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

-------
                     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)

-------
                                          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

-------
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 .

-------
  PERSPECTIVE VIEW OF A MAGNESIA
 SCRUBBING SYSTEM FOR SO2 REMOVAL
ON A COAL-FIRED 500-MW  POWER UNIT-
    TWO-STAGE  VENTURI  CONCEPT

-------
                                                  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.

-------
                                     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

-------
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

-------
                 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

-------
                                              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

-------
                                                   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

-------
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

-------
                                                  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

-------
 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

-------
    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

-------
                                                 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

-------
               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

-------
           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

-------
                    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

-------
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

-------
                            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

-------
            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

-------
                                  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

-------
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

-------
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

-------
                       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

-------
  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

-------
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

-------
             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

-------
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

-------
          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

-------
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

-------
                         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

-------
   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

-------
           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

-------
   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

-------
 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

-------
   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

-------
    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

-------
         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

-------
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

-------
   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

-------
                             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

-------
                                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

-------
       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

-------
                                            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

-------
   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
                       " ' o *   •  '.
                            / a
                       P    /    \.
                          ?  '  •  « *V-^r	i
                                 ©  o
    ooooooOO
    901- IOO1- 1901- 2OCH- 2501- 3
   < IOOO 1500 2000 2500 3OOO 3



OOOO
                                             ,              """"~\J3-J   /   °.»...\"tf'"
                              /      .         3)               O       l©r     i   «    I
                        "	;._r"~-J-.        '                       (  o    •,'  ?    \

            x  v    .                 N       T   E   *   »  s       s  '   /  »
 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

-------
                                                                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

-------
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

-------
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

-------
                 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
£! ^
^^
> >
1 s-
i "s
P
o

5 "2 0.40
D. c
*S J
^ 13
o ^
C t_
"™ O
1 g
S -SI o
a"
L
K


2.60


l-o
0 «J
£• 1 3-°°
o ^
*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.
130

-------
                        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
                                                                                                               131

-------
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.
132

-------
                        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
                                                                                                              133

-------
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
134

-------
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,
                                                                                                                135

-------
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

-------
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

-------
                                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

-------
    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

-------
     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

-------
    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

-------
     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

-------
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

-------
     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

-------
    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

-------
     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

-------
APPENDIX A



  Cost Tables
                                                    147

-------
                          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

-------
                         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

-------
                          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

-------
                         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

-------
                         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

-------
                  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

-------
                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
"£ZZ








41
^IC-^-e
	 	 	








61

3QO









	 2 	 T
-*/« r»
"<"

,/0





22
•rtt/fXis
TfffATMfHT
MAttitS'A AMD
HAT£fi
IMf-OWlS,
fit ASH

£TC


42
OUST TO









62



AS 7


/.//

/£


3

saa A/

*'0





23
ro








43
caress.
PRODUCT ro



400





63
T^ef
/Z9*
2S./*t


soo





	 4 	 T
TO


avo





24
™T



LOS"

3./


44
°iz%iz
	








64
'°m%%y*
l?s*
24.1 H


S40





5
ro
_s*s»r
33 7M
70S





25
22ES2



/.2f

fo


45
ro









65
"*n£Ze"
iej~r
zz*


ISO





6


e,*3f
310





26
"-3"""1


jet





46
,3L









66

6/43-

e.zs







7
TO JO*








27
««£,««•


/#o
I.2O

-?/


47
O/i
TO









67
TO
t,£>0*M

/,//£>

/oo
/.£/




B
GAJ
TO
*""
ft S
127





28
%£?£*
£ Z A/or«-







48
7D
/«/^ 	








68
£££££££
tZ9*



S&3
/.77




9
*£e
Z**"
jta
/6O





29
•&*



/.0£

4-6.


