Conceptual Design
and Cost Study
Sulfur Oxide Removal From
Power Plant Stack Gas
'AMMONIA SCRUBBING
Production of Ammonium
Sulfate and Use as an
Intermediate in Phosphate
Fertilizer Manufacture
Prepared for the National Air Pollution Control Administration
By the Tonne: ;y Authority
1970
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Sulfur Oxide Removal From
Power Plant Stack Gas
> AMMONIA SCRUBBING
Production of Ammonium
Sulfate and Use as an
Intermediate in Phosphate
Fertilizer Manufacture
Conceptual Design and Cost Study Series
Study No. 3
Prepared for
National Air Pollution Control Administration
(U. S. Department of Health, Education, and Welfare)
By
Tennessee Valley Authority
Contract No. TV-29233A
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POWER PLANT EQUIPPED WITH AMMONIA
SCRUBBING PROCESS FOR SULFUR OXIDE REMOVAL
SCRUBBING EQUIPMENT SHOWN IN COLOR
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PREFACE
On February 16, 1967, the National Center for Air
Pollution Control (Public Health Service, U. S. Department
of Health, Education, and Welfare) 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
emissions from power generation. The purpose is to
evaluate objectively and realistically the merits of different
methods under consideration for sulfur oxide control, with
a common and uniform basis used for comparison.
Various types of activities enter into the studies,
including (1) analysis of the published literature bearing on
the process, (2) direct contacts to obtain information from
organizations currently working on the process or in fields
allied to it, (3) bench- and plant-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 conceptual design study,
(5) market studies for processes involving recovery of a
salable product, (6) quotations from vendors and
fabricators on major pieces of equipment, and (7) detailed
cost estimates to cover a wide range of the parameters
involved.
Work has proceeded on three processes: (1) limestone
injection (dry process), (2) use of limestone in a
wet-scrubbing process, and (3) ammonia scrubbing. Reports
on the dry limestone injection and limestone - wet
scrubbing studies were issued in mid-1968 and in mid-1969,
respectively. Ammonia scrubbing, which has many
variations and complications, has been broken down under
several headings; the present report is concerned with the
variations in which ammonium sulfate is obtained as an
intermediate product and is then used in production of a
fertilizer material.
The work has been divided in TVA as follows:
Project Supervision
Applied Research Branch (Division of Chemical
Development)
Cost Estimates
Applied Research Branch
Design Branch (Division of Chemical Development)
Financial Planning Staff (Office of Power)
Report Preparation
Applied Research Branch
Air Quality Branch (Division of Environmental Research
and Development)
Distribution Economics Section (Division of Agricultural
Development)
A major part of the evaluation has been the analysis of
findings by other organizations who have worked on
ammonia scrubbing. These findings, which are, of course,
the basis for the conceptual design, are used throughout the
body of the report and are referenced in an annotated
bibliography. In addition to published literature, several
organizations have supplied information directly for use in
the study; the contributions of the following are
acknowledged.
American Air Filter Company, Inc.
Bloom Engineering Company, Inc.
Brownlee-Morrow Engineering Company, Inc.
C and I/Girdler Inc.
The Ceilcote Company
Chemical Construction Corporation
Chicago Blower Corporation
Cominco Ltd. (Canada)
Continental Manufacturing Company
Dorr-Oliver Incorporated
Dresser Industries, Inc.
Dutch State Mines (The Netherlands)
Electricite de France (France)
Federal Power Commission
Fuel Research Institute (Czechoslovakia)
Japan Engineering Consulting Company (JapL.i)
Kuhlmann (France)
Mitsubishi Shoji Kaisha, Ltd. (Japan)
NationalAir Pollution Control Administration (NAPCA)
National Dust Collector Corporation
Perfex Corporation
Riley Stoker Corporation
Simon Engineering Ltd. (England)
The W. W. Sly Manufacturing Company
Therm-Mech, Inc. [Brown Fintube Company
(Representative)]
Universal Oil Products Company (Air Correction
Division)
Otto H. York Company, Inc.
Reports in this series can be obtained from
Clearinghouse for Scientific
and Technical Information
5285 Port Royal Road
Springfield, Virginia 22151
The reports are identified and priced as follows:
Title
Number Price
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
Surfur Oxide Removal from Power
Plant Stack Gas—Ammonia
Scrubbing: Production of
Ammonium Sulfate and Use as
Intermediate in Phosphate
Fertilizer Manufacture
TB178-972 $3.00
PB183-908 3.00
*Not yet assigned.
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CONTENTS
SUMMARY 9
Study assumptions 9
Process equipment 10
Economic considerations 10
Capital required 11
Profitability 11
Conclusions and recommendations 12
INTRODUCTION 14
PROCESS VARIATIONS IN
AMMONIA SCRUBBING 16
Scrubber design and operation 16
Treatment of scrubber effluent 16
Use of ammonium sulfate 19
HISTORY AND STATUS 23
CHEMISTRY AND KINETICS OF SULFUR
OXIDE ABSORPTION 25
Equilibria involved 25
Vapor pressure 25
pH 27
Solubility 29
Viscosity and specific gravity 29
Kinetics and mass transfer 31
FORMATION OF AMMONIUM SULFATE 37
Oxidation in the scrubber 37
Oxidation in separate vessel 40
Acidification 40
USE OF AMMONIUM SULFATE IN PHOSPHATE
FERTILIZER PROCESSES 43
Nitric phosphate 43
Ammonium phosphate-sulfate 46
MAJOR ECONOMIC CONSIDERATIONS 47
Cost of alternative to recovery 47
Return on investment 47
Power plant capacity factor 49
Sulfur content of coal 50
Product marketing 52
STUDY ASSUMPTIONS AND DESIGN CRITERIA . . 54
Plant size 54
Sulfur content of fuel 54
Degree of sulfur dioxide removal 54
Dust removal 54
Operating time and capacity factor 55
Plant location 55
Amount of storage 55
Stack gas reheat 55
Fertilizer technology 55
Solids disposal 56
Process indices 56
General 56
Operating indices for process A
(28-14-0 production) 56
Operating indices for process B
(26-19-0 production) 56
Operating indices for process C
(19-14-0 production) 57
EQUIPMENT SELECTION AND DESCRIPTION 58
Selected reported technology 58
Major alternatives 65
Equipment description 73
INVESTMENT AND OPERATING COST 81
Investment 81
Operating cost 81
PROFITABILITY AND ECONOMIC POTENTIAL ... 93
Market study 93
Fertilizer industry logistics 93
Pricing of recovery products .100
Profitability 103
Economic evaluation 108
Basic economics of fertilizer process 108
Fertilizer company involvement 109
Power company basis Ill
RESEARCH AND DEVELOPMENT NEEDED 126
Degree of oxidation in scrubber 126
Control of bisulfite :sulfite ratio 126
Dust removal 126
Composition of scrubber liquor at steady state .... 126
Corrosion 127
Optimization of scrubber operation 127
Use of ammonium sulfate 127
CONCLUSIONS AND RECOMMENDATIONS 128
REFERENCES AND ABSTRACTS 131
APPENDIX A: Optimum pricing strategy 140
APPENDIX B: Cost estimates 146
APPENDIX C: Drawings 314
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TABLES
Page
S-l Capital requirements for process A 11
S-2 Profitability of process A 11
S-3 Profitability of process A with supplementary
income as payment for pollution abatement .... 12
S-4 Cost of recovery vs limestone - wet scrubbing
under power company economics 12
1 Reactions of NH3 with S02 and CO2 25
2 Vapor pressures in the system NH3-SO2-H20 ... 28
3 Values of constants A and B for
viscosity calculations 32
4 Effect of SO 2 :NH mole ratio on mass
transfer gas velocity: 1.5-2 m/sec 34
5 Capital cost of limestone - wet scrubbing 47
6 Operating cost for limestone - wet scrubbing .... 48
7 Averaged operating conditions for pilot
plant runs 59
8 Effect of pH on composition of
the scrubber effluent 61
9 Variation of the coefficient of absorption
with decrease in chemical capacity of the
absorbing solution 69
10 Comparison of scrubber combinations 70
11 Scrubber comparison 72
12 Comparison of demisters 73
13 Tray composition conditions 75
14 Estimated tray efficiencies 77
15 Total fixed investment of ammonia scrubbing-
fertilizer manufacturing facilities for
existing power plants 81
16 Total fixed investment of ammonia scrubbing-
fertilizer manufacturing facilities for
new power plants 82
17 Annual capital charges for power industry
financing - new power unit with 35-yr life 85
18 Lifetime operating costs for ammonia scrubbing
processes in new 500- and 1,000-mw
power units 86
19 Phosphate rock transporation cost via rail
and barge from Tampa, Florida 93
Page
20 Nitrogen market profile in the Midwest, 1967 ... 96
21 Materials sold as custom mixtures in
Illinois, 1966-1967 98
22 Fertilizer materials consumption and average
consumption density for the lowa-Illinois-
Indiana area 98
23 Competitive bulk-blending prices for standard
fertilizers and for sulfur oxide recovery
products (delivered to the Midwest) 99
24 Average return to manufacturing
process A (28-14-0) 102
25 Average return to manufacturing
process B (26-19-0) 102
26 Average return to manufacturing
process C (19-14-0) 102
27 Average return to manufacturing
ammonium sulfate 103
28 Summary of estimated fixed investment
requirements: manufacture of 28-14-0
fertilizer by sulfate recycle - nitric
phosphate process 109
29 Nonregulated company economics total
venture annual manufacturing costs for
28-14-0 fertilizer using ammonium sulfate
recycle and nitric phosphate process 110
30 Summary of estimated fixed investment
requirements: manufacture of ammonium sulfate
solution from waste gypsum ammonia, and carbon
dioxide - sulfate recycle process for 28-14-0
nitric phosphate fertilizer Ill
31 Annual manufacturing costs: ammonium sulfate
solution (40%) from waste gypsum, ammonia,
and carbon dioxide - sulfate recycle process
for 28-14-0 nitric phosphate fertilizer .113
32 Economic potential of ammonia scrubbing -
fertilizer production processes 114
33 Present worth of the net annual increase in cost
of power resulting from use of the ammonia and
limestone scrubbing processes ; 114
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FIGURES
Page
1 Ammonia scrubbing: regeneration by stripping ... 17
2 Ammonia scrubbing: acidification of effluent .... 18
3 Ammonia scrubbing: production of
ammonium sulfate 19
4 Ammonia scrubbing: precipitation (zinc oxide) ... 20
5 Ammonia scrubbing: use of (NH4)2S04 in
production of phosphate fertilizer by nitric
phosphate method 21
6 Ammonia scrubbing: use of (NH4)2SO4 in
production of phosphate fertilizer
by bisulfate method 22
7 Ammonia scrubbing: acidification of
effluent with NH4HS04 22
8 Reactions of NH3 with S02 and C02 26
9 Effect of sulfate content on S02
vapor pressure 29
10 Equilibrium vapor pressure over ammonia
sulfite'-bisurfite solutions 30
11 Partial pressure of SO2 in the system
(NH4)2S20S-(NH4)2SO3-S02 31
12 pH of NH4HSO3 -(NH^SOs solutions 32
13 Solubility diagram for the system
NH3-SO2-S03-H2Oat860 F 33
14 The system (NH4)2S04 -(NH4)2S03-NH4HS03-
H20 at 30° C 34
15 Solubility of (NH4)2 SO, in the
(NH, )2S03 -NH4HSQ, -H20 system at 30° C 35
16 System (NH4)2SO3-NH4HSO3-(NH4)2SCVH2O . 36
17 Air oxidation of ammonium sulfite-
bisulfite solution 41
18 Evaporation requirements for production of
(NHL,^ S04 from scrubber effluent 42
19 Ammonium phosphate nitrate by nitric phosphate
route (sulfate recycle process) 44
20 Typical weekly load curve for TVA power
system (spring 1968) 50
21 Annual variation of load in TVA power system ... 51
22 Sulfur oxide emission and sulfur
consumption in the U. S 53
23 Early TVA pilot plant for sulfur dioxide
recovery by ammonia scrubbing 58
24 Effect of packing depth on S02 recovery at
various liquor recirculation rates (at pH 6.4) 59
25 Effect of pH of scrubbing liquor on S02
recovery and NH3 loss 60
26 SO2 absorption in a venturi scrubber as a function
of flow rate of absorbent for various gas
velocities (w) in the scrubber throat 63
27 S02 absorption as a function of pressure
drop in scrubber 64
Page
28 S02 absorption as a function of total
consumption of electric power in a
multistage venturi arrangement (the curve
number corresponds to the number of stages;
pump pressure: 40 mm H20) 65
29 Absorption of S02 by ammonium sulflte-bisulfite
solution in wetted-wall absorber at varying
concentrations of S02 in the inlet gas 66
30 Sieve-plate scrubber tested by Chertkovef a/ .... 67
31 Collection efficiency for 1 -micron particles in
impingement-type scrubber 69
32 Four-stage perforated plate-impingement scrubber
with separate circulation of liquor streams 71
33 Four-stage scrubber with gas-liquid separation
plates under S02 absorption stages 74
34 Relationship of NOg and K , based on
Chertkov data for sieve tray absorption of
SO2 inNH3-SO2-H20 solution 76
35 Typical sly impinjet scrubber 78
36 Effect of power unit size on ammonia scrubbing -
fertilizer plant investment (process A) 82
37 Effect of power unit size on ammonia scrubbing -
fertilizer plant investment (process B) 83
38 Effect of power unit size on ammonia scrubbing -
fertilizer plant investment (process C) 84
39 Effect of sulfur content of coal on total
fixed investment 84
40 Effect of power unit size on annual operating
cost under nonregulated economics 87
41 Effect of power unit size on annual operating
cost under cooperative economics 87
42 Effect of power unit size on average annual
operating cost under regulated economics 88
43 Effect of power unit size on operating cost/ton
of fertilizer under regulated economics 88
44 Effect of power unit size on operating cost/ton
of coal under regulated economics 89
45 Effect of sulfur content of coal on annual
operating cost under cooperative economics 89
46 Effect of sulfur content of coal on unit operating
cost under cooperative economics 90
47 Effect of process operating time on annual
operating cost (process A) 90
48 Effect of process operating time on annual
operating cost (process B) 91
49 Effect of process operating time on annual
operating cost (process C) 91
50 Effect of process operating time on
unit operating cost 92
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Page
51 Effect of credit for air pollution control on
unit operating cost 92
52 Phosphoric acid plant locations 94
53 Central U. S. inland waterway system 95
54 Ammonia plant locations 96
55 Major ammonia pipelines 96
56 Bulk blend fertilizer plants by counties (1968) ... 97
57 Fertilizer use pattern in the United States 99
58 U. S. nitrogen fertilizer consumption
by regions (1945-1968) 100
59 Approximate location of major thermal
power plants 101
60 Substitution of byproduct 28-14-0 for ammonium
nitrate and 1846-0 at specified competitive
price conditions 104
61 Average return to manufacturing (ARM) and
average length of haul (ALH) for 28-14-0
(based on delivered price competitive with
ammonium nitrate) 105
62 Average return to manufacturing (ARM) and
average length of haul (ALH) for 26-19-0
(based on delivered price competitive with
ammonium nitrate). . 105
63 Average return to manufacturing (ARM) and
average length of haul (ALH) for 19-14-0
(based on delivered price competitive with
ammonium nitrate) 106
64 Average return to manufacturing (ARM) and
average length of haul (ALH) for 21-0-0
(based on delivered price competitive with
ammonium nitrate) 106
65 Expected market boundaries for 28-14-0 and
19-14-0 for ammonium nitrate
competition and a 500-mw plant 107
66 Ultimate competitive market boundaries for
28-14-0 and 19-14-0 for diammonium
phosphate competition and a 500-mw plant 107
67 Effect of power unit size on payout period
for nonregulated economics 115
68 Effect of power unit size on interest rate of
return for nonregulated economics 115
Page
69 Effect of power unit size on payout period
for cooperative venture 116
70 Effect of power unit size on interest rate
of return for cooperative venture 116
71 Effect of credit for air pollution control
on payout period 11'
72 Effect of credit for air pollution control
on interest rate of return 117
73 Effect of sulfur content of coal
on payout period 118
74 Effect of sulfur content of coal on
interest rate of return 118
75 Effect of operating time on payout period 119
76 Effect of operating time on interest
rate of return 119
77 Effect of variations in net sales revenue on
payout period (process A) 120
78 Effect of variations in net sales revenue on
payout period (process B) 120
79 Effect of variation in net sales revenue on
interest rate of return (process A) 121
80 Effect of variation in net sales revenue on
interest rate of return (process B) 121
81 Effect of recovery unit life on
interest rate of return 122
82 Effect of power unit size on cumulative present
worth of annual net increase or decrease in
cost of power consumers 122
83 Effect of sulfur content of coal on cumulative
present worth of annual net increase or
decrease in cost of power to consumers 123
84 Effect of operating time on present worth of
the cumulative net increase or decrease in
cost of power to consumers 123
85 Effect of variation in net sales revenue on
cumulative present worth of the annual net
increase or decrease in cost of power to
consumers (process A) 124
86 Effect of variation in net sales revenue on
cumulative present worth of the annual net
increase or decrease in cost of power to
consumers (process B) 125
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SUMMARY
The present study is the third in a series being carried
out by TVA for NAPCA on methods for removing sulfur
oxides from power plant stack gases. The first two were
concerned with use of lime or limestone as absorbents,
which convert the gaseous sulfur oxides to solid compounds
(calcium sulfite and calcium sulfate) that are discarded. In
the processes evaluated in the present study, the oxides are
recovered as intermediates for production of fertilizer
products that can be sold to offset, at least partially, the
cost of operation.
Processes that utilize recovered sulfur products are
potentially superior to the throwaway type because of the
possibility that the sales revenue will reduce the cost of
sulfur oxide control. On the other hand, recovery requires
much more investment, the necessity for product sale
complicates power plant operation, and the very large
amount of end products would have an upsetting effect on
existing markets.
Many processes have been proposed for sulfur oxide
recovery and some have been studiedon a fairly large scale.
In several instances claims have been made that a particular
method will "break even" or even show a substantial profit.
Such optimistic economic projections are not warranted,
however, unless they are based on a thorough conceptual
design and cost study that takes into account all the
complexities of incorporating a major chemical
manufacturing operation into a power plant. This is the
purpose of the current NAPCA-TVA series. The most
promising processes are selected and each subjected to a
detailed study in which the best design is developed from
the available data, capital and operating costs are estimated
on a uniform basis, a market survey is made so that sales
revenue can be estimated, total cash flow is related to
economic promise, and needed research and development is
identified.
Scrubbing with aqueous ammonia solutions, the subject
of the present study, is one of the simplest and most
economical ways of getting the sulfur oxides out of the gas.
Ammonia is relatively cheap, has a high affinity for sulfur
oxides, and can be allowed to go on into the product
because it is a good fertilizer material, worth more in the
solid form than as the original liquefied gas. However, since
use of ammonia requires a wet-scrubbing operation—as in
the limestone - wet scrubbing method-the gas is cooled and
reheating is required.
Scrubbing with ammonia gives a scrubber effluent
solution containing ammonium sulfite [(NH4)2S03] and
ammonium bisulfite (NH4HSO3); the main problem is how
best to convert these to useful products. There are many
ways to do this, too many to be evaluated in a single study.
Ammonia scrubbing can be regarded as a general field of
sulfur oxide recovery technology, with many separate
"processes" for converting the scrubber solution to
something usable.
The approach selected for the present evaluation is to
oxidize the sulfite to sulfate, a more useful form. The
product is ammonium sulfate [(NHt)2SO4], a material
that can be sold (as fertilizer) but does not command a very
large market. It would be better to use the ammonium
sulfate as an intermediate in making some other fertilizer
that has a greater market potential. There are three major
possibilities for this, all of which are evaluated in this
report.
Process A—Direct oxidation of the scrubber solution with
air to give ammonium sulfate solution, which is then
used to precipitate calcium in a nitric phosphate process.
In the latter, phosphate rock (calcium phosphate ore) is
dissolved in nitric acid, the ammonium sulfate solution is
added to precipitate the calcium from the ore as calcium
sulfate, and the resulting solution of ammonium nitrate
and phosphoric acid is separated from the calcium
sulfate and treated with ammonia to give a solid
ammonium nitrate-ammonium phosphate fertilizer
containing about 28% nitrogen and 14% phosphate (as
P2O5). The calcium sulfate is discarded.
Process B—The scrubber solution is treated with sulfuric
acid, which joins with the ammonia to give ammonium
sulfate. Sulfur dioxide freed by decomposition of the
sulfites is evolved and is converted to sulfuric acid in a
standard acid plant. Part of the acid is used to acidify
the scrubber solution and the remainder is used to
supplement the nitric acid in the nitric phosphate
process. The ammonium sulfate solution is used in the
same way as in process A. The process has the advantage
that using sulfuric acid in the nitric phosphate operation
gives a more favorable nitrogen:phosphate ratio in the
product (about 26% N and 19% P2 Os ).
Process C—The scrubber solution is oxidized as in process
A, the ammonium sulfate is crystallized, the crystals are
heated to convert them to ammonium bisulfate
(NH4HS04), and the bisulfate is used (in solution) to
dissolve phosphate ore. Precipitated calcium sulfate is
separated and discarded. The solution is finished as in
process A, giving a product containing about 20% N and
15% P2 Os. The main advantage, as compared with
process A, is that no nitric acid is required and therefore
a more favorable nitrogen:phosphorus ratio is obtained.
Study Assumptions
Recovery process economics depend on several factors,
including sulfur content of the coal, power plant size,
operating factor, and power plant status (new vs existing).
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It was necessary to assume a single combination of
conditions as a base case for the conceptual design. In the
cost estimates, the effect of variation in the major
parameters was evaluated. The basic conditions assumed are
as follows:
Power unit size, mw
Sulfur content of coal, %
Ash content of coal, %
Degree of SO2 removal, %
Degree of dust removal, %
Power plant status
Capacity factor, % of nameplate rating
First to lOthyr
10th to 15th yr
15th to 20th yr
20th to 35th yr
Average over life
Product storage capacity, days
Stack gas reheat temperature, °F
Plant location
Process Equipment
500
3.5
12
90
99.5
New
80
57
40
17
43
90
250
Midwest
The scrubber is one of the most expensive units in a
recovery system because it must handle the full flow of gas
(over 100,000 tons/day for a 1000-mw boiler) whereas the
solution treatment and fertilizer units handle a much lower
throughput. Based on a study and analysis of the data
available on ammonia scrubbing, the scrubber design
selected was the impingement version of the crossflow sieve
tray type. This type appears to give the lowest pressure
drop for the required degree of sulfur dioxide removal and
also has good dust collection efficiency.
Stagewise scrubbing will be necessary to minimize
ammonia loss in all processes and to maximize bisulfite
formation in process B (for maximum yield of sulfuric
acid). The number of stages required was calculated to be
three for processes A and C and four for process B. In
addition, the design includes a prescrubbing stage (in the
same scrubber tower) to remove the dust. Four scrubbers,
each handling 333,000 acfm at 118? F and each 20 x 40 x
27 ft high, are required for the 500-mw boiler unit.
Reheating is accomplished by a closed liquid loop that
transfers heat from the gas before the scrubber to the
scrubber exit gas. Estimates made in the previous study on
limestone - wet scrubbing indicated this to be the most
economical of several reheating methods considered.
Oxidation of the scrubber solution in processes A and C
is carried out in equipment that has been proven in large
installations in Japan. Detailed design information can be
obtained under license. The acidification step in process B
has also been tested on a large scale, by Cominco in Trail,
B.C.
The fertilizer step in processes A and B has been tested
in a TVA pilot plant and on a large scale in Europe. Hence
all steps of these methods are relatively well established and
detailed design information can be readily obtained, which
is not true for most of the recovery methods that have been
proposed. For process C, however, only limited small-scale
data are available.
Economic Considerations
Evaluation of recovery processes brings in factors such as
product marketability and price, profit margin, and
projected financial promise, all of which make the analysis
much more difficult than for the throwaway methods. It
would be desirable, of course, that the 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 the cost by
throwaway. Thus the cost of limestone - wet scrubbing
becomes the basic criterion for comparison. This was
calculated for the various combinations of variables in the
current study and used in evaluating the recovery processes.
The basis on which the recovery project is financed is a
major consideration in evaluating economic promise and
acceptability. Since power companies generally are not
familiar with producing and marketing anything except
power, there would be some advantage if a fertilizer
company operated the recovery process and marketed the
fertilizer products. For a private, unregulated 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
would be required because this varies with the situation. It
is generally considered that the projected cash flow
(depreciation plus profit after taxes) should pay out the
investment in about 5 yrs, or, on another basis which takes
into account the time value of money, the interest rate of
return1 should be about 15% (to recover both investment
and a reasonable return on investment). For the relatively
high investment required in sulfur oxide recovery processes,
this is a major hurdle.
If the power company finances the project, the situation
is entirely different. The investment would be part of the
total power plant investment, 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 a throwaway or recovery method, were to
increase operating cost, then the price of power to the
power consumers presumably could be raised to offset the
extra cost. Sulfur oxide removal (even by recovery), dust
collection, and cooling water recycling can all be considered
'interest rate at which present worth of the annual cash flow over
the life of the plant is equal to the investment.
10
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as necessary to production of power, just as is the boiler
operation, and the costs, therefore should be passed on to
the power consumer. It is true that rate increases are often
contested and delayed, and that the full adjustment may
not be allowed, so that the power company has
considerable incentive to avoid extra investment and
operating cost. In general, however, the power industry has
a more-or-less guaranteed profit. For this reason, there is
little risk and capital can be attracted at the regulated rate
of return.
Thus as a practical matter (but within some limits), loss
from operation of a sulfur oxide recovery unit can be
passed on to the power consumer. The main concern is the
trouble and delay in getting a rate increase. Another
consideration, however, is that neither power producer nor
regulatory authority has any reason to favor recovery if it
loses more money than limestone - wet scrubbing.
Therefore, for evaluation of the regulated financing basis
the present worth of expenditures over the life of the plant
must be compared, for each recovery method, with present
worth for limestone - wet scrubbing cost.
Because of the large product volumes involved, sulfur
oxide recovery (may have a major upsetting effect on
majkets for competing products. For fertilizer industry
financing this is justifiable because each product should
have the right to find its place on the economic ladder. For
power company financing, however, there is the somewhat
artificial factor that financial viability comes from sale of
power rather than sale of recovery product and that the
latter therefore could be dumped on the market at a price
not in accordance with the intrinsic economics. The effect
of this factor on the acceptability of regulated economics
for recovery processes is not clear at the present time.
Capital Required
Investment under various combinations of conditions are
given for process A in table S-l. Investment for processes B
and C ($37.5 and $31/kw for base case) were somewhat
lower than for process A. However, this is not significant as
process A makes more fertilizer product because of the
flature of the process; the production rates in tons/hr are
43, 33, and 19 for A, B, and C. Profitability/unit of
investment is the only valid method for comparing the
processes.
The investment required is relatively high as compared
with other recovery methods. However, a finished product
is made rather than an intermediate such as sulfur or
sulfuric acid; about 75% of the investment is in the
fertilizer part of the plant. Again, return/unit of investment
is the important criterion.
Profitability
A major consideration in profitability is net sales price
of the product. A market survey for the fertilizer products
resulted in the following conclusions.
1. The plant should be located in the Midwest.
2. Sales price should be set to compete with ammonium
nitrate rather than diammonium phosphate. This involves a
relatively large sales area and therefore high shipping cost
but gives more net revenue.
3. Expected returns to manufacturing range from
$33.40-39.50/ton of fertilizer.
4. The market is not large enough to support more than
about three 500-mw plants in the midwestern part of the
country.
Fertilizer Participation—Based on the projected
revenue, process A gives the payout periods and interest
rates of return shown in table S-2. The results are
unpromising and indicate strongly that, on their own, the
processes are not profitable enough to attract capital. It is
conceivable, however, that the power producer would be
willing to pay the fertilizer company a fee for the service of
abating pollution, since otherwise the power plant would
incur the heavy cost of a throwaway process. Table S-3
shows the economics on the basis of a payment to the
fertilizer company equivalent to the cost of limestone - wet
scrubbing. With this maximum service charge for sulfur
oxide control, the larger plant sizes become attractive but
the 500-mw base case remains questionable.
Process B economics are not quite as good as for process
A but the difference probably is not significant. For
Table S-1.Capital Requirements for Process A
Capital, $/kw
Conditions of power capacity
Base case (500-mw, new power unit,
3.5% sulfur in coal, 43% average
capacity factor, reheat to 250° F) 41
Exceptions to base case
Existing power unit 45
5% sulfur 50
Reheat to 175° F 38
1,000 mw 33
Table S-2. Profitability of Process A
Conditions
Base case I500-mw, new power unit,
3.5% sulfur in coal, 43% average
capacity factor, reheat to 250° F
Exceptions to base case
Existing power unit
5% sulfur
Reheat to 175° F
1,000mw
Payout,
yr
8.7
9.8
6.6
7.9
6.4
Interest rate
of return, %
5.7
1.4
11.4
7.3
12.0
11
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example, payout and interest rate of return for the base
case (with payment of pollution abatement fee to the
fertilizer company) are 6.3 yrs and 12.5% as compared with
6.1 yrs and 13.0% for process A,
The process technology for process C is not as well
defined as for processes A and B. Therefore, the accuracy
of estimates used in economic evaluation of this process is
relatively low. However, the conclusion that process C
economics are poor is valid. In most cases, the cash flow is
out rather than in and the investment does not pay out at
all, even with income from the pollution payment.
A cooperative venture was also evaluated, with the
power company financing and operating the scrubbers and
the fertilizer company producing the fertilizer. In
comparison with the all-fertilizer company approach, the
economics are not significantly different. The cooperative
project has a small advantage for the largest plant sizes.
Power Company Economics—If the power company
finances the complete recovery installation and the
investment is incorporated in the rate base, the situation is
considerably different. The main question then is whether
or not the recovery process saves any money as compared
with limestone - wet scrubbing.
A comparison of the two methods is given in table S-4.
The values given are present worth of the net annual costs
over the life of the power plant; this basis was used because
one system may be better in one particular yr and the
reverse in some other yr. Thus the values given represent
the total bill in current money for sulfur oxide control over
the life of the power plant.
The costs for the two methods (at 3.5% S) are about the
same at 500 mw; above this, recovery becomes increasingly
preferable to limestone - wet scrubbing. The same effect
can be obtained by increasing the sulfur content of the
coal.
The economics for both power and fertilizer financing
are quite sensitive to projected sales revenue. For example,
an increase of 10% over the revenue projected would reduce
the equal-cost size to about 300 mw, and 10% less would
increase it to about 850 mw.
Conclusions and Recommendations
Conclusions resulting from the present study can be
summarized as follows:
1. Ammonia scrubbing and production of phosphate
fertilizer has promise, under certain conditions, as a method
for recovering sulfur oxides from stack gases.
2. The main economic factors are product volume
(depending on power plant size and S content of coal), net
sales revenue, and basis of financing.
3. Private industry participation in financing and
operation appears unlikely because of the high projected
Table S-3. Profitability of Process A with Supplementary Income
Conditions
Base case (500-mw, new power unit,
3.5% sulfur in coal, 43% average
capacity factor, reheat to 250° F)
Exceptions to base case
Existing power unit
5% sulfur
Reheat to 175° F
1 ,000 mw
Payout,
vr
6.1
6.4
5.0
5.9
4.9
Interest rate
of return, %
13.0
11.0
17.4
13.7
17.9
Table S-4. Cost of Recovery vs Limestone - Wet Scrubbing
Under Power Company Economics
Present worth of annual
net costs,3 $ millions
Conditions
Base case (500-mw, new power unit,
3.5% sulfur in coal, 43% average
capacity factor, reheat to 250° F)
Exceptions to base case
Existing power unit
5% sulfur
Reheat to 1 75° F
200 mw
I.OOOmw
Recovery
(Process A)
17.2
22.4
5.3
14.2
19.4
4.6
Limestone -
wet scrubbing
16.8
16.9
19.7
14.2
7.2
26.5
aOvei plant life of 35 yrs.
cash flow necessary to attract capital. There is a net profit
for plants about 500 mw and larger but it is not large
enough to attract investment except perhaps under special
conditions. The situation is improved if there is
supplemental income in the form of a payment for the
service of sulfur oxide control; in this case the larger
product volumes (e.g., 1000 mw at 3.5% S in coal or 500
mw at 5% S) give a projected total income adequate for
financing.
4. The economics under power industry financing are
more promising. For plants 500-600 mw and larger in size
the recovery method is favored over limestone - wet
scrubbing because there is less deficit passed on to the
power consumer after payment to investors of the regulated
return on investment.
5. Only a few recovery installations of this type can be
accommodated by the fertilizer market.
6. It may be possible to improve the economics by (1)
increasing the lifetime capacity factor, (2) reducing the
degree of gas reheat, and (3) development of new
departures that may reduce investment and operating cost.
12
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Further data on design and operation of the processes done aimed at eliminating the oxidation step in process A.
are needed to refine the estimates. Some needed No further work on process C is recommended unless
information will be obtained in the current NAPCA-TVA fertilizer research organizations find ways to improve the
pilot plant project on ammonia scrubbing, in which the fertilizer sections of the process. Finally, conceptual design
parameters involved in the scrubbing step will be studied and cost studies should be carried out on other ways of
intensively. It is recommended in addition that research be recovering sulfur values from the scrubber solution.
13
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INTRODUCTION
This report presents the third in a series of conceptual
design and cost studies mady by the Tennessee Valley
Authority (TVA) for the National Air Pollution Control
Administration (NAPCA) on methods for removing or
recovering sulfur oxides from power plant stack gases. The
first two covered use of limestone as a sorbent for sulfur
oxides, in dry and wet processes respectively; in both cases,
the sulfur oxides removed from the gas are discarded as
calcium sulfate or sulfite. The present report is concerned
with the use of ammonia as the absorbent, in processes that
recover a useful product which can be sold to offset, at
least partially, the cost of operation.
Ammonia is an expensive absorbent as compared with
limestone and therefore must be recovered either for
recycle (regenerable process) or as a constituent of the
product (nonregenerable process). The present study is
restricted to those variations of the nonregenerable process
in which ammonium sulfate is obtained as an intermediate
product and is then used as a raw material in production of
a multinutrient fertilizer. It is planned to evaluate other
variations, of both the nonregenerative and regenerative
processes, in future studies.
The need to remove sulfur oxides from power plant
stack gases has been well documented in numerous reports
and publications. Sulfur dioxide is generally regarded as the
most serious of the several gaseous pollutants, mainly
because of the tremendous quantities emitted from
smelters, power plants, and industrial boilers. It has been
estimated that about 30 million tons of sulfur dioxide is
emitted to the atmosphere annually in the United States
alone, and that of this amount power plants account for
about half. Emission can be reduced by using low-sulfur
fuel, either low in the natural state or processed to remove
sulfur, or the polluting effect can be reduced by dispersion
from tall stacks. These approaches have major drawbacks,
however, to the extent that treatment of the stack gas to
remove the pollutants may be preferable.
Recovery of the sulfur oxides in a useful form is
obviously desirable, both to give some income to help
offset the removal cost and also to conserve a valuable
national resource. Moreover, a new source of sulfur is
needed for the fertilizer industry, a major consumer of
sulfuric acid, because the usual sources are being depleted.
Thus the combination of pollution abatement, conservation
of a natural resource, and meeting the needs of the fertilizer
industry is a major incentive to sulfur dioxide recovery.
Unfortunately, the low sulfur dioxide content in the stack
gas (0.2-0.3%), plus unfavorable factors in power plant
operation, make recovery an extremely difficult operation
to carry out at acceptable cost.
In the previous two studies in this series, it was assumed
that recovery would not be attempted and that the product
would be discarded; as a result the process was simplified,
costs for equipment and operation were reduced, and other
advantages not amenable to cost estimating were obtained.
The removal cost was a complete loss, of course, since there
was no income from product sale, but the estimated cost
was low enough (typically $0.65-1.00/ton of coal burned)
to be acceptable. The question in regard to recovery
processes is whether the economics, even after income from
product sale, will be any better. The purpose in this and the
further design studies on recovery methods will be to
answer this question
In addition to the undesirable composition of the gas,
low in sulfur dioxide and high in fly ash and moisture, the
very large amount of sulfur involved is a problem in
applying recovery to modern, large-boiler, multiunit power
plants. Pertinent data for a 1000-megawatt (mw) boiler are
as follows:
Coal burned, ton/day (100% capacity factor) 9,000
Typical sulfur content of coal, % 3.5
Sulfur emitted, % of S in coal 92
Sulfur emitted/day as tons of
Sulfur dioxide 578
Sulfuric acid 885
Sulfur dioxide content in gas, volume % 0.22
Gas flow
Acfm 2.0 x 106
Ton/day 110,000
Du st in gas, ton/day 810
Moisture in gas, ton/day 8,600
For a 3000-mw base station, which power plant size is
approaching, the equivalent of 2,660 tons of sulfuric acid
would be produced/day. Selling this much acid, or any
other product except perhaps elemental sulfur, from one
point is a major problem.
Quantity becomes a problem also if recovery is
considered as a general, country-wide solution to the sulfur
oxide control problem. The large tonnage of
sulfur-containing materials produced would have a major
impact on the market structure for such products. Data
pertinent to this problem are are as follows (estimated data
for the year 1970):
Sulfur emitted from utility power
plants in the U. S. (40)
Sulfur consumed in the U. S. (62)
Power plant sulfur emission expressed
as sulfuric acid
Sulfuric acid consumed in the U. S. (62)
Sulfuric acid consumed by the U. S.
fertilizer industry (62)
Tons/yr
10,000,000
11,000,000
30,700,000
30,600,000
18,500,000
14
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It would not be expected that all plants would be
equipped with sulfur recovery processes, and the processes
would not recover all the sulfur from the gas. Nevertheless,
recovery of even one-half of that emitted would present a
major marketing problem and would seriously affect the
economic situation of companies now making the sulfur
products in question.
A great many sulfur oxide recovery methods have been
proposed-literally hundreds if variations and untried
processes are included in the count; the problem has been a
favorite subject for researchers for several decades. The
field is so complicated that NAPCA has contracted for a
group of area surveys to sort out the methods, organize
them into a manageable classification, and evaluate them on
a preliminary basis. The subjects of these surveys make a
convenient general classification scheme.
1. Scrubbing with aqueous salt solutions.
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 of sulfur dioxide by physical
methods.
Of these, the first three have received major attention.
Large semiworks-scale units have been built to demonstrate
processes falling within each of the three classes. It is not
appropriate here to review these processes or to evaluate
the three general types against each other. It can be said,
however, that each has shown some promise, each has
major disadvantages, and none has been shown conclusively
to be better than the others.
One of the main disadvantages in aqueous salt solution
scrubbing, the class into which the present study falls, is
that the aqueous solution cools the gas-to a temperature as
low as 12^ F-and therefore a good part of the thermal lift
in the gas plume leaving the stack is lost. As a result the
plume may come back to the ground sooner than
otherwise, without the normal degree of dilution by
ambient air, and thereby increase the problem from
pollutants such as nitrogen oxides that it still contains. The
cost of reheating the gas before emission was estimated in
the limestone - wet scrubbing report; the cost is significant
but may be no more a handicap than those of different
nature found in the other process types.
Countering this disadvantage of plume cooling, aqueous
solution scrubbing has the advantages of high absorption
efficiency and simplified handling of absorbent both in
scrubbing and regeneration. (Nonaqueous liquids would
give the same advantages but have some major drawbacks.)
There are also advantages over use of solid sorbents;
granular solids may deteriorate structurally, and fine solids,
since they travel with the gas, may require large vessels or
multicycling to get adequate retention time and special
equipment to get adequate separation from the gas.
Among aqueous scrubbing processes, use of an
ammoniacal salt solution has received the most attention.
The ammonium cation is an effective reactant, the cost of
ammonia makeup is low, and there are several methods for
treating the scrubber effluent to recover the sulfur that may
have promise. Recovery of the sulfur as an ammonium
compound for sale or further use is the simplest method for
treating the scrubber effluent. The regenerative methods
require more processing steps and are subject to process
complications. A pilot plant program is being carried out by
TVA for NAPCA to provide information for future
evaluation of these methods.
Sodium and potassium salt solutions have been studied
also but to a lesser extent. It is planned to extend the pilot
plant program to cover the potassium system as the basis
for a later design and cost study.
15
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PROCESS VARIATIONS IN AMMONIA SCRUBBING
Recovery of sulfur oxides by ammonia scrubbing
involves many possibilities and complications, both in
regard to the scrubbing step and to treatment or use of the
loaded absorbent. Several flowsheets can be drawn up even
for one particular end product and there are several
products that can be made. To clarify the subject, an
outline of the process variations is desirable.
Scrubber Design and Operation
When ammonia is first introduced into the scrubber
system it can react as follows:
NK,
2NH
H2O
S0
NH4HS03
Ammonium
bisulfite
^ (NH4)2SO3
Ammonium
sulfite
(1)
(2)
Process considerations, however, require recycling of part
or all of the scrubber liquor, either from a regeneration step
or because recycling at the scrubber is necessary for good
absorption. In either case, operation does not continue long
until ammonium sulfite becomes the principal scrubbing
agent.
)2 SO3 + SO2
2NH4HS03
(3)
Complete reaction to bisulfite is not feasible, however,
because the pH would be reduced to so low a level that
sulfur dioxide could not be removed effectively. In practice
the pH is adjusted to give the best balance between sulfur
dioxide leakage at low pH and ammonia loss at high pH. To
get the best results in this respect, stepwise scrubbing can
be employed, with relatively high pH in a first or second
stage (preferably the second stage; see below) and lower pH
(plus more dilute solution) in a cleanup stage to minimize
ammonia loss.
Hence the scrubber effluent contains both ammonium
sulfite and bisulfite, in a ratio determined by the way in
which the scrubber is designed and operated. It also
contains ammonium sulfate because some oxidation of
sulfite by oxygen in the stack gas is unavoidable; moreover,
the entering gas contains a small amount of sulfur trioxide
that reacts with ammonia to form ammonium sulfate.
For some of the nonregenerative processes, the
composition of the scrubber solution is not critical; the
scrubber function is only to remove sulfur dioxide while
preventing loss of ammonia. Conversion of ammonia and
sulfur dioxide to ammonium sulfite (equation 2) would be
desirable except that at the high pH (8.0) ammonia loss
would be high. For processes that require ammonium
sulfate as an intermediate or final product, formation of
sulfate would not be a problem and in fact should be
promoted, as much as possible without interfering with
absorption, to reduce the requirement for oxidation of
sulfite to sulfate in a subsequent step.
For regenerative processes (and some of the
nonregenerative type), it is desirable to have as high a
bisulfitersulfite ratio and as low a concentration of sulfate
as possible. Bisulfite forms more readily when the first stage
of scrubbing is operated at relatively low pH (about 4),
thereby increasing the sulfur dioxide:ammonia ratio.
Scrubbing efficiency is reduced but the succeeding stage or
stages, operated at higher pH, finish the job.
Research by previous investigators indicate that sulfate
formation can be minimized in several ways, including (1)
use of oxidation inhibitors, (2) removal of dust before
scrubbing (to avoid any catalytic effect either from the
absorptive surface or the metal compounds present), (3) use
of nonmetal materials in scrubber construction (also to
avoid catalysis), and (4) minimizing oxygen absorption by
selection of scrubber design and by operating at as high
solution concentration as possible. However, the available
data is not adequate for evaluating these effects.
Hence the scrubber effluent is a solution of ammonium
sulfite, ammonium bisulfite, and ammonium sulfate. A
typical liquor composition, (41) for a process requiring high
bisulfite:sulfite ratio, is as follows:
Ammonia
Sulfur, total
Sulfur present in bisulfite form
Sulfur present in sulfite form
Sulfur present in sulfate form
pH
Treatment of Scrubber Effluent
_J5/L
95
133
87
23
23
5.9
The ammonia scrubbing step removes the sulfur dioxide
from the gas efficiently and produces it as a concentrated
solution of sulfite, bisulfite, and suifate. The sulfite and
bisulfite are not useful products so it is necessary to convert
them to something else, and to recover the ammonia for
recycling unless it goes on with the product. Numerous
methods for conversion and recovery have been proposed
and some have been tested. Those that appear to have some
promise will be summarized.
In order to simplify the presentation, the various
methods for treating the scrubber effluent solution will be
divided into five principal classes.
16
-------
1. Stripping—The ammonium bisulfite is an unstable
compound and will produce a relatively high vapor pressure
if heated even to a level of only 50° F or so above the
scrubbing temperature. Moreover, the sulfur dioxide partial
pressure is much higher than for the ammonia, so that
passing the gas through a condenser to condense the
ammonia as ammonium sulfite will produce a stream of
sulfur dioxide and water vapor essentially free of ammonia.
The stripped solution and the condensate are recycled to
the scrubber, and the sulfur dioxide is converted either
to sulfuric acid or elemental sulfur as the final
product (figure 1).
Feasibility of the stripping method depends largely on
the amount of bisulfite in the scrubber effluent solution.
Ammonium sulfite does not contribute because even if it
were decomposed all the sulfur dioxide would recondense
with the ammonia. Therefore it is necessary to design and
operate the scrubber to give as high a bisulfite to sulfite
ratio as can be obtained without incurring offsetting
adverse effects. This is a difficult problem as wiH be discussed
later.
2. Acidification—Since sulfurous acid (H2S03) is a
weak acid, any strong acid added to the scrubber effluent
will capture the ammonia and release sulfur dioxide from
the sulfite and bisulfite. This method gives two products:
(1) either sulfuric acid or elemental sulfur made from the
evolved sulfur dioxide and (2) the ammonium salt of the
added acid. Since sulfuric, nitric, and phosphoric are the
most appropriate acids to use, the coproducts are
ammonium sulfate, ammonium nitrate, and ammonium
phosphate respectively (figure 2).
If sulfuric acid is used, an obvious source of the acid is
the sulfur dioxide evolved, converted to sulfuric acid in an
acid plant installed as part of the recovery installation.
More acid will be produced than needed for effluent
acidification, so that there is some net production of
sulfuric acid for sale. The amount depends on the content
of bisulfite in the scrubber effluent, as each mole of
bisulfite produces one mole of sulfur dioxide in excess of
that required to make the sulfuric acid for recycling,
whereas all the sulfur dioxide evolved from ammonium
sulfite must be recycled.
