3 3001
1821300)
1 8?."300I
15221001
H906000 )
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2150850
2055800
196'3«00
1865750
1675700
1580650
1485600
1390550
1225552
2291150
2196100
210) 100
2306050
_ 1211202
18061.00
1711100
16) 6050
1521000
_ 1425222
1314200
1 219150
1124150
1029100
224050-
839000
744330
648950
E53900
455222
4'. 6B 3POO
(
(
(
~l
(
(
(
-1-
(
(
(
I
1
3390550)
3390550)
3390550)
3390550)
.22225521
3390550)
3393550)
339C550I
339C550I
—22225501
1827000)
18J7000)
1827000)
18270001
18270001
( 14592001
1 14592001
( 14592001
( 14592001
_1 14522021—
1 9116501
I 9116501
( 9116501
I 911650)
-1 2116501—
( 0)16501
( 9116501
( 9)16501
( 9116501
i- 2116501
(
5945300PI
CASH FLOW,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
4904850
4309800
4714800
4619750
_ 4524122-
4429700
4334650
42396PO
41' 4550
-4242552
2291150
2196100
21 Oil OP
2P06050
1211022
1806100
1711100
1616050
1521000
1426220
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
I t
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
( 6365501 4904850 (
( 6365501 9714650 (
( 6365501 14429450 (
( 636550) 190492.00 (
-1 6.26.5521 22512222—1
( 6365501 28003600 (
( 6365501 3233P250 (
( 6365501 36577850 (
( 636550) 40722400 (
1 6365501 44111250 L
(
(
(
(
-i—
(
(
(
(
(
1314200 (
1 2191 50 (
1124150 (
1029100 1
224250—1—
839000 (
744000 (
648Q50 (
- 453222 i
72?23000
(
1827000)
18270001
18270001
1827000)
lfl'10021
14592001
1459200)
14592001
145920PI
14522221
9116501
911653)
9116501
911S50I
— 2116521
91) 6501
9116501
9116501
9116501
2116521
31911000)
6365501
12731001
1909650)
2546200)
- 21427521— -
38193001
44558501
50924001
57289501
63455QOI
47063100 ( 81925001
49259200 ( 100195001
51360300 I '1846500)
53366350 ( 13673500)
55211252—1—1550.05221
57083450 ( 16959700)
58794550 ( )S418900I
60410600 ( 198781001
6193160" ( 213373001
6225162.2— 1—221245PQ1
64671800 ( 23703150)
65390950 ( 24619800)
67015100 ( 25531453)
68044200 ( 26443100)
65215252—1—212541501
69BlT?50 ( ?«?66400I
70561250 ( 2")73050I
71210200 ( 300817001
71764100 ( 31CO135P)
12222QQ2 i M 91 loop I
AVP- =
7.62
7.29
6.95
6.61
5.94
5.60
5.26
4.93
8.17
7.83
7.49
7.15
6.47
6.13
5.79
5.45
4*74
4.39
4.05
3.71
3.02
2.68
2.34
2.00
1*65
5.37
-------
Table A-176
MAGNFSIA SCHEME Ci HONREGULATED CO. ECONOMICS, 1000 MM. NEW COAL FIRED POWER DLANT, 3.5 I S IN FUEL, 98* H2S04 PRODUCTION.
FIXFD INVESTMENT t 275*0000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT 22.R%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT NFG
Payment equivalent to projected operating cost of high-cost limestone process
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START Kw
1
2
3
4
6
7
8
9
10
11
12
13
-15_
16
17
18
19
-22_
21
22
23
24
25
26
27
28
29
iO
PRUDUCT RATE,
tQUIVALENT
TONS/YEAR
100«
H2S04
7000 183000
7000 1B3000
7000 183000
TOGO 183000
2222 laiaaa
7000
7000
7000
rooo
7000
5000
5000
5000
5000
2222_
3500
3500
3500
3500
_ -3522
1500
1500
1500
1500
1500
183000
183000
183000
133000
183000
130700
130700
130700
130700
122222 —
91500
91500
91500
91500
91502
39200
39200
39200
39200
39200
1500 39200
1500 39200
1500 39200
1500 39200
L5QQ 39"'00
TOTAL
MFG.
COST,
t/YEAR
8245100
8245100
8245100
8245100
_ 3245122
8245100
8245100
8245100
8245100
2245122 _
4307500
4307500
43075JO
4307500
_ 4322522
3375900
3375900
3375900
3375900
3225222
2019300
2019300
2019300
2019300
2212222
2019300
2019300
2019300
2019310
221222il__
ALTERNATIVE
NONP.FCOVERY
WET-LIMESTONE
PROCESS COST
AS PAYMENT TO
CHEMICAL C'OM- NET MFG. COST,
PANY FOR AIP t/YEAR
POLLUTION
CONTROL, WITH WITHOUT
$/YEAR PAYMENT PAYMENT
15208800 (
15053700 1
14898600 1
14743500 (
14522422 1
14433200 (
14278100 (
14123000 I
13967900 (
-13212J22 1
11154900 (
10999800 1
10844700 I
10689600 I
12524522-1.
8458700 I
8303600 1
8148500 (
7993400 (
-2223322 1
5007900 (
4852800 (
4697700 (
4542500 (
4322422 i.
4232300 I
4077200 (
3922100 (
3767000 1
—3611222-1.
6963700)
6303600)
66535001
6498400)
£2432221-
6188100)
6033000)
58779001
5722800)
_ 55622221- _
8245100
8245100
8245100
8245100
2245122
8245100
8245100
8245100
8245100
8245100
6847400) 4307500
6692300) 4307500
6537200) 4307500
6382100) 4307500
-62222221 4327500.
5082300)
4927700)
4772600)
4617500)
44624221
2988600)
2833500)
2678400)
25232001
22621221
2213000)
2057900)
1902800)
1747700)
. — 15326221
3375900
3375900
3375900
3375900
2225222
2019300
2019300
2019300
2019300
2212222
2019300
2019300
2019300
2019300
2212222. —
NET REVENUE,'
t/TON
iocs;
H2S04
1.00
8.00
8.00
8.00
3*22
3.00
8.00
8.00
8.00
3*22
5.00
5.00
5.00
5.00
_ 5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
5*22
5.00
5.00
5.00
5.00
_5*22
TOTAL
NFT
SALES
REVENUE,
i/YEAR
1464000
1464000
1464000
1464000
1464222- .
1464000
1464000
1464000
1464000
-1464222
653500
653500
653500
653500
.652522
457500
457500
457500
457500
452522
196000
196000
196000
196000
126222
196000
196000
196000
196000
126222
141061000
283172800 (
142111800)
141061000
22155000
YEARS CF.QUIPEO FOR PAYOUT WITH PAYMENT:
NU PAYOUT WITHOUT PAYMENT
ANNUAL RETURN ON
YEARS GROSS INCOME,
AFTER i/YEAP
POWER
UNIT WITH WITHOUT
START PAYMENT PAYMENT
1 B427700 ( 6781100)
Z 3272uOO ( 6781100)
3 8117500 I 6781100)
4 7962400 ( 6781100)
5 —2222222—1 62211221-
b 7652100 I 6781100)
7 7497000 ( 67811001
8 7341900 1 0781100)
9 7136800 ( 67811001
12_ 2221222 1 62211221
11 7500900 ( 3654000)
12 7345800 ( 36540001
13 7190700 1 365-.OOOI
14 7035600 ( 3654000)
15 £222522 1 26r>4il221
16 5540300 I 2918400)
17 5335200 ( 2918400)
18 5230100 I 2913400)
19 5075000 ( 2918400)
22 4212222 1 22124221
NET INCDME AFTEP TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
*/YFAR i/YEAR i %
WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
4213350 ( 3390550) 6967850
4136300 ( 3390550) 6890300
405P750 ( 3390550) 6812750
3981200 1 33905501 6735200
3903650 1 33905SQ1 6.6.52fi5fl J
3826050 ( 3390550) 6580050
3748500 ( 3390550) 6502500
3670950 1 3390550) 6424950
3593400 ( 3390550) 6347400
2515352 _1 32225521 6262252 J
3750450 1 1827000) 3750450
3672900 ( 1827000) 3672900
3595350 ( 1827000) 3595350
3517800 ( 1827000) 3517800
2442252 1 12222221 2442252 J
2770150 ( 1459200) 2770150
2692600 ( 1459200) 2692600
2615050 ( 1459200) 2615050
2537500 I 1459200) 2537500
245225JJ i 14522221 2452252— J
21 3184600 ( 1823300) 1592300 1 911650) 1592300
22 3029500 ( 1823300) 1514750 ( 911650) 1514750
23 2874400 ( 1823300) 1437200 ( 911650) 1437200
24 2719700 ( 1823300) 1359600 { 911650) 1359600
25_ 2564122—1 12222221 1222252— i 2116521 1222252— J
26 2409000 ( 1823300) 12045JO ( 911650) 1204500
27 2253900 ( 18233001 1126950 [ 911650) 1126950
28 2093300 I 1823300) 1049400 I 911650) 1049400
29 1943700 ( 1823300) 971850 1 911650) 971850
_22 1232622—1 13222221 224222__i 2116521 224222— J
636550) 6967850
636550) 13358150
636550) 20670900
636550) 27406100
6265521 24262252 J
636550) 40643800
636550) 47146300
636550) 53571250
6365501 59918650
6265521 66122522 J
1827000) 69938950
1827000) 73611850
1827000) 77207200
1827000) 80725000
L 12222221 24165252 J
1459200) 86935400
1459200) 89629000
1459200) 92243050
1459200) 94780550
14522221 —22242522 _J
911650) 98832800
9116501 100347550
9116501 101784750
911650) 103144350
L 2116521 124426422—J
911650) 105630900
911650) 106757850
911650) 107807250
9116501 108779100
L 2116521 122622422— J
6365501 14.93
1273100) 14.66
1909650) 14.38
2546200) 14.11
21222521 13*22
3819300) 13.56
4455850) 13.28
5092400) 13.01
5728950) 12.74
62655221 12*46
81925001 13.37
100195001 13.09
11846500) 12.82
136735001 12.54
155225221 12*26
16959700) 9.92
18418900) 9.64
19878100) 9.36
21337300) 9.09
_ 222265221 2*31
23708150) 5.74
24619800) 5.46
25531450) 5.18
264431001 4.90
.—222542521 4*62
282664001 4.34
29178050) 4.06
300B9700I 3.78
31001350) 3.50
L— 212122221 3*22
TOT
164266800 ( 1189060001
59453000) 109673400 ( 319130001
AVG= 9.87
323
-------
Table A-177
MAGNESIA SCHEME D, REGULATED PORTION COOPERATIVE ECONOMICS, SCPUBBING-DRYING, 200 MW NEW COAL F[RED UNIT, 3.5% S, MGS03
$ 7671000
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR $/TON NET
POWFR TION, POWER SALFS
UNIT KW-HR/ MAGNESIUM COMPANY, MAGNESIUM REVENUE,
START KW SULFITE S/YEAR SULFITE t/YEAR
1 7000
2 7000
3 7000
4 7000
-5 2222 _
6 7000
7 7000
8 7000
9 7000
_12 2222
11 5000
12 5000
13 5000
14 5000
15_ 5222 .
16 3500
17 3500
18 3500
19 3500
20 35DQ
56200
56200
56200
56200
56222
56200
56200
56200
56200
56.222- .