49
^rc^£
u./« 	

19*0
/, 600





69





/GO
/. 73




10
7-0
*""
MS
f74





30
"^^



/.OS

3.3


50
1HSS
/j./+i

Zf7






ro
xwr^df^KM
/^-A/

/7_7







II
£B,


^70





31
2SS,'








51
ro



3&&





71
fferzt. £ *c/o
/23*









12

	







32
J£Z£*%e








52
ro
&VCHCH */&
	 /j/v '

.?S7
e-77





72
s»&ot>



J

54
OIL. TO








54
"?£"££
.26.9 *f

257
400





74











IS
££Efr
/OJ


/.09

is-


35
-*/^ 7~(5
«.^







55
/-^T'rf
.?* 5A/

_?






75











16
Z2%*
— ar/







36
,^r^
-?iT^
^?£0
000





56
C YClOHf DUff









76











17
~ZfsZ,Z?
/^~/ "







37
cZ^cr^

ffS4






57
aJOufrlro°*









77











18
S^-«-*
3V^O-^ J^O







38
-sfes-
„*„
/• 4






58
4££r£



?^JT





78











19
ST^
J/63-6JM

/^ r





39
™;*
«^
2.<9






59
~£r









79











20
*"££%£*''
Zte2.*J*i


1.09

to
8

40
ZrZ?JS*e
,.,l,*i
230
/7*r





60
**fCoCr/
/&'&"








80










                                                                                  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

^
a.Oi
1
IN ^ 	 ,
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
ro




2 1
™-
•^^

O/OMff *"0

>~xrr«_
j**ttsx*r/cs
srre.

4[
Sr£*~, TO
™"«
	 1 	


-?6£





&l


	
7.62.


/.J~f

£6


C°Z%Sro0"
tte



2Z
^•r"
22 a







4Z
ffffO
<="<•*"'**









62
CffMS

1 4,0+4


soo





3




23
«,£««
— ~so~t, —

/So
'•ou

12.4 ~<


/to





er/
243



25
™r!zy">
23, 7


/-£-

/3


45
c*t-etfS£*>
c ret. OfSf


^493
>,aoo





65
***#£- W
oxrwn***

&JT$







6
ro
4,0.4



26
TO
47.4-







46
£*LC/*£# G*S
«r*r*oW
~^7~° —

224






66
ff£crct£ *C/£>
°*™*™**

J9Z.

/oo
/.a/




7
ro Jo*.
*,<,



27
"f^Joi
8. 22.







47
srf*»,
*"'"«.•*"
	 * 	


_?**





67
#*?**£ f*CM
ro~s#

77 S

/t>3
/. 77




8
To
60S



26
<$" 70/
— ~/7s —







48
f*i.n»f£a tf*s
-**«*«**
7if)/£>

ZZ4-
7/





68
#£crVi f ACtO
re***

-T9Z.

/*0
/ 73




9
ro
/ 6O



29
^«








49
^f^rxcv^*
«-'•««"
TJ>J^








69
fffcn:tf*c/0
c^-.t*s

31. *







10
ro
£/. 2.



30
o/^ T-e?








5O
Go~tff/*ea
c~i<-c™
,*,„

ZZ4-
4.00





70
tKrcccjve
"•>«»«">

Ti.t







II




31
72^2";^
7-o7S







51
co^aifJfo

IS.,M

2.Z.






71
f>*ooucr
*ro#**c-

/s,s
z z.
/oo
/.se




12
O/i 7T3
530




32
7J" 7^f
	 /9-*"f
3,234-
400





52
ercLOA/eovJr
*">""*«









72
codSS/G
4C'£> COOtfltS

Z.5SS







13
-ea/o




33
7J7AT
/S °*
43s-






53
ess caurcrt>*
********









73











14
Jt •Pv'<
-s>. 4



34
24-. 4*4

0. 7






54
Csate/ASCK.
COOL £#



34£-





74











A*>«T- */**
**# rrvp /B -3"0£




35
— -
_^z^_
/.^r






53
^-wrf-^
*£M

39.4-







75











16
s-its##r TO




36
4,3-57*1
977*1
Z4&
t7f





56
(T^^f/^^/e




zs^r





76
















37
^, 7-? 3








57
A/yj-c
r»^r









77












/.ff
60
&

38
•434-








58
^•^(TKC^i-
«£££*









78
















39
^•J. 7/V


•*oo





59
M^x-e- us*










79
















40
Z7.0M








60
MAK-e-i"*










80










               ro a^J" TO
                                  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

|.
CQ'ft-






2 1
csUfe
fi.isxxt'
TO &Q#a

4"