2NH4HSO3 + H2SO4 -» (NH^ SO4
+ 2SO2 +2H2O (4)
(NH4)2SO3 + H2S04-> (NH4)2SO4
+ S02 + H2O (5)
Thus to maximize production of sulfuric acid, the scrubber
should be designed and operated for high bisulfite; if
ammonium sulfate is preferred then operation to give
sulfite is indicated. In most situations sulfuric acid is the
more desirable of the two products.
3. Oxidation—If ammonium sulfate is the desired
product, the simpler procedure can be used of oxidizing
sulfite directly to sulfate while still in solution. The
scrubber effluent is reacted with oxygen (ordinarily
supplied as air) under pressure to convert ammonium sulfite
Gas
From
Boiler
To Stack
f
1
Scrubber
,
J
1
(NH4)2S03 S
1
Stripper
^~
r~^
\
oln
*»
^. Steam
i
|
1
1
1
i >
SO2
E
Condenser
I
1
_ ^ Reduction
Unit
^ Sulfuric
Acid Plant
-^- Cooling Water
*•
(NH4)2S03 Soln
Figure 1. Ammonia Scrubbing: Regeneration by Stripping
H2S04
17
-------
To Stack
Gas
From
Boiler
1
Scrubber
M LJ
r
i
i
i
i
i
i
i +.
HN0^ t»
H3P04 *.
S05
r
i
Acidification
SC
4
T
Acidification
^ Sulfuric
Acid Plant
i
>* Sulfuric
Acid Plant
I
L».^i Reduction
Unit
_„ .^ Prillinq
or
"*~ ~" "" ' *" Granulation
i *.H2S04
i
B.JMLJ \ CD
»>H2S04
_^S
^ NH+ NOj
__^NH4H2PO4-(NH4)jHP04
Figure 2. Ammonia Scrubbing: Acidification of Effluent
to ammonium sulfate. The bisulfite is first converted to
sulfite by addition of ammonia to the scrubber liquor
before the oxidation step (figure 3). The only product is
ammonium sulfate.
In this method both sulfite formation and oxidation in
the scrubber are desirable, which simplifies the operation
considerably.
4. Autoclaving — If ammonium bisulfite and sulfite are
heated under pressure disproportionation takes place, that
is, part of the material is oxidized and part is reduced. The
reactions involved are complex and have been presented
differently by various investigators. The following is an
example but other reactions are known to take place.
2NH4HS03+(NH4)2S03?i+
2(NH4)2S04+S +
(6)
The process has the advantage, in comparison with
acidification, that sulfur rather than sulfuric acid is the
coproduct with ammonium sulfate. Corrosion, however,
appears to be a major problem.
5. Precipitation—Except for stripping, the above
methods give an ammonium salt as the sole or coproduct
whereas sulfur or sulfuric acid may be preferred from the
marketing standpoint. As stripping requires a very large
amount of heat and recirculation of large volumes of liquid
between the scrubber and stripper, particularly for the
lower ranges of sulfur dioxide content in the gas, alternate
methods haire been sought
One approach is to add to the scrubber effluent some
material that will precipitate the sulfur compounds in a
nonammoniacal form; the precipitate is then separated and
regenerated separately. In the analogous sodium sulfite
scrubbing process, zinc oxide is the preferred material for
18
-------
NH3
Gas
From
Boiler
To Stack
t
Scrubber
1
1
NH3
i,
NH4HS03&
(NHL), SO,
Oxidizer
(NH, )2 S04 (Soln)
.Air
Figure 3. Ammonia Scrubbing: Production of Ammonium Sulfate
this reaction; it precipitates zinc sulfite, a compound that
decomposes at about 500° F to give sulfur dioxide and
regenerated zinc oxide — ZnSOsA* JSO2 + ZnO (figure 4).
Presumably zinc oxide could be used also to precipitate
zinc sulfite from ammonia scrubber effluent solution;
however, the chemistry of the reaction does not seem to
have been worked out.
The bisulfite to sulfite ratio in the scrubber liquor may
not be important in this process but oxidation is
undesirable because it results in formation of zinc sulfate,
which has various undesirable process effects.
Another approach is to operate the scrubber at as high a
solution concentration and bisulfite to sulfite ratio as
possible and then add ammonia to the effluent solution. As
sulfite is less soluble than bisulfite, conversion of bisulfite
to sulfite by the ammoniation causes crystallization of
sulfite. The separated crystals can be decomposed at
relatively low temperature without the large amount of
heat expended for water evaporation in the stripping
process. The problem is that ammonia volatilizes as well as
sulfur dioxide and the two are difficult to separate. Several
methods for separation have been proposed but none have
been, studied enough even for preliminary evaluation.
Use of Ammonium Sulfate
Methods 2 and 3 discussed above for treating the
scrubber effluent produce ammonium sulfate as either the
sole product (method 3) or a coproduct (method 2). The
methods have the advantages that no solution recycling,
with the attending problems, are involved and that both
have been investigated to a relatively advanced degree. The
main drawback, for this country at least, is that ammonium
sulfate is not a desirable product. Although it has been a
leading fertilizer in the past, consumption is now somewhat
static, the amount consumed is small relative to the
potential production from power plants, and the sales price
is relatively low. Moreover, the price structure is affected
adversely by production of ammonium sulfate as a
byproduct in other industries such as nylon and steel.
Hence it would be quite desirable to use the ammonium
sulfate as an intermediate in making some other product.
Production of phosphate fertilizers offers an opportunity
for this, for ammonium sulfate can be used to tie up and
remove calcium from phosphate ore (commonly called
phosphate rock), an operation that must be carried out to
make the phosphate usable as a fertilizer. There are two
major possibilities for using ammonium sulfate in this way.
19
-------
1. Nitric Phosphate Fertilizer—Various methods have
been developed in the fertilizer industry for using nitric
acid to dissolve phosphate rock so that it can then be
converted to an effective fertilizer. Using nitric acid in this
way eliminates the need for the sulfuric acid that is
normally used, thereby gaining both process and economic
advantages. The nitric acid method, however, introduces a
problem because calcium nitrate, a very hygroscopic
material, is formed and must either be removed or
converted to a more acceptable material.
One of the methods that seems promising for dealing
with the calcium nitrate problem is to treat the phosphate
rock-nitric acid reaction slurry with ammonium sulfate,
which reacts with the calcium nitrate to form soluble
ammonium nitrate (an acceptable fertilizer material) and
insoluble calcium sulfate. The precipitated calcium sulfate >
is then reacted with ammonia and carbon dioxide to
convert it back to ammonium sulfate for recycling; the
calcium carbonate also formed is discarded. The process is
now under pilot plant development at TVA and shows
promise as a way of reducing fertilizer cost.
If ammonium sulfate were already available from a
power plant as the product of a sulfur oxide recovery
operation, it could be used in. the nitric phosphate process
in place of the recycled ammonium sulfate. It would not be
necessary then to go through the step of converting calcium
sulfate to ammonium sulfate, and the cost of this
conversion could be credited to the ammonia scrubbing
process. The precipitated calcium sulfate would be
discarded and the filtrate, containing ammonium nitrate
and phosphoric acid, reacted with ammonia to give an
ammonium phosphate-nitrate fertilizer.
A flowsheet for the process is shown in figure 5. An
analogous system is employed in a European fertilizer
plant, where byproduct ammonium sulfate from a
caprolactam operation is used to precipitate calcium
sulfate in a nitric phosphate plant of the type shown.
2. Ammonium Phosphate-Sulfate Fertilizer—In
another approach, the ammonium sulfate is heated at about
700° F to convert it to ammonium bisulfate (NH4HS04)
and the evolved ammonia is recycled.
(NH4)2 SO4-+NH4HSO4 + NH3 t
(7)
The ammonium bisulfate is acidic and therefore a solution
of it can be used in place of sulfuric acid for dissolving
phosphate rock. The resulting slurry would be filtered to
remove calcium sulfate and then ammoniated to give
ammonium phosphate-sulfate fertilizer. A flowsheet for
such a system is shown in figure 6.
Ammonium sulfate can also be used as an intermediate
or raw material in production of sulfuric acid or sulfur.
Again there are two major possibilities.
1. Use in Scrubber Solution Treatment—Since
ammonium bisulfate made by heating ammonium sulfate is
acidic, it can be used in the acidification method discussed
earlier for stripping sulfur dioxide from the scrubber
effluent solution (figure 7).
To Stack
Gas
From
Boiler
t
saJ^
Scrubber
I
!-»•
\
Filter
1
t
ZnO
Dryer
Calciner
1
.Fuel
Figure 4. Ammonia Scrubbing: Precipitation (Zinc Oxide)
20
-------
NH4HS03 + NH4HSO4 -
+ SO2t+H20 (8)
(NH4)2SO3 + 2NH4HS04^ 2(NH4)2S04
+ S02 t + H20 (9)
(NH4)2S04-^NH4HS04 + NH3 t (10)
The advantage of this system is that the amount of
ammonium sulfate ending up as final product is minimized.
Only the sulfate resulting from oxidation before and in the
scrubber goes into the product, whereas if sulfuric acid is
the acidification agent as in the method described earlier,
all the ammonium sulfite is converted to sulfate as well.
2. Conversion to Sulfuric Acid—The ammonium
sulfate can also be converted back to ammonia and sulfuric
acid. Reaction with zinc oxide at high temperature releases
the ammonia and forms zinc sulfate, which can then be
heated (at about 850° C) to regenerate the zinc oxide and
give a rich stream of sulfur trioxide that can be absorbed
directly to form sulfuric acid.
NH3 t + H2 0 (11)
(NH4)2 SO4 + ZnO^ ZnS04
ZnSO^ZnO + SO, t
(12)
(13)
This outline lists some of the many different process
approaches that can be followed in using ammonia
scrubbing for sulfur oxide recovery. Each of them could be
the subject of a full design and cost study. To narrow the
present study down to a manageable size, only those uses of
ammonium sulfate that give a phosphate fertilizer will be
considered. It is planned to cover some of the other
possibilities in forthcoming studies.
Phosphate Rock
HN03
(NH4)2SO4 Soln frorr
Acidulation
Tank
Scrubbing System
/J
Sulfate
pptn
Reactor
Fill
H3P04-NH4N03 Soln
CaS04
to Waste
NH3
1
Neutralization
Concentration
Prilling
or
Granulation
Ammonium
Phosphate-
Nitrate
Product
Figure 5. Ammonia Scrubbing: Use of (NH4)2 SO4 in Production of Phosphate
Fertilizer by Nitric Phosphate Method
21
-------
Scrubber ^
(NH4)2S04
From
Scrubber
System
n
NH3
Furnace
or
Kiln
i
i
Dissolver
*
Ph
Nr^HSQ
J
losphate Rock
i
Extractor
, Soln
i
CaSO4
to Waste
NH3
1
f
Neutralization
Concentration
Prilling
or
Granulation
Ammonium
Phosphate-
Sulfate
Product
Figure 6. Ammonia Scrubbing: Use of (NH4)2 SO4 in Production of Phosphate
Fertilizer by Bisulfate Method
Scrubber
_ NH3
S02
NH4HS04
f
Reactor
NH4S04
H2S04
Plant
Decomposer
Figure 7. Ammonia Scrubbing: Acidification of
Effluent with NH4HSO4
22
-------
HISTORY AMD STATUS
Removal of sulfur oxides from gas streams by reaction
with ammonia or absorption in ammoniacal solution has
been a subject of research since the beginnings of the
chemical industry. In fact, the earliest reference found in
the present survey was a patent by Ramsey in 1883 (72).
The original objective was not control of sulfur oxide
emission from power plants, however, but rather
production of ammonium sulfate without going through
the sulfuric acid step and, later, removal of sulfur dioxide
from the stack gas of sulfuric acid plants and smelters.
Some of the early sulfur oxide scrubbing work beyond
the test tube scale was done in Japan, where in 1926 the
Japanese Government Chemical Research Institute
completed development of an "Oxy-Oxidation" method.
After tests with a 3- to 4-metric tons per day (mt/day) unit
in 1931, a 60-mt/day ammonium sulfate plant was built in
1935, followed by a 200-mt/day plant in Manchukuo in
1937. Pyrite was burned to supply the sulfur dioxide,
which was absorbed by ammonium sulfite solution (4
molar). The solution was then neutralized with ammonia
and oxidized to ammonium sulfate by oxygen or air, at 2-3
and 8-9 atmospheres, respectively (43).
Early work on applying ammonia scrubbing to recovery
of sulfur oxides from waste gases was carried out by the
American Smelting and Refining Company and by the
Consolidated Mining and Smelting Company (now
Cominco, Ltd.), the latter beginning in about 1932.
Operation of zinc and lead smelters at Trail, B. C., by
Cominco gave rise to a pollution problem, part of which
was solved by installing sulfuric acid plants to recover sulfur
dioxide from the zinc smelter waste gas. The gas from the
lead smelter was too low in sulfur dioxide content for acid
manufacture, however, so ammonia scrubbing was
developed as an alternate. This work culminated in
installation of a commercial unit in 1936 (60).
The gas from the lead plant contained only about 0.3%
sulfur dioxide; however, modifications to the sintering
machines and the gas-treating system raised the
concentration to over 1%. The ammonium sulfite-bisulfite
solution from the scrubbing step was acidified by treatment
with sulfuric acid to drive off sulfur dioxide from the
bisulfite. About 44% of the sulfur was evolved as sulfur
dioxide and the remainder was produced as ammonium
sulfate, for which Cominco had a use in fertilizer plants
operated in conjunction with the smelter.
The evolved sulfur dioxide was initially converted to
elemental sulfur by a Cominco-developed process in which
the gas was passed through a bed of incandescent coke.
Production was about 150 tons/day of sulfur in the three
reduction units constructed (57). In 1943 the increasing
need for sulfuric acid in the Cominco operations resulted in
closing down the reduction units and using the sulfur
dioxide to make acid.
In 1945 Cominco installed a unit to remove sulfur
oxides from sulfuric acid tail gas by ammonia scrubbing
(27). This process was later installed on acid plants by the
Olin Mathieson Company in the United States.
In other work (57), Cominco developed a thermal
stripping process, called the "exorption" method. A
commercial plant containing six exorption units was built
and operated for some time. Pilot plant work was done also
on an autoclave method, in which the scrubber effluent was
heated under pressure to disproportionate the ammonium
bisulfite to ammonium sulfate and elemental sulfur (similar
to the older Katasulf method).
During much of the period in which the Cominco
developments were taking place, work was under way also
by Johnstone and coworkers at the University of Illinois.
Five major papers were published in the period 1935-1952
on the basic chemistry of sulfur oxide absorption in
ammoniacal solutions and on desorption from the scrubber
effluent (45,46, 47, 48, 50). Careful measurements of
vapor pressures in the system were made and the merits of
thermal stripping, acidification, and oxidation compared as
methods for regenerating the solution. Johnstone
concluded that stripping was the most expensive of the
three.
Also in the mid-1930's the U. S. Bureau of Mines did
fundamental work on various aspects of ammonia scrubbing
as applied to cleaning smelter gas, including measurement
of vapor pressures, addition of gaseous ammonia to the
stack gas, and oxidation of ammonium sulfite solution (87).
American Smelting and Refining did pilot work on the
Guggenheim process (87), similar to the Cominco exorption
method. The evolved sulfur dioxide was reduced by
reaction with coke.
The autoclave process was applied to the cleaning of
power plant stack gas in the 1940's by Simon-Carves, Ltd.,
an English engineering firm (56). Various pilot and
prototype units were built and tested, for gas flows of
2,000, 56,000, and 60,000 cubic feet per minute (cfm).
The process was considered promising by the developers at
the time (28), and the possibility of profitable operation
was advanced. However, no further effort toward
commercial development has been reported.
In the United States, TVA did pilot plant work,
beginning in 1953, on adapting ammonia scrubbing to use
in power plants burning high-sulfur coal (41). It was
demonstrated that the scrubbing step is operable over a
fairly wide range of conditions with acceptable efficiency,
and that fairly short scrubbing towers' should be adequate.
Further work in the 1950's included use of the
acidification method on smelter gas by the National
23
-------
Smelting Company in England (93). There was further use
of ammonia scrubbing in Japan also; Nakagawa (67) reports
plant installations by Chyu Yu Chemical, Nippon Suiso,
Hito Chemical (Yahe plant), Tohoku Fertilizer (Akida
plant), and Syowa Electric (Kawasaki plant). Plants were
reported also for German Tiran (Traboncol, Kerala State,
India) and Degussa (Frankfurt, Germany). The type of
plant producing the sulfur dioxide was not given;
presumably most of them were sulfuric acid plants.
Nakagawa reported in 1968 that none of the Japanese
plants are still in operation.
A Cominco-type unit was installed in the 1950's to clean
sulfuric acid at Fertilizers and Chemicals, Travancore
(Alwaye, Kerala, India; this may be the same as the plant in
India referred to by Nakagawa). The evolved sulfur dioxide
is dried and either liquefied for sale or returned to the acid
plant feed.
There has been a rapid expansion of work on applying
ammonia scrubbing to the power plant problem in the
1960-1970 decade. One of the major efforts has been the
work of Chertkov and coworkers at the NIIOGAZ
(Scientific Research Institute for Industrial and Sanitary
Purification of Gases) in Russia, beginning in the late
1950's and apparently still continuing (last paper in 1967).
Over 40 papers have been published by Chertkov on sulfur
oxide recovery, most of them involving ammonia scrubbing.
All phases of the subject have been covered: basic chemical
data, mass transfer in scrubbers, the autoclave process,
regeneration by stripping, solution oxidation, and solution
decomposition. Much of the work was on a pilot plant
scale.
Chertkov's investigations apparently have led to
installation of a commercial unit. It was reported in 1967
(36) that a unit was being operated at the Voskresensky
Chemical Combine in which the stripping method was used.
Apparently no information has been made available on the
size and operating details.
In an earlier paper (22), Chertkov stated that an
ammonia scrubbing unit had been "operated for many
years" on a boiler of the Mosenergo TETS-12 power plant
(Moscow region). No details are given other than that the
product is liquid sulfur dioxide, indicating that stripping is
involved. The production reported, 5,000-7,000 tons/year
(tons/yr), indicates a very small unit.
Work on ammonia scrubbing has also been continued in
Japan. Nakagawa (68) reported units at Nitto Chemical
Company (Hachinohe plant, presumably sulfuric acid) and
Showa Denko Company (Kawasaki plant). The latter is a
25-mw test unit operating on stack gas from an oil-burning
boiler supplying process steam for other Showa Denko
operations. The scrubber effluent is oxidized to produce
ammonium sulfate.
In France, Electricite de France built a 25-mw test unit
for ammonia scrubbing in 1967 (64). In cooperation with
Weirtam (an engineering firm) and Ugine Kuhlmann (a
chemical process engineering-design firm). The first unit did
not involve sulfur dioxide recovery; the scrubber solution
was treated with lime to produce calcium sulfate for
disposal and ammonia for recycle. In a second development
phase, a stripping process was worked out that is claimed to
have a very low steam requirement (39). The test unit has
been revamped for the new process and was started up early
in 1969; successful operation has been reported but no data
have been made available.
In Czechoslovakia, the Fuel Research Institute (Prague)
has done pilot plant studies [20,000 normal cubic meters
per hour (Nm3/hr) or about 5 mw] on ammonia scrubbing
of power plant gas (77). Most of the work has been on the
acidification method, with the gas cooled to a relatively low
degree to improve process operation. A full-scale unit
(110-mw) has been planned for the Tusimice I power
station, scheduled for startup in 1971, and a larger unit
(800-mw, Tusimice II) is being considered for 1973-1974.
Two units for scrubbing sulfuric acid tail gas are already in
operation, one producing ammonium sulfate and the other
ammonium sulfate plus ammonium nitrate.
In 1968, NAPCA and TVA entered into a contract for
further development of ammonia scrubbing, with particular
reference to scrubbing problems on which insufficient
information is available from the literature. A pilot plant is
under construction at the TVA Colbert Steam Plant, near
Sheffield, Alabama.
This account is by no means a complete survey of
ammonia scrubbing history. Numerous organizations have
worked on the process over the past 50 years and taken
patents on their developments; complete coverage of the
patent literature has not been attempted and there may also
be developments in sulfuric acid tail gas cleaning and in
ammonium sulfate production from rich gases that have not
been identified.
Application of the ammonia scrubbing process is
relatively well advanced as compared with other processes,
with large power plant test units in Czechoslovakia, Russia',
France, and Japan; commercial units on sulfuric acid and
smelter tail gas in Czechoslovakia, Canada, United States,
Japan, and India; and pilot plant work in several countries.'
The method continues to offer the promise of high solution
capacity, low absorbent cost, and salability of the sulfate
unavoidably produced. If the scrubber problems can be
solved and a more economical regeneration method
developed, the process may compare well with other
methods for sulfur oxide recovery.
24
-------
CHEMISTRY AND KINETICS OF
SULFUR OXIDE ABSORPTION
The chemical equilibria and kinetics involved in
absorption of sulfur dioxide by ammoniacal solutions have
been studied extensively. In addition to the major work of
Johnstone on equilibria, which was aimed primarily at the
power plant problem, the system NH3-S02-H20 has been
studied in a general way and also in connection with the
ammonium sulfite process for wood pulping.
Equilibria Involved
Scott and McCarthy (76) studied the system both
experimentally and theoretically with the objective of
determining the species present. Only H+, OH", HSOa',
SO32', NH4+, and solvated forms of SOj and NH3 were
found to exist in the solutions in significant amounts. In
the pH range 4.2-7.0, only HSO3-, SO32', and NH4+ were
present. An equation was developed for calculating species
concentrations as a function of pH.
[HS03-]
~
<== 1.59xl07
(14)
The concentration of NH,,"1", of course, is equal to [HS03"]
Calculations have been made by Egan (30) to determine
whether the thermodynamics favor reaction of ammonia
with sulfur dioxide rather than carbon dioxide, since the
stack gas contains far more carbon dioxide than sulfur
dioxide. The reactions considered were
2NH3(g) + H200iq) + S02(g) = (NH4 )2S03(c) (15)
2NH3(g) + H20 (liq) + C02(g) = (NH4)2C03(c) (16)
2NH3(g) + C02(g) = NH4COONH2(c) (17)
NH3(g) + H2 0(liq) + C02(g) = NH4HCO3(c) (1 8)
(NH4)2C03(c) + S02(g) (NH ) CO (c) + SO (g)
NH4COONH2(c)
2(NH4)2S03(c)
2S02(g) + 02(g)
= (NH4)2S03(c) + C02(g) (19)
+ SO2(g) + H2O(liq)
= (NH4)2S03(c) + C02(g) (20)
02(g) = 2(NH4)2S04(c) (21)
2S03(g) (22)
The free energies of reaction are shown in figure 8 and
the equilibrium constants are listed in table 1. Figure 8
shows that reactions 15 through 20 are favored by low
temperature, and that sulfur dioxide will displace carbon
dioxide in the solid products.
For equations 21 and 22, the thermodynamics favor
both oxidations at the lower temperatures (the free energies
are beyond the scale of figure 8). It was necessary to
estimate the entropy of solid ammonium sulfite (by an
established method), so that the thermodynamics for
reactions involving this salt are somewhat uncertain.
T,°K
7able 1. Reactions of NH3 with S02 and C02
Equilibrium constant, log KD, for indicated equation No.
300
350
400
450
500
550
600
10.37
5.10
1.15
-1.92
4.38
-6.40
-8.07
3.70
-0.53
-3.70
-6.17
-8.15
-9.76
-11.11
Equation
2
3
4
5
6
7
8
9
3.46 3.00 6.67 6.96
-0.50 -0.08 5.63 5.65
-3.48 -2.38 4.85 4.66
-5.79 4.18 4.25 3.90
-7.64 -5.62 3.76 3.29
-9.15 -6.79 3.37 2.79
-10.41 -7.77 3.04 2.37
No. Free energy equation
AF
AF
AF
AF
AF
AF
AF
AF
= -50,640 + T2U4T
= 40,660 + 118.607
= -38,079 + 11 1.10T
= -29,593 + 84.897
= -9,980+2.747
= -12,603 + 10.167
= -140,460 + 37.307
= 47,006 + 44.757
94.16
79.55
68.58
60.06
53.24
47.66
43.00
24.42
19.52
15.85
13.00
10.71
8.85
7.30
The question of whether carbon dioxide will displace
sulfur dioxide from solution has been considered by
Aerojet-General Corporation (1). The basic equation is
C02 + HSO3- = S02 + HC03-
(23)
The free energy change of this reaction was found to be
plus 8.2 kilocalories (kcal) at 25° C and the entropy change
plus 5.04 entropy units. The free energy change at 50° C
was calculated to be over 8.0 kcal and the equilibrium
constant, K, was 4 x 10"6- For:
C02/PSQz
(24)
and assuming ?C02 = 112 millimeters (mm) and PSO, =
2.28 mm in the gas, the bicarbonate to bisulfite ratio at the
bottom of the scrubber was calculated to be 2 x 10'4,
indicating that practically no bicarbonate would be present.
Vapor Pressure
The vapor pressure of sulfur dioxide over ammonium
sulfite-bisulfite solutions is a highly important
consideration in ammonia scrubbing. The basic data on
vapor pressure were determined by Johnstone (44), who
made determinations at several concentrations and over the
pH range of 4.71-5.96. The results could be expressed by
equations:
25
-------
-10
+10
+20
+30
+40
2NH3(g)+HiO
-------
- C)2
-C(C-S)
-
(25)
(26)
where C is the concentration of ammonia in moles/100
moles of-water and S is the concentration of sulfur dioxide.
The values used by Johnstone for the constants are:
log M= 5.865-
log N= 13.680-
2369
T
4987
(27)
(28)
M and N vary with concentration but the variation is not
enough to introduce any great error over the practical range
of concentration. The approximate values at 125°F, the
probable practical level of scrubbing temperature, are M =
0.0380 and N= 0.0233.
For the practical scrubbing system, in which sulfate is
present, the partial pressure equations become:
(29)
(30)
where A is the sulfate concentration in moles/100 moles of
water. Thus as far as the partial pressure of sulfur dioxide is
concerned, oxidation merely reduces the effective
concentration of ammonia and therefore increases the
sulfur dioxide pressure.
Chertkov (23) also determined vapor pressure over
solutions containing sulfate. The following equation was
derived from the data:
s°2 - C-S-2A
_XTC(C-S-2A)
S0
-—
(31)
where P§O2 (calcd) is the value obtained by the Johnstone
equations without any allowance for sulfate. The effect of
sulfate content in Chertkov's tests is shown in figure 9.
The partial pressure of water can be represented
adequately by the Raoult relationship:
100
H20
(32)
where Pw=vapor pressure of pure water at the temperature
involved.
The effect of temperature on vapor pressure was
represented in Johnstone's work by the Young equation:
The constants a and b are the same as in equations 27 and
28 where the values over the experimental range have been
averaged. The molar heat of absorption canbe approximated
by multiplying constant b by 4.58. For sulfur dioxide, the
values ranged from minus 9,500-11,500 cal/mole, and for
ammonia minus 19,400 to minus 22,900/mole.
The equations of Johnstone have been programmed in
the present study and the vapor pressures calculated over a
range of temperature and S/C (table 2). Curves for the
pressures at key temperatures are given in figure 10.
The vapor pressure of ammonia and sulfur dioxide over
the solid salts is also of interest, as some have proposed
ammonia injection into the gas ahead of the scrubber. Both
the Showa Denko and Electricite de France processes
involve addition of ammonia in this way, and Electricite de
France claims that mass transfer into the scrubber solution
is improved by first forming solid sulfite-bisulfite (or
pyrosulfite) in the gas stream and then using the scrubber as
a "dust collector" to recover it.
St. Clair (U. S. Bureau of Mines) (87) determined such
vapor pressures as part of a study on recovery of sulfur
dioxide from smelter gases. In the same study, Marks and
Ambrose attempted recovery in a solid form by adding
ammonia and water vapor to the gas and collecting the
resulting solid.
St. Clair's data for the system
(NH4)2S2OS-(NH4)2SO3-SO2 are shown in figure 11. (At
the temperatures he used, pyrosulfite is obtained rather
than bisulfite.) Earhart (NAPCA) (29) has reviewed and
analyzed the data of St. Clair and of Ambrose and Marks.
He concluded that addition of ammonia to power plant
stack gas cooled to 125° F by direct contact with water
should give solid (NH4)2S03-H2O as the sole product and
that only about 63% of the sulfur dioxide should react.
PH
Johnstone developed an equation for the pH of
ammonium sulfite-bisulfite solutions:
pH = - 4.62 (S/C)+ 9.2
(34)
logP = a+b/T
(33)
The equation cannot be used all the way to the bisulfite
ratio (S/C = 1.0). Measured pH for bisulfite is
approximately 4.1, which could not, of course, be reached
in ah actual scrubbing system. The pH at a bisulfite to
sulfite mole ratio of 2:1 (S/C = 0.83), which should be
attainable, is about 5.7—perhaps high enough for adequate
corrosion resistance. Johnstone found this to be true in the
pilot plant his staff operated for a long period; there was
little corrosion of the mild steel used. (Others, however,
have encountered corrosion.)
For a given vapor pressure of sulfur dioxide, increase in
solution concentration increased the pH (49).
27
-------
Table 2. Vapor Pressures in the System NH3-S02-H2O, mm Hg
C' S»
1.8
1.7
1.6
1 .5
1.4
1.3
1.2
1.1
4 3.8
3.6
3.4
3.?
3.0
2.8
2.6
2,4
2.2
6 5.7
5.4
5.1
4.8
4.5
4.2
3.9
3.6
3,3
8 7.6
7.?
6.8
6.0
5.2
4 . 4
9.0
8.5
7.5
7.0
6.5
6.0
5.5
12 11.4
10.8
10.2
9.6
9.0
8.4
7,8
7.2
12.6
11.9
11.2
9.8
9.1
B.4
7.7
16 15.2
13.6
12.8
12.0
11.2
10.4
9.6
8.8
18 17.1
16.?
15.3
14.4
13.5
12.6
11.7
10. 8
9.9
20 19.0
18,0
17.0
16.0
15.0
14.0
13.0
12,0
11.0
22 90.9
19.8
18.7
17.6
16.5
15.4
14.3
13.2
1?.)
NH, so,
1.75 5.91
1.75 5,60
1.76 5,29
1.74 4.97
1.77 «.66
1.71 4.34
1.71 4.02
1.79 3.70
3.2? 11.5
3.24 n.O
3.24 10.4
3.25 9.18
3.30 9.32
3.3' 1.75
3.35 8.18
3.37 7,60
3.39 7,01
4.50 16.1
4.54 15.4
4.51 14.6
4.6? 13,9
4.66 13.2
4 .7n 1?.4
4.75 11.6
4.79 10, *
4.811ft. 00
5.69 50.1
5.6! 19.2
5.87 16.6
6.00 14.7
6.14 12.7
6.61 92.6
6.77 51,6
6.94 19.6
7.04 IB. 5
7.33 15.2
7.47 96.7
7.59 95.6
7.8o 53.5
7.91 52.3
8.03 51.2
8.14 19.9
8.29 18.7
8.51 57.2
8.65 56.0
8.94 53.5
9.09 53.2
8.94 11.9
9.25 99.6
9.49 58.3
9.59 57,0
9.74 55,7
9.94 54.3
10,1 59.9
10.3 51.4
9.57 34.2
9.7< 13.0
9.93 31.7
10.1 10.4
10.3 99.1
10.5 97.7
10.7 96.2
10.9 54.7
11.2 93.1
10.1 36.2
10.3 35.0
10.5 33.7
10,9 1J.4
11.0 .11.0
11.5 59.5
11.4 58.0
11.7 56.4
12,0 54.8
10.7 18.1
10,9 36.8
11.1 35.5
11.3 34.1
11,6 32,7
11.1 31.2
12,1 59.6
12.4 58.0
12,7 56.3
pH
5
5
5
5
6
6
6
6
4
5
5
5
5
6
6
6
6
4
5
5
5
5
6
6
6
6
4
5
5
6
6
5
5
5
6
6
4
5
5
5
6
6
6
5
5
6
6
4
5
5
5
6
6
t
t
4
5
5
5
5
6
6
6
6
4
5
5
5
5
6
6
6
6
4
5
5
5
5
6
6
6
A
.0
3
5
.7
.0
.2
.4
.7
.8
.0
.3
.5
.7
. 0
.2
.4
.7
.8
.0
.3
.5
. 7
. 0
.2
.4
.7
.8
.0
.7
.2
.7
.0
.3
.7
.0
.2
.7
.8
.0
.5
,7
.0
.2
,4
.3
.5
,0
.2
.8
.3
.5
.7
.0
.2
.4
.7
,8
,0
.3
.5
.7
.0
.2
, 4
.7
.8
.0
.3
.5
. 7
. 0
.2
.4
.7
.8
,0
.3
,5
.7
.0
,2
,4
.7
'SO,
0.14
0.07
0,04
0.02
0.01
0.0]
0.00
0.00
0.70
0.21
0.14
O.Qfl
0.04
0.09
8.01
0,00
0.00
1. 06
0.45
0.21
0.12
0.07
0,03
0,0?
0.01
0.00
1.41
0.56
0.09
0.09
0.00
0.70
0.36
0.20
0.11
0.06
G.C3
0. 00
0.83
0.23
0.13
0.07
0. 03
0.01
0.50
0.27
0.08
0.04
2.82
0.57
0.31
0.17
0,09
0.04
0, 09
0. DO
1.25
0.64
0.35
0.20
0.10
0.05
0.0?
0.00
3.5?
1.30
0.71
0.39
0.29
0.15
0.06
0.02
0,00
3.. 8 7
1.53
0.78
0.43
0,24
0,13
0.-06
0. 0?
0,01
PHH,
0.00
0.00
0,00
0.00
0.00
0.00
0.01
0.01
0.00
0,00
0.00
0.00
0.00
0.00
0,81
0,01
0,03
0.00
0.00
0.00
0,00
0,00
0.01
0.01
0.02
0.04
0.00
0. 00
0.01
0, 01
0.03
0.06
0.00
0.00
0,01
0.01
0.01
8.02
fl.f!7
0,00
0.00
0.01
0.01
0.01
0.02
0.04
0. 00
0,01
0.02
0,03
0,00
0.01
0.01
0.01
0.02
0.03
0.05
0.11
0.00
n. 01
0.01
0.01
0.02
0.03
0.06
0.13
0.00
0.00
0.01
0.01
0.02
0.02
0.04
0. 06
0.14
0.00
0.00
0.01
0.01
0.112
0.03
0.04
0.07
0.16
PH,0 'SO,
35 0.26
35 0.13
35 0.07
35 0.04
35 0.02
35 0.01
35 0.00
35 0.00
33 1.33
33 0.53
34 0.27
34 0.15
34 0.08
34 0.04
34 0.02
34 0.01
34 0.00
32 2.00
32 0.79
32 0-. 40
32 0.25
33 0,12
33 0.07
33 0.03
33 0.01
33 0.00
31 2.67
31 1,05
32 0.16
32 0.04
32 0.02
32 0.00
30 1.32
30 0.67
31 0.37
31 0.21
31 0.11
31 0.05
31 0.00
29 4.00
29 1.5S
30 0.44
30 0.25
30 0.13
30 0.06
30 0.02
29 0.94
29 0.59
29 0.15
29 0.07
27 5.3«
28 1.08
28 0.59
28 0.33
28 0.18
28 0.08
29 0.03
29 0.01
27 J.J7
27 1.21
27 0.67
27 0.37
28 0.20
28 0.10
28 0.04
28 0.01
26 6.67
26 2.64
26 1.34
26 0.74
27 0.41
?7 0.22
27 0.11
27 0.04
27 0.01
25 7.34
25 2.90
26 1.48
26 0.8?
26 0.45
26 0.24
26 0,12
27 0.05
27 0.01
fHH,
0.00
0.00
0,00
8.01
0. 01
0. 01
0. 02
0. 05
0,00
0.00
0.01
0.01
0.01
0. 02
0.03
0.05
O.il
0.00
0.00
0,01
0.01
0.02
0.03
0.04
0.0.7
0.16
0.00
0.01
0.02
0. 06
0.10
0.22
0. 01
0.01
0.02
0.03
0.05
0.87
0,27
0.00
0.01
0.02
0.04
0.05
0.09
0.15
0.02
0.03
0.06
0.10
0.01
0.02
0,63
0.05
0,07
0,11
0.19
0.44
0,01
0,01
0.02
0.04
0.05
0,08
0.13
0.22
0.49
0.01
0.02
0.03
0.04
0, 06
0.09
0.14
0.24
0.55
0.01
0.02
0.03
0.84
0.07
o.io
0,16
0.27
0.60
PM,0
61
61
62
62
62
62
62
62
59
59
59
59
60
60
60
60
60
57
57
57
51
58
58
51
58
58
55
55
56
56
57
54
54
54
54
54
55
55
52
52
52
53
53
53
53
51
51
51
52
49
49
49
50
50
50
51
*;
47
47
48
48
46
49
49
49
50
46
46
47
47
47
48
48
4fl
49
45
45
45
46
46
46
47
47
4H
'SO,
0.48
0.24
0.13
0,07
0. 04
0.0?
0,01
0.00
2.42
0.96
0.49
0.27
0.15
0. 08
0.84
0. 01
0.00
3.63
1.43
0.73
0.40
0.22
0.12
0. 06
0.02
0.00
4.84
1.91
0.30
0.08
0.01
2.39
1.22
0.67
0.37
0.20
0.10
0.01
7.25
2.87
0.81
0.45
0.24
0.12
0.04
1.71
0.94
0.28
0.13
9.67
1.95
1.07
0.60
0.32
0,15
0.06
o.oi
4.30
2.19
1.21
0.67
0.36
0.17
0.07
0.01
12.1
4.78
2.44
1.34
0. 5
0. 0
0. 9
0 . 7
0. 2
13.3
5.25
2.68
1.48
0.82
0.44
0.21
0.08
0.02
'NH, 'H
0.01 I'
0.01 1
0.01 1
0.02 1
0.03 1
0.05 1
0.08 1
0.19 1
0,00 1
0.01 1
0.02 1
0.03 1
0.041
0.06 1
.10 1
,17 1
.38 1
.01
.02
.03
,04
,06
o.io
0,15
0,25
0.57
0.01
0,02
0, 06
0.90
0.76
0.03
0.05
0.07
0.11
0.16
8.25
0,96
0.01
0.03
0.08
0.13
0.19
0,30
0,51
o 'so, PNH, PH,O 'so, 'NH, PH,O pso, PNH, PH,O pso, PNM, PH,O
5 0.83 0.02 172 1.40 0.05 274 2.28 0.14 423 3.60 0.37 636
5 0.42 0.03 172 0.71 0,09 274 1,16 0.24 424 1,64 0.64 639
5 0.23 0.05 172 0.39 0.14 274 0.64 0,38 424 1.01 1,00 639
5 0.13 0.07 172 0.22 0.20 274 0.36 0.57 425 0.56 1.50 640
5 0.07 0.10 173 0.1? 0.31 275 0.19 0,86 425 0,10 2.24 640
5 0.03 0.56 173 0.06 0.48 275 0.09 1.33 425 0,14 3.49 641
5 0.01 0.27 173 0.02 0,82 275 0.04 2.28 426 0.06 5.99 642
5 0.00 0,62 173 0.00 1.84 276 0.01 5.13 426 0.01 13.5 642
1 4.21 0,02 165 7.09 0,05 264 11,5 0,13 408 18,2 0,33 14
1 1.66 0.03 166 2.80 0.10 264 4.56 0,29 406 7.21 0.75 15
1 0.65 0.06 166 1,43 0.18 264 2.33 0.49 409 3.68 1,28 17
1 0.47 0.69 166 0.79 6.27 265 1.26 0.76 410 2,03 2.00 18
1 0.26 0.14 167 0,44 0.41 265 0.71 1.14 411 1.13 2,99 19
2 0.14 0,21 167 0.23 0.61 266 0.38 1.71 411 0.60 4.49 20
2 0.07 0.32 1«7 0.11 0.95 266 0.18 2,66 412 0.29 6.98 21
2 0.03 6.55 168 0.04 i . 63 267 0.07 4.56 413 0,11 12.0 22
2 0.01 1,23 168 0.01 3.68 267 0.02 10.3 414 0.03 26.9 624
7 6.32 0.62 160 10.6 0.07 254 17.3 0,19 393 27,4 0.50 593
7 2.50 0.65 160 4.20 0.15 255 6.84 0,43 394 10,8 1.12 594
6 1.27 0.09 161 2,14 0.26 256 3.49 0.73 396 5.52 1.92 596
8 0.70 0.14 161 1.18 0.41 256 1.92 1,14 397 3,04 2,99 596
8 0.39 6.21 161 0.66 0.61 257 1.07 1.71 398 1.69 4.49 599
8 0.21 0.31 162 0.35 0,92 258 0.57 2.57 399 0,90 6.73 601
9 0.10 0.46 162 0.17 1.43 258 0.27 3.99 400 0.43 10.5 603
9 0.04 0.62 163 0.07 2,45 259 O.li 6,64 401 0.17 18.0 604
9 0.01 i. 85-163 0.01 5.52 260 0.02 15.4 402 0.04 40.4 606
4 8.43 0,63 154 14,2 0,09 246 23,1 0,25 380 36.5 0.67 573
4 3.33 0.07 155 5,60 0.20 247 9,12 0.57 381 14.4 1.50 575
5 0.52 0.27 156 0.87 0,82 249 1.42 2,28 385 2.25 5.99 581
6 0.13 0.64 158 0.22 1.91 251 0.37 5.32 388 0.58 14.0 565
7 0.01 2.46 159 0.02 7.35 253 0.03 20,5 391 0.05 53.9 589
1 4.16 0.69 150 7,00 0.26 239 11,4 0,71 369 18.0 1.87 556
2 2.12 O.i« 151 3.57 0,44 240 5,82 1.22 371 9,20 3.21 559
2 1.17 0.23 151 1.97 0,68 241 3.21 1.90 372 5,07 4.99 561
2 0.65 0,34 152 1.09 1.02 242 1,78 2.85 374 2,62 7,48 564
3 0.35 0.51 152 0.56 i.53 243 0.95 4,28 376 1,50 11,2 566
3 0.17 O.SO 153 J.26 J.38 244 0.46 6.65 377 0,72 17,5 566
4 0.01 3.66 154 0.02 9.19 246 0.04 25,7 360 0.06 67,3 573
8 4.99 0,10 145 6,40 0.31 231 13.7 0,66 358 21,6 2,24 539
9-1.40 0.27 147 2.36 0.82 234 3.85 2.28 361 6,06 5,99 545
0 0.78 0.41 147 1.31 1.23 235 2.14 3.42 363 3.38 8.96 547
0 0.42 0.62 146 0.70 1.64 236 1.14 5.13 365 1.80 13.5 550
1 0.20 0.96 149 0,34 2.66 237 0.55 7.96 367 0.87 20.9 553
>1 0.08 i.64 150 0.13 4.90 238 0.21 13.7 369 0,34 35,9 556
0,06 66 2.97 0.21 142 5.00 6,61 296 8,14 1,71 349 12,9 4,49 526
0,10 87 1.64 0.32 142 2,76 0.95 227 4.49 2,66 351 7.10 6.98 529
0.22 88 0.49 0,72 144 0.82 2.15 229 1.33 5,99 355 2,10 15.7 535
0.35 88 0.23 1,12 145 0.39 3.34 231 0.64 9,31 357 1,01 2:4,4 538
0,02 63 16.9 0.06 136 26.3 0.18 217 46.2 0,51 335 73.0 1.33 505
0.07 64 3.40 0.23 138 5.72 0.70 219 9.31 1.96 339 14.7 5.13 511
0,11 14 1.87 0.36 139 3.1! 1.09 221 5.13 3.04 341 8rll 7.98 51'4
0.17 85 1.04 0.55 139 1.7! 1.63 222 2.8! 4.!6 343 4,51 12.0 517
0,25 P5 0.55 0,62 140 0,93 2.45 223 1.52 6.64 345 2,40 18,0 521
0.40 86 0.27 1.28 141 0.45 3,81 225 0.73 10.6 348 1,16 27.9 524
0,68 86 0.10 2.19 142 0,17 6,54 276 0.28 18.2 3!0 0,4! 47.9 527
1,53 87 0.02 4.92 143 0.04 14.7 2?8 0.06 41.1 352 0,10107.7 531
0,05 SI 7.49 0.15 1S3 12.6 0.46 212 20.5 1,28 327 32.4 3,37 4-93
0,08 61 3.82 0.26 134 6,43 0,79 213 10.5 2,20 330 16.6 5.77 497
0.13 82 2.11 0,41 13! 3.54 1.23 215 5.77 3.42 332 9,12 8,98 500
0.19 83 1.17 0.62 136 1.97 1.84 216 3.21 5.13 334 5,07 13,5 504
0,29 83 0.62 0.92 137 1.05 2.76 218 1.71 7,70 336 2,70 20.2 507
0.45 84 0.30 1.44 138 0.51 4.29 219 D.8« 12.0 339 1.30 31,4 511
0.76 84 0.12 2.46 139 0.20 7.35 221 0.32 20.5 341 0,51 53,9 514
1.72 65 0.03 5,54 139 0.04 16,5 252 0.07 46.2 344 0,11121.2 518
0.02 78 21,1 0.08 128 35,4 0,23 204 57,7 0.63 316 »1 , 2 1,66 476
0,05 79 6.32 0,17 129 14,0 0,51 206 22,6 1,43 318 36.0 3.74 48B
0.09 79 4.25 0.29 ISO 7,1! 0.66 207 11.6 2.44 321 18,4 6,41 483
0,14 60 2.34 0,46 131 3.94 j.36 209 6.41 3.60 323 10.1 9,98 487
O.?l 80 1.30 0.68 132 2,19 2.04 210 3,56 5.70 326 5,63 15,0 491
0,32 81 0,69 1,03 133 1,17 3,06 212 1.90 6.55 328 3.00 22,4 494
0.50 82 0.33 1.60 134 0.56 4,77 214 0.9? 13..3 330 1.45 34,5 498
0,85 82 0.13 2,74 135 0,22 6.17 215 OV36 22.8 333 0.56 59, 9 '50?