40200
40200
40200
40200
_ 42222 __
28100
28100
28100
28100
ZfllQQ
21 1500 12100
22 1500 12100
23 1500 12100
24 1500 12100
25_ 1522 - 12122
26 1500
27 1500
28 1500
29 1500
22 1522
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
12100
12100
12100
12100
121QQ
3791500
3738300
3685100
3631900
252S222
3525500
3472400
3419200
3366000
. 2212522
2810600
2757400
2704200
2651100
. -2522222
2192900
2139700
2086500
2033300
. __12fl2122
1418100
1364900
1311700
1258500
. 1225222 _
1152100
1098900
1045800
992600
2224Q2
0.0
0.0
0.0
0.0
Oi.2
0.0
0.0
0.0
0.0
_ 2*2 _
0.0
0.0
0.0
0.0
_2*2 „
0.0
0.0
0.0
0.0
__2*.2
0.0
0.0
0.0
0.0
2*2
0.0
0.0
0.0
0.0
Q*2
1024500 71262400
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR, DOLLARS
PRESENT WORTH, DOLLARS PER TON OF COAL BURNED
PRESENT WORTH, MILLS PER KILOWATT-HOUR
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST COR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
DRTCESS RECOVERY RCCOVERY
NET ANNUAL CUMULATIVE INCLUDING PROCESS PROCESS
INCREASE NET INCREASE REGULATED INSTEAD INSTEAD
(DECREASE) (DECREASE) ROI FIR TF WET- OF WET-
IN COST OF IN COST OF POWER LIMESTONE LIMESTONE
POWER, POWER, COMPANY, SCRUBBING, SCRUBBING,
$ $ $/YFAP t - $
3791500
3738300
3685100
3631900
2523222
3525500
3472400
3419200
3366000
_ 2212322- .
2810600
2757400
2704200
2651100
2522222
2192900
2139700
2086500
2033300
128.2122
1418100
1364900
1311700
1258500
— 1225222__
1152100
1098900
1045800
992600
_222422__
71262400
7.29
2.79
29063400
2.97
1.14
3791500
7529800
11214900
14846800
1B.42552Q-
3825400
3761700
3698000
3634200
3570500 (
21951000 3506800 (
25423400 3443000 (
23842600 3379300 (
32208600 3315600 (
25521422 2251900 L
38332000
41089400
43793600
46444700
4.224.26.22
51235500
53375200
55461700
57495000
52425122
60893200
62258100
63569800
64828300
_ 66222622
67185700
68284600
69330400
70323000
2126.24.22
2368100
2804400
2740700
2676900
26.12222
2288900
2225100
2161400
2097700
2222222
1567700
1504000
1440200
1376500
1212B22
1249100
1185300
1121600
1057900
22^122
72705900
7.44
2.85
29257300
2.99
1.15
33900
23400
12900
2300
8.2221
19700)
29400)
39900) (
50400) (
6.222Q1 L
57500 (
47000 (
36500
25800
15222
96000
P5400
74900
64400
52S22
149600
139100
128500
118000
122522
97000
36400
75800
65300
5-4122
1443500
193900
33900
57300
70200
72500
64222
45600
16200
23700)
74100)
1252221
775001
30500)
6000
31800
42122
143100
228500
303400
367800
421622
571200
710300
838800
956800
1264222
1161300
1247700
1323500
1388800
1442522
-------
Table A-178
MAGNESIA SCHEME 0, REGULATED PORTION COOPERATIVE ECONOMICS, SCRUBBING-DRYING, 200 MW NEW COAL FIRED UNIT, 3.5% S, MGS03 PROD.
$ 7671000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR »/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ MAGNESIUM COMPANY, MAGNESIUM REVENUE,
START KW SULFITE $/YEAR SULFITE $/YEAR
1 7000
2 7000
3 7000
4 7000
_5_ 2222
56200
56200
56200
56200
5620Q
6 7000 56200
7 7000 56200
8 7000 56200
9 7000 56200
12 _2222_ 562QQ
11 5000
12 5000
13 5000
14 5000
15_ -5222
16 3500
17 3500
18 3500
19 3500
ZQ 2522_
21 1500
22 1500
23 1500
24 1500
25 15QO
26 1500
27 1500
28 1500
29 1500
_22_ _1522_
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
^ EQUIVALENT
40200
40200
40200
40200
42222
28100
28100
28100
28100
2fil22
12100
12100
12100
12100
12122
12100
12100
12100
12100
121QD
4499500 0.0
4446300 0.0
4393100 0.0
4339900 0.0
4286700 0.0
4233500 0.0
4180400 0.0
4127200 0.0
4074000 0.0
402Q8JJ2 2.0
3316300 0.0
3263100 0.0
3209900 0.0
3156800 0.0
2123.622 2^2
2546900 0.0
2493700 0.0
2440500 0.0
2387300 0.0
2334100 0.0
1569800 0.0
1516600 0.0
1463400 0.0
1410200 0.0
1252222 2*2
1303800 0.0
1250600 0.0
1197500 0.0
1144300 0.0
12211QQ £UO
1024500 84157900
COST, DOLLARS PER TON OF COAL BURNED
CUST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0? TO INITIAL YEAR
PRESENT WORTH, DOLLARS PER TON OF COAL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
0
0
0
0
Q
0
0
0
0
0
0
0
0
2
0
0
0
0
0_
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
4499500
4446300
4393100
4339900
4286700
4233500
4180400
4127200
4074000
_ 4222322—
3316300
3263100
3209900
3156800
2122622
2546900
2493700
2440500
2387300
2334100
1569800
1516600
1463400
1410200
1357000
0 1303800
0 1250600
0 1197500
0 1144300
0_ 129110D
0
, DOLLARS
BURNED
84157900
8.61
3.30
34612600
3.54
1.36
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
4499500
8945800
13338900
17678800
21265522
26199000
30379400
34506600
38580600
—42621422-
45917700
49180800
52390700
55547500
_5fl651122
61198000
63691700
66132200
68519500
_22£5262fl_
72423400
73940000
75403400
76813600
_2M22622_
79474400
80725000
81922500
83066800
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST POR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR $ $
4388700 (
4338300 (
4288000 (
4237700 (
418.2222 1
4137000 (
4086700 (
4036300 (
3986000 (
—2225222 _I_.
3252900 (
3202600 (
3152200 (
3101900 (
2251622 _1_
2508100 (
2457800 (
2407500 (
2357100 (
2226fl22 1_-
1550300 (
1499900 (
1449600 (
1399300 (
1298600 (
1248200 1
1197900
1147600
1222222
82657700 (
8.46
3.24
33873300 {
3.47
1.33
110800)
108000)
105100)
102200)
224221 J
96500)
93700)
90900)
88000)
. -8.51221 J
63400)
60500)
57700)
54900)
522221 J
38800)
35900)
33000)
30200)
222221-J
19500)
16700)
13800)
10900)
5.1221 J
5200)
2400)
400
3300
6122
110800)
218800)
323900)
426100)
. 5255221
622000)
715700)
806600)
894600)
2222221
1043100)
1103600)
1161300)
1216200)
1307000)
1342900)
1375900)
1406100)
L 14224021
1452900)
1469600)
1483400)
1494300)
L 15224221
1507600)
1510000)
1509600)
1506300)
L 150Q2QO)
1500200)
739300)
-------
Table A-179
MAGNESIA SCHEME 0, NONREGULATED POKTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TQ 1 200 MW COAL FIRED UNIT, 3.5* S IN COAL.
FIXED INVESTMENT = $ 5017000
OVERALL INTEREST RATE OF RETURN = NEC
NO PAYOUT
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5,
6
7
8
9
_1Q_
TOT
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100* RECYCLE
H2S04 MGO
45200
45200
45200
45200
_ 45200
45200
45200
45200
45200
45200
452000
23600
23600
23600
23600
23600
23600
23600
23600
22600
236000
TOTAL
MFG.
COST,
S/YEAR
1651300
1651300
1651300
1651300
_16513.Qfl_
1651300
1651300
1651300
1651300
16513000
NET REVENUE, TOTAL
S/TON NET
SALES
100S RECYCLE REVENUE,
H2S04 MGO S/YEAR
12.00
12.00
12.00
12.00
12.00
12.00
12.00
12.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
1132400 (
1132400 I
1132400 <
1132400 (
1122400 i_
1132400 (
1132400 (
1132400 (
1132400 1
1132400 I
11324000 (
GROSS
INCOME,
S/YEAR
518900) (
513900) (
518900) {
518900) (
__51fl20Ql i
518900) (
518900) (
518900) (
518900) (
5189000) (
NET INCOME
AFTER
TAXES,
S/YEAR
259450)
2594501
259450)
259450)
2524501 .
259450)
259450)
259450)
259450)
2594500)
ANNUAL
CUMULATIVE RETURN ON
CASH CASH INITIAL
FLOW, FLOW, INVESTMENT,
S/YEAR $ %
242250
242250
242250
242250
242250
242250
242250
242250
242250
242250
2422500
242250
484500
726750
969000
1211250
1453500
1695750
1938000
2180250
24225Q2_
AVG=
-------
Table A-180
MAGNESIA SCHEMt 0, NHNREGULATfcD PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 1 200 Mrt COAL FIRED UNIT, 3.5* S IN COAL.
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
8
9
1Q.
PRODUCT RATE,
EQUIVALENT
TJNS/YfAk
100 t,
H2S04
45200
45200
45200
45200
4.5.^. iii _
45200
45200
45200
45^00
4.5.2.3.0.
RECYCLE
MGO
23600
23600
23600
23600
Z3_£>0_iJ
23600
23600
23000
23600
2i6piiJ
TOTAL
MFG.
COST,
S/YEAR
1651300
1651300
1651300
1651300
_ 16.5.120.0.
1051300
1651300
1651300
1651300
. lfi5.13.lJi3 .
FIXED INVESTMENT = $
UVFRALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE, TOTAL
t/TON NET
100*
H2S04
12.00
12. 00
12.00
12. 00
li.i.3_0_
12.00
12.00
12.00
12.00
12.J.O.O.
RECYCLE
MGO
55.00
55.00
55.00
55.00
55i.Qj_
55.00
55.00
55.00
55.00
5.5.^0.0. .
SALES
REVENUE,
S/YEAk
1840400
1840400
1840400
1340400
1S40.4.Q.Q .
1840400
1840400
1840400
1840400
1240.4.0.0. .
GROSS
INCOME,
S/YEAR
189100
139100
189100
189100
19.210.P.
189100
189100
189100
189100
1S21UC
5017000
3.3?
8.4
NET INCOMF
AFTER
TAXES,
S/YFAR
94550
94550
94550
94550
2i5_5_Q .
94550
94550
94550
94550
-245.5.Q .
CASH
FLOW,
S/YFAR
596250
596250
596250
596250
. _ 5_26.2.5_g._
596250
596250
596250
596250
- - 5.26.25.0.
CUMULATIVE
CASH
FLOW,
$
596250
1192500
1788750
2385000
2281250
3577500
4173750
4770000
5366250
59625QO
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
1.83
1.83
1.83
1.83
1*8.2
1.83
1.83
1.83
1.83
1*8.3
TUT
452000
236000
16513000
18404000
1891000
945500
5962500
1.83
to
-0
-------
Table A-181
MAGNESIA SCHEME D, NCNREuJLATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 5 200 MW COAL FIRED UNIT, 3.5? S
FIXED INVESTMENT = $ 12354000
OVERALL INTEREST RATE OF RETURN = 8.2?
YEARS REQUIRED FOR PAYOUT = 6.6
YEARS
AFTER
PLANT
START
UP
1
2
^
4
5,
6
7
8
9
LQ _
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
ICO*
H2SU4
226000
226000
226000
226000
2.Z.6. flOO
226000
226000
226000
226000
_ 226.QQfl... _
RECYCLE
MGO
118000
118000
118000
118000
713000
118000
118000
116000
118000
-llflfliiC __
TUTAL
MFG.
CJST,
$/YEAR
4414600
4414600
4414600
4414600
44.14.6.0.!}
4414600
4414600
4414600
4414600
_4jil4.6.Q.Q .