/.as

/.$•


41
a*x0c#.
Z/.4 *l

40. S


/Of

e.2.


co*fBi*Lf T/oti






22
L/G>tso^.
TO &t/je& -f
r&f'0rf*f£'*s7
v^ts
+r**v*Jt*,
n v *j# 4
*4*q#£'-//£>
twrca
/MOt/G/T/fS,
frc.


42
O#V£:A.
f«oac/CT TO
c -Of/tfero^



400





62
COfjSfGJIOtS
T^fJf
S.&74









3
O+fGI/STSOfS
JP/& TO
g<3<3 >/






23
r/trje^rt:
TO ^/futs^
-TjafJK

5£*


s.oz




43
^££D£-X
0&-crt4#G£ ro
cofsrer'ojz









63
rot^fe
ovrj. £-r ff^y
/so*4
S/.^M


/CO





ffWJ-
ro
33.™





24
net^rfo
M/pisa* 7-0
iJpUQK 7XMX
Z% fJOTC








44
come
TO
cavrfYo*,









64
G*J-
/ /
#£*£ TtOfJ-
COftrfJtS/OfS
7-J!*'*

/,S4^


/.03




45
*•£•££>
TO
ett e/ssffZ









65
rorsfiZ
OVTL fr GJ»S
se,e»f
13.9*1


/6O





6
ycxtsasftf-
siasoeseG
8.43S'





26
srrj}** TO
gCsecr/OfS-
eof/rf£G3/OfS
Wft?



S6&





46
7-0
tVff
347

/.?/,€
TO
c*te//J£K
8,*&f








67
aerstss rotrft
3&Z.S-1

9S3

/OO
/.8I




8



/, Jiascnes>rja*
TOnffG
3*3M

2S3

/to
/.7S




10
srf-e+f
ro ?Y/SS<5
T-^>fJK

Jff&







51
4tCW££ 
400





73
sK/£> COOLERS
Z, O4 Z S*f

4-.OS3







14
jefcret *
a fi/e wgoatjcr
t/euo*
4, SO £ M |

/ o&

4.S
s

34
-<•/* TO
<:O*f&VJ T/OM
cwfifafiz.
//. J M








34
f^SOif VSSST
23 /M

Z. /






74











15
±/evo*z
4.03 /M






39
Gaisf:* f*s
ro
osc^ofsf
3o./ M

^ 1 ZO
•4-OO





53
C rCL OfJf
CX/ST ro
csttc/sss^









73











16
TO
TH/CXffJf*






36
OBr-fs K
OUST TO
cofsyeYajz.









76











17
34
/./S

JO


37
*ee*ygSAS
co tsaus r/OfS
CHs4*f££&
JO**

J-2.






37
csit cwc/i
fjeo&c/c T ro
cof *of*>#£X£
i, /4a M

S/9
(7f





39
xfcrci.^
eofsyerojz









79











20
j-t Mtesff/A/G
Ts4fSJ{
/7**i






40
CYC£O/Sf
&c/^r ~ro
cossvfYose









60
****£•- tsf*
f-fyO TO
cofrfyo*









60










-J t. Kt/ri-fsi _-,-<; xt'fi & cse-sJtfs.-c**:*)*/*.
                                         Figure B-6.  Material Balance—Scheme C: Magnesia Clear Liquor Scrubbing-Regeneration

-------
Q

^
Pitoac/rr
cooi f-r*














"
A
£222?