1.91 83 0.03 6.16 136 0,05 18.4 217 0.08 51,3 335 0.13134,7-5115
0,03 76 23,2 0,08 125 39,0 0.25 199 63,5 0,70 3.08100,4 1,83 463
0.06 77 9.16 0,19 126 15.4 0.56 200 25.1 1.57 310 39,7 4.11 467
0.10 77 4.67 0,32 127 7,86 0,9« 202 12,8 2.69 312 2o:,2 7,05. 7\
0.16 78 2.58 0,50 128 4,33 1,50 203 7.0T5 4,16 315 11,2 11,0 74
0,23 76 1.43 0.75 129 2,41 2,25 205 3,92 6.27 317 6.20 16,5 78
0.35 79 0.76 1.13 ISO 1.28 3,37 207 2.09 9,41 32D 3.30 24,7 82
0,55 10 0.37 1,76 1S1 0,62 5,24 208 l.ftl 14,6 322 1,59 36,4 66
0,93 60 0.14 3.01 132 0.24 6,99 210 0.39 2!.l 325 0.62 65,8 90
2.10 11 0.03 6.77 133 0.0! 20.2 212 0.09 56.5 328 0.14148.1 494^
28
aMoles NH3/100 moles H2O.
bMoles SO2/100 moles H2O.
-------
4 -
O!
I
£
a 2
o
I
50° C
0 = 10.2-11.4
S/C=0.91-0.92
I I I I I I I I I I L
1 2
(NH4)j SO4 concentration, molar
Figure 9. Effect of Sulfate Content on SO2 Vapor Pressure (23)
Chertkov and coworkers (10) measured pH over a wider
range (S/C = 0.5-0.95) than that studied by Johnstone (S/C
= 0.7-0.9). They found the same linear relationship in the
0.7-0.9 range and developed a slightly different equation:
S/C = 2.22 - 0.25 pH
(35)
Outside this range, however, the relationship was not linear.
The pH reported for pure ammonium sulfite solution was
8.0; values for bisulfite were 3.0 for 5% solution and 2.7 for
45% solution. A curve for pH versus (vs) S/C is shown in
figure 12.
Solubility
There have been numerous studies of the system
NH3-SO2-H20 but few of the NH3-S02-S03-H20 system
actually involved in stack gas scrubbing. The only major
investigations of the quaternary system identified in the
present study were those of Gottfried et al. (Research
Institute of Inorganic Chemistry, Czechoslovakia) (37) and
Vasilenko (Physico-Chemical Laboratory of the Scientific
Institute for Fertilizers and Insectofungicides, USSR) (89).
West (94) also has presented information on the quaternary
system but his data are calculated from published data on
ternary systems. Data from these studies are shown in
figures 13, 14, 15, and 16.
Viscosity and Specific Gravity
Chertkov (21) has determined viscosity and specific
gravity in the system (NH4 )2 SO3 -NH4HSOS-
(NH4)2SO4-H20. An equation for partial relative viscosity
(>?) was developed:
(36)
29
-------
Constant NH3 concentration
C = 22 moles NH3/100 moles H2O
30
S, moles SO2 /100 moles H2O
Figure 10. Equilibrium Vapor Pressure Over Ammonium
Sulfite-Bisulfite Solutions (94)
-------
o
1.0
0.5
0.2
0.1
I I I
90 95
100
J I
110 120
Temperature, °C
130
140
Figure 11. Partial Pressure of SO2 in the System
03-S02 (87)
where A and B are constants, c is the concentration
[grams-equivalent per liter (g-eq/1)] of the particular salt,
and C is the total salt concentration (g-eq/1). Values of the
constants for the various salts are given in table 3. The
partial viscosity is calculated for each salt and the results
added together to give the overall viscosity relative to
water.
An expression for calculating specific gravity was also
developed:
7= 1.0 + ajKj + a2K2 + a3K3
(37)
where aj, a2, and a3 are component concentrations in
grams per milliliter (g/ml) and Kj, K2, and K3 are
constants. Mean values were used for the constants:
(NH4)2SO3 0.482
NH4HSO3 0.400
(NH4)2SO4 0.474
Kinetics and Mass Transfer
Studies by Chertkov (11) indicate that the chemical
reactions involved in absorption of sulfur dioxide by
ammoniacal solutions are quite rapid and do not affect the
overall absorption rate. The amount of sulfur dioxide
absorbed increased linearly with sulfur dioxide
concentration in the range 0.08-2% of sulfur dioxide. Thus
chemical reactions are not limiting and the mass transfer
coefficient is uniform over a fairly wide concentration
range.
Chertkov postulates the following reactions for aqueous
or alkali scrubbing.
SO
S02 (soln)
(38)
S02 (soln) + H2 O£ HSCy + H+ (39)
H+ + OH" (from basic absorbing soln)^ H20 (40)
(41)
The hydration of sulfur dioxide is regarded as the slowest
of these but it is sufficiently rapid to be nonlimiting up to a
concentration of 3-4% sulfur dioxide in the gas.
Since sulfur dioxide is quite soluble in ammonia
solution, it would be expected that the liquid film
resistance to sulfur dioxide transfer would be low. This is
true at medium and higher pH levels in the scrubber, but at
low pH— such as would be encountered in the first stage of
a multistage scrubber— Chertkov found that liquid film
31
-------
Table 3. Values of Constants A and B for
Viscosity Calculations (21)
resistance becomes important. Transfer was eight times as
fast at an S02 :NH3 mole ratio of 0.78-0.82 as at 0.92-0.96
(table 4); the liquid phase resistance was negligible at
0.78-0.82 but was equal to the gas phase resistance at
0.92-0.96.
The transfer rate decreases with increase in temperature.
Chertkov (17) found relative rates of 10.2 and 2.32 at 23°
Figure 12. pH of NH4HSO3-(NH4)2SO3 Solutions (10)
Concentration range, moles/liter
Effective NH3, 2.5-9.0
Total NH3, 2.7-10.0
Sulfate, 0.1-2.6
0.5
32
0.6
0.7
0.8
s/c
0.9
1.0
-------
45
40
35
30
25
0™ 20
15
10
Ca = Active NH3, moles/100 moles H2O
S = S02, moles/100 moles H2 O
All numbers are moles (NH4)2 S04/100 moles H20
I: Saturated with (NH4)2SCX,
II: Saturated with (NH^SjOs
III: Satu rated with (N H4 )2 S03 • H2 O
3.5
— _4.5
I
"""——£.
0.5
0.6
0.7
s/ca
0.8
0.9
1.0
Figure 13. Solubility Diagram for the System NH3-SO2-SO3-H2O at 86° F (94)
33
-------
(NH4)2S03
146.9
I: Saturated with (NK, )2 S04
11: Saturated with (N H4 )2 SO3
III: Saturated with NH4HS03
Numbers are grams H20 required
to dissolve 100 grams salt
of indicated weight ratio
99.8
24.6
130
(NH4)2S04
24.1
NH4HSO3
Figure 14. The System (NH4)2SO4-(NH4)2SO3-NH4HSO3-H2O at 30° C (90)
Table 4. Effect of S02 :NH3 Mole Ratio on Mass Transfer
Gas velocity: 1.5-2 m/sec (12)
the input soln
0.78-0.82
0.28-0.84
0.84-0.86
0.88-0.90
0.90-0.92
0.92-0.96
NH3effa
moles/100 moles H20
10
10
8.8
7.6
7.3
5.7
Average soln
temperature,°C
27
27
30
26
26
25
Average coefficient
of absorption Ka,
moles S02/m2-hr-%S02
1620
1820
1320
970
635
200
aEffective ammonia is defined as that present in the form of sulfite and bisulfite.
34
-------
Figure 15. Solubility of (IMH4)2SO4 in the (NH4)2 SO3-NH4HSO3-H20 System at 30° C (37)
(NH4)2S03
and 52.5° C. The coefficient was reported to be
proportional to the 0.8 power of the linear gas velocity and
to the 0.16 power of the solution concentration. Chertkov
(18) developed the following empirical equation for the
effects of concentration, density, and viscosity.
t.16 „ 0.1 7
r> 0.4
(42)
where C is solution concentration, 7 is density, and 77 is
viscosity. A small-scale scrubber of the falling-film type was
used in the studies.
Chertkov (19) points out that high gas velocity is
desirable because the benefit from higher mass transfer
more than offsets the cost of the higher pressure drop; he
recommends 2.5-2.7 meters per second (m/sec) for a sieve
tray scrubber.
Several investigators have found that the contact time
required is quite short; Johnstone (47), for example,
reported 1-2 sec as adequate for removing 96.7% of the
sulfur dioxide from flue gases containing 0.3% sulfur
dioxide at 300° F in a grid-packed tower.
Volgin (91) was able to get good absorption even with
the short residence time in venturi scrubbers but found it
desirable to use several in series to get good sulfur dioxide
removal (over 90%) with low pressure drop. He achieved a
transfer of 73.1 kilogram per cubic meter-hour-milimeter
35
-------
(kg/m3 -hr-mm) Hg at low velocity and pressure drop (25
m/sec; totalAP = 14 mm H20), and 237 kg at high velocity
(60 m/sec; totalAP = 705 mm H20).
The actual transfer coefficients that have been reported
vary widely and are difficult to compare because of the
differing conditions used by various investigators—type of
scrubber, gas velocity, solution composition and
concentration, and temperature. For the sieve-tray absorber
discussed later in this report, Chertkov (12) found a sulfur
dioxide transfer of 14.4 kg/m3-hr-mm Hg at 2.63 m/sec gas
velocity, 33° C, and S02:NH3 mole ratio of 0.82-0.9
(effective NH3 only). The transfer rate varied widely with
gas velocity and temperature.
The transfer rate of oxygen into solution is also
important in ammonia scrubbing, as discussed in a previous
section. No actual data on the transfer rate were found;
however, oxygen is not as soluble as sulfur dioxide and
therefore the liquid film resistance should be relatively
more significant. Johnstone (44) studied absorption of
oxygen and sulfur dioxide in water and found that the
oxygen absorption was liquid-film controlled; a bubble-type
scrubber absorbed 30 times as rapidly as a spray type. On
the other hand, Chertkov (12) compared packed and
bubble-type scrubbers and reported that both sulfur
dioxide and oxygen absorption were higher for the bubble
type; however, the increase was much greater for sulfur
dioxide than for oxygen, so that the net effect was less
oxidation. It is not clear why the sulfur dioxide absorption,
which is controlled by the gas film resistance, should have
been improved so much by use of the bubble-type scrubber
(however, it was said to be a "foaming" type of
perforated-plate operation).
Absorption of sulfur dioxide into water, which would be
a consideration in prescrubbing the gas to remove dust, was
studied Johnstone (44). The liquid film resistance was
found to be 96% of the total [at 4 feet per second (ft/sec)
gas velocity]. As would be expected, the absorption rate in
a bubble-type scrubber was faster than in a spray type.
50
40
30
d
C/5
S 20
10
0Q000
c*5 v in co i
10
20
30
40
50
60
H,0
(NH4)2S03 +NH4HS03,%
Figure 16. System
(37)
36
-------
FORMATION OF SULFATE
All three of the principal methods for producing
ammonium sulfate—oxidation in the scrubber, oxidation
of the scrubber effluent, and acidification with sulfuric
acid-will be evaluated in the present study.
Acidification has some advantage because part of the
product is in the form of sulfuric acid, which, as
discussed later, is desirable in the fertilizer processes.
Oxidation, however, may require less equipment.
Oxidation in the Scrubber
Several investigators have studied the factors affecting
oxidation of sulfite or bisulfite during the scrubbing
operation, but the emphasis has been on preventing
oxidation rather than promoting it. The large excess of
oxygen in the stack gas—about 30 times the
stoichiometric amount for oxidizing all of the sulfite to
sulfate—favors oxidation but it is not known to what
degree oxidation could be promoted in the scrubber
without interfering with absorption of sulfur dioxide. As
pointed out by Johnstone, the net effect of oxidation is
to tie up ammonia and thus reduce solution capacity.
Thus all the sulfite could not be oxidized to sulfate in
the scrubber and still retain absorptive capacity, unless
perhaps an additional prescrubbing step were added in
which conditions would be adjusted to give oxidation
rather than sulfur oxide absorption. This is in effect
adding an oxidizer vessel, and a separate oxidizer
(described later) may be preferable.
A possible way for carrying out all the oxidation in
the scrubber is to cool a side stream and crystallize
ammonium sulfate from it, in an amount sufficient to
remove the sulfur dioxide absorbed in the scrubber. The
amount of sulfate crystallized would also have to be
equal to that formed in the scrubber. Hence the rate of
oxidation would have to equal the rate of absorption,
which might be difficult to accomplish. Perhaps the
system would be self-regulating; for example, if
oxidation rate were initially not quite as high as
absorption, it seems likely that absorption would
decrease to an equilibrium level consistent with the
solution composition. Or perhaps an operating parameter
could be identified that, when varied, would increase
absorption and decrease oxidation, or vice versa. Gas
temperature or amount of oxidation promoter added
might be suitable parameters to vary.
In either case, it would be necessary to promote
oxidation to a rate higher than normal. And even if a
separate oxidizer were used, it should be desirable to
maximize oxidation in the scrubber, to the extent
possible without interfering with absorption, so as to
reduce the load on the oxidizer. The obvious way to
accomplish this is to do the opposite of what
researchers have found to be effective ways of inhibiting
oxidation.
Chertkov has made extensive studies of oxidation in
the scrubber (8, 13, 14, 15, 16, 20). In the last paper
of the series, a generalized equation for oxidation rate
based on data from several different industrial type
scrubbers is presented:
Go = 0.8-Q0 -7-a-(S/C)6
(43)
Where G0 =g02 absorbed/(hr) (m2 of liquid-gas contact
surface), equivalent to formation rate of
ammonium sulfate
Q = liquid flow rate, m3/(m2) (hr)
a = JQ where t is the average solution temperature
in°C
S/C = molar ratio of sulfur to ammonia in solution
y = solution density, kg/m3
ju = solution viscosity, kg-sec/m2
Study of Chertkov's work leading to development of
this equation leads to the following conclusions.
1. Rate of sulfite oxidation depends on rate of
oxygen absorption. Therefore, the proportion of the
sulfur dioxide input oxidized depends on the relative
absorption rates of sulfur dioxide and oxygen.
Chertkov's tests showed that maximizing absorption of
sulfur dioxide effectively reduced the proportion
oxidized because the hydrodynamic factors that increase
sulfur dioxide absorption do not have as great an effect
on oxidation rate. For example, sulfur dioxide
absorption was increased ten to fifteenfold (per unit of
scrubber volume) in a bubble-type scrubber (operated
under foam conditions) as compared with a packed
scrubber. In contrast, the rate of oxygen absorption
increased only two to threefold and as a result the
degree of oxidation was only about one-fifth that in a
packed absorber.
2. Although not emphasized by Chertkov, it is
obvious that the SOj :O2 ratio in the gas has a major
effect on degree of oxidation. At low SOa iOj ratios,
more oxygen goes into solution/unit of sulfur dioxide
and as a result a larger proportion of the sulfur oxide is
oxidized.
37
-------
3. Gas velocity is not a factor in oxygen absorption
but sulfur dioxide absorption is proportional to the 0.8
power of the linear velocity in an industrial sieve tray
scrubber (9).
4. Increase in solution concentration decreases both
oxygen and sulfur dioxide absorptioa There does not
appear to be enough data to determine which is
increased more. In any event, economics will probably
dictate running at as high a solution concentration as
possible.
In several of the investigations, including pilot pknt
work at TVA (80), dilute solutions have been found to
oxidize to a higher degree than concentrated solutions.
This supports Chertkov's finding but it should be noted
that in many cases this may have been due to the fact
that the solution was dilute because it was scrubbing a
gas of relatively low S02:02 ratio and therefore a higher
proportion of the sulfur dioxide was oxidized (see 2
above).
5. Increase in absorption temperature promotes
oxidation but decreases sulfur dioxide absorption.
6. Increase in liquor flow gives faster absorption of
both gases. The effect apparently is greater for oxygen
absorption.
7. The ratio of sulfur dioxide to ammonia (S/C,
mole basis and not including ammonia as ammonium
sulfate) is a major factor, possibly the controlling one.
Oxidation is a direct function of (S/C)6 , whereas sulfur
dioxide absorption is affected inversely by increase in
S/C (increasing the ratio from 0.78-0.83 to 0.89-0.93
reduced sulfur dioxide absorption by half; for oxidation,
such a change should give, according to Chertkov's
equation, an increase of about twofold).
It should be noted that Chertkov's papers sometimes
are not very clear and in some cases later papers do not
seem to agree with earlier ones. With this reservation,
the above conclusions indicate that practical conditions
for increasing oxidation in the scrubber include (1) high
S/C in the solution, (2) use of a packed-type scrubber
or some other type that gives a relatively high degree of
oxygen absorption compared with sulfur dioxide, and
(3) low gas velocity.
The conclusion is that by slowing down sulfur
dioxide absorption oxygen will have more time to
dissolve, which has the obvious drawback that scrubber
cost would be increased. Therefore it might be more
economical to minimize scrubber cost by maximizing
sulfur dioxide absorption and then do the oxidation in
a system specifically designed for it.
An exception to this might be use of an oxidation
catalyst. Several catalysts have been proposed. Chertkov
(13) reviewed Abel's work on the catalytic effect of
thiosulfate [(NHSAJ and trithionate
(both are sulfite decomposition products) and proposed
a mechanism involving a chain-type reaction of SO3-,
S2O3=, and S306=. Possibly S2O3= could be generated in
the scrubber solution to serve as a catalyst.
In much earlier work, not connected with power
plant gas cleaning, considerable effort went into
oxidizing ammonium sulfite solutions as a shortcut in
making ammonium sulfate. Vorlander and Lainau (92)
reviewed earlier data and reported further work. The
main conclusions that can be gathered from this are:
1. Investigators have varied widely in their findings.
For example, Vorlander and Lainau state that increase
in pH promotes catalysis by metallic sulfates. A pH of
8 was reported as optimum; at pH 5 or less, there was
little catalytic effect.
2. A great number of organic substances inhibit
oxidation and also interfere with the action of oxidation
catalysts.
3. Metal salts exhibiting catalytic activity are Co"1"1",
Fe++, Ni++, Cu++, Ce++, Mri*, and Vs:
4. Of these, Co++, Fe"1"*, and Mi4"1" were much the
most effective; proportional oxidation rates, respectively,
were 100, 50, and 16.
5. The presence of other catalysts was found to
impair the activity of cobalt. For example, CoSO4,
CuSO4, and an equimolar mixture of CoS04 and
CuS04 gave relative degrees of oxygen absorption of
15.2, 1.9, and 2.7 (0.9 without catalyst).
Other work on catalysts is found mainly in patents.
Yun Kyongshin (58) claims complete oxidation in 18
minutes at atmospheric pressure and 60° C, using CoS,
Cr2O3> Fe3O4, and MnO2in a 0.4:0.4:0.4:0.4 weight
percent ratio (based on S02 content of solution). The
use of organic nitrogen compounds (e.g., pyridine and
pyridine bases) is claimed by Empresa Auxiliar de la
Industria, S. A. (90), Madrid, Spain. A fairly large
amount of the pyridine is used and the phases then
separated by decantation.
It is not clear whether catalysis would be effective in
promoting oxidation in a practical scrubbing operation,
if mass transfer is the limiting mechanism as various
investigators hold. Most of the tests with oxidation
promoters appear to have been carried out on a small
scale where mass transfer presumably was not a limiting
factor. However, to the extent that liquid film resistance
interferes with oxygen absorption, catalysis of oxidation
in the solution "should be helpful.
Certain general effects may have some bearing on
oxidation.
1. Actual stack gas from the burning of coal
apparently contains oxidation inhibitors of some sort.
38
-------
Kashtanov and Ruizhov (55) reported that the inhibitors
are phenolic compounds. Hence anything that would
neutralize the effect of these inhibitors might promote
oxidation.
2. Although the data are not conclusive, there is
some evidence that the presence of extensive solid
surface in the scrubber promotes oxidation. In carbon
adsorption complete oxidation takes place—in contrast
to 10-20% in scrubbing with a solids-free liquid. Fly ash
may also have such an effect, but since the ash is
accompanied by the phenolic inhibitor the effects are
difficult to separate. Chertkov (15) postulates that the
ash has a catalytic effect that offsets the effect of
oxidation inhibitors. The same effect has been noted in
working with sodium sulfite solutions; removal of dust
before the reaction system sharply reduced the degree
of oxidation.
The use of activated carbon placed in the scrubber
solution to serve as a catalyst is claimed in a Rumanian
patent (75).
3. Tarbutton et al (79) at TVA tried the approach
of promoting ammonium sulfate formation in an
ammonia scrubber by use of catalysts. In preliminary
tests with 0.3% Mn++ in the solution and 30 parts per
million (ppm) of ozone fed into the gas, scrubber
solution containing 30% ammonium sulfate removed
75-100% of the sulfur dioxide at a retention time of
18-36 sec. However, the tests were not extensive enough
to determine whether oxidation rate equaled sulfur
dioxide input rate.
In the Simon-Carves work on the autoclave process
(28), a high degree of oxidation was found desirable for
control purposes. Manganese sulfate added to increase
oxidation was effective, but no data are given on the
relative rates of oxidation and sulfur dioxide absorption.
The solution also contained 4-11% of thiosulfate, known
to be a good oxidation catalyst.
When the Simon-Carves plant was shut down for 3
months, the solution after starting up again was
adequately oxidized without use of the manganese
sulfate. It was postulated that rusty surfaces or particles
in the scrubber were acting as oxidation catalysts.
Oxidation in the scrubber was also studied in TVA
pilot plant work (80). The solution composition and
MnSO4 addition were about the same as in the
Simon-Carves work but the SO4= concentration
decreased steadily, from 83-6% of the total sulfur, over
a 4-day period-indicating an oxidation rate much lower
than the rate of sulfur dioxide absorption. The main
differences between these and the Simon-Carves tests
were absence of thiosulfate and a more concentrated gas
(0.3% vs 0.07-0.1%).
In summary, several factors have been identified that
can be varied to increase oxidation rate of sulfur
dioxide but most of them are either impractical or
would be expensive because scrubber size would be
increased. The main exception is catalysis, but not
enough information is available to determine whether
oxidation rate could be increased enough to match
sulfur dioxide absorption rate—which would be necessary
if ammonium sulfate were the only product and all the
oxidation were carried out in the scrubber.
If minimum oxidation were desirable because
production of sulfuric acid as well as ammonium sulfate
was planned—and maximum yield of acid was
desired—then the steps that promote oxidation should
be reversed. For most of the factors this would be quite
desirable because efficient absorption of sulfur dioxide
would be promoted. Oxidation catalysts should be
avoided as much as possible; the main one that might
occur incidentally—thiosulfate—is not likely to be
present in stack gas but could build up in a recycling
system because of solution decomposition. Fly ash may
or may not be a problem; its effect should be
determined.
Oxidation inhibitors also can be used; perhaps a
byproduct phenolic waste material can be found that
would give adequate inhibition at low cost. The fly ash
may be important in this because of Chertkov's finding
(see earlier discussion) that the inhibiting effect of
p-phenylenediamine is reduced three to fourfold by the
presence of fly ash in the scrubber solution. In the
absence of ash, addition of 0.01% of inhibitor reduced
oxidation from 17-21% to 2%. This was accomplished
even though the solution contained up to 0.05 mole/1
of thiosulfate.
Because of the oxidation promotion by thiosulfate, it
should be much easier to minimize oxidation in a
once-through system than in one in which the solution
is regenerated, a sulfur product removed, and the
regenerated solution recycled. -In reverse, oxidation
should be much easier to promote in a regenerative
system as the thiosulfate concentration should build up
to saturation and thus exert maximum catalytic effect.
Another possibility for changing degree of oxidation,
either up or down, is to carry out the reaction of
ammonia with sulfur dioxide in the gas phase to form a
solid product (see earlier discussion under chemistry and
kinetics). This would remove oxygen absorption in the
scrubber solution as a cause of oxidation but would give
oxygen the opportunity of taking part in the gas phase
reaction (or of oxidizing the sulfite after it was
formed), which might result in more oxidation than in
scrubbing. (The latter possibility is supported by the
complete oxidation that takes place in the alkalized
alumina, Mitsubishi, and activated carbon processes, all
39
-------
of which involve gas-solid interactions; however, these
either operate at relatively high temperature or involve
very large surface area, in contrast to the Still process
where oxidation takes place to a much lesser extent.)
Several investigators have carried out the reaction in
the gas phase but few data are available on degree of
sulfur dioxide removal or of oxidation. In TVA tests
(80), addition of ammonia to saturated gas at the
wet-bulb temperature (120-125° F) gave a small amount
of solid material together with a saturated or near
saturated solution of ammonium sulfite, bisulfite, and
sulfate. When gas saturated at 110° F was heated to
120° F (to avoid saturation) and ammonia added, the
product was a damp, crystalline material composed
mainly of ammonium sulfite monohydrate
[(NH4 )zSO3 -Hz 0]— indicating that a solid product can
be recovered if the gas is not saturated. (It seems likely
that solid product formation would be necessary if
reduction in oxidation were desired because operating
with saturated gas gives mainly a concentrated solution,
subject to the same degree of oxygen absorption as
scrubbing with a saturated solution.)
The degree of oxidation was not determined in the
TVA tests and reports by others who have studied the
gas-gas reaction apparently do not contain such data.
Marks and Ambrose (87) studied the reaction of
ammonia with sulfur dioxide carried in partially
humidified air. Oxidation was relatively low but neither
the oxygen nor moisture content were as high as in
power plant stack gas.
Oxidation in Separate Vessel
Although it may be possible to operate the scrubber
in such a way as to obtain oxidation of the sulfite,
such a technique has not been developed and even if it
were the scrubber operation might be complicated
unduly. Because of this, oxidation in a separate vessel
must be considered as the more-or-less established
method for converting the entire scrubber output to
ammonium sulfate.
As noted earlier, most of the work on separate
oxidation has been in connection with efforts to make
ammonium sulfate without going through the step of
making sulfuric acid. The technology should be generally
applicable to the power plant situation, however, as the
problem in both cases is that of oxidizing a fairly
concentrated solution of ammonium sulfite.
The main difficulty in separate oxidation is getting
an adequate rate of oxygen dissolution in the scrubber
effluent solution, a problem that has dictated the use of
pressure in most of the systems developed. The most
complete information obtained in the present study was
on the process developed by the Japan Engineering
Consulting Company in Japan and engineered by
Mitsubishi Shoji Kaisha, Ltd. (42, 43, 66, 96). In this
method, solution from the scrubber is neutralized with
ammonia (to prevent evolution of sulfur dioxide from
NH4HSO3 in the scrubber) and then oxidized with
compressed air or oxygen atomized into a pressurized,
water-cooled reactor. The solution is recycled through
the oxidizer and the heat of reaction removed by a
cooler in the recycle circuit. Ammonia and sulfur
dioxide losses are recovered by introducing the spent air
stream into the stack gas before the absorber. The fairly
detailed design information obtained on the process has
been used in developing the cost estimates presented in
a later section of this report.
Of the other development efforts in this area, that of
Simon-Carves in England appears to be the most
significant. During work by this company on the
autoclave process, tests were also made on oxidizing the
scrubber solution with air, using a special atomizing
device developed by Simon-Carves for another purpose
(95). Although good results were obtained, only
small-scale tests were made.
Most of the other work is reported only in patents.
Bergwerksverband (5) (Germany) describes a process in
which the scrubber solution is neutralized with ammonia
and oxidized with air or oxygen at 5-25 atmospheres
and 150° C. Lonza (61) (Switzerland) claims oxidation
at 50° C (presumably at atmospheric pressure) with 10
m3 /hr of air/kg of sulfur dioxide.
A variation proposed by West (94) involves oxidation
without first neutralizing the scrubber solution, the
objective being to evolve sulfur dioxide from the
bisulfite present; in effect this is the same as the
acidification method except that the oxidation is carried
out in the solution rather than in a sulfuric acid plant.
The flowsheet proposed by West (actual tests were not
made) is shown in figure 17. A possible advantage is
that the relatively high SO2:NH3 ratio would promote
oxidation rate.
Limited tests of such a method have been made at
TVA (80); scrubber effluent solution was treated in a
packed tower with a countercurrent flow of air. Results
were poor, possibly because of insufficient pressure or
need to atomize the air into the solution.
Catalysts might also be used to increase the oxidation
rate, as discussed in the preceding section.
Miscellaneous oxidation methods include (1)
electrolytic treatment of the solution (85) and (2)
separation of solid ammonium sulfite from solution by
crystallization followed by oxidation of the solid with
air at atmospheric pressure.
Acidification
The major work on the acidification process has been
done by The Consolidated Mining and Smelting
40
-------
Ammonium sulfite-bisulfite solution
from absorbers
Air
1
Tower 1
Partially
oxidized
solution
N2 + Oz + SO2 + H2O vapor
+ trace of NH3
Tower 2
Air
I
Tower 3
I
(NH4)2S04 solution
Figure 17. Air Oxidation,of Ammonium
Sulfite-Bisulfite Solution (94)
41
-------
Company (6, 25, 26, 27, 57, 60) (now Cominco, Ltd.)
and TVA (59, 69, 73, 80)! Johnstone (50) has also
given some attention to this system, particularly in
regard to adapting the Cominco data, obtained from
absorption of sulfur dioxide from smelter gases, to a
process for treating power plant gas.
Acidification is a relatively simple process with few
problems. Success of the method depends mainly on the
scrubbing step which has been discussed earlier.
In the Cominco operation, the scrubber effluent
(SO2 :NH3 ratio unknown) is first heated by exchange
with the acidifier effluent and then pumped to the
acidifier, a brick-lined cylindrical steel vessel fitted with
a central air-lift column. Sulfuric acid (93-98%) is
pumped through cast iron lines directly into the vessel.
Gas evolved by the acid-sulfite reaction provides
adequate mixing.
The acidified solution overflows from the acidifier to
the top of the "eliminator," a brick-lined steel tower
packed with spiral rings through which air is passed to
strip out the sulfur dioxide and reduce its concentration
to below 0.5 g/1. The air-sulfur dioxide mixture (30%
SO2) is combined with gas that escapes from the
acidifier vessel and is then passed to a sulfuric acid
plant.
The solution from the eliminator, containing 42%
ammonium sulfate, is treated with ammonia to eliminate
the acidity of the residual sulfur dioxide and then
pumped to an ammonium sulfate crystallizing unit.
Although the TVA work (pilot plant scale) was
aimed primarily at working out the problems of the
scrubbing step, some acidification tests were made. A
residence time of 10-15 minutes (min) was adequate
when the liquor was well agitated; about 90% of the
sulfur dioxide was evolved during the acidification. The
remainder was removed by stripping with steam
(600-800 Ib/ton of SO2 evolved) in a packed tower.
In crystallization tests the sulfite content of the
ammonium sulfate produced was 0.1% or less (as
sulfur); total sulfur was 23.3-24.1% (theoretical for
ammonium sulfate is 24.2%). A white product could be
made by filtering the solution to remove fly ash (2% of
the original ash was caught in the scrubber).
Johnstone has proposed several combinations of
acidification with stripping to reduce the heat
consumption. Since these apply primarily to the
stripping method they will not be covered in this
report.
Johnstone points out that the evaporation
requirement for obtaining solid ammonium sulfate is
independent of the SO2:NH3 ratio in the scrubber
effluent and is a function of the ammonia concentration
(figure 18).
10
I 8
•o
2
Q.
a
j?
1
i
a
5
0)
O
•o
§ 2
o
a.
42
4 8 12 16
C, moles of NH3/100 moles of H20
Figure 18. Evaporation Requirements for Production of
(NH4)jSO4 from Scrubber Effluent (51)
20
24
-------
USE OF AMMONIUM SULFATE IN
PHOSPHATE FERTILIZER PROCESSES
Ammonium sulfate is an important fertilizer, currently
second only to ammonium nitrate in world consumption of
solid nitrogen fertilizers and the world leader as recently as
1959. Consumption of ammonium sulfate and ammonium
nitrate in 1966 represented 18 and 28% of the world total
respectively. Thus ammonium sulfate is losing ground
rapidly although the consumption, equivalent to almost 3
million metric tons (mt) of nitrogen/yr, is still quite large.
In the United States the decline has been even more
rapid. In the period 1923-1947 ammonium sulfate was the
major nitrogen fertilizer and even earlier it was the leading
manufactured fertilizer; only natural materials such as
sodium nitrate and waste organic products were used in
larger quantities. In the past two decades, however,
ammonia, ammonium nitrate, and urea, materials of much
higher nitrogen content, have moved ahead. Today
ammonium sulfate supplies only 577,000 tons of nitrogen
(in 1967-1968), less than in recent yrs. Ammonia and
ammonium nitrate, on the other hand, supplied 3,338,000
and 887,000 tons of nitrogen in 1967-1968 and have been
gaining rapidly.
There are several reasons for this, among them the
relatively low nitrogen content of ammonium sulfate and
the fact that it does not fit well into some of the modern
fertilizer combinations such as liquid fertilizers. Since these
considerations are continuing to grow in importance, the
future of ammonium sulfate is not bright, at least for the
traditional ways of using it—as a straight nitrogen fertilizer
or as a constituent of simple mixes.
The processes shown in figures 17 and 18 (pp 41 and 42)
are new ways of using ammonium sulfate that appear
promising and may improve the status of the material. They
are largely untried, however, and there are several questions
regarding both technology and economics.
Nitric Phosphate
The nitric acid route to phosphate fertilizer production
gained somewhat in popularity in the 1960's because of the
generally increasing cost of sulfur (for making sulfuric acid)
in this period. (Sulfur price began a decline in 1969 and
currently is at a relatively low level.) The problem of
removing calcium nitrate from the phosphate rock-nitric
acid acidulate slurry (or converting it to something less
hygroscopic) has been resolved in several ways; the method
being used in most of the new plants involves refrigeration
of the slurry to crystallize out the nitrate, an expensive and
relatively difficult operation. As an alternative to this,
addition of ammonium sulfate to convert the calcium
nitrate to ammonium nitrate and calcium sulfate (figure 5,
p 21) has considerable promise, assuming that the
ammonium sulfate can be obtained at relatively low cost as
a byproduct material or by recycling the sulfate.
The comparative economics of these two sources are
important in evaluating use of ammonium sulfate from a
power plant recovery unit, because a fertilizer manufacturer
going into production of nitric phosphate by the
ammonium sulfate method would have the choice between
obtaining the ammonium sulfate by sulfate recycle or by
purchase from the power plant. The power plant product
would have to be priced low enough to make it
economically attractive as an alternative to recycling.
A flowsheet of the recycle process, as tested recently in
a TVA pilot plant, is shown in figure 19. The process
consists basically of five steps.
1. Extraction of Pj Os from phosphate rock with nitric
acid.
2. Removal of calcium from the rock-acid extract by
reaction with an ammonium sulfate solution and
subsequent filtration of the gypsum formed.
3. Conversion of the gypsum to byproduct calcium
carbonate and recycle ammonium sulfate solution by
reaction with ammonium carbonate solution.
4. Preparation of the ammonium carbonate solution
from ammonia, carbon dioxide, and water.
5. Neutralization, concentration, and granulation of the
filtrate from the gypsum filtration step (largely a solution
of ammonium nitrate in phosphoric acid).
In steps 1 and 2, unground Florida flotation
concentrate (33% P2OS, 48% CaO) is reacted with enough
65% nitric acid to give an HNOs'CaO mole ratio of 2.2 in
two extraction tanks arranged in series. Foaming is
controlled by the addition of a small amount of
antifoam agent (0.1 Ib/ton product). Extract from
the second extractor overflows to a surge tank
where the total retention time is increased to
about 2# hr and supplemental heat is supplied to maintain
an extract temperature of about 170° F. The extractor
slurry overflows from the surge tank to the precipitator
where it is reacted with ammonium sulfate solution. At a
temperature of about 160° F, the slurry from the
precipitator overflows to a pump feeding the filter.
The product filtrate from the filter consists principally of
ammonium nitrate and phosphoric acid and is ready
for neutralization and concentration, followed by
43
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Phosphate Rock
Nitric _
Acid p u »
Antifoam
Agent
Tj First
Li Stage
First
Stage Second
Stage
Extractors
Precipitator
Product
(28-14-0)
Off Gases
Gypsum
Filter
Cake
Pre Mixing Tank
Sulfate Liquor
Clear
Liquor
Recycle
Gypsum
nverter
Heat Exchanger
Ammonia
Ammonium
Carbonate
Liquor
Absorption
Tower
*" Cooling
Water
Carbon
Dioxide
Cooling Water
Water
Filter
» By-Product
Calcium
Carbonate
Filter
Cake
Heat Exchanger
Figure 19. Ammonium Phosphate Nitrate by Nitric Phosphate Route
(Sulfate Recycle Process)
-------
granulation or prilling. The gypsum cake is washed
countercurrently with water before it is fed to the
gypsum converter.
The filter is a horizontal continuous belt type
provided with separate filtrate and wash collection
systems and a variable-speed drive. Those parts of the
filter and accessories in contact with the process
materials are constructed mostly of Type 316 stainless
steel. The filter medium is a continuous cloth belt of
monofilament polypropylene fibers. The filtrate receivers
are connected to a wet-type vacuum pump.
The reaction vessels in this section are constructed of
Type 316 stainless steel.
In step 3, the gypsum converter is a single-stage unit
of unique design developed by TVA. It allows consistent
preparation of easily filterable calcium carbonate to
overcome a major problem experienced in other
processes that use this conversion step (Merseberg
reaction). Good conversion efficiency also is obtained.
The converter is a mild steel tank with a conical
bottom. The working volume is such as to give a 2-hr
retention time. Operating depth is about 6 ft with a
1-ft 4-inch (in) freeboard. The converter is equipped
with a slow-moving, variable-speed rake to provide gentle
mixing and also to keep material from building up over
the bottom discharge outlet.
Gypsum cake (directly from the filter) and
ammonium carbonate solution are premixed in a small
tank (retention time about 2 min) and fed beneath the
surface of material in the converter. Supernatant liquid
is taken from the top of the converter and recycled to
a point near the bottom of the tank to produce an
upward circulation. Calcium carbonate slurry is drawn
off the bottom of the reactor and pumped to a second
filter.
The calcium carbonate is removed by filtration on
the second belt-type continuous filter and the
ammonium sulfate solution (filtrate) is recycled to the
gypsum precipitation step.
In step 4, there are three major pieces of equipment:
a packed absorption tower constructed of Type 316
stainless steel, and two water-cooled, shell-and-tube heat
exchangers, each constructed of Type 304 stainless steel.
The absorption tower has two sections of loosely
packed 1-in ceramic Raschig rings. The system is
normally operated at a pressure of about 4 pounds per
square inch gage (psig). Wash water from the calcium
carbonate filtration step is added continuously to the
recycled ammonium carbonate solution, and the mixture
is then ammoniated, cooled from about 100-85° F, and
sprayed onto the top packed section of the absorption
tower. Carbon dioxide is introduced through an open
end pipe at the bottom of the tower. The solution from
the tower is then cooled from 100 to 85° F and a portion
is drawn off as product. The remainder is recycled to
mix with additional wash water. The synthesized
ammonium carbonate solution contains about 34%
ammonium carbonate and about 8% ammonium sulfate.
Step 5 is a standard fertilizer operation that is not
being tested in the pilot plant. The operation is similar
to that presently used in making ammonium
phosphate-nitrate products in the TVA full-scale
demonstration plant.
If ammonium sulfate from a power plant were used
in the process, all the equipment after the calcium
sulfate filter would be eliminated and the filter cake
would be transported to a disposal pond. The
ammonium sulfate liquor would come directly from the
oxidizer or acidifier section of the power plant recovery
unit and enter the nitric phosphate process at the point
shown on the flowsheet. The operation would then be
quite simular to that at Dutch State Mines in Geleen,
Netherlands, where byproduct ammonium sulfate
solution from a caprolactam plant is used (65). The
phosphate rock is dissolved in 55-60% nitric acid and
ammonium sulfate solution (40%) is added in two steps
to precipitate calcium sulfate. The content and ratio of
plant nutrients in the product vary with acidulation
ratio, CaO:P2O5 ratio in the phosphate rock, and
phosphate water solubility desired in the product.
Ammonium sulfate solution from a power plant
should be suitable for the process. The sulfate
concentration should be as high as in the Dutch State
Mines operation and higher than in the sulfate recycle
method (35%). The main question would be in regard
to the fly ash content of the solution. In connection
with the current study, small-scale tests have been made
to determine what effect the dust might have. The
results indicate that up to 25% of the fly ash initially
present in the gas could be carried along with the
ammonium sulfate solution without any major effect on
operation; above this the calcium sulfate filtration rate
would be decreased. Hence the bulk of the dust would
have to be removed by (1) an existing electrostatic
precipitator, (2) special scrubbing step before scrubbing
with ammonium sulfite, or (3) a filter to remove dust
from the scrubbing solution. Any dust carried along to
the precipitation step would be filtered out with the
calcium sulfate.
One of the drawbacks to the process is that all the
nitrogen remains in the product, and as a result the
product is relatively high in nitrogen content. In
fertilizer terms, the "grade" ranges from about 25-15-0
to 28-14-0 (depending on type of rock and operating
conditions), which means that it contains 25-28%
nitrogen, 14-15% phosphate (as P2OS), and no potash.
A grade such as this would have less market potential
than the more popular low and medium nitrogen types
45
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made by other processes, including the nitric phosphate
method in which calcium nitrate is removed by
crystallization. In this case the calcium nitrate is
converted to ammonium nitrate and sold separately,
with the result that the phosphate fertilizer grade is
about 23-23-0.
One possibility for reducing the N'.PsOs ratio is to
treat the scrubber effluent in the power plant by the
acidification process and use the resulting coproduct
sulfuric acid to replace some of the nitric acid in the
nitric phosphate plant. Since the consumption of nitric
acid is reduced, the product would contain less nitrogen.
The actual grade produced would depend on the
amount of sulfuric acid available, which depends on the
bisulfite:sulfite:sulfate ratio in the scrubber effluent, as
discussed earlier.
Ammonium Phosphate-Sulfate
Although nitric acid acidulation has received much of
the attention in the search for ways to eliminate the
sulfur requirement in manufacture of phosphate
fertilizers, other acidic materials have also been
considered. One of these is ammonium bisulfate
(NH4HSO4), which can be made by heating ammonium
sulfate to vaporize one of the ammonium radicals from
the molecule.
Use of ammonium bisulfate to decompose phosphate
rock was proposed in patents as early as 1918 (35), but
apparently the only useful data are those developed in
the USSR by Karakhanyan et al (38, 52, 53, 54, 63).
There are a few other papers and several patents on the
subject but most of these deal with production of a
solid, superphosphate-type product (12-18-0). The
process evaluated in the present study differs from this
in that (1) enough ammonium bisulfate solution is used
to produce phosphoric acid rather than monocalcium
phosphate and (2) the product slurry is filtered to
separate and remove the calcium sulfate rather than
leave it in a solid, superphosphate-type product.
The phosphoric acid type of process was mentioned
in an early news item (1927) that reported development
of the method in work at the University of Alabama
sponsored by the Alabama Power Company (2). It was
said that a practicable and economical method had been
worked out but no data were given. The report stated
that construction of a manufacturing plant was being
planned. Apparently the plant was never built.
The only other work of this type identified in the
present survey is reported in the papers by Karakhanyan
et al. Good dissolution of the phosphate rock, up to
98%, was obtained. The main difficulty apparently was
formation of a double salt, 5CaSO4-(NH4)2SO4-H2O,
that caused some loss of nitrogen by retention in the
filter cake. The loss was reduced to 3% of the nitrogen
by washing the cake with dilute sulfuric acid.
To further explore the process, small-scale tests have
been carried out at TVA (81). Phosphate rock was
treated with hot (150-200° F) ammonium bisulfate
solution, the resulting slurry mixed for a period, and
the precipitated calcium sulfate filtered off. Various
mole ratios of NH4HSO4:CaO were tested; for the
ratios 1.6, 1.86, and 2.0, 1.86 gave better phosphate
(P205) recovery (94%) from the rock than did 1.6 and
as good recovery as for 2.0. Dissolution of the rock was
essentially complete; most of the unrecovered PjOs was
present in the filter cake as a citrate soluble but water
insoluble form, indicating that it was reprecipitated
dicalcium phosphate such as is normally found in the
gypsum cake from standard wet-process phosphoric acid
operations. Addition of a small amount of sulfuric acid
to the ammonium bisulfate solution did not reduce the
P205 loss in the cake.
The product grade from these tests, after
ammoniation and granulation of the filtrate (phosphoric
acid plus ammonium sulfate), was approximately
18-18-0.
Work has also been done at TVA on the step of
converting ammonium sulfate to ammonium bisulfate. It
is reported by Ross et al (74) that the conversion takes
place at about 570° F. In TVA tests to confirm this
and to explore procedures, heating at 600° F gave very
slow conversion. About 94% of the ammonium sulfate
was decomposed after heating at 750° F for 1% hrs in
the presence of a sweep gas to remove the evolved
ammonia. Infrared and X-ray examination indicated that
diammonium pyrosulfate [(NH4)2S2O7] was formed
rather than ammonium bisulfate. The material dissolved
easily in water, however, and evaporation of the
resulting solution gave ammonium bisulfate.
These tests and the work reported previously indicate
that the overall process should be technically feasible.
Further small-scale work and pilot plant tests would be
necessary, however, as steps in the further development.
Some increase in rate of ammonium sulfate
decomposition to bisulfate is desirable and might be
obtained in equipment designed for faster removal of
evolved ammonia. A corrosion test program is also
indicated.
In the phosphate acidulation step, it would be
desirable to reduce the citrate-soluble P2O5 content of
the cake, which might be done by use of a
countercurrent washing procedure such as used in the
standard wet-process phosphoric acid method. The
problem of nitrogen loss in the cake by double salt
formation, reported by Karakhanyan et al., and not
checked in the TVA tests, also should be explored
further.