NET REVENUE,
t/TON
100*
H2S04
12.00
12.00
12.00
12.00
12 00
12.00
12.00
12.00
12.00
12*0.0.
RECYCLE
MGO
25.00
25.00
25.00
25.00
25*2Q
25.00
25.00
25.00
25.00
25.*aa
TOTAL
NET
SALES
REVENUE,
t/YEAR
5662000
5662000
5662000
5662000
56 6.20. QO'
5662000
5662000
5662000
5662000
5.6.6.20.0.0.
NET INCOME
GROSS
INCOME,
t/YEAR
1247400
1247400
1247400
1247400
124140.Q
1247400
1247400
1247400
1247400
12iliQfl
AFTER
TAXES,
t/YEAR
623700
623700
623700
623700
6.23.120.
623700
623700
623700
623700
62370,0.
CUMULATIVE
CASH
FLOW,
t/YEAR
1859100
1859100
1859100
1859100
i 8591 00
1859100
1859100
1859100
1859100
ia.S2io.fl
CASH
FLOW,
t
1859100
3718200
5577300
7436400
22255QQ
11154600
13013700
14872800
16731900
lfl5.21flflQ
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
4.88
4.88
4.88
4.88
t. 88
4.88
4.88
4.88
4.88
&*&£
TOT
2260000
1180000
44146000
56620000
12474000
6237000
18591000
AVG= 4.88
-------
Table A-182
MAGNESIA SCHEME 0, NONREGULAT ED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 5 200 Mri COAL FIREO UNIT, 3.5? S
FIXED INVESTMENT = * 12354000
OVERALL INTEREST RATE OF RETURN = 26.63!
YEARS REQUIRED FOR PAYOUT = 3.4
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
12
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
226000
226000
226000
226000
226000
226000
226000
226000
226000
226.222
RECYCLE
MGO
118000
118000
118000
118000
L1S222
118000
118000
118000
118000
1180.00
TOTAL
MFG.
COST,
S/YEAR
4414600
4414600
4414600
4414600
4.414.6.22
4414600
4414600
4414600
4414600
_ 4.4.14.6.22
NET REVENUE,
i/TON
100%
H2S04
12.00
12.00
12.00
12.00
12*22
12.00
12.00
12.00
12.00
TOTAL
NET
SALES
RECYCLE REVENUE,
MGO
55.00
55.00
55.00
55.00
55*22
55.00
55.00
55.00
55.00
55*22
*/YEAR
9202000
9202000
9202000
9202000
2222222
9202000
9202000
9202000
9202000
2222222
GROSS
INCOME,
S/YEAR
4787400
4787400
4787400
4787400
4.2B24.22
4787400
4787400
4787400
4787400
4.231^22
NET INCOME
AFTER
TAXES,
t/YEAR
2393700
2393700
2393700
2393700
2221222
2393700
2393700
2393700
2393700
23.23.222 _.
CUMULATIVE
CASH
FLOW,
S/YEAR
3629100
3629100
3629100
3629100
3.6.22122
3629100
3629100
3629100
3629100
._ 3.6.22122 .
CASH
FLOW,
$
3629100
7258200
10887300
14516400
1 gi 455 OQ
21774600
25403700
29032800
32661900
36221222
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
18.72
18.72
18.72
18.72
iQ 72
18.72
18.72
18.72
18.72
13*22
TOT
2260000
1180000
44146000
92020000
47874000
23937000
36291000
AVG= 18.72
-------
OJ
u>
o
Table A-183
MAGNtSIA SCHEME D, NONREGULATEO PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 10 200 MW COAL FIRED UNIT, 3.5? S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
a
9
10
PRODUCT RATE,
EQUIVALENT
TUNS/YEAR
100*
H2S04
452000
452000
451000
452000
45.22.2.2
452000
452000
452000
452000
422222
RECYCLE
MGO
236000
236000
236000
236000
236.fl0.2
236000
236000
236000
236000
. 224*222
TOTAL
MFG.
COST,
S/YEAR
7734100
7734100
7734100
7734100
1234122
7734100
7734100
7734100
7734100
. 1124122 .
FIXED INVESTMENT = $
OVERALL INTEREST RATE OF RETURN =
YCARS REQUIRED FDR PAYOUT =
NET REVENUE, TOTAL
S/TUN NET
100*
H2S04
12.00
12.00
12.00
12.00
12*.22_
12.00
12.00
12.00
12.00
12^.22
RECYCLE
MGO
25.00
25.00
25.00
25.00
25x22
25.00
25.00
25.00
25.00
25*22
SALES
REVENUE,
$/YEAR
11324000
11324000
11324000
11324000
-11224222
11324000
11324000
11324000
11324000
11224222
GROSS
INCOME,
S/YEAR
3589900
3589900
3589900
3589900
2532222
3589900
3589900
3589900
3589900
_ 2532222__
19534000
14.0?
5.2
NET INCOME
AFTER
TAXES,
t/YEAR
1794950
1794950
1794950
1794950
1124252
1794950
1794950
1794950
1794950
__1124252__.
CUMULATIVE
CASH
FLOW,
I/YEAR
3748350
3748350
3748350
3748350
214325.S
3748350
3748350
3748350
3748350
214325.2
CASH
FLOW,
$
3748350
7496700
11245050
14993400
13141252
22490100
26238450
29986800
33735150
31482522
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
8.82
8.82
8.82
8.82
9*32
8.82
8.82
8.82
8.82
3.32
TOT
4521)000
2360000
77341000
113240000
35899000
17949500
37483500
8.82
-------
Table A-184
MAGNESIA SCHEME D, NONRfGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EOUIV. TO 10 200 1W COAL FIRED UNIT, 3.5? S
FIXED INVESTMENT = * 19534000
OVERALL INTEREST RATE OF RETURN = 35.5%
YEARS REQUIRED FOR PAYOUT = 2.7
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
8
9
10
PROUUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
452000
452000
452000
452000
RECYCLE
MGO
236000
236000
236000
236000
4.5.20.0.0. 236000
4520UO
452000
45^000
452000
4.5.20. ilQ
236000
236000
236000
236000
23.6.0.0.0.
TOTAL
MFG.
COST,
S/YEAR
7734100
7734100
7734100
7734100
223.4.122
7734100
7734100
7734100
7734100
-223.4.122
NET REVENUE,
S/TON
100*
H2S04
12.00
12.00
12.00
12.00
12*2Q
12.00
12.00
12.00
12.00
12*22
RECYCLE
MGO
55.00
55.00
55.00
55.00
5.5,*2Q_.
55.00
55.00
55.00
55.00
5.5.*22
TOTAL
NET
SALES
REVENUE,
S/YEAR
18404000
13404000
18404000
18404000
ia4.24.222
18404000
18404000
18404000
18404000
Iai2i222
GROSS
INCOME,
S/YEAR
10669900
10669900
10669900
10669900
_ 126.62222
10669900
10669900
10669900
10669900
12 6.6.2222
NET INCOME
AFTER
TAXES,
S/YEAR
5334950
5334950
5334950
5334950
5.2.3.A2.5.Q
5334950
5334950
5334950
5334950
. __5.3.3.4.25Q .
CUMULATIVE
CASH
FLOW,
$/YEAR
7288350
7288350
7288350
7288350
22aa25.Q
7288350
7288350
7288350
7288350
Z2S.a3.5-0.
CASH
FLOW,
$
7288350
14576700
21865050
29153400
3.&44125Q
43730100
51018450
58306800
65595150
22&S25.0.0.
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
26.23
26.23
26.23
26.23
26*23
26.23
26.23
26.23
26.23
26*23
TOT
4520000 2360000
77341000
184040000
106699000
53349500
72883500
AVG=
26.23
OJ
LO
-------
Table A-185
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 15 200 MW COAL FIREO JNIT, 3.5? S
YEARS
A FT 6 R
PLANT
START
UP
1
2
3
4
5.
6
7
8
9
1Q_
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2SU4
678000
678000
678000
678000
ai8_o.QQ_
678000
078000
o7dOOO
678000
li/JiliaC
RECYCLE
MGO
354000
354000
354000
354000
3.5.4.0.0.!}
354000
354000
354000
354000
.35400Q .
TOTAL
MFG.
COST,
$/YEAR
10923800
10923800
10923800
10923800
1222330.0.
10923800
10923800
10923800
10923800
12223.3.20. .
FIXED INVESTMENT = *
OVERALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE, TOTAL
$/TON NET
100*
H2S04
12.00
12.00
12.00
12.00
12.m.Q£_
12.00
12.00
12.00
12.00
.12.00 .
RECYCLE
MGO
25.00
25.00
25.00
25.00
25x00
25.00
25.00
25.00
25.00
. __25*QQ_.
SALES
REVENUE,
S/YEAR
16986000
16986000
16986000
16986000
1&.28.6.QOQ
16986000
16986000
16986000
16986000
162S6.QC.Q
GROSS
INCOME,
S/YEAR
6062200
6062200
6062200
6062200
6062200
6062200
6062200
6062200
6062200
6flfi22Qfl__.
26096000
17.2?
4.6
NET INCOME
AFTER
TAXES,,
$/Y€AR-<
3031100
3031100
3031100
3031100
3.Q3.11QO
3031100
3031100
3031100
3031100
2Q3.11QQ
CUMULATIVE
CASH
FLOW,
$/YEAR
5640700
5640700
5640700
5640700
CASH
FLOW,
$
5640700
11281400
16922100
22562800
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
%
11.12
11.12
11.12
11.12
5.64QIOQ 28203500 H»12
5640700 33844200 11.12
5640700
5640700
5640700
._s&&aiatt
39484900
45125600
50766300
56407000
11.12
11.12
11.12
11*12
TOT
6780000
3540000 109238000
169960000
60622000
30311000
56407000
AVG= 11.12
-------
Table A-186
MAGNESIA SCHEME L>, NONREGULAT ED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 15 200 MW COAL FIRED UNIT, 3.5« S
FIXED INVESTMENT = t 26096000
OVERALL INTEREST RATE OF RETURN = 40.(>%
YEARS REQUIRED FOR PAYOUT = 2.4
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
111 .
PRODUCT RATE,
EQUIVALENT
TOMS/YEAR
100*
H2S04
i,78000
67dOOO
678000
6780JO
iiZ£i}0_0.
c78000
b76000
b78000
678000
RECYCLE
MGO
354000
354000
354000
354000
3. Scully
354000
354000
354000
354000
TOTAL
MFG.
COST,
S/YEAR
10923800
10923800
10923800
10923800
NET REVENUE,
S/TON
100% RECYCLE
H2S04
12.00
12.00
12.00
12.00
MGO
55.00
55.00
55.00
55.00
11222.3.30.0. 12..QQ 55..QQ
10923800
10923800
10923800
10923800
67&000 354000 10923800
12.00
12.00
12.00
12.00
12..0.0._
55.00
55.00
55.00
55.00
55*. 0.0.
TOTAL
NET
SALES
REVENUE,
$/YEAR
27606000
27606005
27606000
27606000
2Z&Q&.O.UO. .
27606000
27606000
27606000
27606000
_ 226.Q6.QQO. _.
GROSS
INCOME,
S/YEAR
16682200
16682200
16682200
16682200
16.6.8.22.0.0..
16682200
16682200
16682200
16602200
NET INCOME
AFTER
TAXES,
i/YEAR
8341100
8341100
8341100
8341100
3341100
8341100
8341100
8341100
8341100
ANNUAL
CUMULATIVE RETURN ON
CASH
FLOW,
$/YEAR
10950700
10950700
10950700
10950700
_10.25Q1QQ_
10950700
10953700
10950700
10950700
_16fr.fl220.fl aaillflQ 10^5.0.10.0.