iJ
1 "1'ifZ



u 	 f 	 1
	 ti(
03-




A






1

i,


•wtf-*





*"
zz





23
m




1*
*—





"\^— 'f*
n









«"S£Z<*
%
1-










[TU£^I
nJ— H
1



LSi





)







H^



»

'


1






~-~






TO


ISST
                           Figure B-7. Flow Diagram-Scheme D: Magnesia Slurry Scrubbing-Regeneration Central Process Concept

-------
       OJ
       OS
       o
STREAM NO
DESCRIPTION
SCFM
MRTICULATES, LBS /HR~
TEMPERATURE, 'F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS. X
pH
STREAM NO.
DESCRIPTION
NATE, LBS /HR
3CFM
0PM
PARTICULflTES. UBS /HR.
TEMPERATURE. *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS. %
PM
STREAM HO
OESCRff'TION
0PM
PARTICIPATES, LBS/HR.
SPECIFIC GRAVITY
VISCOSITY. CPS
UNDISSOLVED SOLIDS, %
PH

DESCRIPTION
SCFM
PARTICIPATES. LBS /HR.
TEMPERATURE, 'F.
SPECIFIC GRAVITY
VISCOSITY. CPS
UNDISSOLVED SOLIDS. %
pH

DESCRIPTION
RATE, LBS /HR
SCFM
GPM
'ARTICULATES, LBS./HR
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNDISSOLVED SOLIDS, %
pH
	 j 	
&&n. £#.

26
T*MJT
3*Z

9]
*£10 ftsurr






zzz^™

—*^ —
















2
sttx ro
*sf fS£s*rr#
„„
27
c£*rrjf/fve£
Sff
J/
c*tf,Mf*e*f
fisxjuett j*/*
Z*/





T*MC


















	 	 	
st/# TO

28
tsoifar x**r


TO
C-fte/M£# £4S






ivjtrrjf TO
^i.ts*j*r/fj*


















	 ~ 	 '
 ffSOUfT
J-lfm*r



/.OS

10
e











	 	 	
rf,*J-

32
J./(ltfOlf TO
j-t uir#r7fJS
r*rsx
Me








IZZ?


















e
&*f
,„
33
s-£?a
axr-fjf


co*rvfr•<£ s*r$*ar*.

43
coMV**o
>-°>
45
COfsr^roj*.


act: ft 'i CfteiP
,„
f.tl























	 T\ — ~~
#£crcf. £
j-tuxier
470*.f,/»*rl

4«


71
accrae *£Ji>
ro rra/rntts
12O
— 77-, —























Z2
^iuaaf
ro f>v/uf£
r#r,ir*(xtfT
Cfrfvafisror,
*<4GJS£3I* «.
1*1* rr a
ctJntMtwffiv



72
excrete *CiP
&7/
S.7S























23
JTi U*«Y
TO
JcxfffJ

re>


73
ff£rfi£ sK/B
Cfrot. £Jty
I3J
























24
ro twito*
r*fs<
£/•**{
/ 03-
3-i
C^^Cff^f-K
**fj- TO
l,*~"
',014

74
ro »yya
/££>
























29
4S.4*f
/.Xf
Ji£/#ft **S
ro **ijr*r
f£*r&ort-*X
//. -ft*
£X>

73
rjtootsfr-
sKta ro
^ra/rj**!?
X* f*f
Jl
t.x.
LtZf























 ^* *tSirt/# IfS COMi. f£>Ky a*«J-/S)
 e 7* *fM co*i. f,4s f-/#££> as>sii-J
 't vf  of st/t rve /*/ ce>-*4. *roj. n
3f.&y, Jtr**oif*4i. of f*jrne:t/i.jer£-j TO .rcfi/aye.
»t> y, ^fe>t jex+KSf*r{, #r j~rf*M r*.**ffr et 9A 7 « x*.
  V*>* MiSASjttf er A. *
                                    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 
-------