46
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MAJOR ECONOMIC CONSIDERATIONS
The present study is the first one in the series that
involves sale of a product and therefore new problems
such as profit margin, product marketability, and
projected financial attractiveness are introduced. These
factors cannot be ignored—as some have proposed—on
the basis that the need to reduce pollution justifies any
financial loss that may be incurred in a recovery
process; the limestone-wet scrubbing method is an
example of a reasonable alternative that sets a minimum
operating cost penalty for pollution control, beyond
which any loss from a recovery operation is not
justified.
Cost of Alternative to Recovery
Data on the cost of limestone-wet scrubbing as the
alternative to recovery are available from the previous
NAPCA-TVA conceptual design study (83). In setting a
basic cost figure for comparing with a recovery process,
most of the variables, e.g., size of plant, sulfur content
of fuel, capacity factor, new versus existing plant, and
degrees of sulfur removal and reheat, can be set at the
same level for the two processes. An exception is cost
of limestone, which may vary considerably between
plant locations. However, the limestone cost used in the
design study ($2.05/ton, delivered, -^ in) is believed to
be typical for most parts of the country.
For convenience, the summary tables for investment
and operating cost given in the limestone-wet scrubbing
report are repeated here (tables 5 and 6).
Return on Investment
One of the major drawbacks to recovery processes is
the higher investment as compared with the limestone
methods. This not only increases cost items such as
depreciation, insurance, and taxes, but also intensifies
the effect that projected return on investment has on
the economic attractiveness of the process.
In the limestone-wet scrubbing study, it was assumed
that (1) the investment would be half debt and half
equity, (2) the debt capital would earn only enough to
pay the interest, (3) the equity portion would earn at
11% of average undepreciated investment, and (4) the
plant would be depreciated over a period of 35 yrs.
This seems to be a fair average of the capital structure
and rate of return in the utility industry, although there
is considerable variation among companies (32).
It can be said that no return on equity should be
expected from a pollution control unit. However, the
investment for the sulfur dioxide removal equipment
Table 5. Capital Cost of Limestone
Wet Scrubbing (83)
Conditions
Base case3
Exceptions to base case
2.0% S
5.0% S
Limited reheat"
To 200° F
To 175° F
Process Bc
Process B (with lime)d
500 mw
1,000 mw
1,000 mw, process B
1,000 mw, new power unit6
Capital, $/kw
of power capacity
13.05
11.70
14.30
10.52
9.47
13.80
20.00
10.85
8.21
8.82
6.32
aBase case assumes 200-mw unit, existing power plant, 3.5% sulfur
in coal, process A (injection-scrubbing), reheat to 250 F by heat
exchange, 99.5% dust removal, 95% 862 removal, and nonrecycle of
sluice water.
"Reheat by direct firing natural gas.
cAddition of limestome to the scrubber circuit; 85% SC>2 removal.
"^Addition of lime (CaO) to the scrubber circuit.
Includes credit for eliminating electrostatic precipitator.
would almost certainly be merged with the total power
plant investment as is that for dust-collection
equipment, and would therefore increase the "rate base"
on which the utility is allowed to earn at the rate set
by the regulatory commission. Thus the return on
equity must be included in any process comparison; it is
the "cost of money," as essential as any other cost
item.
When a recovery process is considered on this basis,
certain complications arise. In the first place, recovery is
a chemical enterprise and the chemical industry differs
radically from the utility industry in financial practice,
particularly in evaluating new projects and attracting
investment for them. Because of the usual risk involved,
chemical producers generally require a fairly short
projected "payout" period before going ahead with a
project; the "cash flow" (depreciation plus net profit)
expected must be high enough to return the total
investment in, say, 4-6 yrs. Sometimes the gamble is
unsuccessful, of course, so that the actual average
payout in practice is somewhat longer, about 7.5 yrs for
the basic chemical industry (34).
In contrast, the payout period in the utility industry,
calculated for the assumptions listed above, is about
13.5 yrs-a figure that is borne out by published data
on actual performance of the industry, which show a
cash flow of about 7.5% of original investment, or a
47
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payout of 13.3 yrs (32). The reason that investors
continue to finance power plants with such a long
expected payout period is that little or no risk is
involved. The price of the product is regulated, by
governmental commissions, within limits that average out
to give such a return.
Thus if the investment for sulfur dioxide recovery is
made part of the utility rate base and the usual rate of
return allowed, the prospect for economic feasibility
becomes considerably brighter. If the usual chemical
industry payout were required, about $3S/ton of sulfur
Table 6. Operating Cost for Limestone -
Wet Scrubbing (83)
Conditions
Base case3
Exceptions to base case
2.0% S
5.0% S
$1.00/ton limestone
$4.00/ton limestone
Intermittent operation*5
720 hr/yr (30 days)
4,000 hr/yr (1/a yr)
Reduced boiler operation0
(50% load factor)
Limited reheat
To 200° F
To 175° F
Intermittent reheat to
200° Fd (30 days/yr)
Sluice water recycled
Process Be
Process B (with lime)*
500 mw
1 ,000 mw
1 ,000 mw, process B
1,000 mw, new power unit9
1 ,000 mw, new power unit.
$1.00/ton limestone
$/ton
of coal
1.31
1.05
1.57
1.17
1.56
0.75
1.18
2.10
1.13
1.06
1.07
1.33
1.42
1.85
1.11
0.90
0.99
0.76
0.64
Mills/kwh
0.49
0.39
0.59
0.44
0.59
0.28
0.44
0.79
0.42
0.40
0.40
0.50
0.53
0.69
0.41
0.34
0.37
0.29
0.24
aBase case assumes 200mw unit, existing power plant. 3.5% sulfur in
coal, 8,000 hr/yr operation, process A (injection-scrubbing),
nonrecycle of sluice water, reheat to 250° F by heat exchange,
$2.05/ton limestone cost, 14.5% capital charge, 99.5% dust removal,
and 95% SO2 removal.
"Boiler operating at full load; scrubber operating for period shown;
cost is average based on all coal burned and power produced/yr.
cBoifer operated intermittently or at reduced load; scrubber
operated when boiler is in operation.
^Direct heating with natural gas.
eAddition of limestone to the scrubber circuit; 85% SC>2 removal.
'Addition of lime (CaO) to the scrubber circuit.
^Includes credit for eliminating electrostatic precipitator.
equivalent in the product would be needed to take care
of the cash flow alone (assuming 5-yr payout, 4% S in
coal, $15/kilowatt (kw) investment for the recovery
process, and 70% capacity factor for the power plant).
For utility type of financing, this figure would drop to
$13/ton.
From contacts made in the course of this study, it
appears that power companies generally will favor
making the sulfur dioxide recovery investment part of
the rate base. It can be argued that this would work a
hardship on companies that recover sulfur or make
sulfur products in the unregulated chemical and
metallurgical industries, where there is no regulation of
price and therefore no guarantee of return on
investment. Because of the low risk in the regulated
utility industry, sulfur dioxide recovery may be
economically feasible where otherwise it would not
be-and thus large amounts of sulfur (or sulfur
products) could come on the market that otherwise
would not be there. As a byproduct it would be sold at
whatever price required to move it and therefore could
present formidable competition to the established
sources.
The effect of this aspect of the situation on the
methods finally adopted for financing sulfur dioxide
recovery units is difficult to assess. Another factor that
may be important is the general reluctance on the part
of most power companies to enter into the chemical
field. Probably the most practical arrangement in this
respect is operation of an absorption unit by the power
company and transporting of the loaded absorbent
"across the fence" for regeneration or conversion by a
chemical company. Although this would be a convenient
arrangement, the requirement on the part of the
chemical company that there be an acceptably short
projected payout for its part of the investment would
remain as a major economic obstacle.
Another alternative would be for the power company
to contract with a chemical company to provide all the
facilities and service required for recovery of sulfur
dioxide. This would be advantageous for the utility
because no investment would be required and the cost
for pollution control could be firmly fixed. However,
the larger investment by the chemical company, as
compared with the across-the-fence situation, would
make projected payout even more of a deterrent to
investor acceptance.
Because the most likely mode of ownership and
operation is not clear, economics in the present study
will be developed for all three approaches: (1) all
power, (2) joint venture, and (3) all chemical.
48
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Power Plant Capacity Factor2
Recovery of sulfur oxides combines power generation
and chemical production—two very different types of
operation. The power plant cannot store its product as
can most chemical operations, and since the demand for
electricity is quite variable the plant must be designed
for rapid change in production rate and must operate at
less than full capacity for a good part of the time.
Moreover, power plants are usually operated on a
system basis; several plants distributed over a service
area are operated as an integrated system to supply the
power demand, peak as well as average, in the most
economical way. In many cases a computerized control
system is used to analyze the demand pattern and to
assign the load to those plants that can most
economically supply it to the points of use. Thus some
plants are operated at full capacity a good part of the
time, some operate only at part capacity much of the
time, some operate only at peak system load, and some
are standbys that operate only in case of primary plant
breakdown or other emergency. The range in individual
plant load factor depends on the variation in system
load, which differs between systems because of
geographical variations in use pattern. A typical weekly
load curve for the TVA system is shown in figure 20
and an annual curve in figure 21.
Historically, new generating units added to a power
system have been larger, more efficient, and more
economical to operate than units already in service. It
follows then that the newer units get the most use and
that the dispatch system operates the less efficient
pknts only when necessary. Then as the new units grow
older they in turn are pushed into peak load or standby
status by even newer and more efficient units. The
following is a typical load factor sequence over the life
of a boiler unit.
Years
0-10
11-15
16-20
20-35
Average annual capacity
factor, % of full load
80
57
40
17
The average capacity factor over the 35 yrs is about
43%.
Thus capacity factor becomes an important
consideration in evaluating the cost of sulfur dioxide
removal over the life of the plant. For example, the
2 Capacity factor is plant output as percentage of nameplate capacity.
Load factor is plant output as percentage of unit capability (after
substraction of time for maintenance and repair).
cost of limestone-wet scrubbing in table 6 is $0.76/ton
of coal burned for a 1000-mw unit operating 8000
hr/yr (assumed unit availability), whereas at 43%
capacity factor (equivalent to 3760 hr) the cost is
$1.34/ton of coal. At the lower capacity factor, there
are fewer tons of coal over which to spread the capital
costs.
The effect of the expected future low capacity factor
on the decision to enter into a sulfur dioxide recovery
,project is difficult to evaluate. In the chemical industry
the first few years of operation are the important ones;
the situation 20 or more yrs in the future is seldom
considered. This makes capacity factor less important
because the factor in the first few yrs is relatively high.
The low factors come in the future, beyond the period
considered in planning. Perhaps the main consideration
would be the practicality of operating a recovery unit at
very low capacity factor, even if no profit were
expected because a satisfactory total return had been
obtained in the early years of operation. The cost of
maintaining a crew for intermittent operation and
problems in marketing the sporadic production might
make it expensive to continue recovery merely to
control pollution.
A utility presumably would give more attention to
the entire life of the unit in evaluating the effect of
declining capacity factor on recovery of capital and
return on capital. Since depreciation is a uniform annual
capital charge, the net effect would be higher
income/unit of production in the early yrs than in the
later ones. However, the proceeds needed in the later
yrs is lower because there is less undepreciated capital
remaining in the project. Moreover, the effect of any
decline in proceeds in the later yrs is minimized by the
fact that the present worth of dollars that far in the
future is relatively low.
It is concluded that declining capacity factor is not
as much a drawback as it might seem, at least as far as
capital charges are concerned. Operating cost and
product marketability, however, may be major problems
at the 10-25% capacity factors typical in plants over 15
yrs old. These problems might be avoided by combining
gas flow from adjacent boilers to keep the recovery unit
operating or by switching to limestone scrubbing and
shutting down the fertilizer system.
Notwithstanding these considerations, incorporation of
sulfur dioxide recovery into a power plant during
construction should generally be more economical than
adding recovery facilities to an existing one. In addition
to reduced capital cost (because of better integration of
the two units), there will be more total kwh over
which to, spread the capital charges-which is an
important consideration even though the effect of
reduced production is minimized because it occurs in
the later yrs.
49
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Even in the early yrs, however, the capacity factor is
not ideal. Even though new generating units are usually
assigned a base load status, they do not necessarily have
high load factors because at times other factors such as
location and cost of fuel may favor shifting of load to
some of the older plants. Moreover, problems that
develop during initial operation of new units often
require additional outage time for modification and
therefore reduce the availability of the unit.
This is quite undesirable for a chemical operation;
chemical products can be stored and the usual practice
is to operate the production unit as continuously and
uniformly as possible, with swings in product demand
offset by using storage as a buffer. The plant may be
slowed or shut down completely for a period if storage
becomes a problem. Operation in conjunction with a
power boiler, with wide swings in production rate,
would be expensive and for some processes quite
difficult to accomplish.
In some sulfur oxide recovery situations it may be
practical to use a holding system for loaded absorbent
as a, buffer between the absorption and finishing steps,
so that only the absorber operation would have to vary
with the power plant capacity factor. Or the recovery
unit might be designed for only partial sulfur oxide
removal, where pollution regulations permit, so that
even at reduced boiler load there would be enough
sulfur throughput to keep the recovery unit running at
capacity. These alternatives have been discussed by J. E.
Newell (Central Electricity Generating Board, England)
(70).
Sulfur Content of Coal
A major economic advantage for recovery is that high
sulfur content of the coal works in its favor, whereas
the opposite is true for limestone-wet scrubbing. Most
estimates of process cost have assumed a sulfur content
12000
11000
10000
9000
8000
7000
6000
5000
Sun
Mon
Tue
Wed
Thurs
Fri
Sat
Figure 20. Typical Weekly Load Curve for
TVA Power System (Spring 1968) (84)
50
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of 3-4% but large quantities of coal containing more
than 4% are mined, particularly in Illinois, Ohio,
Missouri, and western Kentucky (71).
In a recovery-type process, use of high-sulfur coal
would give considerable economy in regard to
equipment sized on the basis of gas flow rather than
sulfur throughput. Thus processes in which all
equipment must handle the full gas stream are benefited
the most. In contrast, wet-scrubbing processes require
gas flow only through the scrubber and the si/e of the
rest of the unit must be increased for higher sulfur
throughput. There is some economy of scale but much
18000
17000
16000
15000
14000
13000
« 12000
1
11000
10000
9000
8000
7000
6000
5000
I I I I I 1 I I | I I I I I I f I I I I
Maximum Hourly
Generation
Installed Capacity
I I I I I I I II I I I |
Total Generation
(Hourly Average)
I I I
1965 1966 1967 1968
Fiscal year
Figure 21. Annual Variation of Load in TV A Power System (84)
51
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less than for equipment which does not have to be any
larger for the higher sulfur loading.
There is the possibility that high-sulfur coal could be
obtained at lower cost than for the medium-sulfur
type—an advantage that has been assumed in some
process analyses. This may be true in situations where
high-sulfur coal must be beneficiated at extra cost in
order to meet a large demand for lower sulfur fuel.
However, it is conceivable that very high sulfur coals
could actually command a premium if recovery
processes were generally adopted as the more desirable
method of air pollution control. Also, the advantage of
high-sulfur content would be lost rapidly if selective
mining were required to obtain it. To minimize cost,
the coal deposit should average somewhere near the
desired content and the coal should be mined as found
and handled at the power plant in such a way as to get
a fairly uniform boiler feed—as is usually done in large
plants. Moreover, the use of high-sulfur coal (either
naturally occurring or rejects from a deep cleaning
process for coal) to improve recovery economics
probably would be most feasible in a new plant in
which the boiler would be designed for the individual
coal characteristics.
Product Marketing
The most difficult cost factor to estimate in
evaluating recovery processes is the price obtainable for
the product. The material is a byproduct, produced not
in accordance with the market demand for it but with
the demand for electric power, so that the seller is
somewhat at the mercy of the buyer. And even a few
power plants equipped with recovery facilities would
make so much sulfur product that the market would
likely be depressed. Finally, if the power company
financed and operated the recovery unit a sales agent
likely would be needed (or a company sales
organization) to sell the product, which would introduce
a sales cost difficult to predict.
One of the more important considerations is the
location of the power plant with respect to the
customer for the sulfur byproduct. The very large
amount of sulfur involved makes it almost essential to
have large-quantity sales to single customers if high sales
cost is to be avoided. The sulfur-consuming industry
that qualifies best for this is the phosphate fertilizer
industry, which accounts for over half the sulfur
consumption in the United States. Modern phosphate
plants are quite large and afford individual points of
high consumption such as needed for marketing power
plant byproducts; for example, a plant producing 1000
tons/day of 28-14-0 fertilizer would use 560 tons/day of
ammonium sulfate—the output from about 500 mw of
power-generating capacity.
To keep shipping costs from reducing the return too
much, the phosphate plant should not be very far from
the power plant. The relative locations of power plant
sulfur emission and phosphate plant sulfur consumption
are approximated in figure 22. Unfortunately, much of
the phosphate production is in Florida and along the
Gulf Coast, where sulfur emission is relatively small. In
contrast, a major part of the sulfur emission is in the
Northeast where there is little phosphate production.
The most favorable area is the Upper Midwest region,
where the two are more nearly in balance and much of
the recovered sulfur might be used in phosphate plants
without shipping very far.
Another possibility is barge shipping of the product
from those power plants located on navigable water.
Modern barge transport is quite economical; anhydrous
ammonia, for example, which requires special
refrigeration equipment in transit, is moved on the
central rivers for 4-6 mills/ton-mile—indicating that
sulfur products could be shipped a thousand miles for
less than $4/ton. Fortunately, about 80% of the sulfur
dioxide emission is from plants located on navigable
rivers.
If fertilizer plants were built near power plants, the
product to be shipped would be phosphoric acid, triple
superphosphate, ammonium phosphate, or nitric
phosphate (made with ammonium sulfate as an
intermediate raw material), all products of high enough
concentration for economical shipping. At the present
time overproduction in the phosphate fertilizer industry
makes such ventures unlikely, but presumably this
situation will improve in the future. It should also be
noted that there has been no great rush to build
fertilizer plants near smelter plants, where sulfur
recovery is far more economical than in the power
industry. There are some examples but not many;
however, smelters are not generally located as favorably
as power plants in relation to fertilizer plants and to
areas of high fertilizer consumption. The most recent
sulfur recovery project at a smelter may be significant
for the power plant problem; Falconbridge Nickel near
Sudbury, Canada, is converting recovered sulfur dioxide
to elemental sulfur (by a process developed by Allied
Chemical) (4) rather than making the usual sulfuric acid
as the end product.
This points again to the upper Midwest as the most
favorable location for sulfur oxide recovery. The area is
a heavy consumer of fertilizer phosphate (54% of the
United States total in 1967) and the high-sulfur coal is
there-about 90% of the coal containing over 3.5%
sulfur is mined in the block of states comprised by
Ohio, Illinois, Indiana, Iowa, western Kentucky, and
Missouri. Most of the coal mined in the Eastern States
contains less sulfur and therefore recovery economics
would not be as good. The nonrecovery limestone
processes may be more applicable for this area.
52
-------
o
Q
o
Size of circle indicates relative quantity of sulfur consumed in phosphate fertilizer production in adjacent
area. Shaded circles indicate regional quantity of normal superphosphate. Blank circles indicate phosphoric
acid plant complexes.
LJ Size of square indicates relative quantity of sulfur emitted from power plants in adjacent,
Figure 22. Sulfur Oxide Emission and Sulfur Consumption in the U. S. (84)
53
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STUDY ASSUMPTIONS AND DESIGN CRITERIA
The conceptual design was developed for a basic
scrubbing system plus three process alternatives for using
the scrubber effluent.
Process A—Air oxidation to produce ammonium sulfate
solution from all of the recovered sulfur and use of the
ammonium sulfate solution to produce either crystalline
ammonium sulfate or nitric phosphate (28-14-0).
Process B—Addition of sulfuric acid to convert the
ammonium sulfite and bisulfite in the scrubber solution
to ammonium sulfate and sulfur dioxide. The sulfur
dioxide is converted to sulfuric acid for use in the
process and the surplus acid is used to produce
ammonium phosphate for use in production of a
modified nitric phosphate (19-14-0).
Process C—Decomposition of ammonium sulfate by
heating to produce ammonium bisulfate and ammonia.
The ammonia is recycled to the scrubber and the
ammonium bisulfate used to acidulate phosphate rock
and produce ammonium phosphate sulfate (20-15-0).
Each process is compared under uniform conditions. In
addition, the effects of variables that significantly affect
costs are presented.
Plant Size
The size of power plants being built is steadily
increasing. Projection of boiler unit size (82) indicates that
over 95% of the capacity installed after 1970 will be in
units 600 mw or larger and about 80% in units of 1000 mw
or higher capacity. By 1980, over half of the total capacity
in the United States will be in units 500 mw or larger.
Practically all of the remainder will be in small units
(200-mw and smaller) 10 yrs old or more and the load
factor will be low. Since the pollution problem will thus be
centered in the new and larger plants, application of the
ammonia scrubbing process to a 500-mw unit was assumed
for the base case. To determine the effect of power plant
size on economics, estimates were also made for 200- and
1000-mw units.
The efficiency of power plant boilers varies with size and
design. Since the amount of coal burned/unit of power
produced is important in establishing the quantity of sulfur
evolved, the following rates, based on TV A experience,
were assumed.
Unit size, mw
Btu/kwh
1,000 new
1,000 existing
500 new
500 existing
200 existing
8,700
9,000
9,000
9,200
9,500
The distinction between new and existing plants is made
to reflect improved design of the more modern units.
Sulfur Content of Fuel
The sulfur content of the coal does not significantly
influence scrubber design since the size is determined
mainly by gas flow rate. However, the size of plants
utilizing the scrubber solution is directly affected by the
sulfur level in the coal and economy of scale becomes a
factor. Moreover, the sulfur content of the fuel determines
the tonnage of product that must be sold.
An average sulfur content of 3-4% was assumed and a
value of 3.5% was selected for the base case. Large
quantities of coal containing more than 4% sulfur are
mined, particularly in Dlinois, Ohio, Missouri, and western
Kentucky (88). Thus, operation with a higher sulfur level,
5%, was also evaluated. To complete the evaluation, the
economics of operation with 2% sulfur coal, representing
the lower range of sulfur level, was estimated. It was
assumed that sulfur content would not influence the price
of coal.
Degree of Sulfur Dioxide Removal
The required degree of sulfur dioxide removal is likely to
vary depending on geographic location, weather conditions,
plant size, and local regulations. Use of ammonia scrubbing
will probably be of interest mainly for larger plants that
operate near base load conditions and for which a high
degree of removal will be necessary. Also, within the
limitation of practical scrubber design, a high degree of
removal will improve overall economics of the recovery
system. A sulfur dioxide removal efficiency of 90% was
assumed as the basis for scrubber design.
Dust Removal
A major advantage of wet scrubbing for sulfur dioxide
control is ability to remove fly ash from the combustion
gases and thereby solve dust emission problems that are of
increasing concern to power producers. The present
conventional method for control of fly ash in modern
plants is through use of electrostatic precipitators which at
best are expensive to install and maintain and at worst are
unreliable. Many older plants are equipped only with
mechanical dust collectors and installation of improved
facilities at these is likely to be necessary.
Combustion of coal with 12% ash in a pulverized fuel
boiler results in a dust loading of about 4 grains/cubic foot
(cu ft) at the boiler exhaust; with a cyclone boiler (a far less
54
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common type) the fly ash content would be about
one-third this amount. It was assumed that it will be
necessary to remove 99.5% of the dust.
For new plants, the scrubbing system will be used to
remove fly ash and therefore eliminate the requirement for
an electrostatic precipitator. To prevent excessive solids
concentration in the ammonium sulfite-bisulfite scrubber
liquor, a scrubber stage will be provided ahead of the
absorber where dust will be removed by scrubbing with
water. Sulfur trioxide and a small portion of the sulfur
dioxide in the gas will be absorbed in the first-stage
scrubber. Although ammonia will be added to the gas for
corrosion control upstream of the scrubber, the liquor in
this stage will be acidic and require corrosion-resistant
materials of construction in the scrubber and in a clarifier
used for separation of the dust. The clarified liquor will be
recirculated except for a side stream removed for control of
the sulfate concentration.
In existing plants (assumed to be equipped with 90%
efficient electrostatic precipitators) continued operation of
dust collectors will remove most of the fly ash so that
residual amounts can be handled in the absorber.
Operating Time and Capacity Factor
In the design studies of nonrecovery limestone scrubbing
processes, the possibility of intermittent operation was
recognized. In recovery processes, the heavy investment and
market commitments will make it desirable to operate the
recovery system whenever the power unit is on-stream to
defray the continuing fixed costs. For the base case, a new
500-mw unit, the following schedule was assumed:
Year
1-10
11-15
16-20
21-35
Capacity factor, %
(nameplate rating)
80
57
40
17
Annual kwh/
kw capacity
7,000
5,000
3,500
1,500
The same schedule was used for a new 1 OOOmw plant; for the
200-mw comparison it was assumed thai the plant would be
8 yrs old when the recovery unit was installed so that the
first 8 yrs in the above schedule would be lost. For
comparison of installing ammonia scrubbing facilities in
new and existing plants, it was assumed that existing 500-
and 1000-mw units would be 3 yrs old.
Plant Location
The major fertilizer markets are located in the Midwest.
Because of distribution economics, it is likely that power
plants located near the markets will have the most interest
in use of the ammonia scrubbing process. Therefore, a
midwest location was assumed.
Amount of Storage
The fertilizer market is seasonal because the materials
are applied to the soil mainly in the spring and fall of the
year. Some storage is provided by sales of intermediates
(ammonium sulfate, 28-14-0, 26-19-0, 19-14-0 are in this
category) to manufacturers of custom blends; also
distributors provide some storage. However, it is common
practice for basic producers of fertilizer materials to
provide sizable storage facilities to accommodate
production during periods of low shipments. Moreover,
moving large inventories from storage during relatively
short periods requires unusually high investment for
materials-handling equipment. The average amount of
storage provided with new large fertilizer plants is about 60
days' production, which is normally adequate; if not, the
production rate can be reduced or the plant shut down.
However, with raw material supplied from a power plant,
the fertilizer plant would have to operate to permit
continued operation of the pollution control facility. Thus
for the present study, storage facilities for 90 days'
production were provided.
Stack Gas Reheat
The need for reheat of the cooled gas from the scrubber
has been generally accepted but the required level of reheat
has not been 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 (83). The results indicated
that with a high degree of sulfur dioxide removal (80% or
above) the stack temperature is not important. However, to
prevent high ground-level concentrations during upset
conditions and to avoid increased levels of nitrogen oxides,
it was decided that reheat to 250° F should be used as a
basis for design. The same basis was used in the present
study.
Fertilizer Technology
The technology involved in production of fertilizer from
ammonium sulfate by processes A and B was assumed to be
commercially proven and therefore evaluation was not
necessary in this study. Information for capital and
operating cost estimates was obtained from quotations on
battery limits plants and from TVA experience.
In process C, neither the decomposition of ammonium
sulfate to ammonium bisulfate nor the extraction of
phosphate rock with ammonium bisulfate has been carried
out in commerical or pilot equipment. The process and
equipment design was based on results of limited,
exploratory, small-scale work by TVA and therefore should
be considered as a preliminary study only. Estimates for
this process may be in error by as much as 50%.
55
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Solids Disposal
Process Indices
Fly ash removed in the clarifier will be sluiced to an ash
pond for storage; no additional expense beyond normal
disposal costs should be incurred. It was assumed that the
normally basic ash would neutralize the acidity resulting
from sulfur oxides absorbed in the dust scrubber. If not, pH
control of the sluice pond overflow might be necessary.
It was assumed that calcium sulfate from the fertilizer
plants would be stored in a pond as is common in the
fertilizer industry. Water pollution control facilities were
provided. Storage for 10 yrs' production of gypsum was
assumed.
A summary of indices for the various processes and
operating levels is given below. Flowsheets for each process
are shown in Appendix C and are designated as follows:
Process A - A69-A-5
Y69-A-6
Process B-A69-A-11
Y69-A-12
Process C - A70-A-3
A70-A-4
General:
Power plant
size, mw
200
500
500
500
500
1,000
1,000
Type
plant
Existing
New
New
Existing
New
New
Existing
Sulfur
content
of coal, %
3.5
2.0
3.5
3.5
5.0
3.5
3.5
Gas flow at
boiler exit,
acfm
648 M
1.620M
1 ,620 M
1.620M
1 ,620 M
3,240 M
3,240M
Product rate, ton/hr
Process A
(28-14-0)
18.4
24.8
43.4
44.4
62.0
83.9
86.8
Process B
(26-19-0)
13.9
18.8
32.9
33.7
46.9
63.4
65.7
Process C
(19-14-0)
8.1
10.9
19.1
19.6
27.3
37.1
38.3
Operating Indices for Process A
(28-14-0 Production):
Ammonia Scrubbing
Scrubber effluent
Flow rate, Ib/hr 72.8 M
Temperature, °F 120
Salt concentration, % by wt (NH4 )2 SO4 50
NH3 :S mole ratio 1.49
Neutralizer effluent
Flow rate, Ib/hr 98.4 M
Temperature, ° F 188
Salt concentration, % by wt (NH4)z SO4 40
NH3: S mole ratio 2.0
Oxidizer effluent
Flow rate, Ib/hr 102 M
Temperature, °F 135
Pressure, psig 100
pH 6.5
Retention time, hr 1
Nitric Phosphate Production
Extractor raw material rates, Ib/hr
Nitric acid 77.9 M
Phosphate rock 41.3 M
Antifoam 16.5
Precipitator effluent
Flow rate, Ib/hr 219 M
Temperature, °F 150
Filter effluent
Flow rate, Ib/hr 195 M
Temperature, °F 100
Gypsum slurry
Flow rate to pond, Ib/hr 315 M
Neutralizer
Ammonia flow rate, Ib/hr 5650
Effluent temperature, °F 150
Evaporator
Effluent flow rate, Ib/hr 107 M
Steam requirement, Ib/hr 175 M
Salt concentration, % by wt 28-14-0 99.7
Prilling tower
Recycle ratio, Ib recycle/lb product 1:4
Conditioner rate, Ib/lb product 0.02
Product rate, Ib/hr 86.8 M
Operating Indices for Process B
(26-19-0 Production):
Ammonia Scrubbing
Scrubber effluent
Flow rate, Ib/hr 67.8 M
Temperature, °F 120
Salt concentration, % by wt (NE» )2 S04 52.5
NH3 :S mole ratio 1.32
Stripper solution to precipitator
Flow rate, Ib/hr 68.7 M
Temperature, °F 114
56
-------
NH3:S mole ratio
Nitric Phosphate Production
Extractor raw material rates, Ib/hr
Nitric acid
Phosphate rock
Antifoam
Sulfuric acid
Precipitator effluent
Flow rate, Ib/hr
Temperature, °F
Filter effluent
Flow rate, Ib/hr
Temperature, °F
Gypsum slurry
Flow rate to pond, Ib/hr
Neutralizer
Ammonia flow rate, Ib/hr
Effluent temperature, °F
Evaporator
Effluent flow rate, Ib/hr
Steam requirement, Ib/hr
Salt concentration, % by wt 26-19-0
Prilling tower
Recycle ratio, Ib recycle/lb product
Conditioner rate, Ib/lb product
Product rate, Ib/hr
Operating Indices for Process C
(19-14-0 Production):
Ammonia Scrubbing
Scrubber effluent
Flow rate, Ib/hr
Temperature, °F
Salt concentration, % by wt (Nil, )2 SO4
NH3: S mole ratio
Neutralizer effluent
Flow rate, Ib/hr
Temperature, °F
Salt concentration, % by wt (NHL, )2 SO4
NH3:Smole ratio
Oxidizer effluent
2.0
51.5
40.5
16.2
11.4
M
M
M
170 M
150
146
100
M
310 M
5200
150
81.3 M
129 M
99.7
1:4
0.02
65.7 M
72.8 M
120
50
1.49
98.2 M
163
40
2.0
Flow rate, Ib/hr
Temperature, °F
Pressure, psig
PH
Retention time, hr
Nitric Phosphate Production
Net heat from boiler, Btu/hr
Evaporator-crystallizers
(NH) )2 SO4 rate to decomposer, Ib/hr
(NH4)2 S04 temperature to decomposer,'
Decomposer effluent
Flow rate, Ib/hr
Temperature, °F
(NH4)2 S2O7 :(NK, )2SO, mole ratio
Extractor-precipitators
Solubilizing tank effluent
Flow rate, Ib/hr
Temperature, °F
Phosphate rock flow rate, Ib/hr
Effluent rate to filter, Ib/hr
Filter effluent
Flow rate, Ib/hr
Temperature, °F
Gypsum slurry
Flow rate to pond, Ib/hr
Preneutralizer raw material rates, Ib/hr
Effluent from scrubbers
Ammonia
Ammoniator-granulator
Throughput rate, Ib/hr
Discharge
Moisture content, % by wt H2 O
Temperature, °F
Dryer
Throughput rate, Ib/hr
Discharge
Moisture content, % by wt H2 O
Temperature, ° F
Recycle ratio to ammoniator-granulator,
Ib recycle/lb product
Conditioner rate, Ib/lb product
Product rate, Ib/hr
M
102
185
100
6.5
1.0
115 MM
45.2 M
130
37.8 M
700
1.67
53.5 M
220
17.2 M
110 M
77.5 M
115
135 M
79.8 M
1660
509 M
4.0
180
492 M
1.5
190
12:1
0.02
38.3 M
57
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EQUIPMENT SELECTION AND DESCRIPTION
As discussed earlier, use of ammonia scrubbing for
recovery of sulfur dioxide has been studied over a long
period. Results of these studies are not directly applicable
to the current design, mainly because of difference in scale,
but some of the findings are useful in selection of
equipment type and design of required facilities.
Selected Reported Technology
Packed Absorbers—Most of the pilot and full-scale
work with ammonia scrubbing has been done in packed
absorbers. At Cominco, off-gas from sintering machines in a
smelting operation was treated with ammonia to remove
sulfur dioxide. Approximately 300,000 cfm of gas
containing about 0.75% sulfur dioxide was handled in two
parallel systems (half the flow in each) comprised of a lead
cooling tower about 25 feet square (ft sq) and 48 ft high
followed by three lead-lined absorption towers packed with
wood grids also 25 ft sq and 32 ft high. Liquid flow was
cocurrent with the gas in the first absorber, countercurrent
in the second, and cocurrent in the third. Circulation rate
was 1200-1500 gal/min in the first and second units and
600-800 gal/min in the third; aqua ammonia was added to
the circulating streams. The solution temperature was
controlled at about 90° F by water cooling in shell and
tube exchangers (aluminum tubes and steel shell). Solution
was bled forward from the last tower to the first where the
product concentration was about 240 g/1 of sulfur, mainly
ammonium bisulfite. The tail gas contained about 0.1%
sulfur dioxide; absorption efficiency was approximately
85%. Pressure drop in the system was about 10 in of water.
Most of the dust was removed ahead of the absorbers; the
method was not discussed.
The lead used in tower lining and aluminum for
exchanger tubing were satisfactory materials of
construction (25). In other portions of the Cominco plant,
type 316 stainless steel pumps were used for ammonium
sulfate solution, lead-lined tanks for storage of weak
sulfuric acid (70%) and ammonium sulfate solution, mild
steel tanks for storage of concentrated sulfuric acid (93%),
and neoprene-lined steel evaporators and crystallizers for
ammonium sulfate solution.
At TVA (41), a pilot plant was operated to study
scrubbing of combustion gases with ammonium
sulfite-bisulfite solution. A schematic flow diagram of the
pilot plant equipment is shown in figure 23. Pulverized coal
was burned at a rate of 150-200 Ib/hr in a fire tube boiler
and the combustion products were passed through a
mechanical dust collector and cooled by humidification to
produce gas for the pilot plant. Gas containing about 0.3%
Water
Recirculated
liquor
Cooled
combustion
Ammonia
Flowmeter
Pump
Figure 23. Early TVA Pilot Plant for Sulfur Dioxide Recovery
by Ammonia Scrubbing (41)
Blower
To stack
58
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sulfur dioxide entered the bottom of the scrubber, a mild
steel tower 2 ft in diameter by 10 ft high packed with 2-in
ceramic rings to a depth varied from 3-8 ft. Scrubber
solution was recirculated to the tower and heat was
removed in a water-cooled exchanger. Gaseous ammonia
was added to the solution in the recirculation system. The
major variables studied were circulation rate, pH and
concentration of solution, depth of packing, and gas
velocity. The conditions of operation for the various tests
are shown in table 7 and effect of recirculation rate and
packing depth on recovery of sulfur dioxide in figure 24.
The liquor rate required to obtain a given recovery
increased as the depth of packing decreased. The
approximate rates required for 80% recovery with a pH of
6.4 are given below together with the calculated absorption
coefficients.
Packing
depth, ft
8
4
3
Liquor rate
Gal/min
4
5
7
Overall coefficient
Gal/(min) (sq ft) Lb mole/(hr) (cu ft) (atm)
1.3
1.6
2.2
5.8
11.5
15.3
Table 7. Averaged Opefating Conditions for Pilot Plant Runs (411
Scrubbing liquor
Principal variable
Scrubbing liquor rate
Scrubbing liquor pH
Depth of packing
Gas velocity
Liquor concentration
Material balance
Ammonia recovery
Rate to
tower,
gal/min
0.5-9
5
0.5-9
5
5
5
5
pH
6.3
5.6-6.8
6.4
6.4
6.4
6.4
4.6-5.8
Temp.,°F
In Out
123 127
123 124
121 123
122 124
123 127
120 124
110 115
NH3
concn.,
moles/
100 moles
H2O
20
20
20
20
10-45
20
-
Stack gas to
scrubber
Temp., F S02
Volume,3
cu ft/min
330
340
350
250-600
320
350
350
Dry
bulb
129
122
121
124
125
121
124
Wet
bulb
124
121
123
122
122
121
121
concn..
%
0.29
0.30
0.30
0.28
0.29
0.27
-
SO2
recovered.
%b
56-80
0-90
35-84
84-85
68-85
82
-
Depth of
packing,
ft
8
8
3-8
5
5
5
5
aAt scrubber temperature and 725 mm pressure.
^As percent of SO2 in the stack gas to scrubber.
90
70
0>
§
8 50
30
8 ft of pack
0.5 1.0 1.5 2.0 2.5
Scrubbing liquor recirculation rate, gal/(min)(sq ft)
Figure 24. Effect of Packing Depth on SOj Recovery at Various Liquor
Recirculation Rates (at pH 6.4) (41)
3.0
59
-------
100
80
60
40
20
S02 recovery
NH3 loss
20
16
12
5.6 5.8 6.0 6.2 6.4
pH of scrubbing liquor
Figure 25. Effect of pH of Scrubbing Liquor on SO2
Recovery and NH3 Lots (41)
6.6
6.8
The effect of scrubbing liquor pH on sulfur dioxide
recovery and ammonia loss is shown in figure 25 and the
effect on composition of the scrubber solution in table 8.
These data show that the mole ratio of sulfite to bisulfite
increased with pH and that the amount of ammonia
required for recovery of sulfur dioxide increased as the pH
increased.
Change in gas velocity over the range studied, 1.4-3.5
ft/sec, did not significantly change the degree of sulfur
dioxide recovery; pressure drop through the scrubber was
less than 1 in of water.
Data on effect of solution concentration at a pH of 6.4
on sulfur dioxide recovery and ammonia loss are
summarized below.
Scrubbing liquor
Moles
NH3/100
moles H20
10.5
23.0
36.0
44.5
Composition, g/l
Specific
gravity
1.15
1.25
1.32
1.33
H20, %
by wt
70
52
40
35
NH3
81
143
181
200
Total
98
175
238
255
S
AsS04=
13
13
21
20
S02 recovery,
% of SO2 in
stack gas
85
81
72
68
NH3 toss, %a
5.4
8.4
17.5
23.5
aBased on ammonia added to maintain steady state.
60
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Table 8. Effect of pH on Composition of the Scrubber Effluent (41)
S:NH3 mole ratio
based on
Specific
Solution pH gravity
5.6
5.9
6.1
6.4
6.6
6.8
.18
.19
.20
.24
.25
.25
S02 Effluent composition, g/l
recovered, S
% NH,
0
47
58
82
85
90
84.3
95.0
104.5
131.5
149.5
155.5
Total
125
133
139
169
177
179
AsS04=
20.4
23.3
24.7
20.7
21.6
20.8
Degree of
oxidation?
%
16.3
17.5
17.8
12.3
12.2
11.6
NH3andS
Ammonium combined
sulfite: Total as ammonium
bisulfite Sand sulfite
mole total and
ratiob NH3 bisulfite
0.15
0.26
0.39
0.67
1.14
1.42
0.790
0.735
0.705
0.655
0.630
0.605
0.890
0.825
0.775
0.720
0.655
0.628
%ofS
recoverable as
(NH4)2SQ4
67
69
70
79
82
H2S04
33
31
30
21
18
a(-J9*^xloo).
» Total S '
"Calculated from analyses for total S, NH3, and SO4=
Tests were made to simulate a second-stage scrubbing
operation for ammonia recovery. With a sulfur dioxide
concentration of 0.05% (gas composition from first stage)
and circulation of dilute ammonium sulfite-bisulfite
solution at a rate of 1.6 gal/min/sq ft, ammonia loss was
reduced to about 0.3%.
Simon-Carves Limited of England also developed an
ammonia scrubbing process and constructed a large pilot
plant (56,000 cfm) at the North Wilford Power Station at
Nottingham. The gases.were scrubbed in countercurrent
flow with a solution of ammonium sulfite-bisulfite. A
single-stage scrubber—160-sq-ft cross section, constructed
from mild steel and coated with Epicote resin—was packed
with 5 ft of wood grids 3/32 in thick on 3/4-in sq pitch.
Liquor was circulated at a rate of 1600 gal/min using
Ni-Resist pumps and rubber-lined mild steel pipe. Pressure
drop was approximately 1 in of water. About 95% of the
sulfur dioxide in the inlet gas (0.13%) was removed in the
scrubber. Ammonia loss in the single-stage unit was high. A
typical composition of liquor produced was:
(NH4)2S04
(NH4)2S203
(NH4)2S03
NH4HS03
Mole/1
1.3
0.95
0.75
0.5
Andrianov and Chertkov (3) described an experimental
industrial application of ammonia scrubbing in Russia. The
off-gas [100,000 Nm3/hr or 55,000 scfm (standard cubic
feet per minute)] from a 160- to 200-ton/hr boiler was
scrubbed with an aqueous solution of ammonium sulfite
(after the dust had been removed in an electrostatic
precipitator and the gas cooled to 30-35° C). The resulting
solution of ammonium bisulfite was thermally decomposed
to produce sulfur dioxide and the solution was recycled.
A five-stage, lead-lined mild steel tower was used as a
cooler and absorber. The lower section was lined with
acidproof brick and packed with 50- by 50 mm ceramic
rings; in this section, the inlet gas was cooled from 160-30°
C. The next three sections, the absorber, and the top
ammonium recovery section were also packed with ceramic
rings. The sections were separated by horizontal,
lead-covered trays which permitted flow of gas but
collected the liquor from each stage separately. Liquid
distributors were made of aluminum except in the
gas-cooling section where rubber-coated steel was used.
Stainless steel pumps and aluminum pipe with stainless
fittings were used for handling the scrubber solution. Water
recirculated to the gas-cooling stage was handled in
rubber-lined pumps and pipes.
Residual dust in the gas caused plugging problems
throughout the system and it was necessary to install filters
to reduce the ash content of the scrubber solutions to 1 -2 g/l.
Cooling of effluent from the gas-cooling stage was also a
problem. Cooling the gas, which normally contained about
0.3% sulfur dioxide and 2.5 g/Nm3 of ash, from 170 to 30° C
was attained with a water flow rate of 170-300 m3 /hr. The
cooling process was accompanied by absorption of sulfur
dioxide from the flue gas; on the average about 10% of the
sulfur dioxide was absorbed in the cooling water, giving a
sulfurous acid and salt concentration of 0.5 g/l. At a liquid
flow rate of 300 m3/hr, only 85% of the fly ash was
removed; increasing the rate to 460 m3/hr increased the
dust removal to 91%. Modification of the liquid distributor
gave 92-94% removal of the ash with a liquid flow rate of
250-280 m3/hr. The acidic water reacted with fly ash to
form ferrous and aluminum salts so that only about 20% of
61
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the absorbed sulfur dioxide was free acid. However, the
solution was acidic enough to cause corrosion problems.
Removal of 90% of the sulfur dioxide was achieved by
controlling the S/C mole ratio in the final scrubbing stage at
0.76-0.78. The solution from the first stage had an S/C
mole ratio of 0.95, indicating that about 90% of the sulfur
dioxide was in the bisulfite form. The absorption
coefficient averaged about 0.04 kg/m2/hr/mm Hg. Packing
volume in the three absorption stages totaled 300 m3 or
about 30,000m2.
Ammonia loss was slight, 7-8 kg/hr, mainly due to
carry-over from the top-stage entrainment separator.
Small-scale studies of ammonia scrubbing in packed
towers were made by Chertkov and Johnstone. Also,
packed absorbers are being used in the full-scale units being
operated in France and in Czechoslovakia. Design and
operating information on these units is not available except
that a spiral packing is used in the Czechoslovakian
absorber with gas rates up to 12 ft/sec.
Venturi Scrubber—Absorption of sulfur dioxide by
ammonium sulfite-bisulfite solution in a venturi scrubber
was studied in small-scale equipment by Volgin et al (91).
Apparently, dust-free simulated gas was used. The scrubber
throat was either rectangular with a 10- by 15-mm cross
section and a length of 13-mm or round with a 20-mm
diameter and a length of 10 mm.
In experiments carried out at a constant gas velocity of
30 m/sec in the throat and a solution with S/C mole ratio
of about 0.81, absorption remained relatively constant for
low concentrations of sulfur dioxide in the inlet gas
(0.14-0.6). At higher concentrations, beyond the levels
encountered in power plant stack gas, the absorption
efficiency decreased sharply.
The effect of hydraulic conditions on degree of
absorption is shown in figure 26. The inlet gas
concentration was not stated. The percent absorption as a
function of hydraulic conditions was expressed as:
.absorption = 8.54w°'42 q°'27
where, w = gas flow rate, m/sec
q = liquid flow, 1/m3
(44)
Pressure drop was related to hydraulic conditions as
shown in figure 27. During the tests to generate these data,
the concentration of sulfur dioxide in the gas was 0.34%
and S/C in solution was 0.83.