CASH INITIAL
FLOW, INVESTMENT,
$
10950700
21901400
32852100
43802800
5415350.0
65704200
76654900
87605600
98556300
_10.35fllQQQ
*
30.59
30.59
30.59
30.59
30.4.53
30.59
30.59
30.59
30.59
30*52
TOT
67BOOOO
3540000
109238000
276060000
166822000
83411000
109507000
AVG= 30.59
LO
U>
U)
-------
OJ
U)
Table A-187
MAGNESIA SCHEME D, REGULATED PORTION COOPERATIVE ECONOMICS! SCRUBBING-DRYING, 500 MW NEW COAL FIRED UNIT, 3.5* S, MGS03 PROD.
Computation basis: cost of recycle MgO-$15/ton FIXED INVESTMENT: $
Includes comparison with projected operating cost of low-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING NET ANNUAL
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL INCREASE
AFTER. OPERA- TONS/YEAR R01 FOR S/TON NET (DECREASE)
POWER TION, POWER SALES IN COST OF
UNIT KW-HR/ MAGNESIUM COMPANY, MAGNESIUM REVENUE, POWE*,
START K.h SULFITE S/YEAR SULFITE $/YEAR $
1 7000
2 7000
3 7000
4 7000
_5 ZQOQ
6 7000
7 7000
8 7COO
9 7000
10 7QQO
11 5000
12 5000
13 5000
14 5000
15 .. 5QQCL
16 35CO
17 3500
18 3500
19 3500
2Q 3500
21 1500
22 1500
23 1500
24 1500
25 15OCU
26 1500
27 1500
28 1500
29 1500
30 1 500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
133600
133600
133600
133600
_1326Qtt .
133600
133600
133600
133600
1336QQ
95400
95400
95400
95400
2540,0
66800
66800
66800
66800
66.8.00
28600
28600
28600
28600
26600
28600
28600
28600
28600
286QQ ,
7049700
6946700
6843800
6740900
6.6.330.0^1
6535100
6432100
6329200
6226300
6.12.340.0.
5214300
5111300
5008400
4905500
430.26.flO_
4069000
3966100
3863100
3760200
36.5_130.0_
2645200
2542300
2439300
2336400
—22325 OS
2130600
2027700
1924800
1821800
1718900
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
. Q*0_
0.0
0.0
0.0
0.0
o.O
0.0
0.0
0.0
0.0
q.o
0.0
0.0
0.0
0.0
Q^Jl
0.0
0.0
0.0
0.0
Q..Q.
2433000 132043500
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KI LOWATT-HOUF.
IF DISCOUNTED AT 10.0* TO INITIAL YEAR
PRESENT WORTH, DOLLARS PER TON OF COAL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
0
0
0
0
a
0
0
0
0
Q
0
0
0
0
Q_ .
0
0
0
0
Q
0
0
0
0
Q_ .
0
0
0
0
Q__.
0
, DOLLARS
BURNED
7049700
6946700
6843800
6740900
. 6.6.3. ao_ao.
6535100
6432100
6329200
6226300
_ 6.123400.
5214303
5111300
5008400
4905500
4302600
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
C3ST FOR NON- SAVINGS SAVINGS
RECDVF.RY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
CUMULATIVE INCLUDING PROCESS PROCESS
NET INCREASE REGULATED INSTEAD INSTEAD
(DECREASE) ROI FOR OF WET- OF WET-
IN COST OF POWER LIMESTONE LIMESTONE
POWER, COMPANY, SCRUBBING, SCRUBBING,
* $/YEAR * t
7049700
13996400
20840200
27581100
142121.0.0. _.
40754200
47186300
53515500
59741800
6.5.36.5.20.0,
71079500
76190800
81199200
86104700
9Q9Q13QQ _
4069000 94976300
3966100 98942400
3863100 102805500
3760200 106565700
_36.57.3QQ 110223000
2645200
2542300
2439300
2336400
-22.13.5Jia _
2130600
2027700
1924800
1821800
1113200—
132043500
5.52
2.07
538988CO
7.25
0.85
112868200
115410500
117849800
120186200
122412IQQ.
124550300
126578000
128502800
130324600
-13.2043500
7209600
7087400
6965200
6843000
6.120200.
6598700
6476500
6354300
6232100
6.1100,00. I
5381100
5258900
5136700
5014500
._ _43224Q.Q
4280700
4158500
403630O
3914200
3-2220.0.0.
2926100
2803900
2681700
2559600
-243I4Q1
2315200
2)93000
2070800
1948700
18.26.50.0.
136225900
5.70
2.14
54984900
2.30
0.86
159900
140700
121400
102100
3220.0.
63600
44400
25100
5800
1340.0.1
166800
147600
128300
109000
32300.
211700
192400
173200
154000
13410.0.
280900
261600
242400
223200
20320.0.
184600
165300
146000
126900
1QI6.Q.Q
4182400
1086100
159900
300600
422000
524100
— 6.01000-
670600
715000
740100
745900
1225QQ
899300
1046900
1175200
1284200
12.140.0.0.
1585700
1778100
1951300
2105300
2,240.000
2520900
2782500
3024900
3248100
3.4520QQ
3636600
3801900
3947900
4074800
4182400
-------
Table A-188
MAGNESIA SCHEME D, REGULATED PORTION COOPERATIVE ECONOMICS, SCRUBS ING-DRYING, 500 MW NEW COAL FIRED UNIT, 3.5? S, MGS03 PROD.
* 14844000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
_5
6
7
8
9
10
11
12
13
14
15—
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
ANNUAL
OPERA-
TION,
KW-HR/
KW
7000
7000
7000
7000
2020
7000
7000
7000
7000
_ 7000
5000
5000
5000
5000
-5.222
3500
3500
3500
3500
350Q
1500
1500
1500
1500
1522
1500
1500
1500
1500
. _1522 __
EQUIVALENT
TONS/YEAR
MAGNESIUM
SULFITE
133600
133600
133600
133600
1.3.3- .&20
133600
133600
133600
133600
1336QO
95400
95400
95400
95400
95.422
66800
66800
(6800
66800
66800
28600
28600
28600
28600
23.602
28600
28600
28600
28600
2B£22
REGULATED
ROI POR
POWER
COMPANY,
S/YEAR
9289700
9186700
9083800
8980900
3S23220
8775100
8672100
8569200
8466300
83 634QO
6814300
6711300
6608400
6505500
£.4226.00
5189000
5086100
4983100
4880200
42223.20
3125200
3022300
2919300
2816400
27135.0Q
2610600
2507700
2404800
2301800
. -2123222-.
NET REVENUE,
t/TON
MAGNESIUM
SULFITE
0.0
0.0
0.0
0.0
o».o
0.0
0.0
0.0
0.0
2*0
0.0
0.0
0.0
0.0
np
0.0
0.0
0.0
0.0
_2jtO_
0.0
0.0
0.0
0.0
0*0 _ _
0.0
0.0
0.0
0.0
_2,Q
TOTAL
NET
SALES
REVENUE,
I/YEAR
0
0
0
0
2
0
0
0
0
0
0
0
0
0
_ 2
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
9289700
9186700
9083800
8980900
8878000
8775100
8672100
8569200
8466300
__.8.26.2422 _
6814300
6711300
6608400
6505500
64226.Q2
5189000
5086100
4983100
4880200
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
9289700
18476400
27560200
36541100
-45412100
54194200
62866300
71435500
79901800
33265200
95079500
101790800
108399200
114904700
—1213.023.00
126496300
131582400
136565500
141445700
fl_ 41223.00 146222QQQ
0
0
0
0
0_
0
0
0
0
_ _ 2.
3125200
3022300
2919300
2816400
2213.500-
2610600
2507700
2404800
2301800
2198900
149348200
152370500
155289800
158106200
__lfLQ312202_
163430300
165938000
168342800
170644600
_ 122343.522—
ALTERNATI VE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
RFGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
9115900
9016300
8916700
8317100
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
( 173800) (
( 170400) (
( 167100) (
( 163800) (
INSTEAD
OF WFT-
LIMESTONE
SCRUBBING,
$
173800)
344200)
511300)
675100)
3212600 t 16Q40Q1 i 8255001
8618000
8518400
8418800
8319200
_ B2.126.QQ
6719600
6620000
6520400
6420800
6.221220-
5139500
5039900
4940300
4840700
4241120
3114300
3014700
2915100
2315500
__ 2215222
2616400
2516800
2417200
2317600
_ 2213222
( 157100) (
I 153700) (
( 150400) (
( 147100) 1
I_ 1423201 i.
( 94700) I
( 91300) (
( 88000) (
( 84700) (
i 314001 i
( 49500) {
( 46200) (
( 42800) (
( 39500) (
992600)
1146300)
1296700)
1443800)
15876QQ1
1682300)
1773600)
1861600)
1946300)
-22222221
2077200)
2123400)
2166200)
2205700)
_i 26.2QQ1-JL- 2241900)
t 10900) (
( 7600) (
( 4200) (
( 900) (
2402 1
5800 {
9100 (
12400 (
15800 I
12120 1
2252800)
2260400)
2264600)
2265500)
226.2.1201
2257300)
2248200)
2235800)
2220000)
. 22202Q21
TOT 127500 2433000 172843500 0 172843500
EQUIVALENT COST, DOLLARS PEP TON OF COAL BURNED 7.23
EQUIVALENT COST, MILLS PER KILOWATT-HOUR 2.71
PRESENT WORTH IF DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS 71455800
EQUIVALENT PRFSFNT WORTH, DOLLARS PER TON OF COAL BURNED 2.99
EQUIVALENT PRESENT WORTH, MILLS PER KILOWATT-HOUR 1.12
170642600
7.14
2.68
70296800
2.94
1.10
2200900)
1159000)
-------
Table A-189
MAGNESIA SCHEME D, NONREGULATED POKTIUN COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 1 500 MW COAL FIRED UNIT, 3.5* S
FIXED INVESTMENT = t 8294000
OVERALL INTEREST RATE OF RETURN = NEG
NO PAYOUT
PRODUCT RATE,
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
Ifl -
EQUIVALENT
TONS/YEAR
100*
H2S04
110400
110400
110400
110400
11Q4P.O.
110400
110400
110400
110400
lli}4.iiiJ
RECYCLE
MGfl
56000
56000
56000
56000
_ 56.i2g.il
56000
56000
56000
5t>000
5-iQ.Qfl
TOTAL
MFG.
COST,
S/YEAR
2838500
2838500
2833500
2838500
2aia5.o.o_
2836500
2838500
2838500
2833500
2&3.8..5.0.3.
NET REVENUE,
S/TON
100% RECYCLE
H2S04 MGO
12.00
12.00
12.00
12.00
_12iQfl
12.00
12.00
12.00
12.00
12x0.0.
15.00
15.00
15.00
15.00
15iCU
15.00
15.00
15.00
15.00
1.5 xQQ.
TOTAL
NET NET INCOME
SALES GROSS AFTER
REVENUE, INCOME, TAXES,
$/YEAR S/YEAR $/YEAR
2164800 ( 673700)
2164800 ( 673700)
2164800
216480J
216.4.SflQ _J
2164800
2164800
2164800
2164800
673700)
673700)
623IQC1 J
673700)
673700)
673700)
673700)
336850)
336850)
336850)
336850)
L 3.3-6.8.5.0.1
336850)
336850)
336850)
336850)
216,430.3 _I 6I22flfll_i 3.3_&.a5.0.1__
ANNUAL
CUMULATIVE RETURN ON
CASH
FLOW,
S/YEAR
492550
492550
492550
492550
42255.2
492550
492550
492550
492550
42255. 0.