The high gas velocity in the throat and high absorbent
flow rates required for a high degree of sulfur dioxide
removal make a single-stage venturi scrubber economically
unsuitable in comparison with packed- and bubble-type
apparatus. The very short time of contact between gas and
liquid (0.004 sec at 25 m/sec) is not enough for the
diffusion and liquid circulation necessary to move the gas
molecules into the interior of the drops. The gas
accumulates on the surface of the drops so that the external
portion of the drop, the area that "sees" the gas, has a
higher concentration of sulfur dioxide than the bulk of the
liquid. The driving force for absorption is therefore
reduced. When the drops are collected, the concentration of
sulfur dioxide in the liquid is lower than it was on the
surface of the drops. If this liquid is reintroduced into the
scrubber, the sulfur dioxide vapor pressure will be lower
above the new drop than it was at the final moment in the
preceding pass. The advisability of carrying out the
absorption in several stages is evident. Moreover, a series
arrangement of several scrubbers makes possible
counterflow of gas and liquid which increases the degree of
absorption.
The results of test by Volgin et al (91) on absorption in
a multistage apparatus are shown in figure 28. The gas
velocity was 30 m/sec, sulfur dioxide concentration was
1.1%, and S/C was 0.82.
Volgin's work indicates that multistage absorption in
venturi scrubbers is competitive with packed- and
bubble-type absorbers. The author cautioned, however, that
the data should be considered preliminary because of the
small scale of the apparatus.
Wetted Wall Absorber—Small-scale studies of sulfur
dioxide absorption in ammonium sulfite-bisulfite solutions
in a wetted-wall absorber were reported by Chertkov (11).
The primary objective of the work was to establish the
effect of initial gas-phase sulfur dioxide concentration on
mass transfer coefficients. A wetted-wall apparatus was
chosen for the work because the contact phases remain
constant and the flow rates can be controlled so that
absorption of sulfur dioxide causes a negligible change in
solution composition.
The gas mixture was prepared by adding sulfur dioxide
to air and was introduced at the bottom of an absorption
tube 1.2 centimeters (cm) in diameter and 106 cm high
(active surface of 400 sq cm). The absorbing solution was
fed through a liquid-seal, passed through the orifice of a
conical nozzle, an.d flowed over the edge of the absorption
tube. Thus the flow was countercurrent.
The results of tests, with sulfur dioxide concentrations in
the inlet gas varying from 0.08-2.0% are shown in figure 29.
The tests were carried out at a gas rate of 7 1/min (velocity,
1 m/sec), a solution flow rate of 75 ml/min [2 l/(min)
(linear m) of tube perimeter], and a temperature of
21-25° C. The composition of the absorbing solution was:
Total NH3, moles/1
Effective NH3 (as sulfite and
bisulfite), moles/1
SO2 (as sulfite and bisulfite),
moles/1 .
7.8-8.2
4.6-4.7
3.70-3.75
62
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100,
90 _
80 -
70 _
60 _
10
o 50
40
30
10
1. w = 25 m/sec
2. w = 30 m/sec
3. w = 40 m/sec
4. w = 60 m/sec
10
15
q, t/cu m
Figure 26. SO2 Absorption in a Venturi Scrubber as a Function of
Flow Rate of Absorbent for Various Gas Velocities (w) in the
Scrubber Throat (91)
SO2 :NH3 (effective) mole ratio
(NH4)2SO4, moles/1
(NH4)2S203, moles/1
Solution density, kg/1
0.8
1.4-1.5
0.1-0.2
1.26-1.28
The equilibrium sulfur dioxide pressure over a solution of
this composition was 0.19-0.23 mm mercury, which
corresponds to a sulfur dioxide concentration in the gas
phase of 0.025-0.03% by volume.
The quantity of sulfur dioxide absorbed increased
linearly over the whole range as the sulfur dioxide gas
concentration increased. This indicates that the chemical
reactions between sulfur dioxide and the liquid phase do
not limit the overall sulfur dioxide solution process and
that the mass transfer coefficient does not depend on the
sulfur dioxide concentration in the gas phase. The
experimental values of mass transfer also confirm this since,
except at very low sulfur dioxide gas concentration
63
-------
approaching the equilibrium sulfur dioxide pressure over
the solution, the value for the coefficient was nearly
constant at about 10 moles/hr/m2.
Sieve Plate Absorber—The absorption of sulfur dioxide
from flue gas was studied by Chertkov and coworkers in a
laboratory absorber containing six perforated plates (7).
With a gas velocity of 1.5-2.4 m/sec, a total pressure drop
of 150-200 mm of water, and a temperatue of 30-33° C,
90% sulfur dioxide removal was achieved under foaming
conditions. Foaming on the plates was found to depend on
the ratio of gas velocity through the perforations to the
velocity through the scrubber column; narrow limits of the
ratio, between 5 and 6, were found necessary. The
absorption coefficient increased directly with resistance of
the solution layer on the plates.
A pilot plant designed to handle 10,000 m3/hr (5500
scfm) of flue gas was operated at a Moscow power plant to
study absorption of sulfur dioxide in ammonium
sulfite-bisulfite solution (12). The plant, shown in figure
30, was comprised of a six-stage perforated-plate absorber
constructed of aluminum with appropriate liquid and
gas-handling equipment. The tower was operated under
foaming conditions to produce a solution containing 9-10
moles ammonia/100 moles water and an S/C ratio of about
0.9. Approximately 90% sulfur dioxide removal was
achieved from inlet gas containing 0.3-0.4% sulfur dioxide.
Most of the fly ash in the inlet gas (concentration was not
given) was removed in the lower stages of the scrubber.
Pressure drop at a gas velocity of 1.5-2 m/sec in the total
cross section was 30-35 mm of water across one plate and
200-220 over the whole column.
The scrubber solution was not collected for recirculation
at each stage but flowed countercurrently to the gas from
plate to plate. The effect of inlet solution composition on
absorption coefficient is shown in table 9.
Operating conditions considered to be optimum were:
Linear gas rate, m/sec
In the total cross section
In perforations of grates
Scrubber hydraulic resistance,
mm H2O
Circulation of solution,
m3/m2-hr
Average solution temperature
in gratings, °C
Ratio of S02 :NH3effin solution
Entry
Exit
SO2 content in flue gas, % total
Entry
Exit
Degree of SO2 recovery, %
1.70
10.0
186
2.60
32.0
0.809
0.900
0.358
0.041
88.5
100
80
60
* 40
09
g
W.
c*
20
10
= 0.25 I/sec
40
w = 60 m/sec
w = 25 m/sec
q = liquor rate
w = gas velocity
. I
20
30 40
60 80 100
A P, mm H2O
200
400
600 800
Figure 27. SO2 Absorption as a Function of Pressure
Drop in Scrubber (91)
64
-------
100,
100
200
Power consumption, kwh
Figure 28. SO2 Absorption as a Function of Total
Consumption of Electric Power in a Multistage Venturi
Arrangement (the curve number corresponds to the number
of stages; pump pressure: 40 mm H2 0) (91)
Average coefficient of absorption
moles SO2
'm2-hr-%SO2
kgS02
' m -hr-mm Hg
1780
21.2
Major Alternatives
The equipment required for the ammonia scrubbing
process can be divided into three major categories:
1. Gas scrubbing and reheat
2. Conversion of the scrubber solution to ammonium
sulfate
3. Use of ammonium sulfate in production of fertilizer
Several alternatives were considered in selection of
equipment type for category 1. For the other categories the
specific process selected dictated choice of equipment.
Gas Scabbing—A study of scrubber types was made
on the basis of information from plant visits, scrubber
consultants, scrubbers vendors, and literature sources.
65
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A scrubber for use in an ammonia scrubbing process
should have the following characteristics:
1. Minimum pressure drop (12 in of water or less at 90%
SO2 absorption).
2. High efficiency for removal of sulfur dioxide (at least
90%) and particulates (minimum, 99.5%).
3. Minimum oxidation of sulfite to sulfate (important
for process B only).
4. Resistance to plugging by solids removed from the
gas stream.
5. A high turndown ratio (ratio of design volume rate to
minimum volume rate).
6. Provision for stagewise contact of gas and liquid and
for maintaining separate circulation of liquid streams in
each stage. This is considered to be the most important
single requirement as it is necessary in order to get good
sulfur dioxide absorption with minimum ammonia loss.
The following types of scrubbers were considered:
1. Packed
a. Countercurrent flow
b. Cocurrent flow
c. Crossflow
2. Sieve tray
a. Countercurrent with and without downcomers
b. Crossflow impingement plate with downcomers
3. Venturi
4. Spray
a. Cyclonic
b. Spray tower
5. Mobile-bed
6. Orifice
With no dust collection ahead of the scrubber (new
power plants), the dust loading will be about 7-9 grains/cu
ft. If a dust collector is used upstream of the scrubber
(existing power plants), the inlet dust loading is reduced to
about 1 grain/cu ft or less. Most scrubber designs will
effectively remove particles 10 microns in diameter or
12
8
fc sr
0)
1
CO O
o
CO
0.32
0.24
0.16
0.08
I
I
1
0.5 1.0 1.5
Inlet gasconcentration-S02, % by volume
Figure 29. Absorption of SO2 by Ammonium Sulf ite-Bisulf ite
Solution in Wetted Wall Absorber at Varying Concentrations of
SOj in the Inlet Gas (11)
2.0
66
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10
1. Gas conduit (500-mm diam)
.a 2. Disc damper
3. Bubble absorber
4. Solution input pipe
5. Diaphragm
6. Control valve
7. Blower
8. Exhaust pipe
9. Saturated-solution pipe
10. Pitot tube with micro ma no meter
Figure 30. Sieve-Plate Scrubber Tested by Chertkov et al (12)
a. Sampling of gas and
solution for analysis
t. Temperature measurement
p. Pressure measurement
67
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larger, but removal of smaller particles is necessary for good
plume appearance since about 30% of a typical fly ash is
less than 10 microns in size. A 100-g sample of this ash
would have approximately the following particle
distribution:
Particle size
microns3
0.5
1
2
3
4
5
6
7
8
9
10
20
30
40
50
70
100
+100b
Weight in fly
ash, g
0.13
0.37
1.5
2.5
3.5
1.5
3.5
3.5
4.5
4.0
5.0
20.0
12.0
8.0
8.0
9.0
3.0
10.0
Number of particles
8.1 X1011
2.9x 1011
1.5 x 1011
7.4 x 1010
4.3x 1010
9.5 x 109
12.9 xlO9
8.1 x109
7.0 x 109
4.4 x109
4.0 x109
2.0 x 109
3.5 x 10s
1.0x 10s
5.0 x 10 7
1.7 x107
2.4 x 106
2.9 x 106
aAssumes particles smaller than 0.5 micron ate 0.5 micron in
diameter, particles smaller than 1 micron and larger than 0.5 micron
are 1 micron in diameter, etc., to 100 microns.
"Assumes all +100-micron particles to be 150 microns in size.
A crossflow impingemen-t plate scrubber with three plates
and operating at a pressure drop of 6 in of water should
remove (according to manufacturer's claims):
Micron size
+20
20
10
5
4
3
2
1
0.5
Percent removal
100
99.8
99.5
98.6
98
97
96
93
85
This scrubber would remove 99.5% of the wt of dust but
only 89.5%. of the number of particles. Operation at a
higher pressure drop would result in a higher efficiency for
small particles (figure 31), but in most cases the added
expense probably would not be justified since removal of
99.5% (wt basis) by electrostatic precipitators is normally
adequate.
The volume of gas to be scrubbed is quite large; stack gas
flow rates for 200-, 500- and 1000-mw units are 533,000,
1,332,000, and 2,664,000 actual cubic feet per minute
(acfm), respectively, at 118°F, the estimated scrubber
exhaust temperature. To simplify gas distribution, the
number of scrubbers/boiler should be as small as possible.
Table 10 shows scrubber combinations for the three power
plant sizes. The turndown ratio for the scrubbers is based
on operation of the power plant at reduced load, as low as
30% of design. (A typical 200-mw unit has six coal
pulverizers and can be operated with as few as two of them,
giving a load of about 60 mw.) Only a limited number of
manufacturers are presently capable of supplying scrubbers
as large as those required; the turbulent bed and crossflow
impingement scrubbers are the only types available at this
time in sizes up to 500,000 cfm. However, scrubber sizes
offered are increasing as manufacturers work with the
problem. A venturi scrubber manufacturer has recently
offered a 450,000-acfm unit.
A comparison of different scrubber types is given in table
11, showing the dust-removal capabilities, pressure drop,
and turndown ratios of each. For staged operation it is
desirable to have all the stages in a single scrubber shell to
reduce investment, which is easier to accomplish for some
scrubbers than for others. The countercurrent sieve (with
downcomers) and crossflow sieve (figure 32) are the easiest
as the weir overflow from each tray, part of the basic
design, accomplishes the desired separation of liquor from
gas so that the liquor can be recirculated to the same stage.
For other scrubber types—countercurrent packed,
countercurrent sieve without downcomers, TCA mobile
bed, and Hydro-filter mobile bed—a special liquor
collection tray must be placed under each stage (figure 33).
Still other types—crossflow packed, cocurrent packed,
venturi, spray towers, and orifice—present special problems
in using liquor-collection trays.
Although any of these types might be adapted to staged
operation, it was considered that those requiring special
collection trays would have the disadvantage of extra
pressure drop introduced by the trays. Therefore, the sieve
tray types were favored. Chertkov obtained good operation
with a sieve plate absorber and his results appear to be as
good or better than those reported for other scrubber types
by other workers, although the data are difficult to
compare because of differing test conditions.
In regard to the two applicable sieve tray types, the sieve
tray with downcomers gives the required sulfur dioxide
absorption with a minimum pressure drop. The
impingement type of cross flow sieve has a higher
dust-removal efficiency, however, and is therefore
considered to be best suited to the ammonia scrubbing
process. Consequently, it was used as the basis for this
conceptual design study.
68
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Table 9. Variation of the Coefficient of Absorption with
Decrease in Chemical Capacity of the Absorbing Solution3 (12)
S02:NH3eff. in
the input soln.
0.78-0.82
0.28-0.84
0.84-0.86
0.88-0.90
0.90-0.92
0.92-0.96
NH3eff.. moles/
100 moles H20
10
10
8.8
7.6
7.3
5.7
Average soln.
temperature, °C
27
27
30
26
26
25
Average coefficient of
absorption K*, moles
S02/m2-hr-%S02
1620
1820
1320
970
635
200
aThe linear gas rate in the total cross section was 1.5 -2 m/sec.
TOO,
95
s
£ 90
85
80
4 8 12
A P, in. of water
Figure31. Collection efficiency3 for 1-Micron Particles in
Impingement-Type Scrubber
16
20
aData from W. W. Sly Manufacturing Company (Catalog 151).
69
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Table 10. Comparison of Scrubber Combinations
Plant
size,
mw
200
200
200
500
500
1,000
Assumed
number of
scrubbers
1
2
4
2
4
4
Design
capacity/
scrubber,
acfm
533,000
266,500
133,250
666,000
333,000
666,000
Gas flow
at maximum
turndown,
acfma
160,000
160,000
160,000
400,000
400,000
800,000
Volumetric turndown
ratio required
for each scrubber
in operation
3.33
1.67C
1.67C
1.67
1.67C
1.67C
Approximate
number of
scrubber
manufacturers'3
2
4
6
2
3
2
"Assuming scrubber system would be operated at a minimum capacity of 30% of design.
Presently known manufacturers for scrubbers of the sizes required.
°Turndown ratio required for each scrubber when using only one-half of the scrubbers at minimum system flow.
Mist Eliminators—The removal of liquid entrained in
the scrubber exit gas serves three purposes:
1. Reduces the load on the stack gas reheater.
2. Decreases the deposition of liquid in the fan and in
ducts located downstream from the scrubber.
3. Reduces amount of solids discharge by removing the
dissolved solids contained in the mist which, after
reheating, would be emitted to the atmosphere as dust.
The mist emitted by a wet scrubber would be comprised of
liquid particles ranging from about 10 microns to 60
microns in diameter; particles smaller than 10 microns
would not normally be produced unless water were
condensed from the flue gas. With no mist removal from
the scrubber exhaust, the gas would contain about 0.012 Ib
of entrained liquid/cu ft of gas. Use of a 95% efficient
demister would reduce the heat required for reheat by
about 3 million Btu/hr or about 4% of the total required
for reheat to 250° F.
The mist eliminator should have the following
characteristics:
1. A removal efficiency of at least 70% for 10-micron
liquid particles and an overall efficiency of about 95%;
above this the high capital cost is not justified by the
advantages.
2. The ability to flush (with the collected mist) any
undissolved solids collected in the separator.
Several types of mist eliminators were evaluated. The
simplest and most common is the impingement vane type,
the shape of the vanes and their arrangement cause
impaction and coalescence of the mist. Other types of
entrainment separators evaluated were the swirl vane, wire
mesh (York), fiber bed (Brink), cyclonic, and packed bed
(6-12 in of Tellerettes, Pall Rings, or others).
A comparison of the mist eliminators is shown in table
12. From this it appears that the vane types offer the
lowest investment and best plugging resistance at acceptable
pressure drops; overall removal efficiency should be about
95%. The Brink type is more efficient than justified for this
application. The wire mesh and packed-bed entrainment
separators could be used but should be equipped with a
means for flushing with fresh water to remove solids
collected on the mesh or packing. The cyclonic type (swirl
chamber or tangential scrubber outlet) would probably not
give an overall efficiency of 95%.
An impingement vane mist eliminator was selected for
use with the sieve plate scrubber in the conceptual design.
Equipment for Reheating Gas—Alternate methods
studied for reheat of the stack gas were:
1. Install a combustion system at the base of the power
plant stack for burning natural gas, oil, or coal and mix the
combustion products with the scrubber exit gas.
The main advantages for this method are low
investment, flexibility in degree of reheat, minimum added
pressure drop, low maintenance, and good reliability.
Disadvantages are fuel cost, introduction of objectionable
components (S03, SO2, ash) into the gas, and fuel supply
problems. Natural gas is the most expensive fuel but the
added cost might be justified on the basis of convenience
and clean combustion. However, gas would not be available
at many power plants. Oil would be less expensive but
receiving, storing, and handling would be a problem. Use of
coal would 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.
2. 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. As discussed in the limestone -
wet scrubbing study, however, bypass of the 310°F gas
from a point after the air heater increases ground-level
concentration rather than decreasing it. Bypass of gas from
70
-------
Gas out
S02 absorption stage
S02 absorption stage
S02 absorption stage
Dust removal stage
Liquor distributor
/\ /"\ /N
|— r~ r~ i— 1
iL
r-""1 f-^ r-^ r- I
L
"L
r-^ r-~ r-^ r~ 1
\/ \/ \/
n n n
Spray nozzles for gas
separation and initial
dust removal
Ammoniacal liquor
feed to 4th stage
Liquor to 4th stage
circulation system
Feed to 3d stage
Jo 3d stage
circulation system
Feed to 2d stage
To 2d stage
circulation system
Recirculated water
for dust removal
Water-dust slurry
to settling tank
Figure 32. Four-Stage Perforated Plate-Impingement Scrubber
with Separate Circulation of Liquor Streams
71
-------
upstream of the air heater would be more effective but this
would reduce boiler efficiency and possibly give rise to
problems in removing the dust.
3. Use 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
possibility of fouling—which would lead to low efficiency
and high maintenance cost. Corrosion by sulfur trioxide
would be a problem with mild steel exchangers.
4. Use 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.
The better heat transfer cofficient would permit use of
smaller exchangers than those required for gas-gas exchange
and the smaller surface would reduce pressure drop and
maintenance.
5. Heat with steam from the turbine cycle in a heat
exchanger at the scrubber outlet.
This method would require additional coal firing 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 the gas is relatively clean. Corrosion, fouling, and
pressure drop would be minimized. The main disadvantage
is the added fuel requirement.
6. Use 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;
Table 11. Scrubber Comparison
Scrubber type
Countercurrent
packed"
Cocurrent
packed"
Crossflow
packed11
Countercurrent
sieve
Usual
application
GA
GA
GA
GAand PR
Approx. maximum
inlet gas
dust loading,
gr/cu ft
1-2
2
3-4
10
Approx. dust-removal
efficiencies8
1-micron
particles
0
0
0
85
2-micron
particles
0
0
0
92
5-micron
particles
95
95
95
95
Approx.
pressure drop
for 90% S02
removal.
in. water'1
11
10
8
9
Suitable for
new power plants
without upstream
mechanical dust
collection
No
No
No
Yes
Approx.
turndown
ratio0
1.2
5.0
5.0
1.2
Crossflow
sieve (impinge-
ment type)
SF venturi
Splash plate
venturi
Cyclonic
spray
Spray tower
Mobile bed
Hydro-filter
Mobile bed TCA
Orifice
GA and PR
GAand PR3
GAandPR3
GAand PR3
GA and PRe
GA and PR
GA and PR
PR
100
+100
+100
15-20
15
25
25
25
93
97
97
30
20
92
92
35
96
99
99
70
60
98
98
75
98-99
99+
99+
94
90
99+
99+
93
9
24
24
10
12
26
13
24
Yes
Yes
Yes
No
No
Yes
Yes
No
1.2
1.3
2.0
2.0
4.0
1.5
1.5
1.2
aWhen operating at pressure drop required for 90% SOj removal.
''For process A (three absorption stages) and including 1 in of pressure drop for each liquor-collection tray, if required (see figure 33).
cRatio of design volume rate to minimum allowable volume rate.
^These scrubbers will not remove particles smaller than 3 microns unless nucleation is effected by condensing water vapoi.
eFor highly soluble gases only.
Key: E (Excellent), G (Good), F (Fair), NR (Not Recommended), GA (Gas Absorption), PR (Particulate Removal), Y (Yes), N (No), TJC
(Uncertain).
72
-------
Table 12. Comparison of Demisters
Tvoe
Impingement vane
Swirl vane
Wire mesh (York)b
Fiber bed (Brink)
Packed bedc
Cyclonic
Removal efficiency
for 10-micron
mist particles, %
70
70
98-99
100
90
60-70
Pressure
drop, in.
of water3
0.4
0.3
0.8
7.0
• 0.1-0.2
0.5-1.0
Approx. cost
for 200-mw
installation, $
3,500
3,000
12,000
75,000
9,000
5,000
Resistance
to solids
pluqqinq
Good
Good
Fair
Poor
Fair
Good
^Required for removal efficiency shown for 10-micron particles.
"Six in-thick bed.
in of packing.
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.
Insufficient information is available to prepare a cost
estimate on this reheat method.
Based on the cost comparison shown below, the
cyclic-liquid heat exchange method of-reheat was chosen.
scrubber to neutralize sulfur trioxide absorbed on the
dust-removal tray. A bypass duct would be provided around
each scrubber to permit shutdown of a scrubber for
inspection, cleaning, or maintenance.
For an existing power plant, the scrubbing system would
serve the primary function of sulfur dioxide absorption and
a secondary function of final dust removal subsequent to
dust removal by mechanical collectors.
From English and Van Winkle (31), plate efficiencies for
sulfur dioxide and ammonia were estimated using solution
viscosities and densities derived from Chertkov and
Pekareva (21) and Tans (78). Vapor pressure data were
calculated for ranges of ammonium ion concentration and
sulfite-bisulfite mole ratio using the formulas of West (94).
Vapor-liquid concentration lines were plotted from these
data and in conjunction with the efficiencies, calculations
Technique3
Direct, natural gas
Indirect, liquid-gas
Indirect, gas-gas
Indirect, steam-gas
Direct, coal stoker
Fuel,$
247,000b
_c
_c
147,600d
109,200e
Fan and
power, $
3,100
31,000
55,000
14,000
3,400
Labor,
maintenance
& overhead, $
5,300
23,000
64,200
16,800
31,000
Capital
charges, $
38,400
131,200
333,000
60,900
65,200
Total, $
293,800
185,200
452,200
247,300
208,800
$/ton
coal
burned
0.49
0.31
0.75
0.41
0.35
Reheat
invest., $
265,000
905,000
2,300,000
420,000
450,000
a200-mw power plant; reheat to 250° F; 440 M scfh.
"Natural gas at $0.40/MM Btu.
^Indirect liquid-gas and gas-gas utilize waste heat in exhaust gases.
dSteam at S0.30/MM Btu from 200-mw plant designed for excess process
eCoal at $0.20/MM Btu.
Equipment Description
Gas Scrubbing and Reheat—For a new power plant, the
scrubbing system would serve the dual function of
particulate removal and sulfur dioxide absorption. In an
impingement plate scrubber, about 99.0% of the
particulates would be removed on the first tray, with
recirculating water used as the scrubbing medium.
Ammonia would be added to the stack gas upstream of the
steam.
were made to determine both the number of plates required
for 90% absorption of sulfur dioxide and the resulting loss
of ammonia. The results indicate that, for processes A and
C, three absorption stages would be required to remove
90% of the sulfur dioxide. For process B, four absorption
stages would be needed to remove 90% of the sulfur
dioxide and maintain a maximum content of ammonium
bisulfite in the effluent liquor from the lower stage.
The validity of the estimated tray efficiencies was tested
by developing a mass transfer model from the experimental
73
-------
Gas out
SO2 absorption stage
SO2 absorption stage
S02 absorption stage
Liquid collection tray
Dust removal
Stack gas in
Liquor distributor
7N
\
7\
TV
\
Ammoniacal liquor
feed to 4th stage
Liquor to 4th stage
circulation system
Feed to 3d stage
Jo 3d stage
circulation system
Feed to 2d stage
To 2d stage
circulation system
Recirculated water
for dust removal
Water-dust slurry
to settling tank
Figure 33. Four-Stage Scrubber with Gas-Liquid Separation
Plates Under SO2 Absorption Stages
74
-------
data of Chertkov. As a first consideration, Oiertkov (24)
indicated that the liquid-phase resistance begins to have an
effect on the mass transfer rate when the pH drops below
5.5-6.0 or the S02:NH3 ratio is in the range of 0.7-0.83.
Estimated solution compositions are shown in table 13.
Two trays for the process A and C scrubbers and all of the
trays for the process B scrubber are in the above pH range.
In 1959 Cherktov (12) reported the effect of S02:NH3
ratio on tray efficiency at constant gas velocity and nearly
constant temperature. It was assumed that the partial
pressure of sulfur dioxide in the gas phase and the liquid
rates were held essentially constant. A transfer model was
developed on the assumption that the mechanism for
absorption is as follows:
1. Solution of sulfur dioxide in water
2. Diffusion of sulfur dioxide to ammonia interface
3. Diffusion of ammonia to sulfur dioxide interface
4. Reaction
•
A two-film mechanism was used as the statistical
representation of the performance:
K' =
1
(45)
m
where
= f [(Us - Uc) iV ]
= superficial velocity
= minimum tray velocity
= liquid rate
Us
Uc
L
m = slope of equilibrium line
and
T =
q
Cai
L =
f> l (q) f» 1 > (Cai) fiv (L)
= temperature
= excess ammonia
= concentration of sulfur dioxide in solution
in equilibrium with sulfur dioxide in vapor
= liquid rate
Since kL a n "• and M (viscosity) for a water solution is
proportional to exponent (-0.02 T), the function e'nT is
e-o.oi X jj^e k^ value is a function of L and because of
tray traverse and weir overflow the effect of L will range in
the exponential value of -1/3 to +1/3. The values for Cai
and m were taken from the equilibrium compositions of the
S02-NH3-H20 system. Data from Chertkov (12) were used
in a regression analysis to define the best fit equation:
K' = 1 (46)
0.00846 + 0.00044 m
Cai
;0.7S
(Ug-0.5) 2q (1-6-1.4 q) e°-olT
Conversion of K' values to efficiencies was based on the
relationship:
1 - Eog = exp"
9m
(47)
where E0g = removal efficiency
P = tower pressure
Z = tower height
0 = residence time
NOg = number of transfer units
The conversion constants were calculated from the
Chertkov data (12) with the assumption that solution on a
tray is totally mixed.
Tray efficiencies were established from the relationship:
_ P inlet - P outlet
-
(48)
P inlet - P*
where P = partial pressure of solute gas
P* = partial pressure of gas in equilibrium with
liquor
Values for N0g were calculated and Us NOg was plotted vs
K' (figure 34). The following equation is a good
approximation of the curve.
Us Nog = 0.00192 K'+1.35
Tray efficiencies were then calculated as follows:
(49)
Table 13. Tray Composition Conditions
Process
scheme
A-C
A-C
A-C
B
B
B
B
Plate
2
3
4
2
3
4
5
(NH4}2S03,
g/mole
0.1402
0.0317
0.01035
0.0964
0.0714
0.0386
0.01525
NH4HS03,
g/mole
0.1668
0.0429
0.01 635
0.2285
0.1361
0.0613
0.02044
NH3,
g/mole
0.4472
0.1063
0.03705
0.4113
0.2789
0.1385
0.05094
SO 2,
g/mole
0.3070
0.0746
0.0267
0.3249
0.2075
0.0999
0.03569
S02:NH3,
mole ratio
0.687
0.702
0.720
0.79
0.744
0.721
0.70
H20,l
0.0496
0.0877
0.0956
0.0475
0.0662
0.0837
0.0941
75
-------
I
I
2 _
500
600
2000 2100
Figure 34. Relationship of Nog and K', Based on Chertkov Data for
Sieve Tray Absorption of SO2 in NH,-SO2 H2O Solution
-------
1. q, Cai, T and Us were established for each tray.
2. K' was calculated from the above semiemperical
equation based on Chertkov data.
3. Us NOg was calculated using the linear relationship
with K1.
4. E0g was determined by conversion of the Nog values.
The predicted tray efficiencies are shown in table 14, Based
on these results, the design is adequate.
The assumed 500-mw power plant would be fitted with
four recovery trains (one scrubber to each train). A typical
plot plan for the plant is shown in figure Y69-A-10 in
Appendix C. A plan and elevation view of the system are
shown in figures Y69-A-8 and Y69-A-9, respectively, also in
Appendix C. Each of the four scrubbers would handle
333,000 acf of gas at 118° F and full power plant load. The
units are four-plate (processes A and C) or five-plate
(process B), countercurrent Impinjet gas scrubbers
manufactured by the W. W. Sly Manufacturing Company
(figure 35). Each scrubber has a 20- by 40-ft rectangular
cross section, is 27 (processes A and C) or 30 (process B) ft
high, and is constructed of mild steel internally coated with
a coal tar epoxy resin.
Internal impingement baffle plates and spray assemblies
are of stainless steel construction. The perforated
impingement plates have holes about 0.1 in in diameter on
about 3/16-in centers. They are installed in a stepdown
design to minimize the liquid gradient. The scrubbers are
designed for 9-in (processes A and C) or 11-1/4-in (process
B) pressure drop with an L/G volume ratio of 2 (gal/1000
acf) on each tray. At reduced load, one or more of the
scrubbers will be shut down by closing a louvered-type
damper installed at the scrubber inlet.
The absorption stages have common recirculation tanks
for each pair of scrubbers. For processes A and C, six tanks
are required and for process B, eight tanks. Each tank has
an operating capacity of 5000 gal and is 10 ft in diameter
by 7 ft high. The settling tank, which collects fly ash slurry
from all four scrubbers is 15 ft in diameter by 7 ft high, has
an operating capacity of 10,000 gal, and is equipped with a
cone bottom for discharge of solids from the system
through a variable-speed pump. The system is designed for
12% solids in the ash slurry to the pond. Scrubber liquor
Table 14. Estimated Tray Efficiencies
Tray
A-C-2
A-C-3
A-C-4
B-2
B-3
B-4
B-5
K'
520
1,040
800
930
1,130
1,140
1,070
UsNoa
1.4
2.6
2.1
2.4
2.8
2.8
2.7
Nog
0.94
1.73
1.4
1.6
1.86
1.86
1.8
e'Nog
0.4
0.18
0.25
0.2
0,16
0.16
0.17
Eoa,%
55
82
75
80
84
84
83
circulating pumps deliver 680 gal/min split between each
pair of upper plates. The recirculation pump for the settling
tank delivers 765 gal/min. Installed spares are provided.
Monitors for measuring pH are installed in the circulation
tanks.
The gas is reheated by mild steel, finned-tube heat
exchangers installed in the ductwork on each side of each
scrubber. The tubes have an outside diameter of 2 in and
3Mn fins spaced five/in. Based on a coefficient of 8
Btu/hr/sq ft, 197,000 sq ft of surface area is required. The
tubes are 20 ft long and are arranged in 11- by 16-ft tube
bundles.
As mentioned earlier, a small amount of ammonia is
added to the gas stream before the cooler to react with the
sulfur tri oxide in the gas stream and thereby prevent
sulfuric acid corrosion.
Circulating water (treated boiler water) at a rate of 710
gal/min is used to transport heat from one exchanger to the
other. In a cold climate, antifreeze should be added for
periods when the system is shut down. The design
temperature profile is:
Heat removal,'
Gas
liquid
Reheat, °F
Gas
Liquid
310-172
143-280
115-250
280-143
Conversion of Scrubber Solution to Ammonium
Sulfdte—For processes A and C, the scrubber solution is
oxidized to convert the sulfite to sulfate for further use.
Since oxidation in the scrubber is desirable, a packed
scrubber would be a better choice than a sieve plate type to
improve the oxygen:sulfur dioxide absorption ratio.
However, even if an oxidation promoter were used,
complete conversion would be difficult to achieve and
further treatment would probably be necessary. Moreover,
residual dust in the scrubber solution would be a problem
in operating packed scrubbers because of tendency to
plugging. The most practical approach appears to be
provision of a scrubber for effective dust and sulfur dioxide
removal and to carry out the oxidation as a separate step.
The JECCO method (43) was selected as the basis for
design of the oxidizing system. Sufficient information was
obtained for preparation of capital and operating cost
estimates but details were not made available. It is assumed
that a firm design could be provided on a fee basis by
JECCO.
Before oxidation, the ammonium bisulfite in the
scrubber effluent is converted to ammonium sulfite by
addition of ammonia in a neutralizer. Conversion is
necessary to prevent loss of sulfur dioxide during oxidation.
The neutralizer is a lined, mild steel vessel 6-H ft in
77
-------
Figure 35. Typical Sly Impinjet Scrubber
78
-------
diameter and 10 ft high with dished head and bottom.
Ammonia is added through spargers in the bottom. The
vessel is vented to a point upstream of the scrubbers to
recover ammonia in the off-gas. The salt concentration in
the solution is adjusted to 40% to prevent crystallization of
ammonium sulfate in the oxidizer.
The stream is s^lit to two parallel oxidizers comprised of
stainless steel pressure vessels 7 ft in diameter by 32 ft high
with dished heads and bottoms. Air is introduced through
mechanical atomizers into the solution, which is maintained
under a pressure of 100 psig. Air is supplied to each vessel
by 6300 scfm centrifugal compressors with
1500-horsepower drives. Heat of reaction is removed by
circulation of the solution through a 3000-sq-ft
water-cooled exchanger to maintain a temperature of
185°F. Temperature control is required to improve
solubility of oxygen.
It was assumed that the oxidizer would be located
adjacent to the scrubber and that the ammonium sulfate
solution would be pumped to surge storage at the fertilizer
production facilities in a separate area.
For process B, oxidation in the scrubber should be
minimized because sulfate formation reduces the amount of
sulfur dioxide which can be recovered by acidulation of the
scrubber effluent. The sieve plate scrubber should provide
conditions for a low degree of oxidation; 10% conversion to
sulfate in the scrubber was assumed. A high degree of
conversion of ammonium sulfite to bisulfite should be
achieved by recirculation of scrubber liquor around the
bottom stage of the scrubber where sulfite will be exposed
to the maximum sulfur dioxide concentration in the gas.
For design of the decomposition and stripping processes
an S02 :NH3 ratio of 0.72 was assumed.
Sulfuric acid (93%) is reacted with the scrubber effluent
in a stainless steel sieve plate column 1-% ft in diameter by
20 ft high. Liberated sulfur dioxide is stripped from the
solution by passing air through the liquid on the plates; air
is provided at a rate of 4800 scfm by a centrifugal blower.
The sulfur dioxide-air mixture (30% SO2) evolved from
the stripping column is processed in a standard contact
sulfuric acid plant, except that no sulfur burner is needed.
Approximately 7500 scfm of gas is treated to produce
about 400 tons/day of acid; two-thirds of the production is
consumed in the acidification step and the remaining third
is transferred to the fertilizer plant. Storage for 2 days' of
acid pioduction is provided.
The solution from the stripping column is essentially a
45% solution of ammonium sulfate with less than 0.5 g/1 of
sulfur dioxide. It is pumped at a rate of 112 gal/min (15
tons/day of ammonium sulfate) to the fertilizer process.
Decomposition of Ammonium Sulfate (Process C)—In
processes A and B, the ammonium sulfate is used directly as
a 40% solution in the fertilizer process. In process C,
further treatment of the liquor is necessary. The solution is
concentrated and ammonium sulfate crystallized in a
double-effect vacuum evaporator-crystallizer. The crystals
are separated in a continuous centrifuge and the liquid
phase returned to the evaporator. Damp crystals are fed by
a screw conveyor into a two-stage submerged combustion
vessel where the ammonium sulfate is decomposed at a
temperature of 700° F; a retention time of 1 hr is required.
Ammonia in the exhaust gas is removed by scrubbing and
recycled. The ammonium bisulfate, a melt at
decomposition temperature, is quenched and dissolved in
water in an insulated tank equipped with an agitator. The
hot (220° F) ammonium bisulfate liquor is pumped to an
extractor where it is used instead of nitric or sulfuric acid
for digestion of phosphate rock.
Raw Material Storage—The primary raw materials are
ammonia and phosphate rock. Ammonia is received in
railroad cars in liquid form and stored in an insulated,
atmospheric pressure tank (at -28° F). A 3-week supply is
provided, amounting to the following quantities (for the
500-mw unit and 3.5% S coal assumed):
1. Process A - 8000 tons
2. Process B - 5500 tons
3. Process C - 4500 tons
Phosphate rock is received in railroad cars and stored in a
bin in the extraction unit. About 2 days' storage is
provided.
Nitric Acid Production—The nitric acid requirements
for processes A and B are produced from ammonia in a
standard commercial plant designed to produce 60% acid.
Product storage capacity for 2 days' production is provided.
Acidulation, Precipitation, and Filtration—The primary
function in acidulation is to react phosphate rock with an
acid to form a soluble fertilizer intermediate and insoluble
calcium sulfate (gypsum); the latter is removed by
filtration. The equipment required for this function and the
following fertilizer production steps is of standard design
and will not be described in detail. The flow scheme for this
unit varies with each of the three processes:
Process A—Phosphate rock is reacted with nitric acid to
form calcium nitrate and phosphoric acid, both in
solution. Calcium nitrate is subsequently reacted with
ammonium sulfate (from the oxidizers) to form a
solution of ammonium nitrate (with phosphoric acid and
water) and a precipitate of gypsum. The gypsum is
separated by filtration.
Process B—A portion of the rock is reacted with nitric
acid as in process A. Sulfuric acid is added in a second
79
-------
stage of rock extraction to complete the acidulation and
form phosphoric acid and gypsum. Calcium nitrate
formed in the first extraction stage is reacted with
ammonium sulfate as in process A. The filtrate (after
removal of gypsum) contains more phosphoric acid and
less ammonium nitrate than in process A.
Process C—Phosphate rock is acidulated with ammonium
bisulfate to form phosphoric acid and ammonium sulfate
in solution and a precipitate of gypsum that can be
removed by filtration.
Gypsum Disposal—The gypsum filter cake is sluiced in
the acidulation unit and pumped as a 20% slurry to a
gypsum disposal pond. The pond is sized to hold a 10-yr
supply of gypsum. For process A in a 500-mw power plant,
the pond is 1650 ft long and 1100 ft wide with dikes 50 ft
high. A seepage ditch encircles the pond and a portable
pump is used to return the seepage. The pond is equipped
with internal overflow weirs to control the level and collect
clarified water. This water is returned for sluicing gypsum.
Excess overflow is treated with lime to neutralize any acids.
Neutralization and Prilling (Processes A and B)—The
filtrate from the acidulation unit is neutralized by reacting
ammonia with phosphoric acid to attain an NH3:H3PO4
mole ratio of about 1.37. The neutralized stream is pumped
to a falling-film evaporator for concentration to about a
99.5-99.7% melt. The melt is sprayed into the top of an
induced draft prilling tower where it falls through an
upward flow of air. The resulting prills are subsequently
cooled and screened with the product size going to storage
and the oversize and undersize sent back to the
concentrator as a solution. Air pollution abatement
facilities are included.
Granulation (Process C)—The granulation unit in
process C is similar to the drum ammoniator-granulator
commonly used in manufacture of diammonium phosphate.
Filtrate from the acidulation is neutralized to an
NH3:H3P04-mole ratio of about 1.37 and fed to the
granulator. Additional ammonia is added to raise the mole
ratio to about 1.8. The solids from the granulator are dried
and screened, the product-size material is cooled and sent
to storage, and the oversize solids are crushed and recycled
to the granulator along with undersize. Some product size is
recycled as required to control the granulation step. Air
pollution abatement facilities are provided.
Fertilizer Storage and Shipping—Product storage is
provided for 90 days of production. For process A in a
500-mw plant, the storage building holds about 60,000
tons. The building is 110 ft wide and 830 ft long with
10-ft-high concrete walls. The floor is concrete and the
upper siding and roof is transite attached to a steel
framework. Fertilizer solids are distributed in the building
by an 800-ft tripper-conveyor.
Fertilizer is removed from the building with a payloader
and fed to the bulk shipping building. The solids are
screened and the oversized crushed and rescreened prior to
shipment by railroad cars. The shipping rate is 300 tons/hr.
Car pullers are used to move railroad cars to the loading
station and railroad scale.
80
-------
INVESTMENT AND OPERATING COST
Unit size
200-mw
Process
A
B
C
Limestone -
wet scrubbing
$(M)
12,520
11,428
9,589
2,610
$/kw
62.6
57.1
47.9
13.1
500
$(M)
22,320
20,191
17,329
5,425
•mw
$/kw
44.6
40.4
34.6
10.8
1,000
$(M)
36,550
32,904
26,646
8,210
-mw
$/kw
36.5
32.9
26.6
8.2
a3.5% sulfur in coal.
Unit size, mw
200
500
500
500
500
1,000
1,000
Status
Existing
New
New
Existing
New
New
Existing
Sulfur content
of coal, %
3.5
2.0
3.5
3.5
5.0
3.5
3.5
Based on the design assumptions and equipment selected, Table 15. Total Fixed Investment of Ammoma Scrubbing-Fertilizer
investment and operating cost estimates were made for
several different combinations of the more important
variables.
Investment
Estimates were prepared for seven different
combinations of the three major variables that affect
investment—power unit size, power unit status (new or
existing), and sulfur content of coal.
and process C the least; however, it should be pointed out
that the amount of fertilizer produced is greatest with
process A and least with process C. The importance of this
can be seen only after full examination of the profitability
estimates given later, which take into account production
rate, net sales revenue, and operating cost.
In comparison with other recovery processes, the range
of $26.60-62.60/kw is quite high. The reason for this is that
a finished product is made rather than an intermediate such
as sulfuric acid, sulfur, or ammonium sulfate.
The overall fixed investments for installation in new
power plants are given in table 16. Also given is the
effective investment if credit is taken for eliminating
electrostatic precipitators that are normally installed (99%
efficiency assumed). Such a credit is based on the
assumption that the scrubbers will remove dust to an
acceptable degree.
The division of investment between the ammonia
scrubbing and fertilizer manufacturing portions of the
installations are shown in figures 36, 37, and 38. The
fertilizer portion requires much more investment than the
scrubbing section and accounts for most of the variation
between processes.
The sulfur content of the coal burned is also important
in investment requirement (figure 39). Doubling the sulfur
content (2-4%) increases total investment by about 30%.
Operating Cost
The estimating of operating cost was complicated by the
fact that, as discussed earlier, projects for sulfur dioxide
removal may be financed on different bases-the regulated
power industry basis, the unregulated chemical industry
practice, or a combination of the two. This has a major
effect on capital cost items such as depreciation and taxes.
Because of this, four estimates were made for each of the
The effect of plant size and process type on investment 21 combinations of plant size, power unit status, sulfur
is summarized in table 15 (for existing plants and 3.5% content of coal, and process type. The four covered the
sulfur in coal). Process A requires the largest investment following:
Each of the seven combinations was estimated for processes
A, B, and C, making a total of 21 investment estimates;
these are given as tables B-l—B-21 in Appendix B.
Operating life of the new units is assumed to be 35 yrs.
Remaining life of the existing units is considered to be 27
yrs for the 200-mw units and 32 yrs for the 500- and
1000-mw sizes.
The estimates are based on vendor quotations and
authoritative publications. The process equipment costs
were first determined and installation expense then added
to yield the direct installed costs. Utilities distribution, but
not generation facilities, was included. Indirect costs,
including estimated contractor fees, overhead, engineering
design, and arbitrary contingency, were then calculated
according to the following schedule.
Indirect investment costs,
percentage of direct installed cost
500-mw
Engineering design
Contractor fees
and overhead
Contingency
Total
200-mw
existing unit
10
15
10
35
Existing
unit
10
15
10
35
New
unit
8
12
10
30
1,000-mw
Existing
unit
8
12
10
30
New
unit
7
10
8
25
81
-------
40
o
•o
o
c
0)
4-J
V)
0)
>
c
'i
X
30
20
10
28-14-0 fertilizer manufactured
3.5% S in coal
Existing units
New units
200
400 600
Power unit size, mw
800
1000
1200
Figure 36. Effect of Power Unit Size on Ammonia Scrubbing •
Fertilizer Plant Investment (process A)
Table 16. Total Fixed Investment of Ammonia Scrubbing-Fertilizer
Manufacturing Facilities for New Power Plants8
500
•mw
Unit
size
1 ,000-mw
After precipi-
Actual
Process
A
B
C
Limestone -
wet scrubbing
$(M)
21,470
19,689
1 6,357
5,135
$/kw
42.9
39.4
33.1
10.3
tator credit
$(M)
20,565
18,784
15,452
4,230
$/kw
41.1
37.5
30.9
8.5
Actual
$(M)
34,500
31,000
24,639
7,620
$/kw
34.5
31.0
24.6
7.6
After precipi-
tator credit
$(M)
32,950
29,450
23,089
6,070
$/kw
32.9
29.5
23.1
6.1
a3.5% sulfur in coal.
82
-------
40
o
T3
O
C
tu
+^
CO
•It
>
C
30
20
10
T
26-19-0 fertilizer manufactured
3.5% S in coal
Existing units
— New units
200
400 600
Power unit size, mw
800
1000
1200
Figure 37. Effect of Power Unit Size on Ammonia Scrubbing •
Fertilizer Plant Investment (process 6)
1. Power industry financing
2. Chemical industry financing
3. Joint venture: power company portion
4. Joint venture: chemical company portion
Thus the total number of operating cost estimates was
84. These are given in tables B-22-B-105 in Appendix B.
For power industry financing (regulated utility-type
economics), the usual practice was followed of including in
the capital charges the regulated return on investment. A
breakdown of the capital charges is given in table 17. The
depreciation rate is 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 insurance are also based on original fixed
investment. However, because most regulatory commissions
base the annual permissible 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 debt, and income
taxes are established in such a manner. In this study, the
cost of money to the power industry is assumed to be 8%
interest on borrowed money and 12% return on equity
money to attract investors. Assuming a capital structure of
50% debt-50% equity, the overall cost of money under
regulated economics comes to 10%. Federal income taxes
are assumed to be 50% of gross income or equivalent to the
return on equity. State income tax was 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 (32, 33).
83
-------
o
T5
O
~
£
19-14-0 fertilizer manufactured
3.5% Sin. coal
200
400
600
Power unit size, mw
800
1000
1200
Figure 38. Effect of Power Unit Size on Ammonia Scrubbing
Fertilizer Plant Investment (process C)
40
o
-a
o
500-mw new units
Process A -A
Process B - a
Process C - o
Limestone - wet scrubbing - x
30
>
•5 20
I
10
cj
(0
a
O)
60 ••=
CO
01
C
40
c
Q)
4-<
tSI
i
c
-o
0)
X
20
-X-
I
I
1234
Sulfur in coal, %
Figure 39. Effect of Sulfur Content of Coal on Total Fixed Investment
84
-------
There are, of course, methods available to express the
declining annual capital charge as a fixed annual percentage
of original investment (for example, a single uniform series
charge made up of sinking fund depreciation plus interest
or capital recovery factor). On a present worth basis
(recognizing the time value of money), the declining and
the uniform annual capital charges are equivalent. An
average annual charge was used for the operating cost
estimates given in Appendix B; such a treatment is useful
for direct comparisons. However, for the profitability
estimates given later, the calculations were based on
declining capital charges so that actual annual cash flows
could be determined.
For chemical industry financing (unregulated
economics), the only capital charges applied aie
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 unregulated economics basis (10%), which is
commonly used in the industry, is much higher than for
regulated economics (2.85%).
Using different bases for the estimates is confusing but
seemed necessary as these are the approaches that are
actually used in practice. The basic difficulty is that the
regulated and unregulated bases cannot be compared in the
usual way. The fairly well assured return on investment for
the power company makes a low rate of depreciation
Table 17. Annual Capital Charges for Power
Industry Financing - New Power Unit with 35-yr Life
As percentage of
original investment
Depreciation (based on a 35-yr life of
a new power unit)
Interim replacements (equipment having
less than 35-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
2.85
0.75
0.50
4.10
As percentage
of outstanding
depreciation base3
4.00
6.00
6.00
4.80
20.80
acceptable, and return on investment can be logically
included in production cost because it is a fixed charge
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 a variable because it cannot be passed on to the customer
as a cost item.
Although the differing bases make comparisons between
operating cost estimates infeasible, there is no difficulty in
comparing economic promise, as will be seen later.
For joint ventures, such as operation of a scrubbing
system by the power company and regeneration of the
absorbent (with accompanying recovery of sulfur dioxide)
by a chemical firm, the power portion was estimated on the
regulated basis and the chemical company portion on the
basis of unregulated economics.3
The delivered costs of raw materials, such as ammonia,
phosphate rock, catalyst for production of nitric acid from
ammonia, antifoam and product conditioner, are based on
prices and freight rates considered to be likely over the next
several yrs. For the larger plant sizes and higher sulfur
content of the coal burned, price discounts and freight
savings are assumed for some materials due to the increased
volume and possibility of contractual agreements. Since the
projections used in this study cover as many as 35 yrs and it
is not possible to project raw material price changes for
such a period, it is assumed that as the raw material prices
change, so will the value of the product fertilizer.
Labor costs are based on current rates and are not
escalated over the life of the project. Labor cost will
certainly increase in the future but productivity increase in
the past generally has kept up with wage increase. Lacking
any better basis, it is assumed this relationship will
continue.
The costs of utilities depend on quantity and source.
The values used are fully allocated costs, as if purchased
from an independent source with full capital charges
included. For existing power plants, it was assumed that no
excess steam, water, or electricity would be available and
that new investment would be required; the new investment
is not included in that shown for the process since the unit
cost of the utility includes capital charges. For new power
plants, it was assumed that provision would be made in the
power plant design to furnish necessary utilities to the
process, but the capital charge is included in the unit cost
for this situation also.
aOriginal investment yet to be recovered or "written off."
This assumes that the loaded absorbent would be passed "across
the fence" to the chemical plant. .However, the intermediate could
also be collected from several power plants and processed in a large
central plant to reduce processing cost. This concept has already
been proposed by others and could have considerable potential;
however, because the evaluation of such a venture could depend
largely on the specific freight costs involved in shipping the
intermediate to the fertilizer plant (and perhaps back again), this
concept is considered outside the scope of generalized evaluation
used in the present study.
85
-------
Table 18. Lifetime Operating Costs for Ammonia Scrubbing Processes
in New 500- and 1,000-mw Power Units3 .
500
Total operating cost, $
Unit operating cost,0
$/ton of coal burned
500
10OP mw
Cooperative Economics
Process A 245,306,500 397,746,300 9.71
Process B 208,775,200 339,071,900 8.26
Process C 154,968,100 249,567,000 6.13
Regulated Economics
Process A 302,344,400 491,743,400 11.97
Process B 258,478,200 417,215,500 10.23
Process C 193,135,400 313,022,200 7.64
8.13
6.93
5.10
10.05
8.53
6.40
^Sulfur content of coal, 3.5%; yrs of operation, 35; operating factor (see text); no discounting of costs.
Average over life of unit.
Unit operating cost,L
$/ton of fertilizer
500 mw
41.85
47.06
59.97
51.58
58.27
74.74
1000 mw
Nonregulated Economics
Process A 225,007,500 367,961,000 8.91 7.52 38.38 3 .
Process B 186,562,500 306,231,000 7.38 6.26 42.06 3b./4
Process C 133,968,000 223,611,500 5.30 4.57 51.85 44.68
35.08
39.57
49.86
43.38
48.69
62.54
Alternate
limestone -
wet scrubbing
process
45,357,100
71,465,700
1.80
1 .46
For all the operating cost estimates given in Appendix B,
it is assumed that the fertilizer plant is sized to match the
total potential output of the power plant and operates
7000 hr/yr. Thus the estimates apply only to the early yrs
of power plant operation. Other estimates (not given in
detail) were made to take into account the declining
operating factor in the middle and later yrs of the power
plant life (three additional estimates for each of the 84
combinations). Thus the costs over the entire plant
operating life could be accumulated and the average
production cost estimated. The resulting estimates are
presented in table 18 for perspective and general interest
only, as direct comparisons can be misleading.
An advantage is indicated for process C in cost/ton of
coal but process A gives lower cost/ton of fertilizer. Both
tonnage of fertilizer produced and price obtainable for the
fertilizer must also be considered before any conclusions on
the comparative economics can be made. The main
conclusion from table 18 is that cost is far higher than for
limestone - wet scrubbing and therefore a major return
from sales is essential.
Comparisons between costs for early-life power plant
operation (7000 hr/yr; tables B-22-B-105 in Appendix B)
are given in figures 40-51. The effect of unit size for various
combinations of other variables is given in figures 40-44 and
the effect of sulfur content in figures 45 and 46. All these
are given only to show the general effect of the variables; as
for table 18, no conclusions can be drawn because of the
varying effect of income items, which are applied later in
the discussion of profitability.
Curves showing the effect of annual operating time on
operating cost are given in figures 47,48, and 49 for various
size power units. Unit costs/ton of fertilizer under the same
conditions are shown in figure 50 for process A. Increase in
operating stream time, of course, effects a major reduction
in unit operating cost.
86
-------
20
o
-o
15
2 10
I
7000 hr annual operation
3.5% S in coal
Process A - A
Process B - o
Process C - o
Existing units
New units —
200
400 600
Power unit size, mw
800
1000
1200
Figure 40. Effect of Power Unit Size on Annual Operating
Cost Under IMonregulated Economics
20
o
T3
§ 15
7000 hr annual operation
3.5% S in coal
Process A - A
Process B - a
Process C - o
Existing units
New units
10
200
400 600
Power unit size, mw
800
1000
1200
Figure 41. Effect of Power Unit Size on Annual Operating
Cost Under Cooperative Economics
87
-------
20
o
T3
O
15
01
c
I
0)
Q.
O
« 10
13
2
I
r
7000 hr annual operation
3.5% S in coal
Process A - A
Process B -
Process C -
Existing units
New units ---
200
_L
400 600 800
Power unit size, mw
1000
Figure 42. Effect of Power Unit Size on Average Annual Operating
Cost Under Regulated Economics
1200
80
60
c
o
O)
c
E 40
£
o
a
c
D
20
Existing units
7000 hr annual operation
3.5% S in coal
1
Process A - A
Process B - n
Process C - o
200
400 600
Power unit size, mw
800
1000
1200
Figure 43. Effect of Power Unit Size on Operating Cost/Ton of
Fertilizer Under Regulated Economics
-------
20
8.0
15
J3
O
Existing units
7000 hr annual operation
3.5% S in coal
Process A
Process B
Process C
Limestone
A
a
o
- wet scrubbing - x
10
o
I 5
6.0
4.0 8
en
c
V*
ro
k.
o>
Q.
O
c
D
2.0
•*•
•*-
I
•*•
200
400 600
Power unit size, mw
800
1000
1200
Figure 44. Effect of Power Unit Size on Operating Cost/Ton of
Coal Under Regulated Economics
20
:
Cooperative economics Process A -
500-mw new units Process B -
7000 hr annual operation Process C -
JS 15
o
•o
Z 10
8
a>
c
Sulfur in coal, %
Figure 45. Effect of Sulfur Content of Coal on Annual Operating
Cost Under Cooperative Economics
89
-------
80
t
£
5
I
c
3
60
Cooperative economics
500-mw new units
7000 hr annual operatic!?
40
Process A - A
Process B - D
Process C - °
20
Sulfur in coal, %
Figure 46. Effect of Sulfur Content of Coal on Unit Operating
Cost Under Cooperative Economics
90
20
_ro
"5
O
O)
c
O
"ro
15
! " "~" i
Cooperative economics
28-14-0 fertilizer manufacture
I
I
1500
3000 4500
Annual operating time, hr
6000
7500
Figure 47. Effect of Process Operating Time on
Annual Operating Cost (process A)
-------
20
15
o
•a
o
8
C
"-t-j
(O
i_
&
o
"ro
c
10
i s
Cooperative economics
26-19-0 fertilizer manufacture
1500 3000 4500
Annual operating time, hr
Figure 48. Effect of Process Operating Time on
Annual Operating Cost (process B)
6000
7500
o
-a
o
8
c
Cooperative economics
Process C—Ammonia scrubbing
19-14-0 fertilizer manufacture
1500 3000 4500
Annual operating time, hr
Figure 49. Effect of Process Operating Time on
Annual Operating Cost (process C)
6000
7500
91
-------
120
•5 80
c
o
o
40
5
Q.
O
vj
'c
=3
1500
Cooperative economics
Existing units
3.5% S in coal
Process A
28-14-0 fertilizer manufacture
3000 4500
Annual operating time, hr
6000
7500
Figure 50. Effect of Process Operating Time on
Unit Operating Cost
S 80
N
r
*
60
8
01
o
'c 40
20
T
Cooperative economics
Existing units
7000 hr annual operation
3.5% S in coal
Process A - A
Process B - n
Process C - o
Without credit for air pollution control
With credit for air pollution control —
I
I
200
400 600 800
Power unit size, mw
1000
1200
92
Figure 51. Effect of Credit for Air Pollution Control on
Unit Operating Cost
-------
PROFITABILITY AND ECONOMIC POTENTIAL
Having established investment and operating costs, the
next step is to determine profitability (plus or minus) of
the various process combinations and to relate this to
economic attractiveness as compared with other ways of
solving the pollution problem. This is a much more difficult
task as it requires estimation of net income from product
sale, and income can vary over a wide range depending on
several variables that cannot be evaluated accurately.
Net income depends not only on sales price but also on
production volume (which varies between the processes
considered), sales cost (which will likely be higher for a
power company than a chemical company), and shipping
cost (which varies with size of the sales area needed to
move the product). Much of this depends on the market
potential for the product; therefore a market study was
conducted as the first step in determining profitability.
MARKET STUDY
The end products of the processes considered differ
mainly in the ratio of the two plant nutrients
involved—nitrogen (N) and available phosphoric acid
(P205). In the order of decreasing nitrogen to phosphate
ratio, these products are 21-0-0, 28-14-0, 26-19-0, and
19-14-0 (% N-% P2O5-% K2O). The fact that the plant
nutrient ratios and contents differ complicates
determination of relative market price. Moreover, because
of the process complexities described earlier, the tonnages
of the various products differ considerably; for a 500-mw
plant burning coal containing 3.5% sulfur, 156,000;
304,000; 230,000; and 134,000 tons of the respective
grades above would be produced each yr. Thus, the size of
the market area required varies with each and affects
transportation costs. For example, the total amount of
nitrogen produced is 3.5 times as great for 28-14-0 as for
19-14-0. As a result, it is estimated that the market area
would be increased to the extent that average shipping cost
for 28-14-0 would be $7.00/ton of nutrient as compared
with $4.30 for 19-14-0.
Although transportation costs are the major source of
calculable variation, estimation of nutrient sales price is the
first order of business. An understanding of the basis for
pricing in the current market is necessary.
Fertilizer Industry Logistics
Present Market—Almost all fertilizers are produced
from some combination of four basic raw
materials— ammonia, phosphate rock, sulfuric acid, and
potassium chloride. Although significant quantities of
ammonia and sulfuric acid are produced as industrial
byproducts, the primary sources of these materials are
natural gas and elemental sulfur, respectively. The basic
logistical problems facing the U. S. fertilizer industry stem
from the fact that commercially minable sources of
phosphate rock, potassium chloride, sulfur, and natural gas
do not occur at the same location and do not all occur near
major end-use markets. Problems of collecting the basic raw
materials, processing them into the types of products
needed by farmers, and supplying them at the time of need
are complex.
The major source of phosphate rock is near Tampa,
Florida. The major source of sulfur is near the Gulf Coast
of Louisiana. These two materials are used to produce
phosphoric acid mainly along the gulf coast, in Florida, and
northern Illinois (figure 52). Many of the northern plants
use byproduct sulfuric acid. The phosphoric acid producers
supply the major portion of the phosphate fertilizer
markets by combining the acid with phosphate rock to
produce triple superphosphate (0-46-0) or with ammonia to
produce diammonium phosphate (18-46-0). The
distribution of the phosphates to domestic markets is
significantly influenced by barge transportation along the
inland waterway (figure 53); this alternative compels rail
rates which are much lower than they ordinarily would be.
An example of comparative rates is shown in table 19.
Ammonia is produced from natural gas in every major
consuming region. Recent technological developments in
large-scale production have caused a shift in location for
new production capacity to the Gulf Coast area where
low-cost gas is available (figure 54). Distribution of this
production to the midsection of the country is facilitated
by pipeline shipment (figure 55).
The present study does not involve the use of potassium
chloride because the products contain only nitrogen and
phosphate. As a matter of interest, potassium chloride is
Table 19. Phosphate Rock Transportation Cost Via
Rail and Barge From Tampa, Florida3
Method
of
delivery
Barge
Rail
Minimum
quantity,
tons/yr
140,000
120,000
100,000
80,000
60,000
40,000
-
Muscle
Shoals
5.28
5.75
5.95
6.15
6.35
6.55
6.75
7.65
East
St. Louis
4.78
6.50
6.70
6.90
7.10
7.30
7.50
8.40
Chicago
5.28
6.95
7.15
7.35
7.55
7.75
7.95
8.85
aRail rates reflect TVA Section 22 negotiations.
93
-------
i Furnace phosphoric acid
Wet process phosphoric acid
> New wet process phosphoric acid plant
Figure 52. Phosphoric Acid Plant Locations
mined in New Mexico and in Canada and shipped to the
point of use, normally by rail.
The fertilizer production pattern is somewhat complex.
Some plant nutrient requirements are met by direct
application of materials sometimes considered as
intermediates, such as ammonia, ammonium nitrate, and
superphosphate. However, most fertilizers are supplied as
mixes or blends by a local producer who purchases the
nitrogen, phosphate, and potash materials and proportions
them to meet required ratios of nutrients. The blended
materials are normally transported only a short distance to
the farmer. This system, generally called bulk blending,
prevails throughout the Midwest (figure 56). In 1968, there
were 1537 bulk blenders in the states of Indiana, Illinois,
and Iowa, or approximately one for every 100 sq miles. If
the area were uniform, each blender would serve a circular
area about 6 miles in radius. This indicates the large number
of blending plants serving small, local markets.
Another system, chemical mixing, is also widely used.
One version is mixing phosphate rock with local supplies of
sulfuric acid to produce normal superphosphate (0-20-0),
which is then mixed with nitrogen solutions and potassium
chloride to produce granular mixed fertilizer of the desired
ratio. Triple superphosphate (0-46-0) may also be included
in the mix. Still another system is production of
ammonium phosphate from phosphoric acid and ammonia
with other materials such as potassium chloride added, if
required, during the manufacturing operation.
Fertilizer consumption in four major regions is shown in
figure 57. The historical consumption of nitrogen is shown
in figure 58. The North Central region has shown by far the
greatest growth and also has a high consumption density.
There are other regions with high levels of consumption but
the North Central is the only one that extends over a large
area. Therefore, the Midwest was chosen as the primary
marketing area for this study and fertilizer use was
evaluated in detail.
The states of Iowa, Illinois, and Indiana are considered
to be representative of the general use pattern in the region.
The nitrogen market is most critical because the recovery
products will be used mainly to supply nitrogen. The
quantity of nitrogen consumed in these three states by type
of product is shown in table 20. Consumption is reported as
that supplied by direct application materials and that
supplied by mixtures. Bulk blend consumption in Illinois is
shown in table 21; consumption in Iowa and Indiana was
assumed to be in the same proportion to the total as in
Illinois. Based on data in table 20, nitrogen consumption
densities were calculated and are summarized in table 22.
The three-state average should be considered a statistical
94
-------
I
r»is< ® _,
LEGEND
9 FT. DEPTH OR MORE
err.ros n. DEPTH
F'"9"re 53. Central U.
95
-------
New plant
Figure 54. Ammonia Plant Locations
Table 20. Nitrogen Market Profile in the
Midwest, 1967 (Tons Nitrogen) (86)
Land area (sq miles)
Direct application materials
Anhydrous ammonia
Aqua ammonia
Nitrogen solutions
Ammonium nitrate
Ammonium sulfate
Urea
Phosphate materials
Commercial mixtures
Ratio (1-4-X)
Ratio (1-1-1)
18-46-0
Other
Custom mixtures
Total mixtures
Total nitrogen
Iowa
56,032
451,682
331,619
28,187
51,646
35,205
500
3,298
1,227
(69,855)
20,133
732
23,327
(25,663)
(21,834)
91,689
543,471
Illinois
55,930
464,239
282,970
38,037
90,681
42,400
4,905
4,346
900
102,762
21,003
11,842
13,776
56,141
32,120
134,882
599,954
Indiana
36,185
234,926
117,978
10,311
79,535
16,370
763
8,917
1,052
(73,943)
26,115
15,919
18,890
(13,019)
(23,112)
97,055
332,125
Source: Comsumption of Commercial Fertilizers in the U. S., 1967
USDA SpCjfJ (5-68). Figures in parenthesis are estimated in
proportion to Illinois.
Mid-Americo planned
Coast Midwest planned
Gulf Central planned
A Terminal
Figure 55. Major Ammonia Pipelines
-------
LEGEND
1-5 PLANTS PER COUNTY
MORE THAN 5 PLANTS PER COUNTY
Figure 56. Bulk Blend Fertilizer Plants by Counties (1968)
-------
Table 21. Materials Sold as Custom Mixtures
in Illinois, 1966-1967 (Tons) (86)
Quantity of Estimated
Material N P20S
Nitrogen solutions
Ammonium nitrate
Urea
Ammonium sulfate
Superphosphate under 22%
Superphosphate over 22%
18-46-0
11-48-0
Muriate of potash
Miscellaneous
Total
9,374
20,616
2,457
3,781
3,224
35,953
91,758
33,102
82,971
194
283,430
3,140
6,906
1,106
794
16,516
3,641
17
32,120
645
16,538
42,209
15,889
34
75,315
K20
49,783
34
49,817
Source: Consumption of Commercial Fertilizers in the United
States, 1967 USDA SpC^-7 (5-68), page 5.
Table 22. Fertilizer Materials Consumption and
Average Consumption Density for the lowa-lllinois-
Indiana Area (Tons Nitrogen)
Item
Land area (sq mi)
Direct application materials
Anhydrous ammonia
Aqua ammonia
Nitrogen solutions
Ammonium nitrate
Ammonium sulfate
Urea
Phosphate materials
Commercial mixtures
Ratio (1-4-X)
Ratio (1-1-1)
18-46-0
Other
Custom mixtures
Total mixture
Total nitrogen
Area
totals
148,147
1,150,847
732,567
76,535
221,862
93,975
6,168
16,561
3,179
246,560
67,251
28,493
55,993
94,823
77,066
323,626
1,475,550
Average
consumption
density
(tnns/sq mi)
7.77
4.95 ~
.52
1.50_
.63 ~
.04
.11
.02
1.66_
6.96
0.81
.45
.19
.38
.64
.52
2.18
9.95
estimate of point consumption density. Through use of the
point estimate, the density patterns shown in figure 57 can
be used to extrapolate to other areas in the North-Central
region.
The potential for movement of recovery products in
international markets was considered. Many countries now
have or soon will have local ammonia production capability
based on natural resources or imported petroleum products.
With the inclination to protect local industries with import
tariffs and quotas, it would appear risky to base an
investment decision on significant penetration of foreign
nitrogen markets. Moreover, even the current export
market, mainly ammonium sulfate, is dwindling and has left
large supplies of byproduct ammonium sulfate looking for
new markets.
The international phosphate markets are somewhat
different since local supplies of phosphate rock and sulfur
are limited. Trade in phosphate fertilizers is significant and
should continue to grow.
Substitution of Recovery Products—The most
significant possibility for raw material substitution is use of
sulfur-containing products recovered from a power plant
instead of mined sulfur. The location of major thermal
power plants is shown in figure 59. By using such local
sulfur, cost of recovery might be partially offset by reduced
transportation costs. Power plants are normally located
near large streams because of cooling water requirements so
that low-cost barge shipments or rail shipments at
water-compelled rates could be negotiated for phosphate
rock requirements.
Although not a recovery product, partial substitution of
nitric acid for sulfuric acid to digest the phosphate rock
may also be an important raw material factor. Nitric acid
might be available at relatively low price from local
producers who face competition from direct application of
ammonia delivered by pipeline. Economics may also favor
production of nitric acid since the large quantities of
ammonia required in the scrubbing operation may give low
ammonia cost.
The recovery products are also well suited for
substitution in bulk blending. This is fortunate since much
of the output from recovery plants must of necessity move
through the bulk blending outlets.
In addition to use in bulk blends, substitution of
recovery products in the direct application market is
another potential outlet. Seventy percent of all the nitrogen
applied is supplied as ammonia and nitrogen solutions, the
lowest cost sources. It is assumed that recovery products
will not compete with this use. Use of solid nitrogen
products for direct application is practiced on some of the
smaller farms because of the large investment required for
liquid application equipment. Recovery products can be
substituted in this use although they are at a disadvantage
because of the dual nutrient content. Nitrogen, which
readily leaches from the soil, is often applied after the crop
is up while phosphates are applied prior to planting because
they are more stable and represent a long-term investment
in soil fertility. The value of nitrogen in a multi-nutrient
material applied prior to planting must be discounted. The
degree of substitution will depend on the price of the
recovery products relative to the products now used.
As a basis for establishing market potential for the
recovery products, two levels of consumption density were
98
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UNITED STATES
TOTAL
133,258,950
1 DOT-10,000 ACRES
Figure 57. Fertilizer Use Pattern in the United States
Table 23. Competitive Bulk-Blending Prices for Standard Fertilizers and
for Sulfur Oxide Recovery Products (Delivered to the Midwest)
Established Products*-
Ammonium nitrate (33.5-0-0)
Diammonium phosphate (18-46-0)
Triple superphosphate (0-46-0)
Sulfur Recovery Products
Ammonium phosphate nitrate (28-14-0)
Ammonium phosphate nitrate (26-19-0)
Ammonium phosphate sulfate (19-14-0)
Ammonium sulfate (21-0-0)
Input
price,
$/ton
45.00
73.00
56.00
Shadow
Ammonium
nitrate3
competition
52.47
55.09
42.79
28.21
price, $/ton
Diammonium
phosphate0
competition
43.49
47.69
37.15
19.83
aNitrogen cost = (45.00/0.335) = $134.33/ton.
Phosphate cost = (73 - [134.33] 0.18)/0.46 = $106.13/ton.
bPhosphate cost = (56.00/0.46) = $121.74/ton.
Nitrogen cost = (73 - 46)/0.18 = $94.44/ton.
cThese prices are manufacturers' list prices for the winter of 1969, with $13/ton freight added to the phosphate products (shipped from Tampa,
Florida). Actual prices at that time were being discounted 20%, but are expected to recover to the above levels in the long-run.
99
-------
assumed. The lower level (0.25 tons N/sq mile) corresponds
to approximately 10% of the solids used for direct
application and all of the straight nitrogen solids used in
custom blends. The higher level (1.0 ton N/sq mile)
corresponds to replacing all the solid nitrogen products in
blends, approximately 20% of the direct application solid
fertilizer, and 75% of the 1846-0 (diammonium phosphate)
used in commercial mixtures.
The higher level is probably not realistic for the early yrs
but with gradual penetration and market growth (estimated
at 6% annually) it is reasonable to consider it as an average
over the life of the recovery plant.
Pricing of Recovery Products
Base Price—If the recovery products are priced so that
a bulk blender realizes lower costs, it is reasonable to
assume that he will substitute them for his present raw
material inputs. Table 23 lists the assumed prices for the
major established products and the maximum prices a
blender could pay for the substitution products (hereinafter
called "shadow prices"). The fertilizer prices assumed in
table 23 are estimates of long-run levels in terms of current
dollars. In late 1968 actual prices were about 20% below
these but at this writing (late 1969), prices seem to be
recovering. It is expected that they will recover to the
long-run estimates and thereafter reflect price levels of the
general economy.
As an aid to understanding the shadow prices shown in
table 23, consider the following example. Suppose that a
blender has a market for 3000 tons of plant nutrient/yr in a
1:1:1 fertilizer ratio. He can purchase the established
products at the input prices given in table 23. (The price of
potassium chloride is immaterial in the present example
since it is the only potash source considered.) Suppose that
it has been decided to produce 28-14-0 at the power plant,
but it has not yet been decided how much to supply at any
given point in the market. It is assumed, however, that
whatever quantity is supplied will be such a small part of
the total market that the 28-14-0 supplier does not expect
his supply will affect the market prices of other established
products.
With this in mind, consider figure 60. The horizontal
axis indicates the quantity of 28-14-0 supplied to and
purchased by the blender in question. The lower curves give
on the right-hand ordinate the quantities of the other
inputs that would be needed to supply the 3000 tons of
nutrient/yr if the corresponding quantities of 28-14-0 were
used. The upper curve is the blender's demand curve for
28-14-0 and gives the maximum price he can pay for a
particular quantity of 28-14-0 (based on table 23). If the
price of 28-14-0 were higher than the indicated $52.47/ton,
it would not pay him to use any of this product. He would
use 33.5-0-0 and either 1846-0 or 0-46-0, depending on
which minimizes the cost. In arriving at this least-cost
decision, the blender calculates his nitrogen cost on the
basis of 335-0-0 as $45.00/0.335 = $134.33/ton of
nitrogen If 0-46-0 were to be used, the phosphate cost
would be calculated as $56.00/0.46 = $121.74/ton of
P2O5. With 1846-0 as the phosphate source, the phosphate
cost is calculated as
$73.00- ($13433)018 = $106.13/ton of P,O5
0.46
which is equivalent to removing the value of the 0.18 tons
of nitrogen in 18-46-0 as ammonium nitrate and treating
the residual value as being that of 0.46 tons of P2 Os. It can
be seen that the use of 1846-0 results in a phosphate cost
which is $15.61/ton of P2O5 less than the equivalent cost
of 046-0. The shadow price of 28-14-0 is calculated as
($134.33)0.28 + ($106.13)0.14 = $52.47/ton.
After substitution for all of the 33.5-0-0, further
increase in use of 28-14-0 requires not only the substitution
of 28-14-0 nitrogen for 1846-0 nitrogen, but 0-46-0
phosphate for 18-46-0 phosphate. The cost of added
phosphate in this substitution is calculated as $56.00/0.46
= $121.74/ton of P2O5, which, as noted in the initial
least-cost decision, is a $15.61/ton P205 increase in the
phosphate cost. At this higher phosphate cost, 28-14-0
c
o
T3
C
i
o
:' 3
c
-------
Figure 59. Approximate Location of Major Thermal Power Plants
must be sold at a correspondingly lower price. The nitrogen
in 28-14-0 is worth only
$73-°oio56'00 = $94.44/ton of nitrogen
0.18
and the product is worth only ($94.44) 0.28 + ($121.74)
0.14=$43.49/ton.
Market Strategy—In view of the differing substitution
price levels and consumption densities, it is desirable to
develop a market strategy that will optimize the relation
between sales price and transportation cost. This is merely a
matter of the producer setting a price, for a given
production level, that will maximize the net sales revenue.
Higher price (within realistic limits) maximizes gross return
but requires a larger sales area for such a "skim the cream"
marketing strategy and consequently a higher total
transportation cost. Lower prices reduce gross return but
also decrease shipping charges.
For the situation in question, there are four main pricing
strategies to be considered: (1) fob basis (highest price level
at which all the product can be sold at the plant), (2)
delivered basis, competitive with ammonium nitrate
(requires longest shipping distance), (3) delivered basis,
competitive with diammonium phosphate (lower price level
but lower shipping cost), and (4) a dual-zone basis
(combination of 3 and 4). Analysis of these alternatives is a
complicated matter and is discussed in detail in Appendix
A. Based on this analysis, it is concluded that except for
very large quantities from a single production point (over
400,000 tons of N/yr, outside the production capacities
assumed in the present study), pricing the recovery
products to compete with ammonium nitrate is the most
economical approach. Average return to manufacturing
("net back") on this basis is shown for each product as a
function of production quantity of nitrogen in figures
61-64. Net returns were also assembled for each of the
process variable combinations (tables 24-27).
Extent of Market for Recovery Products—The subject
of the present study is the economic viability of a single
large plant, but the question of maximum utility of the
process is also of interest. It is assumed that initially only a
few power plants would be equipped with ammonia
scrubbing-nitric phosphate facilities and that they would be
101
-------
Table 24. Average Return to Manufacturing3
Process A (28-14-0)
Annual operating hours
Size,
mw
200
500
500
500
500
1,000
1,000
Power plant
Type
New or existing
E
N
N
E
N
N
E
7,000
S in coal,
% by wt
3.5
2.0
3.5
3.5
5.0
3.5
3.5
Tons
N/yr
128,600
173,600
303,800
310,800
434,000
587,500
607,600
$/ton of
fertilizer
42.46
42.06
41.12
41.07
40.36
39.61
39.53
5,000
Tons
N/yr
91,700
123,900
217,000
222,000
309,800
419,700
433,800
$/ton of
fertilizer
42.86
42.52
41.71
41.68
41.08
40.44
40.36
3,500
Tons
N/yr
64,200
86,700
151,900
155,400
217,000
293,800
303,700
$/ton of
fertilizer
43.21
42.92
42.23
42.22
41.71
41.18
41.12
1,500
Tons
N/yr
27,600
37,200
65,300
66,800
92,800
126,300
130,100
5/ton of
fertilizer
43.82
43.63
43.18
43.17
42.86
42.49
42.45
aBased on delivered price competitive with ammonium nitrate.
Table 25. Average Return to Manufacturing3
Process B (26-19-0)
Annual operating hours
Size,
mw
200
500
500
500
500
1,000
1,000
Power plant
Type
New or existing
E
N
N
E
N
E
N
7,000
S in coal,
% by wt
3.5
2.0
3.5
3.5
5.0
3.5
3.5
Tons
N/yr
97,100
131,500
230,000
235,800
328,600
460,000
444,000
$/ton of
fertilizer
45.17
44.84
44.04
44.00
43.41
42.70
42.78
5,000
Tons
N/yr
69,500
93,900
164,300
168,200
234,700
328,600
318,000
$/ton of
fertilizer
45.50
45.22
44.54
44.51
44.01
43.41
43.49
3,500
Tons
N/yr
48,600
65,800
115,000
117,900
164,300
230,000
222,000
$/ton of
fertilizer
45.79
45.55
44.99
44.96
44.54
44.04
44.11
1,500
Tons
N/yr
20,800
28,200
49,300
50,500
70,400
98,500
95,200
$/ton of
fertilizer
46.30
46.15
45.78
45.75
45.48
45.16
45.22
aBased on delivered price competitive with ammonium nitrate.
Table 26. Average Return to Manufacturing3
Process C (19-14-0)
Annual operating hours
Size,
mw
200
500
500
500
500
1,000
1,000
Power plant
Type
New or existing
E
N
N
E
N
E
N
S in coal,
% by wt
3.5
2.0
3.5
3.5
5.0
3.5
3.5
7
Tons
N/yr
56,700
76,600
134,000
137,000
191,400
268,000
259,500
,000
$/ton of
fertilizer
35.05
34.82
34.30
34.27
33.87
33.40
33.44
5
Tons
N/yr
40,500
54,700
95,700
97,900
136,700
191,400
185,400
,000
$/ton of
fertilizer
35.27
35.06
34.63
34.61
34.27
33.87
33.91
3
Tons
N/yr
28,400
38,300
67,000
68,500
95,700
134,000
129,800
,500
$/ton of
fertilizer
35.47
35.30
34.93
34.91
34.63
34.30
34.33
1
Tons
N/yr
12,200
16,400
28,700
29,400
41,000
57,400
55,600
,500
$/ton of
fertilizer
35.82
35.70
35.46
35.45
35.27
35.04
35.06
aBased on delivered price competitive with ammonium nitrate.
102
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Table 27. Average Return to Manufacturing3
Ammonium Sulfate
Annual operating hours
Size,
mw
200
500
500
500
500
1,000
1,000
Power plant
Type
New or existing
E
N
N
E
N
E
N
7,000
S in coal,
% by wt
3.5
2.0
3.5
3.5
5.0
3.5
3.5
Tons
N/yr
65,860
89,000
155,925
159,500
222,810
311,850
301,560
$/ton of
fertilizer
22.08
21.82
21.23
21.21
20.77
20.24
20.29
5,000
Tons
N/yr
47,000
63,600
111,400
113,900
159,200
222,800
215,400
$/ton of
fertilizer
22.32
22.10
21.61
21.59
21.21
20.77
20.81
3,500
Tons
N/yr
32,900
44,500
78,000
79,800
111,400
155,900
150,800
$/ton of
fertilizer
22.53
22.35
21.94
21.92
21.61
21.23
21.27
1,500
Tons
N/yr
14,100
19,100
33,400
34,200
47,700
66,800
64,600
$/ton of
fertilizer
22.91
22.79
22.52
22.51
22.31
22.06
22.08
aBased on delivered price competitive with ammonium nitrate.
located with a minimum of market overlap. Assuming a
hypothetical central Illinois plant with 500-mw capacity,
the market boundaries for 19-14-0 and 28-14-0 based on
0.25 consumption density are shown in figure 65. The area
covered indicates that only two or three plants could be
accommodated without serious overlap if 28-14-0 is
produced. With production of 19-14-0, about three times as
many plants could utilize the process. The limiting
competitive case is that which results in diammonium
phosphate competition (consumption density of 1.0) at all
points. Market boundaries for such a case are shown in
figure 66.
PROFITABILITY
If chemical companies enter into the sulfur recovery
field, on the basis either of contributing all the investment
or of supplying only part of it, profitability of the venture
becomes of paramount importance. An unregulated
company, with no guarantee of sales price or net profit and
with all the uncertainties associated with the future of
chemical enterprises, must be able to see promise of a
relatively high rate of return in order to attract capital to
the project.
The cost of recovering sulfur oxides and the revenue
from sale of product have been estimated in previous
sections. Another 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 removing
sulfur oxides from the gas (unless it reduces or eliminates
this cost by entering into a recovery project itself).
The amount of payment presumably would be
negotiated between the two companies, and could range
from zero to the full cost of lime or limestone scrubbing.
Hence the profitability estimates in the present study have
been calculated on two bases-full payment (equivalent to
lime-limestone scrubbing cost) and no payment. In practice,
the payment might well be in between.
The above applies to the situation in which the chemical
company finances and operates the entire installation,
including scrubbing. For the joint venture approach, several
different arrangements are conceivable. In the one selected
for the present study, the power company finances and
operates a stack gas scrubbing and reheat system under
regulated economics and sells the intermediate scrubber
effluent to a fertilizer company. The fertilizer company is
assumed to invest in an adjacent on-site plant for further
processing the intermediate into product and to market the
product with the expectation of attaining an adequate
return on investment. Because the power company will be
seeking to minimize the cost to power consumers by
attaining the highest possible "transfer price" for the
intermediate, and the fertilizer company will be seeking the
lowest possible price for the "raw material" to maximize
return on investment, a critical part of this concept depends
on the negotiated price. The fertilizer company cannot
afford to pay more than the price at which the intermediate
could be obtained elsewhere. On the other hand, the power
company cannot go lower than the level at which the net
cost of the scrubbing operation becomes higher than for the
alternative lime scrubbing method.
Once again, as with the "payment" under full
nonregulated economics, only a range can be established in
regard to the loss the power company can afford to incur
and pass on to the fertilizer company as a "deduction."
Therefore, the operating cost to the fertilizer company is
presented in two ways—with a raw material cost equivalent
to (1) that required to give normal return to the power
plant on the scrubbing operation and (2) that resulting
from the power plant incurring a loss equal to the cost of
lime scrubbing.
103
-------
60 r-
_: 50
9
CO
CM
1 40
Q)
Q
30
18-46-0
,0-0-60
33.5-0-0
\
- 3000
— 2000 '=
~ 1000
c
10
d
— o
1000
2000 3000
28-14-0, tons
4000
Figure 60. Substitution of Byproduct 28-14-0 for Ammonium Nitrate
and 18-46-0 at Specified Competitive Price Conditions
So that consistent comparisons can be made of the three
processes under consideration, the processes are split
arbitrarily after the point where ammonium sulfate is
produced. All prior operations are costed on the basis of
regulated economics and the remainder on unregulated
economics.
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
nonregulated industry; three of the more common ones
104
-------
46 i-
-, 400
I
9
oo
CN
30 -
100
200
300
400
500
600
700
Nitrogen in 28-14-0, thousands of tons
Figure 61. Average Return to Manufacturing (ARM) and Average Length of Haul (ALH)
for 28-14-0 (Based on Delivered Price Competitive with Ammonium Nitrate)
48 r-
400
300
200
100'
100
200 300 400 500
Nitrogen in 26-19-Q, thousands of tons
600
700
Figure 62. Average Return to Manufacturing (ARM) and Average Length of Haul (ALH)
for 26-19-0 (Based on Delivered Price Competitive with Ammonium Nitrate)
105
-------
38 i-
Expected ARM prices
400
30
20
300
200
100
I 500-mw plant
J_ _L
I
100
200 300 400 500
Nitrogen in 19-14-0, thousands of tons
600
700
Figure 63. Average Return to Manufacturing (ARM) and Average Length of Haul (ALH)
for 19-14-0 (Based on Delivered Price Competitive with Ammonium Nitrate)
-i 400
c
o
9
p
CN
100
200 300 400 500
Nitrogen in 21-0-0, thousands of tons
600
700
Figure 64. Average Return to Manufacturing (ARM) and Average Length of Haul (ALH)
for 21-0-0 (Based on Delivered Price Competitive with Ammonium Nitrate)
106
-------
Figure 65. Expected Market Boundaries for 28-14-0 and 19-14-0 for
Ammonium Nitrate Competition and a 500-mw Plant
Figure 66. Ultimate Competitive Market Boundaries for 28-14-0 and 19-14-0 for
Diammonium Phosphate Competition and a 500-mw Plant
107
-------
(annual return on initial investment, payout period, and
interest rate of return) have been calculated in the present
study for all applicable cases where nonregulated industry
economics are involved. ""He 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, sometimes 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.
Results of the profitability estimates are presented as
computer print-outs in Appendix B. Operation of the entire
facility by the fertilizer company (nonregulated economics)
is covered in tables B-106-B-126 and joint venture
(cooperative) operation in tables B-127—B-147. Each yr of
operation is calculated separately to cover the adverse
effect of declining operating factor on profitability in the
later yrs of power plant operation. Gross income is
calculated as sales revenue plus the pollution abatement
payment, if any, less manufacturing cost; deduction of
income tax then gives the total net income/yr.
The estimates show that net income varies widely
depending on several factors. Under some conditions (small
plant size, low sulfur content of coal, no pollution
abatement payment, later yrs of operation), there is a loss
rather than net income. On the other hand, at the other
extreme of these variables net income is high-particularly
in the early yrs of operation.
Full evaluation of a nonregulated venture must include
cash flow (depreciation plus net income) and an analysis of
economic promise at the time of going into the venture.
This is considered in detail in the next section.
ECONOMIC EVALUATION
Basic Economics of Fertilizer Process
The fertilizer process in question, production of nitric
phosphate by calcium precipitation with ammonium
sulfate, has been used commercially in Europe but not in
the United States. Presumably the European company, a
large and successful one, found the method economically
attractive. However, the ammonium sulfate used is a
byproduct from a chemical process and it is not known at
what price it is charged to the nitric phosphate plant;
moreover, market conditions differ between Europe and
the United States. Therefore, the first step in the present
analysis was an estimate based on U. S. conditions to
establish the basic economics of the nitric phosphate
process without reference to power plants. The possibility
exists, of course, that in the United States the process
would not be attractive even under the most favorable
situation that could be visualized.
As a starting point, an evaluation was prepared for
operating process A without any connection to a power
plant; in this case the ammonium sulfate would be recycled
in the process by reacting product calcium sulfate with
ammonia and carbon dioxide. Investment for the plant
(process A; 1040 tons 28-14-0 fertilizer/day, equivalent to
production from a 500-mw power plant burning coal
containing 3.5%S) is given in table 28 and operating cost
(8000 hr/yr; indirect costs on nonregulated industry basis)
in table 29. Profitability was then calculated on the basis of
the sales revenue estimated for this level of production
(unit price for product varies with production level). The
result was 6.5% annual return on initial investment, 10%
interest rate of return (over 10 yr, to end of depreciation
period), and 6.1 yrs payout time.
It is difficult to say whether this degree of profitability
is large enough to attract investors. Each company has its
own criteria as to what it considers to be an attractive
investment opportunity and no generally applicable
standard can be set. However, a rough concensus appears to
be 7-10% annual return on investment, 12-15% interest rate
of return, and less than 6 yrs payout time. On this basis, the
nitric phosphate process is on the low side for the 500-mw
size assumed in the estimate. Profitability could be
improved, however, by increasing either the plant size (to
reduce operating cost) or the sales revenue; for example, an
increase in the price of sulfur to the fertilizer industry
would operate indirectly to increase sales price realizable
for the nitric phosphate product. Rough estimates (not
reported) indicate that a 5-yr payout (15% interest rate of
return for 10-yr life) could be obtained by increasing the
plant size to that equivalent to an 800-mw power plant or
by increasing the sales revenue by 10%. Moreover, it is
likely that in practice the nitric phosphate plant would be
operated in conjunction with an ammonia plant, in which
case reduction in sales, handling, and overhead costs would
reduce the ammonia cost as compared with purchasing the
ammonia; a reduction of $5/ton of ammonia might well be
possible, which would increase interest rate of return from
10% up to 12.6%. Finally, the economics cduld be
improved if the process were tied to a power plant and if
such joint operation made it possible to obtain the
ammonium sulfate at a cost lower than by making it from
gypsum.
The cost of making ammonium sulfate by gypsum
108
-------
Engineering design
Contractor fees and overheads
Contingency allowance
Total fixed investment
Table 28. Summary of Estimated Fixed Investment Requirements:3 Manufacture of 28-14-0 Fertilizer
by Sulfate Recycle • Nitric Phosphate Process
(43.4 tons/hr of fertilizer)
Investment, $
Yard, utilities, and storage facilities (raw material storage, railroad unloading
and shipping, and utilities distribution)
Gypsum conversion unit (sulfate recycle by ammonium carbonate reaction)
Nitric acid plant (60% nitric acid)
Extraction-filtration (equipment for .acidification of phosphate rock, ammonium sulfate
addition, and gypsum filtration)
Neutralization and prilling (equipment for neutralization, evaporation, prilling,
screening, and conveying product)
Bulk storage (storage and shipping buildings, 90 days' storage)
Waste disposal (calcium carbonate disposal including pond)
Subtotal direct investment
2,043,000
680,000
3,200,000
1,100,000
3,830,000
1,770,000
200,000
12,823,000
1,046,000
1,581,000
1,287,000
16,737,000
aBasis:
Capacity of unit same a? provided by 500-mw power unit burning coal with 3.5% S using ammonia scrubbing of stack gas. Carbon dioxide
and ammonia assumed available from adjacent facilities.
conversion is given in table 30 and 31. Assuming a 20%
annual return before taxes on initial investment (10% net
return; 15% interest rate of return over 10 yr), the price at
which the ammonium sulfate solution would be charged to
the nitric phosphate plant is $14.35/ton of ammonium
sulfate (process A). The cost for making it by ammonia
scrubbing of power plant stack gas varies with several
factors: sulfur content of the coal, operating factor of the
power plant, choice between regulated and nonregulated
economics (or combination thereof), and new vs existing
power plant. For a comparable amount of ammonium
sulfate, the variation is from about $16 to well over
$20/ton (see Appendix B). Hence tying the fertilizer plant
to the power plant (as opposed to operating the fertilizer
plant independently with ammonium sulfate made by
gypsum conversion) would not be justified economically
unless some credit were allowed for air pollution control.