CASH INITIAL
FLOW, INVESTMENT,
S %
492550
985100
1477650
1970200
246225Q
2955300
3447850
3940400
4432950
422.5500
TOT
1104000
560000
28385000
21648000 ( 6737000) (
3368500)
4925500
AVG=
-------
Table A-190
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 1 500 MW COAL FIRED UNIT, 3.5% S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
10 _
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
110400
110400
110400
110400
11Q4.UO
110400
110400
110400
110400
. 112400
RECYCLE
MGO
56000
56000
5&000
56000
56.000
56000
56000
56000
56000
_ 56.222
TOTAL
MFG.
COST,
S/YEAR
2838500
2838500
2838500
2838500
2333520
2838500
2838500
2838500
2838500
,_ 2333522
FIXED INVESTMENT = $
OVERALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE, TOTAL
$/TON NET
100*
H2S04
12.00
12.00
12.00
12.00
12*02
12.00
12.00
12.00
12.00
_ 12*22_
RECYCLE
MGO
55.00
55.00
55.00
55.00
55*02
55.00
55.00
55.00
55.00
55*00 .
SALES
REVENUE,
S/YEAR
4404800
4404800
4404800
4404800
-_ _44Q4SflO .
4404800
4404800
4404800
4404800
GROSS
INCOME,
S/YEAR
1566300
1566300
1566300
1566300
1566200 _
1566300
1566300
1566300
1566300
8294000
14.4*
5.1
NET INCOME
AFTER
TAXES,
S/YEAR
783150
783150
783150
783150
133.150 .
783150
783150
783150
783150
. -.4404800 . ,. 1566200 .783150. .
ANNUAL
CUMULATIVE RETURN ON
CASH
FLOW,
S/YEAR
1612550
1612550
1612550
1612550
16,12.5.50,
1612550
1612550
1612550
1612550
1612.550 _
CASH INITIAL
FLOW, INVESTMENT,
t *
1612550
3225100
4837650
6450200
2262250
9675300
11287850
12900400
14512950
—16125503
9.15
9.15
9.15
9.15
3*15
9.15
9.15
9.15
9.15
3*15
TOT
1104000
560000
28385000
44048000
15663000
7831500
16125500
AVG=
9.15
OJ
LO
-o
-------
OJ
1-0
oo
Table A-191
MAGNESIA SCHEME 0, NONREGULAT ED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROO. EQUIV. TO 2 500 MM COAL FIRED UNITS, 3.5% S
FIXED INVESTMENT = $ 12354000
OVERALL INTEREST RATE OF RETURN = 0.3?
YEARS REQUIRED FOR PAYOUT = 9.9
YEARS
AFTER
PLANT
START
UP
1
2
3
4
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
220800
220800
220800
220800
RECYCLE
MGO
112000
112000
112000
112000
TOTAL
MFG.
COST,
$/YEAR
4292300
4292300
4292300
4292300
NET REVENUE,
J/TON
100S
H2S04
12.00
12.00
12.00
12.00
RECYCLE
MGO
15.00
15.00
15.00
15.00
_5 220800 112QQQ 42223J3Q 12*.QQ 15_^QQ _
6
7
8
9
10
220800
220800
220800
220800
222.8.0-2
112000
112000
112000
112000
_ 1120.QQ
4292300
4292300
4292300
4292300
__4.2223.flQ .
12.00
12.00
12.00
12.00
12.»Q{1_
15.00
15.00
15.00
15.00
liiflfl
TOTAL
NET
SALES
REVENUE,
$/YEAR
4329600
4329600
4329600
4329600
4.3.226.0.0.
4329600
4329600
4329600
4329600
4.3.226.20.
GROSS
INCOME,
S/YEAR
37300
37300
37300
37300
__3_23.0_fl_
37300
37300
37300
37300
_ 3.23.22__
NET INCOME
AFTER
TAXES,
t/YEAR
18650
18650
18650
18650
Lfl6.£2__
18650
18650
18650
18650
1S65.2
CUMULATIVE
CASH
FLOW,
S/YEAR
1254050
1254050
1254050
1254050
12^4.25.2
1254050
1254050
1254050
1254050
12,5.4.052
CASH
FLOW,
$
1254050
2508100
3762150
5016200
6223252
7524300
8778350
10032400
11286450
i25.4Q_5.02
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
0.15
0.15
0.15
0.15
fl»15
0.15
0.15
0.15
0.15
0*1.5.
TOT
2208000
1120000
42923000
43296000
373000
186500
12540500
AV6= 0.15
-------
Table A-192
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 2 500 MW COAL FIRED UNITS, 3.51 S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
8
9
1Q_
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
220800
220800
220800
220800
22P.8.Q.1}
220800
220800
220800
220800
22iiiiiO.
RECYCLE
MGO
112000
112000
112000
112000
XltiMOl
112000
112000
112000
112000
112GO.Q
TOTAL
MFG.
COST,
t/YEAR
4292300
4292300
4292300
4292300
4.2223.20.
4292300
4292300
4292300
4292300
4.22230.0. .
FIXED INVESTMENT = t
OVERALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE, TOTAL
$/TON NET
100*
H2S04
12.00
12.00
12.00
12.00
12.00
12.00
12.00
12.00
12.00
12*2.0.
RECYCLE
MGO
55.00
55.00
55.00
55.00
55*0.2—
55.00
55.00
55.00
55.00
55*22
SALES
REVENUE,
t/YEAR
8809600
8809600
8809600
3809600
. _ 33226.22 .
8809600
8809600
8809600
8809600
£8.0.26.0.0. .
GROSS
INCOME,
t/YEAR
4517300
4517300
4517300
4517300
4.5123.0.0.
4517300
4517300
4517300
4517300
4.5.1Z3.0.0.
12354000
25.3%
3.5
NET INCOME
AFTER
TAXES,
t/YEAR
2258650
2258650
2258650
2258650
2256.6.50. _.
2258650
2258650
2258650
2258650
225.3.6. 5.0.
CUMULATIVE
CASH
FLOW,
t/YEAR
3494050
3494050
3494050
3494050
3.4.24-0-5.2
3494050
3494050
3494050
3494050
3-4.9.4_25_2
CASH
FLOW,
$
3494050
6988100
10482150
13976200
- 124.2Q25Q
20964300
24458350
27952400
31446450
3.4.24.0.5.0.0
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
17.69
17.69
17.69
17.69
12*62
17.69
17.69
17.69
17.69
12*62
TOT
2208000
1120000
42923000
88096000
45173000
22586500
34940500
17.69
-------
U)
4^
O
Table A-193
MAGNESIA SCHEME 0, NOMREGULAT ED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 4 500 MW COAL FIRED UNITS, 3.5? S
FIXED INVESTMENT = $ 19534000
OVERALL INTEREST RATE OF RETURN = 5.1*
YEARS REQUIRED FOR PAYOUT = 7.7
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
8
9
10
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
441600
441600
441600
441600
4416QO
441600
441600
441600
441600
441600,
RECYCLE
MGO
224000
224000
224000
224000
224222
224000
224000
224000
224000
. _22A222
TOTAL
MFG.
COST,
S/YEAR
7473200
7473200
7473200
7473200
2423.2.22 .
7473200
7473200
7473200
7473200
NET REVENUE,
S/TON
100%
H2S04
12.00
12.00
12.00
12.00
_12*22-
12.00
12.00
12.00
12.00
12*g.O.
RECYCLE
MGO
15.00
15.00
15.00
15.00
15.4.0.0.
15.00
15.00
15.00
15.00
15.a.22
TOTAL
NET
SALES
REVENUE,
$/YFAR
8659200
8659200
8659200
8659200
8.6.5.220.2
8659200
8659200
8659200
8659200
£6.5.2222
GROSS
INCOME,
$/YEAR
1186000
1186000
1186000
1186000
113&222
1186000
1186000
1186000
1186000
1126222
NET INCOME
AFTER
TAXES,
$/YEAR
593000
593000
593000
593000
5.22222
593000
593000
593000
593000
5.23.222
CUMULATIVE
CASH
FLOW,
S/YEAR
2546400
2546400
2546400
2546400
25^6422
2546400
2546400
2546400
2546400
2.5^6.422
CASH
FLOW,
$
2546400
5092800
7639200
10185600
12222222
15278400
17824800
20371200
22917600
25.464222
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
2.92
2.92
2.92
2.92
lm.22
2.92
2.92
2.92
2.92
2*22
TOT
4416000
2240000
74732000
86592000
11860000
5930000
25464000
AVG*
2.92
-------
Table A-194
MAGNESIA SCHEME 0, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 4 500 MM COAL FIRED UNITS, 3.5* S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
L2
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100?
H2S04
441600
441600
441600
441600
441600
441600
441600
441600
441600
A4J.6.22
RECYCLE
MGO
224000
224000
224000
224000
224000
224000
224000
224000
224000
. _2.Z4222
TOTAL
MFG.
COST,
S/YEAR
7473200
7473200
7473200
7473200
. 24.23.22fl.
7473200
7473200
7473200
7473200
1AI122Q
FIXED INVESTMENT = $
OVERALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE, TOTAL
i/TON NET
100*
H2S04
12.00
12.00
12.00
12.00
RECYCLE
MGO
55.00
55.00
55.00
55.00
._ _12*QQ 55*0.0
12.00
12.00
12.00
12.00
12*22
55.00
55.00
55.00
55.00
.5.5*0.0.
SALES
REVENUE,
i/YEAR
17619200
17619200
17619200
17619200
_ iI6.122.2Q
17619200
17619200
17619200
17619200
__U6122fl2 __
GROSS
INCOME,
$/YEAR
10146000
10146000
10146000
10146000
10.14.6222 _.
10146000
10146000
10146000
10146000
19534000
34.1*
2.8
NET INCOME
AFTER
TAXES,
i/YEAR
5073000
5073000
5073000
5073000
5213.222
5073000
5073000
5073000
5073000
__1214.6.2Q2 5Q23.QQP. _.
CUMULATIVE
CASH
FLOW,
i/YEAR
7026400
7026400
7026400
7026400
122.6.4.22 _
7026400
7026400
7026400
7026400
122.6.4.22 _
CASH
FLOW,
i
7026400
14052800
21079200
28105600
3.5.13.2Q22
42158400
49184800
56211200
63237600
12264.222
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
24.99
24.99
24.99
24.99
24*22
24.99
24.99
24.99
24.99
24.99
TOT
4416000
2240000
747J2000
176192000
101460000
50730000
70264000
AV6=
24.99
-------
U)
-^
to
Table A-195
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 6 500 M* COAL FIRED UNITS, 3.5* S
FIXED INVESTMENT = $ 26096000
OVERALL INTEREST RATE OF RETURN = 8.7%
YEARS REQUIRED FOR PAYOUT = 6.5
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5.
6
7
8
9
10
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
662400
662400
662400
662400
662422
662400
662400
662400
662400
_ 662^00
RECYCLE
MGO
336000
336000
336000
336000
-3.3.6.222
336000
336000
336000
336000
336000
TOTAL
MFG.
COST,
t/YEAR
10190700
10190700
10190700
10190700
12122222
10190700
10190700
10190700
10190700
1019.0700
NET REVENUE,
S/TON
100*
H2S04
12.00
12.00
12.00
12.00
12x22
12.00
12.00
12.00
12.00
-IZxQQ.
RECYCLE
MGO
15.00
15.00
15.00
15.00
15x22
15.00
15.00
15.00
15.00
15x211
TOTAL
NET
SALES
REVENUE,
S/YEAR
12988800
12988800
12988800
12988800
12.23.3.8.22
12988800
12988800
12988800
12988800
12233322
NET INCOME
GROSS
INCOME,
$/YEAR
2798100
2798100
2798100
2798100
_212aiQ2
2798100
2798100
2798100
2798100
AFTER
TAXES,
$/YEAR
1399050
1399050
1399050
1399050
1122252
1399050
1399050
1399050
1399050
.1399050
CASH
FLOW,
S/YEAR
4008650
4008650
4008650
4008650
4222652
4008650
4008650
4008650
4008650
4Q.Qflfi.5Q
CUMULATIVE
CASH
FLOW,
$
4008650
8017300
12025950
16034600
2.2242250.