The alternative cost for limestone - wet scrubbing,
expressed for convenience as the cost of removing an
amount of sulfur dioxide equivalent to a ton of ammonium
sulfate, ranges from $9-12. Hence if the power company
were willing to operate an ammonia scrubbing unit at the
same net cost as limestone - wet scrubbing, the ammonium
sulfate could be transferred to the fertilizer plant at a
charge of only $7.30-10.10/ton.
Thus the economics of making ammonium sulfate by
scrubbing stack gas and using the ammonium sulfate in a
nitric phosphate process appear favorable if the fertilizer
unit is given at least partial credit for pollution control.
Fertilizer Company Involvement
Since the comparable economics of using byproduct
ammonium sulfate solution from a power plant as a raw
material for nitric phosphate production appear acceptable,
the next step is to assess the economic promise for the
various combinations of conditions. To do this, the payout
periods and interest rates of return calculated from the
projected cash flows (tables B-106-B-147 in Appendix B)
are assembled in table 32.
The data indicate that under certain conditions both
processes A and B merit consideration as reasonably
attractive financial ventures. In most of the process C cases,
however, the initial investment is not even recovered, since
interest rate of return is negative. Process A is slightly more
attractive than process B, having a marginally higher
interest rate of return and a lower payout period. For these
processes to be attractive, however, some credit for
pollution control would be needed and fertilizer tonnage
would have to be large. In general, it appears that power
units must be larger than 500 mwand burn coal containing
at least 3.5% sulfur to give acceptably profitable operation.
For smaller power units, the joint venture approach
(cooperative economics) is generally a little less attractive
than total investment and operation by the fertilizer
company (unregulated economics). The reasons for this are
quite corfiplex because several factors, some varying in
effect with the magnitude of others, affect the relative rates
of return over the operating lifetime of the plant. The main
109
-------
Table 29. Nonregulated Company Economics - Total Venture Annual Manufacturing Costs for
28-14-0 Fertilizer Using Ammonium Sulfate Recycle and Nitric Phosphate Process3
(347,000 tons/yr fertilizer) ^^_
Annual quantity
Unit cost, $
Total
annual
cost, $
Cost/ton of
fertilizer, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Carbon dioxide
Sulfuricacid
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
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,
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28-14-0 fertilizer
116.2 M tons
143.9 M tons
67.6 M tons
9.6 M tons
6.0 M tons
115.2M Ib
570 troy oz
100,000 man-hr
1,112,000 Mlb
5,254,000 M gal
35,033,000 kwh
35.00/ton
11.88/ton
1.00/ton
23.00/ton
46.60/ton
0.18/lb
120/troy oz
4.50/man-hr
0.40/M Ib
0.05/M gal
0.005/kwh
4,067,000
1,709,500
67,600
220,800
279,600
20,700
68,400
6,433,600
450,000
444,800
262,700
175,200
784,400
55,000
2,172,100
8,605,700
1,673,700
334,700
434,400
217,200
2,660,000
11,265,700
32.46
aBasis:
Fertilizer plant on-stream time, 8,000 hr.
Midwest plant location-1969 costs.
Capital investment $16,737,000 fixed.
Carbon dioxide and ammonia assumed available as package from adjacent ammonia plant.
Capacity of unit same as provided by 500-mw power unit burning coal with 3.5% S using ammonia scrubbing of stack gas.
110
-------
Premix tanks, mixers, pumps, and conveyors
Converters, mixers, heaters, and pumps
Carbonate filter system, including vacuum pumps, wash pumps, tanks
Product storage tank and pumps
Carbonate reactor tower pumps, heat exchangers, carbonate storage
General buildings and supporting facilities
Subtotal direct investment
Engineering design
Contractor fees and overheads
Contingency allowance
Total fixed investment
Table 30. Summary of Estimated Fixed Investment Requirements:3 Manufacture of
Ammonium Sulfate Solution from Waste Gypsum Ammonia, and Carbon Dioxide - Sulfate Recycle
Process for 28-14-0 Nitric Phosphate Fertilizer
(22.3 tons/hr ammonium sulfate in a 40% solution)
Investment, $
47,000
115,000
320,000
87,000
111,000
200,000
880,000
880,000
144,000
88,000
1,200,000
aBasis:
Capacity of unit same as provided by 500-mw power unit burning coal with 3.5% S using ammonia scrubbing of stack gas.
COj and NHs assumed available from adjacent facilities.
factor is the fixed rate of return on the scrubber unit
(treated as a cost item to the fertilizer company) in the
cooperative venture as compared with a varying rate in the
all-fertilizer company arrangement. Only for the largest
plant sizes (highest rates of return) does the cooperative
venture have an advantage. In all cases, however, the
differences between the two bases are probably not large
enough to be significant.
The effects of power unit size on the payout period and
interest rate of return are given in figures 67-70. Only the
1000-mw size gives the desired 15% or better interest rate
of return.
The important effect of the credit for air pollution
control is given in figures 71 and 72. Without the credit, no
combination is attractive.
Sulfur content of the coal (figures 73 and 74) has a
major effect. The conclusions given earlier are for coal
containing 3.5% sulfur. If the content is increased to 5%,
the interest rate of return goes to well over 15% even for a
500-mw unit. Annual operating time of the system has
much the same effect (figures 75 and 76); over 5000 hr/yr
is necessary for the 15% return (1000 mw). It is of interest
to compare these values with those for the declining
operating factor assumed for an actual plant situation
(figure 68), for which about 16% return is obtained at 1000
mw.
The net sales revenue, of course, is an overriding factor.
The effect of change in this from the value obtained in the
market study is given in figures 77-80; a 10% decrease in
revenue drops the indices to unattractive levels but an
increase of 10% makes even a 500-mw installation
attractive.
The effect of power unit age (new vs existing), and
consequent operating life of the recovery unit, is shown in
figure 81. Operating times for the existing units are
assumed to follow the same schedule as for the new units,
with the number of yrs of 7000-hr operation being the only
period affected. Because of this, the adverse effect of
reduced life is more drastic than if it had been spread over
the entire life.
It should be pointed out that the data on existing units
does not reflect the recent special legislation which permits
a fast (5-yr) amortization for a portion of the investment in
pollution abatement facilities added to existing plants.
Since profit-producing facilities are not included under this
law and the definition of qualification is best applied to
specific cases, no attempt is made to describe its effects on
economics in this study.
Power Company Basis
For regulated economics, there is no credit for pollution
control but instead a direct present worth comparison
between the recovery (ammonia) and nonrecovery
(limestone) methods (table 33). Since the basic assumption
under regulated economics is that the profitability (rate of
return) of the power company will be maintained, the data
only indicate which process gives the minimum cost of air
pollution to the power consumer. Process C is not
acceptable under any conditions (net cost higher than for
limestone - wet scrubbing), and A and B have an advantage
only for the 1000-mw size (except for a new 500-mw unit
burning coal containing 5% S). However, from the curves
given in figure 82, it can be seen that although limestone
111
-------
scrubbing is slightly less costly at 500 mw (new plant, 3.5%
S), the situation is reversed at a little above 500 mw. The
curves diverge rapidly so that at about 600 mw and above
there is a clear advantage for ammonia scrubbing. Moreover,
projection of the curves indicates that process A might even
reduce the cost of power to consumers when used on new
units greater than 1100 mw in size.
In contrast, figure 68 shows that under nonregulated
economics the plant size would have to be about 1000 mw
to give the assumed minimum interest rate of return of
15%, even with full credit for the cost of removing sulfur
oxides by lime-limestone scrubbing. This major difference
results from the lower rate of return acceptable in the
regulated power industry.
Increase in sulfur content of the coal also improves
recovery economics rapidly (figure 83). Even for 500 mw,
ammonia scrubbing becomes preferable to limestone
scrubbing at a little above 3.5% sulfur, and at 5.5% process
A would reduce the cost of power to consumers.
Improvement in operating factor may be one of the
better ways to improve economics (figure 84); for example,
if a lifetime operating time of 7000 hr/yr (80% operating
factor) could be maintained, even an 800-mw unit would
reduce the cost of power. Provision of surge capacity
between power and fertilizer plants, scrubbing of only part
of the gas, and other methods might be used to increase
operating factor; these could not be evaluated fully in the
present study.
Sales revenue obviously is highly important also under
regulated economics (figure 85 and 86). It is so important,
in fact, that the difficulty in predicting future sales revenue
may be an argument for selecting limestone - wet scrubbing
unless the cost estimate for the particular situation
indicates an advantage for the recovery process.
112
-------
Table 31. Annual Manufacturing Costs: Ammonium Sulfate Solution (40%) from Waste Gypsum,
Ammonia, and Carbon Dioxide - Sulfate Recycle Process for 28-14-0 Nitric Phosphate Fertilizer3
(178,000 tons/yr ammonium sulfate)
Annual quantity
Unit cost, $
Total
annual
cost, $
Cost/ton of
ammonium
sulfate, $
Direct Costs
Raw materials
Ammonia 50.00 M tons
Carbon dioxide 67.6 M tons
Sulfuric acid 9.6 M tons
Gypsum waste from
fertilizer process 300.0 M tons
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Treated water 8,500 M gal
Cooling water 33,000 M gal
Electricity 2,000,000 kwh
Maintenance
Labor and materials
Anajyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% of fixed investment
Taxes and insurance at 2% of fixed investment
Overheads
Plant, at 20% of conversion costs
Administrative, at 40% of operating labor
Subtotal indirect costs
Total operating costs
Credit for reduced solids disposal cost,
CaCO3 vs CaS04
Charge for desirable return on investment
by chemical company, 20% of investment before taxes
Total annual manufacturing cost
35.00/ton
1.00/ton
23.00/ton
0.20/M gal
0.10/M gal
0.008/kwh
1,750,000
67,600
221,000
2,038,600
70,000
1,700
3,300
16,000
54,000
5,000
150,000
2,188,600
120,000
24,000
30,000
28,000
202,000
2,390,600
(75,000)
240,000
2,555,600
14.35
"Basis:
Operating stream time assumed to be 8,000 hr/yi.
Capacity of unit same as provided by 500-mw power unit burning coal with 3.5% S using ammonia scrubbing of stack gas.
COj assumed available as byproduct from adjacent ammonia plant. Value of waste gypsum assumed as zero.
Tons/yr of CaCO3 for disposal is 75,000 less than for gypsum.
113
-------
Table 32. Economic
Power plant
Process A
200-tnw, existing unit, 3.5% S in coal
500-mw, new unit, 2.0% S in coal
500-mw, new unit 3.5% S in coal
500-mw, existing unit, 3.5% S in coal
500-mw, new unit, 5.0% S in coal
1,000-mw, new unit, 3.5% S in coal
1 ,000-mw, existing unit, 3.5% S in coal
Process B
200-mw, existing unit, 3.5% S in coal
500-mw, new unit, 2.0% S in coal
500-mw, new unit, 3.5% S in coal
500-mw, existing unit, 3.5% S in coal
500-mw, new unit, 5.0% S in coal
1 ,000-mw, new unit, 3.5% S in coal
1,000-mw, existing unit, 3.5% S in coal
Process C
200-mw, existing unit, 3.5% S in coal
500-mw, new unit, 2.0% S in coal
500-mw, new unit, 3.5% S m coal
500-mw, existing unit, 3.5% S in coal
500-mw, new unit, 5.0% S in coal
1 ,000-mw, new unit, 3.5% S in coal
1 ,000-mw, existing unit, 3.5% S in coal
Potentia
With
Payout
11.4
7.4
6.1
6.4
5.0
4.9
5.2
14.5
7.8
6.3
6.4
5.2
5.1
5.3
-
—
17.5
-
11.0
10.0
11.8
of Ammonia Scrubbing
Nonrequlated
payment3
Interest
rate of
return, %
1.5
9.3
13.0
11.0
17.4
17.9
15.6
0.5
8.3
12.5
11.1
16.5
17.3
15.1
-
-
0.4
-
3.3
4.0
2.5
] Fertilizer
Production Processes .
economics
Without
Payout
yrs
-
—
8.7
9.8
6.6
6.4
6.9
—
—
9.4
11.3
7.2
6.9
7.5
-
-
—
-
-
-
-
payment
Interest
rate of
return, %
-
-
5.7
1.4
11.4
12.0
9.1
-
-
4.0
0.8
9.6
10.5
7.5
-
-
—
-
—
-
-
With
Cooperative
deduction13
interest
Payout rate of
vrs return, %
—
8.0
6.1
6.4
4.7
4.6
4.8
—
9.0
6.4
6.5
5.0
4.8
5.1
-
—
—
-
-
-
-
—
7.3
13.2
10.4
18.9
19.8
17.5
—
4.4
11.9
10.1
17.4
18.7
15.6
—
—
-
-
-
-
-
economics
Without
Payout
yrs
—
—
10.0
—
6.7
6.5
6.9
—
—
-
-
7.6
7.3
8.6
-
—
-
-
—
-
-
deduction
Interest
rate of
return, %
—
—
—
—
11.0
11.8
8.3
—
-
-
-
7.9
9.0
3.3
-
-
-
-
-
-
-
aPayment from power company to fertilizer company of a credit equivalent to the cost of limestone - wet scrubbing.
"Deduction from the price at which the power company sells ammonium sulfate to the fertilizer company; deduction equivalent to the cost of
limestone - wet scrubbing.
Table 33. Present Worth3 of the Net Annual Increase in Cost of Power
Resulting From Use of the Ammonia and Limestone Scrubbing Processes
Ammonia scrubbing-fertilizer
Power plant
200-mw, existing unit, 3.5% S in coal
500-mw, new unit, 2.0% S in coal
500-mw, new unit, 3.5% S in coal
500-mw, existing unit, 3.5% S in coal
500-mw, new unit, 5.0% S in coal
1 ,000-mw, new unit, 3.5% S in coal
1,000-mw, existing unit, 3.5% S in coal
Process
A
$19,423,200
21 ,453,300
17,156,200
22,400,000
5,324,900
4,594,800
16,058,000
Process
B
$18,957,200
22,586,800
18,404,200
21 ,364,600
9,563,800
9,470,500
19,161,400
Process
C
$22,882,000
32,598,700
36,843,600
40,208,100
39,847,900
50,606,500
55,086,300
Alternate
limestone -
wet scrubbing
process
$ 7,219,400
14,120,000
16,864,800
16,933,200
19,662,100
26,463,500
26,919,700
aCash flow discounted at 10% to initial yr.
114
-------
20
Existing units
3.5% S in coal
Assumes payment for air pollution control
Process A - A
Process B - n
15
>
o
o
cu
CL
10
I
200
400 600
Power unit size, mw
800
1000
1200
Figure 67. Effect of Power Unit Size on Payout Period
for Nonregulated Economics
I
•5
JG
o>
1
Existing units, 3.5% S in coal
Assumes payment for air pollution control
Process A -
200
400
600
Power unit size, mw
1000
1200
Figure 68. Effect of Power Unit Size on Interest Rate
of Return for Nonregulated Economics
115
-------
20
Existing units
3.5% S in coal
Assumes deduction for air pollution control
Process A -A
Process B - n
15
•o
o
o
10
200 400 600 800
Power unit size, mw
Figure 69. Effect of Power Unit Size on Payout Period for Cooperative Venture
1000
1200
c
I
0)
I
Existing units
3.5% S in coal
Assumes deduction for air pollution control
Process A -
Process B -
200
400
600 800
Power unit size, mw
1000
1200
116
Figure 70. Effect of Power Unit Size on Interest Rate
of Return for Cooperative Venture
-------
20
3
O
ra
a.
15
Nonregulated economics
Process A
Existing units
3.5% S in coal
. With payment for air pollution control —
» Without payment for air pollution control
20
15
e
| 10
£
I
-------
15
10
•o
o
o
Cooperative economics
500-mw new units
Assumes deduction for air pollution control
Process A -A
Process B - o
1
1234
Sulfur in coal, %
Figure 73. Effect of Sulfur Content of Coal on Payout Period
25
20
15
2 10
c
Cooperative economics
500-mw new units
Assumes deduction for air pollution control
Process A -A
Process B - a
118
12345
Sulfur in coal, %
Figure 74. Effect of Sulfur Content of Coal on Interest Rate of Return
-------
25
20
15
1
I
D
O
10
I
Nonregulated economics
Process A
Existing units
3.5% S in coal
Operation - 35 yr at indicated number of hrs
Assumes payment for air pollution control
200
800
400 600
Power unit size, mw
Figure 75. Effect of Operating Time on Payout Period
1000
1200
3
£
"5
5
I
Nonregulated economics
Process A
Existing units
3.5% S in coal
Assumes a 35-yr life with payment for
air pollution control
200
800
400 600
Power unit size, mw
Figure 76. Effect of Operating Time on Interest Rate of Return
1000
1200
119
-------
20
15
S. 10
O
I"
Cooperative economics
Process A
Existing units
3.5%S in coal
Assumes credit for air pollution control
Net sales revenue varied, by the percentage indicated, from that estimated in the market study
200
400 600 800
Power unit size, mw
1000
1200
Figure 77. Effect of Variations in Net Sales Revenue on
Payout Period (Process A)
20
15
i
8. 10
Cooperative economics
Process B
Existing units
3.5% S in coal
Assumes deduction for air pollution control
Net sales revenue varied, by the percentage indicated, from that estimated in the market study
120
200
400 600
Power unit size, mw
800
1000
1200
Figure 78. Effect of Variations in Net Sales Revenue on
Payout Period (Process B)
-------
30
25
20
15
10
Cooperative economics
Existing units
3.5% S in coal
Assumes deduction for air pollution control
Net sales revenue varied, by the percentage indicated, fron
that estimated in the market study
200
400 600
Power unit size, mw
800
1000
1200
Figure 79. Effect of Variation in Net Sales Revenue on
Interest Rate of Return (Process A)
30
25
20
15
10
I : <
Cooperative economics
Existing units
3.5% S in coal
Assumes deduction for air pollution control
Net sales revenue varied, by the percentage indicated,
from that estimated in the market study
200
400 600
Power unit size, mw
800
1000
1200
Figure 80. Effect of Variation in Net Sales Revenue on
Interest Rate of Return (Process B)
121
-------
25
20
5?
fc
c
I
o 15
10
Cooperative economics
Process A
3.5% S in coal
Assumes deduction for air pollution control
Existing units
New units
200
400
800
600
Power unit size, mw
Figure 81. Effect of Recovery Unit Life on Interest Rate of Return
1000
1200
10 MM
•s 8
o
.2 |
CD o
O. £
11
2 §
O
o
<-> c
§8
o c
o
•5 c .«
•
0 i .fc
"D to
Regulated economics
New units, 3.5% S in coal
Annual values discounted at 10% to initial yr
Process A -A
Process B -
Limestone • wet scrubbing - x
30 MM
0
200
400 600
Power unit size, mw
800
1000
1200
122
Figure 82. Effect of Power Unit Size on Cumulative Present Worth of
Annual Net Increase or Decrease in Cost of Power Consumers
-------
10 MM
C
ra a
ll
E R
2 =
E 1-
o
Q.
0! o C
•S .E -2
III
•O
O
I 6 „•
ro *_i 0)
10MM
20 MM
30 MM
Regulated economics
500-mw new units
Annual values discounted at 10% to initial yr
Process A -A
Process B - a
Limestone - wet scrubbing - x
1
Sulfur in coal, %
Figure 83. Effect of Sulfur Content of Coal on Cumulative Present Worth of
Annual Net Increase or Decrease in Cost of Power to Consumers
0.50
•S | _ "g
9! o ° £
ID Q- C 3
£ M- O J3
O ° < —
I
I TD
II
M- 3
O -O
<$> =
S S
0.50
1.00
1.50
Regulated economics
3.5% S in coal
Process A -A
Limestone - wet scrubbing • x
Annual values discounted at 10% to initial yr
Operation at 35 yr at indicated hr
New units
0.187
-
0.187
0.375
o
a
"5 -£
200
400 600
Power unit size, mw
800
1000
0.561
1200
Figure 84. Effect of Operating Time on Present Worth of the
Cumulative Net Increase or Decrease in Cost of Power to Consumers
123
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30 MM
45 MM
Regulated economics
New units
3.5% S in coal
Annual values discounted at 10% to initial yr
Process A -A
Limestone - wet scrubbing - x
Net sales revenue varied by the amount indicated from that
obtained in the market study
200
1200
200
400 600
Power unit size, mw
800
1000
1200
Figure 85. Effect of Variation in Net Sales Revenue on
Cumulative Present Worth of the Annual Net Increase or Decrease
in Cost of Power to Consumers (Process A)
124
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45 MM
Regulated economics
New units
3.5% S in coal
Annual values discounted at 10% to initial yr
Process B - a
Limestone - wet scrubbing - x
Net sales revenue varied by the amount indicated from that
obtained in the market study
200
1000
1200
I
200
400 600
Power unit size, mw
800
1000
1200
Figure 86. Effect of Variation in Net Sales Revenue on
Cumulative Present Worth of the Annual Net Increase or Decrease
in Cost of Power to Consumers (Process B)
125
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RESEARCH AND DEVELOPMENT NEEDED
As would be expected in a conceptual design study,
confidence level is reduced by lack of complete design and
cost data. Further information is needed on several
variables to improve the assumptions made in the present
evaluation. Much of this is in process of development in the
current pilot plant study being carried out by TVA for
NAPCA on the scrubbing step; this study will provide data
on sulfite oxidation, dust removal, control of scrubber
liquor composition, and corrosion. In addition, the need for
further research on treatment of the scrubber effluent
solution should be considered. All the research needs, both
for the scrubbing and effluent treatment operations, are
listed for reference as follows.
Many of the variables involved in ammonia scrubbing
have been tested previously by other investigators.
However, some of the published data are conflicting and
many studies were carried out under process conditions
that do not appear applicable (for example, cooling the gas
to well below the wet bulb temperature). Therefore, it is
considered that further study is necessary.
Degree of Oxidation in Scrubber
In processes A and C (page 54), it was assumed that a
separate processing step would be required to convert the
ammonium sulfite-bisulfite in the scrubber effluent solution
to ammonium sulfate. If the oxidation could be
accomplished in the scrubber circuit with oxygen contained
in the boiler exhaust gas, the considerable investment and
operating costs for the oxidizer system would be
eliminated. Even if all the oxidation could not be carried
out in the scrubber circuit, partial oxidation would help
since it would reduce the size of the oxidizer section.
Riot plant data should be obtained on the effect of all
the variables that may effect oxidation rate, including
scrubber design, scrubber material, fly ash content of
scrubber liquor, addition of oxidation catalysts,
development of thiosulfate in the scrubber liquor, amount
of excess air in the boiler, concentration of solution in the
last liquor scrubbing stages, and pH of the scrubber liquor.
Adverse effects of such factors on scrubbing efficiency
would have to be evaluated against the benefit of increased
oxidation.
The possibility of crystallizing ammonium sulfate from a
scrubber side stream as a means of avoiding a separate
oxidizer should also be tested.
For process B (page 54), oxidation in the scrubber is
undesirable because formation of sulfate reduces the net
amount of sulfuric acid that can be produced. The
oxidation studies described above should also provide
information on methods for inhibiting oxidation in the
scrubber.
Control of Bisulfite:Sulfite Ratio
In process B, the amount of sulfuric acid available for
the fertilizer process depends on the ratio of
bisulfite:sulfite in the scrubber liquor. Although much
experimental work has been done on control of this ratio,
data on operation with boiler exhaust gas in scrubbers of
modern types are needed. Further information would be
helpful, for example, on the effect of number of stages, pH
and concentration in each stage, and liquor rates.
In contrast, bisulfite should be minimized for processes
A and C in order to take advantage of any increase in
scrubbing efficiency obtainable by use of high
sulfite:bisulfite ratio.
Dust Removal
The degree of dust removal desirable before the sulfur
dioxide scrubber depends both on effect of the dust on
oxidation and effect on the phosphate fertilizer process.
Tests on dust content of solutions in process A indicated
that up to 25% of the dust could be tolerated in the
phosphate process. Presumably this would be true also for
process B but confirming laboratory tests should be made.
As to process C, the economics may not be promising
enough to warrant further tests.
For existing plants already equipped with dust-removal
facilities, it has been assumed that no special wet-scrubbing
section would be needed for dust removal. In some plants,
however, the dust-removal efficiency of the dry collection
units is not as high as desirable so this load would be
thrown on the ammonia scrubbing system, which brings in
the problem of efficiently removing the finer dust particles
in a scrubber designed primarily for sulfur oxide
absorption. Riot scale or larger tests to determine the
optimum scrubber type for both functions are needed.
Composition of Scrubber Liquor at Steady State
For the operating modes assumed in the present study,
all the processes considered are once-through in regard to
the scrubber circuit, that is, the operation is not the
closed-loop type and there is no recycle from the scrubber
effluent treatment steps. Therefore, dissolved solids would
not be expected to accumulate in the scrubber liquor
except to the extent that recycle rate in the scrubber circuit
is larger than product draw-off rate and therefore allows
limited accumulation.
If the concept of crystallizing ammonium sulfate from a
scrubber side stream is practical, however, the system
would then be closed loop except to the extent mother
126
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liquor adhered to the crystals. In such case, studies would
be needed on the effect of dissolved solids buildup in the
liquor on scrubber operation and efficiency.
Corrosion
The equipment design in this study is based on providing
resistant materials of construction to avoid high
maintenance costs. If pH excursions could be eliminated
through adequate process control, plain steel equipment
probably could be used in most of the scrubber system and
significant investment savings would result. Pilot plant data
are needed to evaluate the possibility.
Optimization of Scrubber Operation
There are several further variables that obviously need
study in optimizing the scrubbing step, including scrubber
type, gas velocity, mist collector type, inlet gas
temperature, and point of ammonia addition. In regard to
the last of these, it was assumed in the present study that
some ammonia would be introduced ahead of the heating
coil (in the gas reheat loop) to prevent corrosion by sulfuric
acid mist. It might also be advantageous to introduce all the
ammonia feed ahead of the scrubber. It has been claimed
[by Kuhlmann (France)] that this converts most of the
sulfur oxides to solid particles of ammonium sulfite and
that collection of the solid particles in the scrubber is
relatively easy-a particulate removal operation rather than
gas absorption. This possibility should be tested.
Use of Ammonium Sulfate
The technology for use of ammonium sulfate in
processes A and B is well defined. Decomposition of
ammonium sulfate in process C to produce ammonium
bisulfate and use of the bisulfate to digest phosphate ore
are much less developed. Since the present study indicates
that the economics of the method are not promising, there
is some question as to whether any further research effort
should be made. The main question is whether or not the
relative lack of data unduly penalizes the process. Since the
method is primarily a fertilizer process, it seems best to
defer consideration in connection with the sulfur oxide
recovery problem. If the fertilizer industry develops the
method further and finds promise, it should then be
considered again.
127
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AND
In removing sulfur oxides from power plant stack gas,
wet scrubbing has several advantages over dry absorption,
including (1) better mass transfer, (2) easier absorbent
circulation and handling, (3) less trouble with loss of
absorbent in the gas stream leaving the system, (4) no
problem with physical deterioration of the absorbent.
Disadvantages include (1) necessity of reheating the gas and
(2) possibility of corrosion. However, the cost of reheating
is a relatively small part of the total cost and corrosion can
be eliminated by proper choice of materials.
Of the various absorbents that can be used in a scrubber
operation, alkali salts (ammonium, potassium, and sodium
compounds) are especially effective because of their
relatively high affinity for sulfur dioxide and the fact that
both the absorbent and product are soluble, thereby
avoiding the problems associated with using slurries.
Ammonia has some advantage over the other alkalis because
of its low cost. Moreover, the ammonia can be allowed to
pass on into the product and sold at a price higher than
initial cost, thereby avoiding problems in recycling the
absorbent. Sodium has little or no value in the product and
although potassium has fertilizer value the initial cost of the
type of compound required (potassium carbonate or
potassium hydroxide) is too high to make transfer to the
product economically feasible.
Scrubbing with ammonia gives a solution of ammonium
sulfite, ammonium bisulfite, and ammonium sulfate. There
are many ways of converting this solution to a salable
product. One of the more promising is conversion of the
sulfites to ammonium sulfate and use of the ammonium
sulfate in making a phosphate fertilizer. There are also
variations of this approach.
Process A—Direct oxidation of the sulfites to ammonium
sulfate and use of the resulting ammonium sulfate
solution to precipitate calcium in a nitric phosphate
process.
Process B—Acidification of the scrubber effluent with
sulfuric acid to evolve sulfur dioxide and convert the
ammonia to ammonium sulfate. The sulfur dioxide is
converted to sulfuric acid, part of which is used for the
acidification and the remainder, along with the
ammonium sulfate, in the nitric phosphate process.
Process C—Ammonium sulfate is obtained as in process A
above and is then converted to ammonium bisulfate by
heating. The bisulfate, which is quite acidic, is reacted
with phosphate rock (phosphate ore) and the acidulate
further ammoniated to give ammonium phosphate.
The present study indicates that process A has a slightly
better economic potential than process B and that both are
markedly superior to process C. In fact, process C shows
little economic promise under any of the combinations of
conditions evaluated, mainly because of relatively high
investment and low production volume.
It should be noted in regard to process C that process
data were scanty as compared with the other methods. It
may be that the indices assumed were too conservative, and
that further research and development would develop more
promise. This is primarily a matter for the fertilizer
industry, however, for the process can be carried out
without use of ammonium sulfate from a power plant. If
the process is considered by the fertilizer industry to have
promise, and if further development indicates it can
compete with established phosphate processes, then it
should be considered again for use in conjunction with
ammonia scrubbing of power plant stack gas.
Investment for the entire operation-scrubbing,
conversion of sulfite to sulfate, and fertilizer production—is
relatively high because a finished product is made rather
than an intermediate such as sulfur or sulfuric acid; a major
portion of the investment—about 75%--is in the fertilizer
plant. Total investment ranges from $26.60-44.60/kw,
depending on plant size and process type; in comparison,
investment for limestone - wet scrubbing varies from
$8.20-13.10 for the same plant sizes. If the recovery system
is installed at the same time the power plant is built, some
reduction in investment is obtained because the precipitator
can be eliminated. The resulting range, after credit for the
precipitator, is $23.10-41.10/kw.
The high investment makes capital charges an important
part of total operating cost and consequently the method
of assessing capital charges has a major effect on process
profitability. Project financing was evaluated on three
different bases.
1. All investment by a fertilizer company.
2. Cooperative venture in which the power company
would finance the scrubbing and oxidation portions and the
fertilizer company would build the fertilizer plant only.
3. All investment by the power company.
Since the power company investment presumably would
be incorporated into the rate base, depreciation is
considerably less than that usual in the unregulated
fertilizer industry; the annual rates assumed were 2.85 and
10%, respectively. Other items also differ, giving total
capital charges of 6.5% for power company operation (not
including interest, return on equity, or income tax) and
12% for the fertilizer company.
The estimated operating costs vary not only because of
difference in capital charges among the financing bases
assumed but also because the three processes make
128
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different types of fertilizer and different amounts/unit of
power production. Hence the only valid comparisons are
those concerned with cash flow (net income plus
depreciation) per unit of investment. As a matter of
perspective, however, it is of interest to note that overall
operating cost/ton of coal burned ranges from $4.57-11.97,
as compared with $1.46-1.80 for limestone - wet scrubbing
(average over life of the power plant, for which average
operating factor is relatively low). This indicates the
magnitude of the revenue that must be obtained from sale
of product to offset operating cost.
The price obtainable for the product varies with product
type (ratio and concentration of plant nutrients) and
pricing strategy (competitive products aimed at in
marketing). Net revenue is also affected by product volume
(larger tonnage requires larger sales area and consequent
higher freight cost). For a plant located in the Midwest, the
most favorable location, the best market strategy appears to
be pricing for competition with ammonium nitrate. Prices
obtainable on this basis are estimated at $42.79-5 5.09/ton
of fertilizer. The netback price (return to manufacturing)
ranges from $33.40-46.30/ton.
Another finding in the market study is that not more
than about three 500-mw plants using process A could be
accommodated in the midwestern part of the country
under the marketing strategy assumed. Several more would
be feasible, perhaps up to 10, if the product price were
lowered to allow competition with diammonium
phosphate. However, the price reduction required, about
$9/ton of 28-14-0 product, would have a drastic adverse
effect on economics. Fertilizer markets in other parts of the
country might support a few more scattered 500-mw-size
recovery plants but profitability would be poorer than in
the midwestern area.
Profitability based on the estimated market prices (for
ammonium nitrate competition) is affected by several
factors, including (1) plant size, (2) sulfur content of coal,
(3) average operating factor over the life of the power
plant, and (4) power plant status (new or existing at the
time of recovery unit installation). The sensitivity of
economic promise (expressed as projected interest rate of
return, which takes into account the time value of money)
to these factors is illustrated by the following.
Chanqe in factor
From To
500 1,000
3.5 5.0
Existing New
5,000 7,000
Percentage increase
in interest rate
of return, %
110
100
30
36
Plant size, mw
Sulfur content of coal, %
Status
Operating factor, hr/yr
These figures are only typical, of course, as the effects are
interdependent; the magnitude of each depends on the level
of the other factors.
It is concluded that plants of 200-mw equivalent size do
not break even (in the sense of lifetime net income
exceeding costs) under any circumstances. Most of the
500-mw combinations (for processes A and B) do better
than break even but do not generate enough profit to pay a
return on equity capital sufficient to attract investment.
This is true for both the all-fertilizer and the cooperative
ventures (no major difference between the two).
Under a few extreme combinations of conditions, the
cash flow may be sufficient to make the venture attractive
enough to generate the necessary capital. For example, a
new 500-mw unit burning coal containing 5.0% sulfur pays
out the investment in 6.6 yr and gives an 11.4% interest
rate of return; a new 1000-mw unit burning more typical
coal (3.5% S) pays out in 6.4 yr at 12.0% interest rate of
return (both for process A). These profit levels might be
acceptably high under some circumstances but they appear
to be lower than average. There is no set level, of course,
below which a company turns down a venture because of
lack of promise; much depends on the situation. A payout
of 5 yr and an interest rate of return of 15% seem to be
reasonable rough averages for minimum levels required in
industrial practice. At the current high interest rates, a
shorter payout and higher interest rate of return may well
be necessary.
For an operation such as pollution abatement, there is
always the possibility of accelerated depreciation being
allowed, which is, in effect, a reduction in income tax in
the early yrs of operation. No attempt has been made in the
present study to make a detailed analysis of the effect of
such acceleration. However, for the two examples given
above, allowance of 5-yr depreciation would make the
project pay out in about 5 yr-an attractive investment
opportunity. In contrast, for a 500-mw new unit burning
3.5% sulfur coal, payout would require 7.7 yr even with the
allowance of 5-yr depreciation; in this case, gross income is
so relatively small that income tax is not a major cost
factor.
It is concluded that even with accelerated depreciation,
the basic economics are not very promising for fertilizer
industry participation. The situation would be improved if
the power producer paid to the fertilizer company a service
charge for pollution abatement, or, if in a joint project the
power company transferred the ammonium sulfate solution
at a discount. The upper limit of such a payment or
discount would be the cost of abating pollution by
limestone - wet scrubbing.
On this basis, the prospect is much better although still
not highly promising. For all-fertilizer operation and
assuming payment by the power company of the full cost
of limestone - wet scrubbing, a new 500-mw unit burning
3.5% sulfur coal (process A) would pay out in 6.1 yr and
give a 13.0% interest rate of return. For a 1000-mw unit on
the same basis, the respective figures are 4.9 yr and 17.9%.
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It is concluded that fertilizer industry participation in
sulfur recovery, by the methods evaluated in the present
study, is somewhat questionable from the economic
standpoint. The relatively high investment required and the
resulting high cash flow projection needed to attract capital
are major obstacles. This does not rule out the possibility,
however, that in some situations (probably limited in
number) particular sets of conditions will be favorable
enough to make project financing possible.
For power industry financing, the fact that profit is
much less significant makes the economic approach quite
different. The investment in recovery facilities presumably
would be incorporated in the rate base, on which, in
principle, a reasonable rate of return is allowed by the
regulatory authority. The main question in regard to sulfur
recovery is whether the net cost situation would be better
or worse than for limestone - wet scrubbing, which
currently appears to be the most economical alternate to
recovery.
On this basis, all 200-mw installations considered in the
present study would cost more to operate than for the
limestone process. For the base case (500-mw, process A,
new power plant, 3.5% S in coal), the two methods are
almost a toss-up, one more costly during some yrs of the
operating life and the reverse in other yrs. On a present
worth basis (discounted at 10%), process A loses $17.2
million over the 35-yr life and lime scrubbing costs $16.9
million. All 1000-mw units, plus 500-mw with 5.0% sulfur
in coal, show a major advantage for recovery for either
process A or B.
Hence for power units of about 600 mw and larger in
size, processes A and B can be considered as ways of
reducing the cost of sulfur dioxide control and would be
attractive ventures. With fertilizer industry participation,
1000-mw installations are required before the economics
begin to justify the venture. This reflects the effect of
regulated profits.
There are opportunities for improving the economics
further. For example, if some way could be found to
operate the recovery unit fairly uniformly rather than in
accordance with the declining load factor of the power
plant, a major advantage would be obtained. High-sulfur
coal is also quite advantageous; higher sulfur content
increases revenue much more than it increases operating
cost.
The economics are quite sensitive to the price assumed
for the product. Even a 10% increase over the price level
assumed would bring units as small as 300 mw into
consideration for recovery, and at about 800 mw there
would even be the prospect of making enough profit to
reduce the cost of power (after paying the usual return on
investment allowed to the power industry). On the other
hand, a 10% lower price level would increase the power unit
critical size (breakeven between recovery and lime
scrubbing) to about 850 mw. The estimate of future price
was the best that could be developed but, like any such
long-term estimate, it could well be off by 10% or more.
It should be noted that even under the best conditions,
processes A and B will not be widely applicable. The
fertilizer market can absorb the output from only a few
500-to 1000-mw installations.
Further research on the processes is needed, most of
which is planned in the current NAPCA-TVA pilot plant
program. In addition, the approach of eliminating the
oxidizer by crystallizing ammonium sulfate from the
scrubber liquor should be worth further study. Finally,
design and cost studies should be carried out on other ways
of treating the scrubber effluent solution, including
acidification with nitric acid or phosphoric acid to make
ammonium nitrate and ammonium phosphate, respectively.
The latter might be especially promising if the evolved
sulfur dioxide could be fed into a sulfur-burning sulfuric
acid plant where the full amount of sulfuric acid needed for
the phosphoric acid would be made, which should greatly
reduce the cost of converting the sulfur dioxide to acid.
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REFERENCES AND ABSTRACTS
1. Aerojet-General Corporation. "The Applicability of
Aqueous Solutions to the Removal of S02 from Flue
Gases." Special Report S-4850-01-1, 7 pp. (June 21,
1968) (unpublished).
It was sought to determine whether C02 would
replace SO2 in an aqueous solution, and decrease the
capacity of the solution for absorbing SO2. Calcium or
magnesium oxide slurries in excess of the amount of
SQz present will absorb CO2 and be converted into
carbonates. There js a moderate possibility of
precipitating calcium sulfite even in fairly dilute
solutions.
2. Alabama Power Company. "New Process of Fertilizer
Manufacture Announced." Mfr. Rec. 92(26), 53 (Dec.
29,1927).
A process for making ammonium phosphate is
described. Phosphate rock is digested with a strong
solution NH4HSO4 giving CaS04, H3PO4, and
(NH4)2SO4; excess NH3 is added, precipitating
(NH4)3P04 which is separated and converted by heat
to diammonium phosphate. The CaSO4 product is
reconverted to ammonium sulfate by reaction with
C02 and NH 3. Finally the ammonium sulfate is heated
to 300° C with formation of NH3 and NH4HSO4.
3. Andrianov, A. P., and Chertkov, B. A. "Ammonia
Recycle Method for the Sulfur Dioxide Absorption
Method from Flue Gases." Khim. Prom, 1954(7),
394-401.
Flue gas is purified by cooling with water and
neutralizing with NH3.
4. Anonymous. "Smelters Poised for Move into Sulfur."
Can. Chem. Process. 52(3), 63-65 (Mar. 1968).
A special report is given on the plans of some
Canadian ore processors to reclaim sulfur from
smelting operations.
5. Bergwerksverband zur Verwertung von Schutzrechten
der Kohlen technik GmbH (by A. Adelsberger, O.
Grosskinsky, W. Klempt, and H. Umbach).
"Ammonium Sulfate Recovery from Flue Gases." Ger.
Pat. 962,253 (Apr. 18,1957).
SO2 in flue gas is absorbed by NH3-containing
solutions, then oxidized. The ammonium sulfate
formed is separated by evaporation. The NHj
concentration of the absorbing liquid is 1.3-2.1
moles/mole SO2.The ammonium sulfite solution is
neutralized with NH3, oxidized by air or O2 in a
tower, and the crystalline product contains 90% of the
S02 of the flue gas.
6. Burgess, W. D. "S02 Recovery Process as Applied to
Acid Plant Tail Gas." Chem. Can. (June 1956), 116,
118,120.
The Cominco process for recovering S02 from tail
gas containing 1% S02 is described. The gas is collected
in a flue, discharged into a tower where it is scrubbed
with ammonium sulfite-bisulfite solution; NH3 is
added to maintain the concentrations; the mixture is
discharged into a tower, 93% H2SO4 is added yielding
S02 and converting the solution to ammonium sulfate.
The ammonium sulfate is saturated with SO2 so this is
stripped. The ratio is ammonium sulfate 56 parts to
SO2 44 parts.
7. Chertkov, B. A., Aristov, G. E., and Puklina, D. L.
"Absorption of Sulfur Dioxide from Flue Gas in a
Bubble-Type Absorber." Khim. Prom, 1956, 19-25.
The process was studied in the laboratory with 4-6
perforated plates, hole diameter 4-5 mm. With 6 plates,
linear gas velocity 2.4 m/sec, total bubbler resistance
150-200 mm water, temperature 30-33°, 90% of the
SO2 can be extracted, and the absorbing ammonium
sulfite-bisulfite becomes saturated. Foaming depends
on gas velocities, and occurs only in a narrow range.
Absorption rate is 10-20 times the rate in a
checkerwork absorber.
8. Chertkov, B. A. "Oxidation of Ammonium
Sulfite-Bisulfite Solutions." /. Appl. Chem. USSR
30(10), 1564-72 (1957).
Ammonium bisulfite is oxidized preferentially. In
the range of ammonium bisulfite content 63-100%,
which is the range of practical importance, the
oxidation rate of the solution increases sixfold. If free
H2SO3 is present in addition to ammonium bisulfite,
the oxidation rate decreases to complete cessation of
oxidation, because of the sharp decrease in pH.
Solution concentration has a complex influence on the
oxidation rate; it depends on the rate of access of
oxygen from the air. At a concentration of sulfite and
bisulfite in the range of 2-3 moles/1, the oxidation rate
is maximum, and it is at a minimum at very
concentrated and very dilute concentrations.
9. Chertkov, B. A. "Kinetics of Absorption of S02 from
Dilute Gaseous Mixtures." Vestn. Tekhn. i Ekon.
Inform,, Mezhotrasl. Lab. Tekhn.-Ekono. Issled. i
Nauchn.-Tekhn. Inform., Nauchn.-hsled. Fiz.-Khim.
Inst. 1958(5), 7-9.
The rate of absorption of SO2 was controlled
mainly by the resistance of the gaseous boundary film.
The study was made in a packed absorber of 0.6 m
diameter. The more concentrated solutions had greater
capacity. For each original SO2 concentration, the
optimum concentration of NH, salts and S/C ratio
must be selected; 10-12 moles NH3/100 moles H20
and S/C ratio = 0.93-0.95 are used for 0.3-0.4% S02.
131
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In the regeneration solution the SC^NHa must be
0.78-0.8 at 400-500 mm Hg pressure.
10. Chertkov, B. A., Puklina, D. L., and Pekareva, T. I.
"The pH Values of Ammonium Sulfite-Bisulfite
Solutions." /. Appl. Chem. USSR 32(6), 1417-19
(1959).
A study was made of the pH over the range of
0.5-1.2, ratios of SO2:NH3. Determination of the pH
of the solution is considered a simple, dependable
means of determining approximate compositions,
instead of resorting to complex chemical analyses.
11. Chertkov, B. A. "The Influence of S02 Concentration
in a Gas on Its Rate of Absorption by Different
Solvents." Khim. Prom. 1959(7), 586-91.
The mass transfer coefficient remains constant
during the variation of the initial SO2 concentration
from 0.08 to 3.5% by volume. At higher initial SO2
concentrations, a constant decrease of the coefficient is
observed.
12. Chertkov, B. A. "Removal of SO2 from Flue Gases in a
Perforated Plate Bubble Absorber." Khim. Prom.
195 9(5), 413-17.
In a six-stage bubble absorber at optimum
conditions the average coefficient of absorption of S02
is 21 kg S02/m3 x hr x mm Hg, which is 13 times
higher than in a packed column absorber. The fly ash is
collected in the first two or three stages.
13. Chertkov, B. A. "Theory of the Oxidation of
Sulfite-Bisulfite Solutions." J. Appl. Chem. USSR
32(12), 2687-90 (1959).
An explanation is given for the so-called
"catalytic" role played by thiosulfate in the general
mechanism for the oxidation of sulfite-bisulfite
solutions, which is supported by experimental results.
The presence of thiosulfate as impurity is due mainly
to the spontaneous decomposition of the
thermodynamically unstable bisulfite. The catalytic
action exerted by the thiosulfate is linked with its
participation in the continuous thiosulfate-trithionate
conversion, facilitating the more rapid oxidation of the
sulfite-bisulfite solution.