24051900
28060550
32069200
36077850
42236522
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
5.15
5.15
5.15
5.15
C 1C
5.15
5.15
5.15
5.15
__5xJ5
TOT
6624000
3360000
101907000
129888000
27981000
13990500
40086500
AVG=
5.15
-------
Table A-196
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EO.UIV. TO 6 500 M* COAL FIRED UNITS, 3.5? S
FIXED INVESTMENT = $ 26096000
OVERALL INTEREST RATE OF RETURN = 39.1%
YEARS REQUIRED FOR PAYOUT = 2.4
YEARS
AFTER
PLANT
START
UP
1
2
3
4
6
7
8
9
10
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
662400
662400
662400
662400
6^2.4.0,0
662400
662400
662400
662400
662400
RECYCLE
MGO
336000
336000
336000
336000
3.16flQ.a._-
336000
336000
336000
336000
336(000
TOTAL
MFG.
COST,
$/YEAR
10190700
10190700
10190700
10190700
10J.2flIQfl_.
10190700
10190700
10190700
10190700
NET REVENUE,
S/TON
100?
H2S04
12.00
12.00
12.00
12.00
RECYCLE
MGO
55.00
55.00
55.00
55.00
12»flfl_ 5.5.A.Q.Q
12.00
12.00
12.00
12.00
55.00
55.00
55.00
55.00
TOTAL
NET
SALES
REVENUE,
$/YEAR
26428800
26428800
26428800
26428800
_26.4.2aaO.Q_
26428800
26428800
26428800
26428800
GROSS
INCOME,
$/YEAR
16238100
16238100
16238100
16238100
-i&ziaiao.
16238100
16238100
16238100
16238100
iQ12fl2flfl 12*flO. 55*.flQ. 26.4.23.30.0. 16.23.&10.Q.
NET
' INCOME
AFTER
'AXES,
i/YEAR
8119050
8119050
8119050
8119050
8119050
8119050
8119050
8119050
.ail2Q5fl
CUMULATIVE
CASH CASH
FLOW, FLOW,
S/YEAR $
10728650
10728650
10728650
10728650
10728650
10728650
10728650
10728650
10728650
21457300
32185950
42914600
.52643252
64371900
75100550
85829200
96557850
LO.Z2flfi50.fl
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
?
29.89
29.89
29.89
29.89
29.89
29.89
29.89
29.89
22.82
TOT
6624000 3360000
101907000
264288000
162381000
81190500
107286500
AVG=
29.89
-------
Table A-197
MAGNESIA SCHEME 0, REGULATED PORTION COOPERATIVE ECONOMICS, SCRUBSING-DRYING, 1000 MW NEW COAL FIRED UNIT, 3.5* S, MGS03 PROD.
Compu tation basis: cost of recycle MgO-$l Of ton
FIXED INVESTMENT:
22673000
ALTERNATIVE
Includes comparison with projected operating cost of low-cost limestone process OPERATING
COST FOR NON-
RECOVERY WET-
TOTAL LIMESTONE
MFG. COST PROCESS
PRODUCT RATE, INCLUDING NET ANNUAL CUMULATIVE INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL INCREASE NET INCREASE REGULATED
AFTER OPERA- TONS/YEAR ROI FOR $/TON NET (DECREASE) (DECREASE) ROI FOR
POWER TION, POWER SALES IN COST OF IN COST OF POWER
UNIT KW-HR/ MAGNESIUM COMPANY, MAGNESIUM REVENUE, POWER, POWER, COMPANY,
START KW SULFITE i/YEAR SULFITE */YEAR $ $ I/YEAR
1 7000
2 7000
3 7000
4 7000
6 7000
7 7000
8 7000
9 7000
Ifl 7QQQ
11 5000
12 5000
13 5000
14 5000
15 _ 5000_
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
29 1500
30 J.50Q
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
258300
258300
258300
258300
10850800
10693600
10536400
10379200
10222000 _
258300 10064800
258300 9907500
258300 9750300
258300 959310C
258300 .. 9435900
184500
184500
184500
184500
1B45CO
129100
129100
129100
129100
55300
55300
55300
55300
55300, __
55300
55300
55300
55300
55300
8021100
7863900
7706700
7549500
7392300
6252700
6095500
5938300
5781100
4053400
3896100
3738900
3581700
3267300
3110100
2952900
2795700
2638500
0.0
0.0
0.0
0.0
Q&fl
0.0
0.0
0.0
0.0
0.0
0
0
0
0
n
0
0
0
0
0
0.0 0
0.0 0
0.0 0
0.0 0
0.0 0
0.0 0
0.0 0
0.0 0
0&0 o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4704000 203117700
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
PRESENT WORTH, DOLLARS PER TON OF COAL BURNED
PRESENT WORTH, MILLS PER KILOWATT-HOUR
0
0
0
0
0
0
0
0
0
0
10850800
10693600
10536400
10379200
lflZ22.flflfl
10064800
9907500
9750300
9593100
8021100~
7863900
7706700
7549500
73923QO
6252700
6095500
5938300
5781100
4053400~
3896100
3738900
3581700
3424500 _
3267300
3110100
2952900
2795700
_ 26.3.fl5flfl_ .
203117700
4.39
1.59
82965000
1.80
0.65
10850800 11082800
21544400 10892700
32080800 10702700
42460000 10512600
526fl2Qflfl LQ3.225flfl
62746800 10132500
72654300 9942400
82404600 9752300
91997700 9562200 (
_1Q1433£D.Q 222220C I_
109454700 8236300
117318600 8046200
125025300 7856200
132574800 7666100
139967100 14.I6.QflC
146219800 6530600
152315300 6340600
158253600 6150500
164034700 5960400
. 16965B6QQ SIlflAflfl
173712000 4451700
177608100 4261600
181347000 4071600
184928700 3881500
Ififl3-522flfl _ -36.314.flfl
191620500
194730600
197683500
200479200
__2.flilllZflfl _
3501300
3311300
3121200
2931100
2I4.11Q.Q- .
208272000
4.51
1.63
84316100
1.82
0.66
ANNUAL
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
232000
199100
166300
133400
Iflfliflfl
67700
34900
2000
30900)
215200
182300
149500
116600
277900
245100
212200
179300
398300
365500
332700
299800
26.62flfl
234000
201200
168300
135400
5154300
1351100
CUMULATIVE
SAVINGS
(LOSS)
USING
RECOVERY
PROCESS
INSTEAD
OF WET-
LIMESTONE
SCRUBBING,
$
232000
431100
597400
730800
fl3J.2flfl_
899000
933900
935900
905000
fl4.L30.fl-
1056500
1238800
1388300
1504900
15SS6QO
1866500
2111600
2323800
2503100
3047900
3413400
3746100
4045900
4546800
4748000
4916300
5051700
-------
Table A-198
MAGNESIA SCHEME D, REGULATED PORTION COOPERAT[VF ECONOMICS, SCRUBS ING-DRY ING, 1000 MW NEW COAL FIRED UNIT, 3.558 S, MGS03 PROD.
$ 22673000
Includes comparison with projected operating cost of high-cost limestone process
TOTAL
MFG. COST
PRODUCT RATE, INCLUDING
YEARS ANNUAL EQUIVALENT REGULATED NET REVENUE, TOTAL
AFTER OPERA- TONS/YEAR ROI FOR S/TON NET
POWER TION, POWER SALES
UNIT KW-HR/ MAGNESIUM COMPANY, MAGNESIUM REVENUE,
START KW SULFITE I/YEAR SULFITE $/YEAR
1 7000
2 7000
3 7000
4 7000
_5 _2QQO_
6 7000
7 7000
8 7000
9 7000
10 2QQQ-
11 5000
12 5000
13 5000
14 5000
_15 5.000
16 3500
17 3500
18 3500
19 3500
2Q 3.5.0.Q
21 1500
22 1500
23 1500
24 1500
26 1500
27 1500
28 1500
29 1500
30 1500
TOT 127500
EQUIVALENT
EQUIVALENT
PRESENT WORTH
EQUIVALENT
EQUIVALENT
258300
258300
258300
258300
25.3100
258300
258300
258300
258300
25.fi3.QO
184500
184500
184500
184500
129100
129100
129100
129100
_ _ 1221QQ
55300
55300
55300
55300
5.5.3.QQ
55300
55300
55300
55300
5.53.00
15722700
15565500
15408300
15251100
15Q23J2QQ
14936700
14779400
14622200
14465000
_ 14-3.028.00
11501100
11343900
11186700
11029500
8688700
8531500
8374300
8217100
3052200
5097400
4940100
4782900
4625700
_ _ 4468500
4311300
4154100
3996900
3339700
36B2500
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
SLtS.
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4704000 291856700
COST, DOLLARS PER TON OF COAL BURNED
COST, MILLS PER KILOWATT-HOUR
IF DISCOUNTED AT 10.02 TO INITIAL YEAR
PRESENT WORTH, DOLLARS PE» TON OF COAL
PRESENT WORTH, MILLS PER KILOWATT-HOUR
0
0
0
0
Q
0
0
0
0
Q
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
a
0
, DOLLARS
BURNED
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$ $
15722700
15565500
15408300
15251100
_ 15Q23.2QQ
14936700
14779400
14622200
14465000
15722700
31288200
46696500
61947600
_ 22Q4.15QQ .
91978200
106757600
121379800
135844800
15Q15_2600 _
11501100 161653700
11343900 172997600
11186700 184184300
11029500 195213800
!Q3223flQ 2060a61QQ_.
8688700 214774800
8531500 223306300
8374300 231680600
8217100 239897700
8Q592PO 247957600
5007400
4940100
4782900
4625700
_ _ 4A635QQ
4311300
4154100
3996900
3839700
291856700
6.31
2.29
121150900
2.62
0.95
253055000
257995100
262778000
267403700
22ia222QQ .
276183500
280337600
2843^4500
288174200
2218.56.200
ALTERNATIVE
OPERATING ANNUAL CUMULATIVE
COST FOR NON- SAVINGS SAVINGS
RECOVERY WET- (LOSS) (LOSS)
LIMESTONE USING USING
PROCESS RECOVERY RECOVERY
INCLUDING PROCESS PROCESS
REGULATED INSTEAD INSTEAD
ROI FOR OF WET- OF WET-
POWER LIMESTONE LIMESTONE
COMPANY, SCRUBBING, SCRUBBING,
$/YEAR $ $
15208800 (
15053700 1
14898600 (
14743500 (
14433200 (
14278100 (
14123000 (
13967900 (
11154900 (
10999800 (
10844700 (
10689600 (
1053.4200 _1 .
8458700 (
8303600 (
8148500 (
7993400 (
_2a38.3QQ__i_.
5007900 (
4852800 (
4697700 (
4542500 (
4.3.324.00 i
4232300 (
4077200 (
3922100 (
3767000 (
2611200 i
283172ROO (
6.13
2.22
117761000 (
2.54
0.92
513900) (
511800) (
509700) (
507600) (
505500) I
503500) (
501300) (
499200) (
497100) (
. A25QQQ1 1
346200) (
344100) I
342000) (
339900) (
. 3.3.23001 i .
230000) (
227900) (
225800) (
223700) (
2216001 i
89500) (
37300) (
85200) (
83200) (
aiiooi i
79000) (
76900) (
74800) (
72700) (
206001 I
8683900)
3889900)
513900)
1025700)
1535400)
2043000)
.-25425001
3052000)
3553300)
4052500)
4549600)
. 5.Q4.A6QQ1
5390800)
5734900)
6076900)
6416800)
6984600)
7212500)
7438300)
7662000)
—2353-6001
7973100)
8060400)
8145600)
8228800)
£3022.001
8388900)
8465800)
8540600)
8613300)
S6B.3-20Q1
-------
Table A-199
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROO. EQUIV. TO 1 1000 1W COAL FIRED UNIT, 3.5* S
FIXED INVESTMENT = t 12354000
OVERALL INTEREST RATE OF RETURN = NFG
NO PAYOUT
YEARS
AFTER
PLANT
START
UP
1
2
3
4
^
6
7
a
9
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100* RECYCLE
H2S04 MGG
213500 108265
213500 108265
213500 108265
213500 108265
21.35.fl2 Ifla265.
213500 108265
213500 108265
213500 108265
213500 108265
. 213.5.0.0- _lQa2£5.
TOTAL
MFG.
COST,
S/YEAR
4187000
4187000
4187000
4187000
Alfllflfla .
4187000
4187000
4187000
4187000
4.iaifl2fl .
NET REVENUE, TOTAL
S/TON NET NET INCOME
SALES GROSS AFTER
100X RECYCLE REVENUE, INCOME, TAXES,
H2S04 MGO */YEAR WYEAR $/YEAR
12.00 10.00
12.00 10.00
12.00 10.00
12.00 10.00
lia.22 1Q..22
12.00 10.00
12.00 10.00
12.00 10.00
12.00 10.00
__12.»fl2 _ IQxflfl- _
3644700
3644700
3644700
3644700
3.6.4.4.ZO.Q J
3644700
3644700
3644700
3644700
3.fi4.4.ZO.Q_ J
542300)
542300)
542300)
542300)
L __5A2iQfll J
542300)
542300)
542300)
542300)
L 5A23flfll_J
271150)
271150)
271150)
271150)
L 22115Q1 _
271150)
271150)
271150)
271150)
L 21115fll__
CASH
FLOW,
S/YEAR
964250
964250
964250
964250
_26425Q_
964250
964250
964250
964250
264252.
ANNUAL
CUMULATIVE RETURN ON
CASH INITIAL
FLOW, INVESTMENT,
$ %
964250
1928500
289275Q
3857000
4B2125Q
5785500
6749750
7714000
8678250
264252Q
TOT
2135000 1082650
41870000
36447000 (
5423000) (
2711500)
9642500
AVG=
-------
Table A-200
MAGNESIA SCHfcME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 1 1000 «IW COAL FIRED UNIT, 3.5* S
PRODUCT RATE,
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
a
9
Ifl .
EQUIVALENT
TONS/YEAR
100%
H2S04
213500
213500
213500
213500
RECYCLE
MGO
108265
108265
108265
108265
_2.13_5_QO. 103265
213500
213500
213500
213500
_213500__.
108265
108265
108265
108265
1Q8265
TOTAL
MFG.
COST,
S/YEAR
4187000
4187000
4187000
4187000
4.18.10.0.0.
4187000
4187000
4187000
4187000
_iiaiQiifl .
FIXED INVESTMENT = $
OVERALL INTEREST RATE OF RETURN =
YEARS REQUIRED FOR PAYOUT =
NET REVENUE,
$/TL)N
1003 RfcCYCLE
H2S04
12.00
12.00
12.00
12.00
12*fl2 _ .
12.00
12.00
12.00
12.00
12*0.0.
MGO
55.00
55.00
55.00
55.00
-_55*flfl
55.00
55.00
55.00
55.00
5.5.1.P.Q
TOTAL
NET
SALES
REVENUE,
S/YEAR
8516600
8516600
8516600
8516600
_ 35.16.6.0.0.
8516600
8516600
8516600
8516600
85.16.6.0.0.
GROSS
INCOME,
$/YEAR
4329600
4329600
4329600
4329600
4.3.2262Q
4329600
4329600
4329600
4329600
43226QQ _
12354000
24.4?
3.6
NET INCOME
AFTER
TAXES,
S/YEAR
2164800
2164800
2164800
2164800
_2164.aflO.
2164800
2164800
2164800
2164800
CASH
FLOW,
S/YEAR
3400200
3400200
3400200
3400200
CUMULATIVE
CASH
FLOW,
$
3400200
6800400
10200600
13600800
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
%
16.97
16.97
16.97
16.97
3.4.QQ2P.Q 17QQ1QQQ 16.91
3400200
3400200
3400200
3400200
20401200
23801400
27201600
30601800
16.97
16.97
16.97
16.97
216_4.aQQ 34QQ200 34.002QQQ 16,97
TOT
2135000
1082650
41870000
85166000
43296000
21648000
34002000
AVG*
16.97
-------
OJ
J^
oo
Table A-201
MAGNESIA SCHEME 0, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 2 1000 MW COAL FIRED UNITSt 3.51 S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5.
fa
7
8
9
10
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
427000
427000
427000
427000
RECYCLE
MGO
216530
216530
216530
216530
TOTAL
MFG.
COST,
S/YEAR
7263900
7263900
7263900
7263900
FIXED INVESTMENT = * 19534000
OVERALL INTEREST RATE OF RETURN = 0.1?
YEARS REQUIRED FOR PAYOUT = 9.9
NET REVENUE, TOTAL
S/TC1N NET NET INCOME
100%
H2S04
12.00
12.00
12.00
12.00
RECYCLE
MGO
10.00
10.00
10.00
10.00
iZZOflfl 216530 2263200. 12*00 10*00 .
427000
427000
427000
427000
427000
216530
216530
216530
216530
2.1f>53.fl
7263900
7263900
7263900
7263900
12&3.2QQ
12.00
12.00
12.00
12.00
1,2,00
10.00
10.00
10.00
10.00
10.1.0.0.
SALES
REVENUE,
S/YEAR
7289300
7289300
7289300
7289300
Z2.a9-3.aa _.
7289300
7289300
7289300
7289300
22fl23.QO.
GROSS
INCOME,
S/YEAR
25400
25400
25400
25400
25400
25400
25400
25400
25400
2.5.4.QO
AFTER
TAXES,
S/YEAR
12700
12700
12700
12700
_iziaa
12700
12700
12700
12700
121QQ
CASH
FLOW,
S/YEAR
1966100
1966100
1966100
1966100
126-6.1Q2
1966100
1966100
1966100
1966100
12661QQ
ANNUAL
CUMULATIVE RETURN ON
CASH INITUL
FLOW, INVESTMENT,
S
1966100
3932200
5898300
7864400
2fi3.fl5.flfl
11796600
13762700
15728800
17694900
__12661QQfl .
*
0.06
0.06
0.06
0.06
3.*0.£
0.06
0.06
0.06
0.06
a .1.06.
TOT
4270000
2165300
72639000
72893000
254000
127000
19661000
AVG=
0.06
-------
Table A-202
MAGNESIA SCHtME D, NONREGOLAT ED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 2 1000 HW COAL FIRED UNITS, 3.5? S
YEARS
AFTER
PLANT
START
UP
1
2
3
4
s.
6
7
a
9
lii
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
427000
427000
427000
427000
42200.0.
427000
427000
427000
t27000
4.2200sl_
RECYCLE
MbO
216530
216530
216530
216530
216.5.3.Q
216530
216530
210530
216530
21&.5.3-0.
TOTAL
MFG.
COST,
S/YEAR
7263900
7263900
7263900
7263900
226.3.200.
7263900
7263900
7263900
7263900
22622011
FIXED INVESTMENT = t 19534000
OVERALL INTEREST KATE OF RETURN = 33.0?
YEARS REQUIRED FOR PAYOUT = 2.9
NET REVENUE, TOTAL
S/TON NET NET INCOME
100*
H2S04
12.00
12.00
12.00
12.00
i2*oc
12.00
12.00
12.00
12.00
i2*aa
RECYCLE
MGO
55.00
55.00
55.00
55.00
SALES
REVENUE,
S/YEAR
17033200
17033200
17033200
17033200
GROSS
INCOME,
S/YEAR
9769300
9769300
9769300
9769300
AFTER
TAXES,
S/YEAR
4884650
4884650
4884650
4884650
CUMULATIVE
CASH
FLOW,
S/YEAR
6838050
6838050
6838050
6838050
CASH
FLOW,
i
6838050
13676100
20514150
27352200
55.iO.fi 170332QQ 9169300 4884650 6838050 34190250
55.00
55.00
55.00
55.00
5.5.i.aa
17033200
17033200
17033200
17033200
iifl23.2aa _.
9769300
9769300
9769300
9769300
2i6.23.aa .
4884650
4884650
4884650
4884650
6838050
6838050
6838050
6838050
41028300
47866350
54704400
61542450
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
24.10
24.10
24.10
24.10
24.*lfl
24.10
24.10
24.10
24.10
4.084.6.50. &8.3.8.05.Q. &83SQ5QQ 24.12
TOT
4270000
2165300
72639000
170332000
97693000
48846500
68380500
AVG= 24.10
-------
Table A-203
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EOUIV. TO 3 1000 M W COAL FIRED UNITS, 3.5% S
FIXED INVESTMENT = $ 26096000
OVERALL INTEREST RATE OF RETURN = 3.5%
YEARS REQUIRED FOR PAYOUT = 8.3
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5_
6
7
8
9
10 .
PRUDUCT RATE,
EQUIVALENT
TONS/YEAR
100*
H2SH4
640500
640500
640500
640500
64.£5_0_Q
640500
640500
640500
640500
6.4^0500
RECYCLE
MGO
324795
324795
324795
324795
12419.5.
324795
324795
324795
324795
. 32*12.5 _.
TOTAL
MFG.
COST,
S/YEAR
9875900
9875900
9875900
9875900
2&./.5.2J.Q.
9875900
9875900
9875900
9875900
. 2325200 .
NET REVENUE,
S/TON
100*
H2S04
12.00
12.00
12.00
12.00
12*0.0.
12.00
12.00
12.00
12.00
12.00
RECYCLE
MGO
10.00
10.00
10.00
10.00
10-A.OQ
10.00
10.00
10.00
10.00
lOa.00
TOTAL
NET
SALES
REVENUE,
S/YEAR
10934000
10934000
10934000
10934000
lQ23.4D.fla
10934000
10934000
10934000
10934000
iQ23.*aoa
NET INCOME
GROSS AFTER
INCOME,
S/YEAR
1058100
1058100
1058100
1058100
105fllOQ
1058100
1058100
1058100
1058100
lQ5fllQO__
TAXES,
S/YEAR
529050
529050
529050
529050
5220.50
529050
529050
529050
529050
52.9050
ANNU&L
CUMULATIVE RETURN ON
CASH CASH INITIAL
FLOW,
S/YEAR
3138650
3138650
3138650
3138650
313.fi6.50
3138650
3138650
3138650
3138650
. 3123650
FLOW, INVESTMENT,
$
3138650
6277300
9415950
12554600
15623250.
18831900
21970550
25109200
28247850
31326520
*
1.95
1.95
1.95
1.95
1*9.5
1.95
1.95
1.95
1.95
1*25
TOT
6405000 3247950
98759000
109340000
10581000
5290500
31386500
AVG=
1.95
-------
Table A-204
MAGNESIA SCHEME D, NONREGULATED PORTION COOPERATIVE ECONOMICS, MGO-H2S04 PROD. EQUIV. TO 3 1000 MW COAL FIREO UNITS. 3.5* S
FIXED INVESTMENT = $ 26096000
OVERALL INTEREST RATE OF RETURN = 38.51
YEARS REQUIRED FOR PAYOUT = 2.5
YEARS
AFTER
PLANT
START
UP
1
2
3
4
5
6
7
8
9
10
PRODUCT RATE,
EQUIVALENT
TONS/YEAR
100%
H2S04
640500
640500
640500
640500
640500
640500
640500
640500
640500
6_4_Q5_Qfl
RECYCLE
MGO
324795
324795
324795
324795
-3.24225
324795
324795
324795
324795
-124225
TOTAL
MFG.
COST,
t/YEAR
9875900
9875900
9875900
9875900
2fi25200 .
9875900
9875900
9875900
9875900
_2fl2520Q_.
NET REVENUE,
*/TON
100*
H2S04
12.00
12.00
12.00
12.00
12*00
12.00
12.00
12.00
12.00
12 a. 00
RECYCLE
MGO
55.00
55.00
55.00
55.00
5.5*00
55.00
55.00
55.00
55.00
55-00
TOTAL
NET
SALES
REVENUE,
$/YEAR
25549700
25549700
25549700
25549700
2554.220Q
25549700
25549700
25549700
25549700
25542200
NET INCOME
GROSS
INCOME,
S/YEAR
15673800
15673800
15673800
15673800
15673800
15673800
15673800
15673800
.15621300
AFTER
TAXES,
J/YEAR
7836900
7836900
7836900
7836900
2&16^flO.
7836900
7836900
7836900
7836900
2ai6^oo.
CASH
FLOW,
*/YEAR
10446500
10446500
10446500
10446500
10446.500.
10446500
10446500
10446500
10446500
1,04. 4,6|?2Q
CUMULATIVE
CASH
FLOW,
$
10446500
20893000
31339500
41786000
52212500
62679000
73125500
83572000
94018500
10446.5QQQ
ANNUAL
RETURN ON
INITIAL
INVESTMENT,
*
28.90
28.90
28.90
28.90
_2fi»3fl
28.90
28.90
28.90
28.90
28.9Q
TOT
6405000
3247950
98759000
255497000
156738000
78369000
104465000
AVG= 28.90
-------
APPENDIX B
Engineering Drawings
352
-------
DUCT
VAfff
VK
PRODUCT
STORAGE
TANK
I
72
A '
*
Ul
OJ
Figure B-1. Flow Diagram—Scheme A: Magnesia Slurry Scrubbing-Regeneration
-------
STREAM NO.
DESCRIPTION
RATE, LBS./HR.
SCFM
GPM
PARTICULATES, LBS./HR.
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOUD3, %
PH
STREAM NO
DESCRIPTION
SCFM
PARTICULATES, LBS./HR.
TEMPERATURE, * F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
pH
STREAM NO.
DESCRIPTION
SCFM
GPM
PARTICULATES, LBS./HR,
TEMPERATURE, "F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
PH
STREAM NO
DESCRIPTION
RATE, LBS./HR
SCFM
GPM
PARTICULATES, LBS /HR
TEMPERATURE, 'F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
1
TO
21
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JKA/jSO^ /-V T-**0i-C^
.
a. itsi s r
Figure B-2. Material Balance-Scheme A: Magnesia Slurry Scrubbing-Regeneration
-------
OPTIONAL INDIVIDUAL SYSTEM BYPASS
1
J
DUCT
\
r
1
PRODUCT
TANK
\
71
A*
gl
Q
ATUOSPMEftl
*
1
A"
PRODUCT
ACID
COOLERS
A
93KACIO
COOLERS
69 I
1 98% ACID
T COOLERS
TO WASTE
CONTROL
"I PUMP
\TANK
96% ACID
ABSORPTION
TOWER
e-—*
n
^CATALYST
r ^
HEAT
-r*
1 [.
#f>ar
f/MACfAS
v
1
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a.Oi
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S f
Kfff
[<"£/*
67
4 1
n
1 ^
STRIPPING
TOWER
f"
" m
L ' LJ"
66
isr
j
Figure B-3. Flow Diagram-Scheme B: MgO-MnO2 Slurry Scrubbing-Regeneration
-------
Lfl
ON
STREAM NO
DESCRIPTION
RATE, LBS /HR
SCFM
PARTICULATES, LBS/HR
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDfSSOLVED SOLIDS, %
PH
STREAM NO
DESCRIPTION
RATE, LBS /HR
SCFM
GPM
TEMPERATURE, BF
VISCOSITY, CPS
UNOISSOLVEO SOLIDS, %
pH
STREAM NO
SCFM
GPM
PARTICULATES, LBS /HR
TEMPERATURE. "F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
PH
STREAM NO
SCFM
GPM
PARTICULATES, LBS/HR
TEMPERATURE, "F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNOISSOLVED SOLIDS, %
PH
1
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Figure B-4. Material Balance-Scheme B: MgO-MnO2 Slurry Scrubbing-Regeneration
-------
tf. ACTUAL LOCATIONS OF STREAM INLET AND OUTLET DEPEND
UPON TYPE OF SCRUBBER-ABSORBER CHOSEN
* NEED rOH SURGE TANK AND AGITATOR DEPENDS UPON
rrr>£ or SCRUBBER-ABSORBER CHOSEN.
Figure B-5. Flow Diagram—Scheme C: Magnesia Clear Liquor Scrubbing-Regeneration
-------
U)
t-n
oo
STREAM NO.
DESCRIPTION
RATE, LBS /HR
SCFH
GPM
PARTICULATES, LBS/HR
TEMPEPATURE, 'F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
pH
STREAM NO,
DESCRIPTION
SCFM
GPM
PARTICULATES, LBS /HR
TEMPERATURE. 'F
VISCOSITY, CPS
UNDISSOi-VED SOLIDS, %
PH
STREAM NO
DESCRIPTION
SCFM
GPM
PARTICULATES, LBS /HR
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOUVED SOLIDS, %
PH
STREAM NO
DESCRIPTION
RATE, LBS /HR
SCFM
GPM
PARTICULATES, LBS/HR.
TEMPERATURE, "F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS. X
pH
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Figure B-6. Material Balance—Scheme C: Magnesia Clear Liquor Scrubbing-Regeneration
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Figure B-7. Flow Diagram-Scheme D: Magnesia Slurry Scrubbing-Regeneration Central Process Concept
-------
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DESCRIPTION
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DESCRIPTION
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TEMPERATURE, 'F.
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VISCOSITY. CPS
UNDISSOLVED SOLIDS. %
pH
DESCRIPTION
RATE, LBS /HR
SCFM
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'ARTICULATES, LBS./HR
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
pH
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Figure B-8. Material Balance-Scheme D: Magnesia Slurry Scrubbing-Regeneration Central Process Concept
-------
Figure B-9. Control Diagram-Scheme A: Magnesia Slurry Scrubbing-Regeneration
-------
o
0
Q
Figure B-10. Overall Plot Plan-Magnesia Scrubbing System Attached to Power Unit
-------
POWERHOUSE
STACK
RECYCLE PUMPS
x—OPTIONAL BYPASS
DUCT
363
Figure B-11. Two-Stage Venturi Scrubber System-Plan and Elevation-New Unit
-------
STACK
364
DAMPER (TYPICAL
WHERE SHOWN)
THIS DAMPER NOT REQUIRED
UNLESS OPTIONAL BYPASS
DUCT 15 INSTALLED
Figure B-12. Venturi-Mobile Bed Scrubber System-Plan and Elevation—New Unit
-------
EXPANSION JOINT
(TYR WHERE SHOWN)
365
Figure B-13. Venturi-Mobile Bed Scrubber System-Plan and Elevation-Existing Unit
-------
STACK
366
THIS DAMPER
NOT REQUIRED
UNLESS OPTIONAL
BYPASS DUCT-
IS INSTALLED
Figure B-14. Spray Tower-Plan and Elevation-New Unit
-------
WASTS HfJT FLUID BED
BOILER CALC1NEK
ELEI/AT I ON A-A
U)
ON
Figure B-15. Fluid Bed Dryer-Calciner Layout-Elevation
-------
PAOCFSS AHD MOTOR CONTROL
SUtLDING,
LABORATORY AMD LOCKER ROOM
Figure B-16. Fluid Bed Dryer-Calciner Layout-Plan
-------
OJ
ON
Figure B-17. Rotary Dryer and Calciner Layout-Plan
-------
R
O
D
OJ
-J
O
s
LOADING PUMPS
-93% ACID COOLERS
ACID COOLERS
STORAGE
TANK
ACID STORAGE
ACID DRAIN PUMP
PRODUCT ACID COOLERS
93 % AC ID PUMP TANK
98% ACID PUMP TANK
a PUMP
CONVERTER
COOLING AIR
FAN
PRIMARY HEAT
EXCHANGERS
PRODUCT a
STRIPPING PUMP
98% ABSORPTION
TOWER
93 % DRYING TOWER
STRIPPING
TOWER
^START-UP
FURNACE
CONVERTER HEAT
EXCHANGER
GAS PRE'HEATER
'—MAIN GAS BLOWER
-START-UP FAN
245'-0" (APPROX.)
Figure B-18. Sulfuric Acid Unit Layout—Plan
-------
93% DRYING TOWER
VENT
98% ABSORPTION TOWER
PRIMARY
HEAT EXCHANGERS
ACID STORAGE
TANK
ACID S
TA
'OR AGE
245'-O" (APPROX)
CONVERTER COOLING
AIR FAN
CONVERTER
HEAT EXCHANGER
GAS PREHEATER
Figure B-19. Sulfuric Acid Unit Layout—Elevation
-------
BIBLIOGRAPHIC DATA
SHEET
1. Report No.
EPA-R2-73-244
3. Recipient's Accession No.
5- Report Date
May 1973
I. Title and Subtitle
Sulfur Oxide Removal from Power Plant Stack Gas
(Magnesia Scrubbing-Regeneration)
6.
7. Author(s)
G.G.McGlamerv, R. L. Torstrick, J. P. Simpson. J. F. Phillips
8- Performing Organization Rept.
No.
9. Performing Organization Name and Address
Tennessee Valley Authority
Muscle Shoals, Alabama 35660
10. Project/Task/Work Unit No.
11. Contract/Grant No.
TV-29233A
12. Sponsoring Organization Name and Address
EPA, Office of Research and Monitoring
NERC/RTP, Control Systems Laboratory
Research Triangle Park, North Carolina 27711
13. Type of Report & Period
Covered
14.
15. Supplementary Notes
16. Abstracts The repOr|- is a conceptual design and cost study on magnesia scrubbing-
regeneration. It describes the process history, current development status, and
variations which have been pursued, and presents process chemistry, kinetics, and
mass transfer data. It outlines the four leading processing techniques for evaluation,
and discusses the advantages and weaknesses of magnesia scrubbing-regeneration as
compared to other SO2 removal processes. It gives results of a complete economic
evaluation, including details of the capital, annual operating, and lifetime operating
cost estimates. It compares magnesia processes with both low (rural) and high
(metropolitan) cost limestone scrubbing systems, and gives sensitivities of such
variables as unit size, status (new or existing), fuel type, sulfur content of fuel,
on-stream time, and net sales revenue. It enumerates conclusions of the study.
17. Key Words and Document Analysis. 17o. Descriptors
Magnesium oxides
Kinetics
Mass transfer
Sulfur dioxide
Limestone
Fuel
Sulfur
Air pollution
Chemical reactions
Desulfurization
Economic analysis
Capitalized costs
Operating costs
Washing
Regeneration (engineering)
Design
17b. Identifiers/Open-Ended Terms
Air pollution control
Stationary sources
Conceptual design
Scrubbing-regeneration
17c. COSATI Field/Group 13B, 14A, 7A, 7C , 7D, 21D
18. Availability Statement
Unlimited
19. Security Class (This
Report)
UNCLA?
VSSIFIED
-lass (Thi:
20. Security Class (This
Page
UNCLASSIFIED
21. No. of Pages
372
22. Price
FORM NTIS-35
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