14. Chertkov, B. A. "Effects of Temperature and Partial
Pressure of Oxygen in the Gas on the Oxidation Rate
of Ammonium Sulfite-Bisulfite Solutions." /. Appl
Chem. USSR 32(1), 78-85 (1959).
An empirical relation was derived which can be
used for the estimation of the oxidation rate of the
solution at any given temperature if the oxidation rate
of the solution at any other temperature is known.
Increasing 02 partial pressure in the gas increases the
oxidation in the solution.
15. Chertkov, B. A. "Use of Paraphenylenediamine as
Oxidation Inhibitor for Ammonium Sulfite-Bisulfite
Solutions." /. Appl Chem. USSR 32(5), 975-82 (1959).
It is most effective as an oxidation inhibitor when
added to pure solutions, not contaminated with solid
impurities. When ash from flue gases is present, for
example, the efficiency is reduced three to four-fold.
The inhibitor effect is evident both under static
conditions and in a cyclic process in the extraction of
SO2 from flue gases.
16. Chertkov, B. A. "Oxidation of Ammonium
Sulfite-Bisulfite Solutions in the Extraction of S02
from Flue Gases." /. Appl. Chem. USSR 32(5), 983-87
(1959).
Practical data on the oxidation in packed
absorbers is analyzed. The degree of oxidation of the
absorbed SO2 can be lowered considerably if the
absorption is effected in a bubbler absorber operated
under foam conditions.
17. Chertkov, B. A., and Puklina, D. L. "Effect of
Temperature on the Rate of SO2 Absorption from
Gases." J. Appl Chem. USSR 33(1), 7-10(1960).
Laboratory experiments were conducted to obtain
data of effects of temperature change alone on the rate
of S02 absorption. Temperature had a strong effect
especially on saturated solutions with a ratio SO2 :NHa
= 0.936. The mass transfer coefficient fell from 10 to 2
moles/m2 x hr x % S02 over the range 23-52° C. The
strong effects are ascribed to the strong increase of
equilibrium SO2 vapor pressure with temperature
increase, and also with increase in the SO2 :NH3 ratio.
18. Chertkov, B. A. "Influence of Absorbent Composition
on the Rate of Absorption of S02 from Gases." Khim.
Prom. 1960,223-27.
The coefficient of mass transfer K is not constant,
but depends on the free chemical capacity and
viscosity of the absorbent.
19. Chertkov, B. A. "Mass Transfer Coefficient for the
Absorption of S02 in a Multistage Absorber." Khim.
Prom. 1960,559-62.
K, for gases containing 0.35-2.56% SOj, is
independent of the initial concentration of S02. hi a
six-stage absorber with gas velocities of 2-2.3 m/sec at
room temperature, K = 1450 to 1970 moles/m2 x hrx
% SO2, and 91.2% S02 was absorbed.
20. Chertkov, B. A. "General Equations for the Oxidation
Rate of Sulfite-Bisulfite Solutions in the Extraction of
SO2 from Gases." /. Appl. Chem. USSR 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.
132
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Oxidation rate Go2 = 0.8 Q°'7 a(S/CV^
a M
a = constant
Q = liquor rate ir^/rn2 /hr
a = d
M = viscosity
21. Chertkov, B. A., and Pekareva, T. I. "Density and
Viscosity of Ammonium Sulfite, Ammonium Bisulfite,
and Ammonium Sulfate Solutions." J. Appl. Chem.
USSR 34(1), 135-41 (1961).
The density and viscosity of
(NH4)aSO3-NH4HSO3 process liquors and artificial
solutions were measured over a wide range of total salt
concentration. The process liquors contained
considerable amounts of (NH4)2S04 and small
amounts of ammonium thiosulfate. The SO2:NH3
effective ratio was maintained roughly constant to
correspond to the compositions of saturated and
regenerated liquors in the cyclic NH3 process for the
extraction of SO2.
22. Chertkov, B. A. "Problem of Using Waste Sulfurous
Gases and Protecting the Atmosphere Against
Pollutants." Khim. Prom. 1962, 336-38.
The need for economical recovery of SO2 on a
large scale and possible uses of SO2 are discussed.
23. Chertkov, B. A., and Dobromyslova, N. S. "The
Influence of Traces of Sulfate on the Partial Pressure of
S02 Over Ammonium Sulfite-Ammonium Bisulfite
Solutions." /. Appl Chem. USSR 37(8), 1707-11
(Aug. 1964).
When the concentration of ammonium sulfate
present is greater than the concentration of the
sulfite-bisulfite, or in a dilute solution, or in processes
in which the solutions obtained approach a state of
equilibrium with the gas of a given concentration, the
partial pressure of SO2 over the solution may be
affected seriously by changes in the concentration of
ammonium sulfate.
24. Chertkov, B. A. "Coefficients of Mass Transfer in
Absorption of S02 from Gases by Ammonium
Sulfite-Bisulfite Solutions." /. Appl. Chem. USSR 37,
2404-10(1964).
Equations are given for the calculation of partial
coefficients of mass transfer in the gas phase in
absorbers of different dimensions for alkaline
absorbents. The overall coefficient of mass transfer
decreases with increasing saturation of the absorbent
and with approach to equilibrium with the absorbed
gas.
25. Colls, E. A. G. "Corrosion-Resistant Material and
Coatings in Trail Chemical Operations." Trans. AME
187, Minirlg Engineering, pp. 491-94 (Apr. 1950).
Corrosion in the Trail plant is discussed. The most
costly materials are cheaper in the long run. Steel
towers lined with lead and acidproof brick are used for
absorption of S02. Sulfite solution coolers have
aluminum tubes. Ammonium sulfate is handled in 316
stainless steel. The cooler for SO2 gas is cast iron.
26. Cominco Ltd. "The Story of Cominco." Chemical and
Fertilizers Division, part 5, chap. 33-34. Can. Mining J.
75, 287-91 (May 1954).
S02 recovery systems are discussed;
concentrations of S02 in the gas are low; S02 is
absorbed in ammonium sulfite (made from NH3 and
ammonium bisulfite); ^804 is added to the liquor
giving ammonium sulfate and concentrated S02;
products are ammonium sulfate and r^SO,^. NH3 is
used to scrub all outlet gases.
27. Cominco Ltd. "Cominco's Fertilizer Operation."
Nitrogen 35, 22-27,29 (May 1965).
A review is given of the large chemical and
metallurgical production at Trail. The process for the
recovery of ammonium sulfate and SO2 by the
acidulation of ammonium bisulfite solutions with
H2S04 is described.
28. Craxford, S. R., Poll, A., and Walker, W. J. S.
"Recovery of Sulfate from Flue Gas by the Use of
Ammonia." /. Inst. Fuel XXV(141), 13-14 (Jan.
1952).
A description of the Simon-Carves and Fulham
Borough plant for NH3 scrubbing at a fuel research
station is described. Exit gas contained 0.0005% S02,
or 99% removal. The use of Mn catalyst was effective
in promoting oxidation, but it was found that, after
the equipment had corroded, the Fe oxide in the
system was a good catalyst.
29. Earhart, J. P. (National Air Pollution Control
Administration, U. S. Department of Health,
Education, and Welfate, Cincinnati, Ohio). Private
communication to C. C. Shale of the Morgantown Coal
Research Center, May 5, 1969; enclosure entitled
"Discussion of Gaseous Ammonia for Flue Gas
Desulfurization," 19 pp.; copy of letter and enclosure
received by A. V. Slack May 26, 1969.
This is a critical review of the data in USBM RI
3339, with additional calculations on the
thermodynamics of the system.
30. Egan, E. P., Jr. "Removal of S02 from Stack Gases."
Tennessee Valley Authority Progress Report Assembly
No. 47B, (Oct. 1955-Feb. 1968) (unpublished).
Thermodynamic calculations were made of the
removal of S02 from stack gases by the addition of
NH3 (one of a number of possible processes) into the
gas at a point of favorable temperature to form solid
ammonium sulfite. The stack gases usually contain
10-20 times as much CC^ as S02, and it was necessary to
determine whether the thermodynamics favored the
reaction of NH3 with SO2 rather than CO2.
133
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31. English, G. E., and Van Winkle, M. "Efficiency of
Fractionating Columns." Chem. Eng. 70(23), 241-44,
246 (Nov. 11,1963).
A correlation equation was developed to give
values for Murphee vapor plate efficiencies of
fractionating columns. Experimental data and
calculated properties were used. Variables having a
definite effect on efficiency are weir height, contact
area of vapor and liquid phases, relative vapor and
liquid rate, surface tension, viscosity and density of the
liquid, liquid diffusivity, and relative volatility.
32. Federal Power Commission. "Statistics of Privately
Owned Electric Utilities in the United States." FPC
S-186 (1966). Superintendent of Documents, U. S.
Government Printing Office, Washington, D. C. 20402.
Composite statements are given for utility
companies of class A (> 2.5 million dollars operating
revenue) and class B (1.0-2.5 million dollars operating
revenue). Historic tables for the last 30 yr, charts of
most operations, balance sheets and other details are
included.
33. Federal Power Commission. "Statistics of Publicly
Owned Electric Utilities in the United States." FPC
S-188 (1966). Superintendent of Documents, U. S.
Government Printing Office, Washington, D. C. 20402.
The 560 publicly owned utilities (498 municipals
and 62 Federal), for which financial and operating
information is presented in this volume, reported total
electric revenues of $2.2 billion for sales of 297 billion
kwh to an average of 6.7 million customers during
1966.
34. Fedor, W. S. "Chemical Firms' Financial Performance
Matches Other Industries'." Chem. Eng. News 46(21),
20-26 (May 13, 1968).
A financial analysis of 35 major chemical and
allied products companies for 1963-1967, performed
by a CEN computer, is presented.
35. Gardiner, R. A. "Process of Making a Mixed Phosphatic
and Nitrogenous Fertilizer." U. S. Pat. 1,258,106 (Mar.
5, 1918). 2pp.
Ground apatite was fused with ammonium sulfate;
the temperature was increased to the decomposition of
ammonium sulfate (about 400° C). Extraction of P
was more complete if the apatite was ignited to 900° C
before the reaction with ammonium sulfate. *
36. Gordeev, L. S., and Chertkov, B. A. "Investigation of
the Steady State Characteristics of a Process for
Obtaining 100% S02 from Ammonium Bisulfite." Int.
Chem. Eng. 7(4), 634-36 (Oct. 1967).
A study was made for optimizing an existing
process for the recovery of S02 from ammonium
bisulfite solutions. Liquid flow rate, boiling point, and
S/C ratio are important variables. Aiming for the
maximum possible plant efficiency is not advisable,
since this leads to a sharp decrease in capacity and a
deterioration of the quality of the spent solutions.
37. Gottfried, J., Nyult, J., and Hayerova, Z. "Research of
the Phase Equilibrium in the Ammonium
Sulfate-Ammonium Sulfite-Ammonium Bisulfite-Water
System." Chem. PrumyslNo. 3, 149-51 (1966).
The equilibrium was studied at 40, 50, 60, 70,80,
and 90° C. Synthetic solutions were prepared by
saturating dilute aqueous NH3 with gaseous S02. The
concentration range of the solutions was SO2:NH3 =
0.9, 0.8, 0.7; 0.3. Solubility data were obtained. Phase
diagrams are given. The solubility of ammonium sulfate
was independent of the ratio ammonium
sulfite: ammonium bisulfite.
38. Grigoryan, G. O., Karakhanyan, S. S., Mirumyan, R.
L., and Makhtesyan, I. M. "Processing of Common
Salt. VI-Decomposition of Apatite Concentrate by
Ammonium Bisulfate with an Increase in Acid
Normality and Establishment of Optimal Conditions
for Filtration and Washing of the Resulting Filter
Cake." Arm. Khim. Zh. 20(2), 157-63 (1967).
The highest decomposition (96-98%) and better
filterability were obtained when 140-144 parts H2S04
(as NH4HSO4) was used/100 parts apatite by wt (1 hr,
at 98°); three stages of countercurrent washing were
used.
39. Hamelin, R. (Ugine Kuhlmann, Paris, France). Private
communication, May 1969.
40. Hangebrauck, R. P., and Spaite, P. W. "Pollution from
Power Production." Paper presented at the National
Limestone Institute Convention, Washington, D. C.,
January 21-23, 1970.
Predictions of source of fuel for power generation
and effect on total emission of SO2 and NOX are
presented. Methods of controlling air pollution by S02
from power plant stack gases are discussed. Cost
estimates are included. Emphasis is placed on
limestone-based processes and on improved methods of
removing particulates. Of the three pollutants, S02, N
oxides, and particulates, it is indicated that the most
immediate and serious problem is posed by SO2. The
most comprehensive program of control technology
development at present is aimed at SO2 control.
41. Hein, L. B., Phillips, A. B., and Young, R. D.
"Recovery of SO2 from Coal Combustion Stack
Gases." IN Problems and Control of Air Pollution
(Frederick S. Mallette, ed.), Reinhold, New York
(1955) pp. 155-69.
Pilot plant work was carried out on the absorption
step of the process for the recovery of SO2 from dilute
gases using actual combustion gas from high-sulfur
coal. The acidification and crystallization steps were
studied briefly. Gases from the boiler passed through a
dry cyclone dust collector, cooler, humidifier, cyclone
134
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collector for entrainment separation, a meter, then a
scrubber packed with 2 in. Raschig rings (depth varied
3-8 ft); scrubber liquor was distributed over the
packing with a cone distributor. Recirculation rate, pH,
concentration of the scrubber liquor, depth of packing,
and gas velocity in the scrubber were studied.
Optimum pH of liquor was 6.4; packing depth of 3 ft
was adequate for high liquor rates, which were around
3 gal/min/sq ft; the whole range of 1.4-3.5 ft/sec gas
velocity studied was satisfactory; recovery of SOj
added was 85%; NH3 losses were kept low by using
ammonium sulfite-bisulfite scrubber in a second stage.
42. Hori, S. (Kitazato University, Tokyo, Japan). Private
communication, December 12,1968.
43. JECCO process. "Ammonium Sulfate Production
Without Free Acid." Economic and Technical Monthly
-Japan 1(1), 22-23 (June 1952).
Ammonium sulfite solution is reacted with air or
02 to give ammonium sulfate. Atomized O2 bubbles
are introduced in the solution at 2-3 atm pressure.
44. Johnstone, H. F. "Progress in the Removal of S
Compounds from Waste Gases." Combustion 5(2),
19-30 (Aug. 1933).
The possibility of economically washing large
quantities of gases with water is very remote. The
limits imposed by the solubility of S02 from such
dilute gases are those of the quantity of water required,
and time and surface of contact needed. Bubble type
of washing was found to require the least time of
contact and smallest volume of washing space.
45. Johnstone, H. F. "Recovery of S02 from Waste
Gases." Ind. Eng. Ghent 27(5), 587-93 (May 1935).
The partial vapor pressure of the system
NHg-SOyH^O was studied at 35-90° C over a wide
range of NH3 concentrations and SO2 concentrations
in solution. The capacity to absorb 0.3% SO2 may be
as high as 8 lb/100 Ib solution.
46. Johnstone, H. F., and Keyes, D. B. "Recovery of S02
from Waste Gases." Distillation of a three-component
system NH3-SO2-H2O. Ind. Eng. Chem, 27(6), 659-65
(June 1935).
Methods of calculating theoretical plates, or values
of diffusional potential, in the regeneration of
solutions of NH4 sulfite-bisulfite saturated with respect
to a dilute SO2 gas are given. Though SO2 is less
volatile than H2O, its relative concentration in vapor
may be increased by the stripping action of vapor
countercurrent to the solution if no reflux is returned
to the top of the column.
47. Johnstone, tt F., and Singh, A. D. "Recovery of SC^
from Waste Gases; Design of Scrubbers for Large
Quantities of Gases." Ind. Eng. Chem. 29(3) 286-97
(Mar. 1937).
Measurements of the rates of absorption and heat
transfer, and of resistance to gas flow were made for
different systems. The most desirable packing for large
amounts of flue gas is composed of grids with 11A in.
channels and individual sections 4-6 in. high.
48. Johnstone, H. F. "Recovery of S02 from Waste
Gases." Ind. Eng. Chem. 29(12), 1396-98 (Dec. 1937).
Tests are reported on the effect of solvent
concentration on capacity and steam requirements of
sulfite-bisulfite solutions. There is an optimum
concentration of NH3 in the solution which produces
the maximum capacity and requires a minimum of
steam for regeneration; this is a function of the raw gas
composition and other operating conditions. For dilute
gases at high humidity, the optimum concentration can
be one-half the concentration of a saturated solution.
49. Johnstone, H. F., Read, H. J., and Blankmeyer, H. C.
"Recovery of SO2 from Waste Gases. Equilibrium
Vapor Pressures Over Sulfite-Bisulfite Solutions." Ind.
Eng. Chem. 30(1), 101-109(1938).
Partial vapor pressures are reported for a wide
range of concentrations and compositions of sodium
sulfite-bisulfite solutions and of methylamine
sulfite-bisulfite solutions at 35, 50, 70, and 90° C.
Other solutions, such as ammonium sulfite-bisulfite
solutions, were studied to show the effect of the nature
of the solution on the temperature coefficient of vapor
pressure of SO2. More steam was required for
regeneration of the solution for sodium or
methylamine than for ammonium solutions.
50. Johnstone, H. F. "Recovery of S02 from Waste
Gases." Pulp Paper Mag. Can. 53(4), 105-12 (Mar.
1952).
The possibility of recovering SO2 from waste gases
is reviewed as a source of SO2 for pulp mills.
Equilibrium vapor pressure of solutions of
NH3-S02-H20 system indicate that solutions of
bisulfite-sulfite can be used efficiently even if SO2
concentration is 0.4%. Modification of Trail process is
suggested. Half of S02 that is recovered is converted to
ammonium sulfate, the rest used as gas for preparation
of cooking liquor.
51. Johnstone, H. F., and West, W. E., Jr. "Recovery of
Sulfur Dioxide from Waste Gases." Unpublished
report, University of lEinois, Urbana, Illinois, 51 pp.
The equilibrium vapor pressures over solutions of
the NH3-SO2-H2O system indicate that these solutions
may be used to recover SO2 with good efficiency and
without serious loss of NH3, even if the concentration
of the original gas is as low as 0.4% SO2.
52. Karakhanyan, S. S., Grigoryan, G. 0., and Makhtesyan,
I. M. "Processing of Common Salt. Hi-Decomposition
of Apatite Concentrate with Ammonium Bisulfate."
Izv. Akad. Nauk Arm. SSR, Khim. Nauk 18(5), 516-20
(1965).
135
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Apatite was decomposed by varying the reaction
temperature, contact time, and ammonium bisulfate
concentration. Optimum conditions were 95°, 2 hr,
and 60% ammonium bisulfate; ratio of NH4HS04 to
apatite was 164-100 parts by wt.
53. Karakhanyan, S. S., and Grigoryan, G. O. "Processing
of Common Salt. IV-Decomposition of Apatite
Concentrate with an Ammonium Sulfate Mixture and
the Chemistry of the Process." Izv. Akad. Nauk Arm.
SSR, Khim. Nauk 18(5), 521-28 (1965).
Apatite was decomposed with a mixture of
ammonium sulfate and ammonium bisulfate with a
molar ratio of NH3:H2S04 of 1:1.33. Treatment with
50-55% of the sulfate solution, in an amount
equivalent to the amount of H2SO4 needed for
superphosphate manufacture, decomposed 93.4% of
the apatite in 1 hr at 90° C. When NH4HSO4 was used
alone, only 80-83% was decomposed.
54. Karakhanyan, S. S., Grigoryan, G. 0,, and Mirumyan,
R. L. "Processing of Common Salt. V—Preparation of a
Nitrogen-Phosphorus Fertilizer by Decomposition of
Apatite Concentrate with Ammonium Bisulfate." Izv.
Akad. Nauk Arm. SSR, Khim. Nauk 18(6), 615-20
(1965).
Reacting apatite with 50-56% ammonium bisulfate
for 2 hr at 95-98° gave 97-99% decomposition of the
apatite.
55. Kashtanov, L. I., and Ruizhov, V. P. "The Kinetics of
Oxidation of Gaseous S02 in Aqueous Solutions, and
Poisoning of Manganese Sulfate by Phenol." Izvestiya
Tephtekh. Inst. No. 7, 37 (1935).
The oxidation processes occurring in the
absorption of SO2 are similar to those of H2SO3
solutions. Ratio of oxidation decreases with increase in
stream velocity. Desorption ratio decreases with higher
S02 concentration in the solution. Mn sulfates increase
oxidation velocity by 100%. Presence of phenols in the
solution inhibits autoxidation of SO2 ; oxidation rate is
lowered with higher concentrations of phenol. Action
of catalysts is completely inhibited in presence of 0.1%
phenol. An insignificant phenol concentration sharply
lowers autoxidation velocity in presence and absence
of Mn. Phenol concentration of > 0.1% has practically
no effect on oxidation processes.
56. Kennaway, T. "The Fulham-Simon-Carves Process for
the Recovery of S from Flue Gases." /. Air Pollution
ControlAssoc. 7(4), 266-74 (Feb. 1957).
A summary is given of the the development of
S02 pollution control in England. The Battersea
effluent process (scrubbing with Thames River water);
the Howden ICI cyclic lime process (scrubbing with
circulating lime water); and the Simon-Carves process
pilot plant at Fulham (scrubbing with NH4 liquors,
then autoclaving to yield ammonium sulfate and
sulfur).
57. King, R. A. "Economic Utilization of SO2 from
Metallurgical Gases." Ind. Eng. Chem. 42(11), 2241-48
(Nov. 1950).
The development of a process for the removal of
SOz from spent gases is described. Important factors
were the availability of NHs for absorption; of H2S04
for acidification of absorbing solutions to release the
S02; and the fact that Trail was already producing and
marketing ammonium sulfate. Less than 9% of the
sulfur charged to the recovery unit was lost to the air.
58. Kyongshin, Yun. "Aqueous Ammonium Sulfate
Solutions." Ger. Pat. 1,275,036 (Aug. 14,1968).
Aqueous ammonium sulfate solutions are
produced by quantitative oxidation of ammonium
sulfite solutions with oxygen at 1 atm and 20-70° C
using heavy metal oxides and sulfides of group V-VIII
metals.
59. Lawler, W. C. "Use of a SO2 Scrubbing System in
Air-Pollution Control." IN Problems and Control of
Air Pollution (Frederick S. Mallette, ed.), Reinhold,
New York (1955), pp. 222-24.
The Olin-Mathieson development work on the
Corm'nco system of SO2 recovery with ammonium
sulfite-bisulfite solutions is described.
60. Lepsoe, R, and Kirkpatrick, W. S. "SO2 Recovery at
Trail." Trans. Can. Inst. Mining Met. XL, 399404
(1937).
An outline is given of the SO2 recovery
operations, particularly the absorption and reduction
plants; 450 tons/day of sulfuric acid and 45 tons/day
of sulfur are produced. A concentrated ammonium
bisulfite solution is the product of the absorption
system. It is acidified in a packed tower with sulfuric
acid, yielding ammonium sulfate and 100% S02 gas.
The SO2 is reduced to sulfur in an incandescent coke
bed.
61. Lonza Elektrizitaetswerke und Chemische Fabriken A.
G. (by A. Egger). "Removal of Sulfur Oxides from
Gases Containing CO2." Swiss Pat. 357,825 (Dec. 15,
1961).
Stack gases containing SO2 were scrubbed with
NH4 sulfate-sulfite-bisulfite-carbonate solution at pH
5.5-6.5, yielding ammonium sulfite and bisulfite which
were subsequently oxidized to ammonium sulfate.
After separation of the product the mother liquor was
recycled.
62. Manderson, M. C. "The Sulfur Outlook." Chem. Eng.
Progr. 64(11), 47-48 (1968).
The sulfur shortage is no longer a problem, and
industry is now moving into a surplus situation.
Various sources will meet a demand growth of
4.75%/yrtol971.
63. Manvelyan, M. G., Grigoryan, G. O., and Karakhanyan,
S. S. "Processing of Common Salt. II-Decomposition
136
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of Ammonium Chloride by Sulfuric Acid with
Production of Ammonium Bisulfate and Hydrogen
Chloride." Izv. Akad. Nauk Arm. SSR, Khim. Nauk
18(1), 92-95 (1965).
With a 1:1 mole ratio of NH4C1:H2S04, 93.5%
H2S04 decomposed the NH^Cl almost completely in 1
hr at 150°forming HC1 and ammonium bisulfate. With
100% H2 S04 the decomposition time was % hr.
64. Mascarello, J., and Auclair, J. "Sulphur Oxides
Removal from Flue Gases in the Large Power Plants of
Electricite de France." Paper presented at the
American Power Conference, Chicago, Illinois, April
22-24, 1969.
Most of the plants burn fuel oil. The removal
process consists of adding NH3 to the stack gas when it
leaves the air heater, ahead of a primary scrubber.
Products are ammonium sulfite, bisulfite, and sulfate.
S02 is recovered by steam stripping. In a second phase
the liquors are treated with a lime slurry to recover
NH3. Precipitated calcium sulfate and sulfite and fly
ash are discarded. Investment and operating costs are
estimated.
65. Mitchell, D. A. "The Use of Nitric Acid in the
Manufacture of Fertilisers." Paper presented at the
British Engineering Event in Mexico, February 12-16,
1968.
Principal methods of producing P fertilizers are
reviewed. Nitric phosphate manufacture is described,
principally the Odda process in various forms, and the
NP/ASU process involving nitric phosphate sulfate
recycle. A Dutch State Mines nitric phosphate unit is
mentioned which uses byproduct ammonium sulfate
from a caprolactam plant, and less contaminated
ammonium sulfate from byproduct gypsum.
66. Nakagawa, S. "Removal and Utilization of S02 in
Stack Gas by the JECCO Process." Ryusan 16,211-18
(1963).
S02 removal by NH4 sulfite solution or milk of
lime is used in this process; ammonium sulfate or
gypsum is produced by oxidation with air or oxygen.
67. Nakagawa, S. "Sulfur Dioxide Gas in Exhaust Smoke;
Its Removal, Recovery, and Utilization." Japan
Analyst 15(8), 872-81 (Aug. 1966).
The need for SO2 pollution control is discussed.
Several methods of absorption and reaction, recovery
of products, and regeneration of reactants are
described.
68. Nakagawa, S. (Japan Engineering Consulting Company,
Tokyo, Japan). Private communication, 1968.
69. Newall, H. E. "Ammonia Process for Removal of S02
from Flue Gases." IN Problems and Control of Air
Pollution (Frederick S. Mallette, ed.), Reinhold, New
York (1955), pp. 170-90.
The Fulham-Simon-Carves process is described; it
involves the scrubbing of flue gases with a concentrated
solution of ammonium salts and the addition of NH3
gas to the liquor.
70. Newell, J. E. "Making Sulfur from Flue Gas." Chem.
Eng. Progr. 65(3), 62-66 (Aug. 1969).
A description is given of a design study for a plant
using the alkalized alumina process to recover sulfur. A
typical station with four 500-mw units, burning coal
containing 2.3% S is assumed as the source of flue gas.
Regenerators are designed to use fluidized bed heaters.
x An economic evaluation is given.
71. Perry, H., and De Carlo, J. A. "The Search for
Low-Sulfur Coal." Mech. Eng. 89(4), 22-28 (Apr.
1967).
Economic aspects of air pollution by SO2 are
discussed. Sources of coal of low S content are
reviewed, and the means of removal of S from coal
before combustion or from the flue gas afterwards are
evaluated.
72. Ramsey. "Use of the NH3-S02-H20 System as a Cyclic
Recovery Method." Brit. Pat. 1,427 (1883). See:
"Recovery of SO2 from Waste Gases." Johnstone, H.
F.,Ind. Eng. Chem. 27(5), 587-93 (May 1935).
73. Rees, R. L. "Removal of S02 from Power-Plant Stack
Gases." IN Problems and Control of Air Pollution
(Frederick S. Mallette, ed.), Reinhold, New York
(1955), pp. 143-54.
Flue gas washing processes are described that
involve use of water, lime slurries, ammonia solutions,
or sodium sulfite-bisulfite slurries combined with zinc
oxide slurries for recovery of sulfur.
74. Ross, W. H., Merz, A. R., and Jacob, K. D.
"Preparation and Properties of the Ammonium
Phosphates." Ind. Eng. Chem. 21(3), 286-89 (1929).
Methods of preparation of three series of
salts-meta-, pyro-, and orthophosphates of
ammonium—are described and the properties are
outlined. Particular attention is given to those
compounds which are useful as concentrated fertilizers.
75. Rumanian Minstry of Petroleum Industry and
Chemistry. "Ammonium Sulfate." Brit. Pat. 1,097,257
(Jan. 3, 1968).
At 60-80° C, S02 from residual gases was
absorbed in presence of 0 in an ammoniacal solution
containing 5-35% wt NH3 in the presence of activated
charcoal and H3P04. Ammonium sulfate containing
1% ammonium sulfite is recovered.
76. Scott, W. D., and McCarthy, J. L. "The System
S02-NH3-H20 at 25° C." Ind. Eng. Chem.,
Fundamentals 6(1), 40-48 (Feb. 1967).
Experiments were conducted using modified
standard procedures to obtain IR absorption spectra,
pH values, and electrical conductivity data for
137
-------
solutions over the entire range of mole ratio NH3:S02.
It was determined that H2SO3, NH4OH, and S2OS~
do not exist in the solution system to any appreciable
extent, and that, at pH values of > 4.2 and < 9.5 H+
and OH' exist in only negligible amounts.
77. Sunderhauf, Frantisek (Fuel Research Institute,
Prague, Czechoslovakia). Private communication, May
1969.
78. Tans, A. M. P. "A New Type of Nomogram-Aqueous
Ammonium Sulfate Solutions." Ind. Eng. Chem. 50(6),
971-72 (June 1958).
The density, vapor pressure, and viscosity of
solutions of varying concentration at different
temperatures are included in one nomograph.
79. Tarbutton, G., Driskell, J. C., Jones, T. M., Gray, F. J.,
and Smith, C. M. "Recovery of Sulfur Dioxide from
Flue Gases." Ind. Eng. Chem. 49, 392-95 (Mar. 1957).
A simple, direct acid process for recovery of SO2
was studied. A small amount of ozone was added to
flue gas and the mixture was scrubbed in a packed
tower with H2S04 solution containing Mn. Maximum
concentration of Hj SO4 obtained was about 40%. SO2
recovery was higher when more dilute acid was used as
a scrub liquor.
80. Tennessee Valley Authority. Progress Report Assembly
No. 47A (Feb. 1954-Sept. 1955) (unpublished).
"Recovery of Sulfur Dioxide from Flue Gases."
Miscellaneous small-scale, bench-scale, and pilot
plant tests on the recovery or removal of S02 from
flue gases are described. The effects of use of HN03,
MnSO4, solid MnO ore, or nascent 0 in the scrubbing
system, or a supported Pt or Cu catalyst in the hot gas
stream were investigated. A scrubbing tower containing
lumps of MnO ore was tested with promising results.
81. Tennessee Valley Authority. Applied Research Branch
monthly progress reports (Oct.-Nov. 1967; Jan. 1968)
(unpublished).
Small-scale tests of reactions of phosphate rock
with hot ammonium bisulfite solutions are described.
Use of S02 to produce sulfuric acid for fertilizer
production was also investigated.
82. Tennessee Valley Authority. "Sulfur Oxide Removal
from Power Plant Stack Gas: Sorption by Limestone or
Lime-Dry Process" (1968). Report No. PB 178-972,
Clearinghouse for Scientific and Technical
Information, 5285 Port Royal Road, Springfield,
Virginia 22151.
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.
83. Tennessee Valley Authority. "Sulfur Oxide Removal
from Power Plant Stack Gas: Use of Limestone in
Wet-Scrubbing Process" (1969). Report No. PB
183-908, Clearinghouse for Scientific and Technical
Information, 5285 Port Royal Road, Springfield,
Virginia 22151.
Use of limestone or lime in a wet scrubber is one
of the more promising methods of recovery of S02,
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 converts 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.
84. Tennessee Valley Authority. "Economic Factors in
Recovery of Sulfur Dioxide from Power Plant Stack
Gas." Paper presented at the 62d annual meeting of Air
Pollution Control Association, New York, New York,
June 22-26, 1969.
Methods for determining the capital and operating
costs for S02 removal processes are presented. Both
throwaway- and recovery-type processes are
considered. The importance of load factor, return on
investment and marketing is discussed.
85. Toyo Koatsu Industries, Inc. (by M. Okuide, T.
Tanaka, and O. Shigeno). Jap. Pat. 19,824 (Oct. 19,
1961).
Ammonium sulfate solutions containing
ammonium sulfite and (NH4)2S406 were electrolyzed.
Most unstable S compounds were oxidized. A
noncorrosive ammonium sulfate solution was obtained.
86. United States Department of Agriculture.
"Consumption of Commercial Fertilizers in the United
States." Year ended June 30, 1967, 11 pp.
Totals of consumption of fertilizer, of N, of P, of
K, and of primary plant nutrients are each tabulated by
states. Some distinction of sources is made.
87. United States Department of the Interior. Bureau of
Mines Report of Investigations No. 3339. "Fixation of
Sulfur from Smelter Smoke." (May 1937), 51 pp.
The present status of sulfur fixation and plans of
investigations are discussed. In the Guggenheim
process, ammonium sulfite solution absorbs SOj
yielding ammonium bisulfite which, on heating, gives
off SOj with regeneration of the sulfite. Vapor
pressures and thermodynamic properties of ammonium
sulfites were determined. Four crystalline compounds
are discussed: (NH4)2SO3, (NH4)2SO3-H20,
NH4HSO3, and (NH4)2S20S. The last-named is the
only one that was found to decompose directly into its
138
-------
gaseous components; this was the only one whose
vapor pressure could be measured. The recovery of
sulfur in solid compounds (sulfites) by the addition of
NH3 and water vapor to smelter gas is described. Such
a process should be cyclic to permit reuse of NH3. It
was found that if sufficient moisture is present and an
efficient system of baffles is used, practically complete
precipitation takes place. If the temperature is below
50° C, losses of ammonium sulfite will be fairly large.
The oxidation of ammonium sulfite solution is
discussed.
88. United States Department of Interior. Bureau of Mines
Report of Investigations No. 5469. "Cost Estimates of
Liquid Scrubbing Processes for Removing Sulfur
Dioxide from Flue Gases." (1959), 51 pp.
Estimated capital and operating costs are reported
for removing SO2 from flue gases of a power plant of
120-mw capacity by liquid purification processes, using
limestone, ammonia, or sodium sulfite as the reactant.
89. Vasilenko, N. A. "The System Ammonium
Sul fate-Ammonium Sulfite-Ammonium
Bisulfite-Water; a 30° Isotherm." /. Appl. Chem. USSR
26(6), 601-603 (1953).
These phases were found in equilibrium with the
solutions at the junction points of the diagram at 30°
C:
Liquid phase: (NH4)2SO3 25.74, (NH4)2S04
24.33 wt %; no NH4HSO3;
Solid phase: (NH4)2S04 + (NH4)2S03-H2O
Liquid phase: (NH4)2SO4 6.52, NH4HS03 73.83
wt%;no(NH4)2S03;
Solid phase: (NH4)2SO4 +(NH4)2S20S
Liquid phase: (NH4)2S03 12.75, NH4HSO3
66.73 wt %; no (NH4)2S04,;
Solid phase: (NH4)2SO3 -H2O + (NH4)2S205
90. Vian-Ortuno, A., and Martin-Municio, V. (to Empresa
Auxiliar de la Industria, S. A.). "Method for Oxidizing
Ammonium Sulfite to Ammonium Sulfate." U. S. Pat.
3,330,620 (July 11,1967).
An organic, N-containing base, such as pyridine, is
dispersed in a solution of ammonium sulfite to
completely oxidize the sulfite to sulfate at 80-90° C.
The amount used is 10-80% of the volume of the
dispersion.
91. Volgin, B. P., Efimova, T. F., and Gofman, M. S.
"Absorption of SO2 by Ammonium
Sulfite-Ammonium Bisulfite Solutions in a Venturi
Scrubber." Int. Chem. Eng. 8(1), 113-18 (Jan. 1968).
A venturi scrubber was said to be 6 times as
effective as a bubble-type absorber, and 60 times as
effective as a packed absorber, although the resistance
is also higher by 38%. The venturi data are based on
small-scale apparatus and are compared with larger
scale data.
92. Vorlander, D., and Lainau, A. "The Oxidation of
Ammonium Sulfite to Ammonium Sulfate by Means of
Air, in the Presence of Mineral Salts." /. Prakt. Chem.
123(2), 351-76(1930).
A literature survey with 20 references on
oxidation of ammonium sulfite to ammonium sulfate is
given. Tests were made using air and/or mineral salts.
CoSO4 was the best catalyst, optimum pH 8.4, and the
effect was detectable at very low concentrations.
93. Wallis, E. "Atmospheric Pollution and the Zinc
Industry." Chem. Ind. (London) No. 41, 1271-73 (Oct.
8,1955).
Exit gases from a contact sulfuric acid plant were
treated to remove SO2. In the first step, 32,500 cu
ft/min exit gas was scrubbed with an ammonium
sulfite-ammonium bisulfite solution; then the liquor
was acidified to give ammonium sulfate and SO2. The
ammonium sulfate was stripped of S02 with air and
passed to a crystallizer.
94. West, W. E., Jr., Thesis "Evaluation of Sulfur Dioxide
Recovery Processes." University of Illinois, Urbana,
Illinois (195 3), 99 pp.
Economic comparisons of eight processes are
given: Trail (hot gases); Trail (cool gases); steam
stripping + acidification; acidification + steam
stripping; acidification + steam stripping—SO4~
removal by cooling and crystallization; low SO2
recovery, low SO4" production; autoclave; and air
oxidation of the rich effluent.
95. Wood, C. W. (Simon Engineering, Ltd., Stockport,
England). Private communication, January 7,1969.
96. Yamamoto, M. (Mitsubishi Shoji Kaisha, Ltd., Tokyo,
Japan). Private communication, March 19, 1969.
139
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APPENDIX A
OPTIMUM PRICING STRATEGY
Fertilizer products generally have low values/unit wt. As
a result, the spatial aspects of marketing are important. In
deciding how to market a product, the firm must consider
the alternatives of intensive vs extensive marketing. Under
intensive marketing, the tendency is to sell large quantities
of product close to the point of production. This results in
low transportation costs, but also low product prices.
Under extensive marketing, the tendency is to "skim the
cream" from the market at any given point and ship the
product as far as necessary to dispose of it. This results in
higher transportation costs, but higher product prices. In
choosing its optimum strategy, the firm substitutes
extensive marketing practices for intensive ones until the
marginal value added to net revenue from each is equated.
A number of pricing strategies are found in the fertilizer
industry. Four alternative strategies for pricing, the
byproducts in question are considered in this appendix: (1)
delivered price competitive with ammonium nitrate, (2)
delivered price competitive with diammonium phosphate,
(3) dual zone pricing (combination of 1 and 2), and (4) fob
pricing. The desirability of each strategy is quantified in
terms of the amount of revenue that is generated by the
sale of a given quantity of product. A single production
location is considered and the potential market is composed
of all points in the area surrounding the production point.
It is assumed that all market points are similar in the
quantities and types of fertilizer consumed. It is also
assumed that the prices of competing products are the same
at all market points. As a result of the above assumptions,
the demand curve (maximum price a blender can pay for a
given quantity of product) at each market point is the same
for all points. From the prices in table 23 (see main text) and
the assumed densities 0.25 and 1.00 ton of N/sq mi, the
demand curve for each byproduct can be derived. The
demand curve for 28-14-0 is shown in figure A-l. At prices
greater than $52.47/ton, consumption density is zero. At
prices greater than $43.49/ton but less than $52.47/ton,
consumption density is 0.25 ton of 28-14-0 N/sq mi or
0.893 ton of product/sq mi. In this price range blenders
substitute 28-14-0 N for ammonium nitrate or other
straight N. At prices less than $43.49/ton blenders use only
28-14-0 N for a density of 1.00 ton of N/sq mi or 3.57 tons
of 28-14-0/sq mi. At lower prices, higher densities can be
expected but this portion of the demand curve was not
included in the present study.
In choosing a pricing strategy the firm must face the
realities expressed in the demand curve for its product.
While the firm would like a very high price, such a strategy
would result in no sales or zero revenue. At a price of
$52.47 (P,), figure A-l shows that the revenue from the
point in question will be $46.85/sq mi [P,Dj = (52.47)
(0.25)/(0.28) = 46.85]. (Dx is the ratio of consumption
density to N content of the product.) At a slightly lower
price there is no increase in density so revenue decreases.
Obviously the firm wants the maximum price for a given
density. But suppose price is lowered to $43.49 (P2); the
revenue then is
P2Dz = (43.49)(1.00)/(0.28) = $155.32/sq mi,
which is an increase of
P2D2-PiD, = 155.32 46.85 = $108.47/sq mi.
Marginal revenue (Pk) at a given market point is the change
in total revenue/unit change in density,
* ATRk,PkDk-Pk-»Pk-i
ADk Dk-Dk.!
For example,
P* = 52.47 (since Do = O)
and,
* 43.49(1. 00)- 52.47C25)
2" 1.00 -.25 ~40'50'
which uses nitrogen consumption densities, since the
nitrogen content (.28) cancels out. Marginal revenue from
adding a new market point-going from Do=0 to Dj =.89-is
$52.47/ton, while marginal revenue from selling more
product at a given point-going from Dj=.89 to
D2=3.57-is only $40.50/ton. Hence, if a new market point
can be added without increasing distribution cost it would
pay to do so.
Distribution cost to a point r miles from the
production point is defined as,
TDCk (r) = m(PkDk) + (ho + hr)Dk)
where,
m = sales cost, %
ho = handling cost, $/ton
h= transportation cost, $/ton-mile.
Total returns to manufacturing from a given market point is
total revenue at that point (P\J\) minus total distribution
cost,
140
-------
60 .-
PI = $52.47/ton
c
o
00
CN
J
P2 = $43.49/ton
>! = 0.25/0.28 = 0.89 j
I
40
D2 =1.00/0.28 = 3.57
2 3
Consumption density
(tons of 28-14-0/sq mi)
Figure A-1. Demand for 28-14-0 at a Given Market Point
141
-------
TRMk(r)=[(l-m)Pk-h0-hr]Dk.
Marginal returns to manufacturing at a given point is,
ADk Dk - Dk.!
= (l-m)Pk-h0-hr,
which is analogous to and contains marginal revenue, Pk.
It was shown above that if distribution costs are ignored,
then it pays to supply the lower density DI and receive the
higher price PI. However, when market radius reaches R^,
which just equates the marginal returns to manufacturing
MRM2 (o) and MRMj (Rf), then it pays to supply points
near the plant at the higher density Dj . This critical radius
can be seen to be,
Once this critical radius is exceeded, the firm supplies
additional product in such a manner as to maintain the
equality,
MRM1(R1) = MRM2 (R2),
where Rx and R2 are the radii of the markets in which the
densities Dt and D2 are supplied. Given the above linear
distribution cost model, the optimum relationship between
these two radii can be shown to be the constant,
R2 = Rj - Rc! > 0,
where R2 cannot be negative. The above pricing strategy is
called dual zone delivered pricing, though for small
quantities of product there may actually be only one zone,
and for large quantities a third zone might pay.
Dual zone delivered pricing maximizes the firm's total
return to manufacturing a given quantity of product and
hence is the firm's optimum pricing strategy. To see this it
is first necessary to construct the firm's total returns to
manufacturing function, which is the sum of returns over
all market points. In general, the firm's market consists of
concentric circles with radii,
R = Rl>R2> ... >RS>RS+I = O,
in which the appropriate densities are,
DS>DS-I> ...>D2> D,>DO = O.
Total returns to manufacturing is found by polar
coordinate integration to be,
S 2ir Rk
TRM = V C f TRMk O) rdr dB
i « «
k=i o Rk+1
S 2?r Rk
C C MRMk(r)ADkrdrd0,
k=i o o
where the angle 0 is the direction of any market point
from the plant. The quantity of product is calculated in an
analogous manner as,
S 1-n Rk
x=X \ \ °k rdr de
k=i o Rk+,
S 2?r Rk
= V 0 C ADkrdrd0.
k=i ° °
When evaluating the above integrals between 0 and Rk,
it is convenient to define added quantities of product as,
2?r Rk
Xfc = \ \ ADk rdr de
o o
so that,
X =
k=i
It is also convenient to define market proportions as
xk=Xk/X,
so that,
k=i
When the above integrals are evaluated, it is found that,
S
TRM = [ (1-m) Pk - h0 - h 2/3Rk] Xk
k=i
142
-------
and,
ARM = (1-m) P! - ho - h ALHj
and
X =
4-
k=i
Note that the added quantity of product in the ktn market
(xk) is equal to the added density ADk times the area of the
kth circle. Average returns to manufacturing is,
ARM = TRM/X
S
k=i
where average returns in the kth market is,
ARMk = (1-m) Pk - h0 - h ALHk-
Average length of haul in the kth market is,
ALHk = 2/3Rk)
which is two-thirds of the market radius.
The total returns to manufacturing maximizing problem
can now be stated as: find positive values of Rk which
maximize TRM, given a quantity of product X. This
problem is equivalent to maximizing the Lagrangian
expression,
S 2?r Rk
TRM = V C ( (MRMk
k=i o o
rdr d0 + LX,
where the Lagrangian multiplier is L. By partial
differentiation under the integral, the first order
maximizing condition can be shown to be,
MRMk
= L (k=l,2,. . .,S),
Rk>0.
This is just the optimizing condition stated earlier, which is
to supply all markets in such a manner as to equate all
marginal returns to manufacturing. If this rule implies that
some Rk are negative, then these levels of density are not
supplied.
An alternative strategy is to maintain a uniform
delivered price. Actually this is the optimum strategy for
supplying relatively small quantities of product. Hence, by
setting (S=l) in the above results it is seen that,
X=D,7rR*,
since,
and
*
Pi=P»
D0 =
As a result,
ALHi= 2/3(X/7rDi )' n
= 0.3761 264(x/Di)1/2,
so that average length of haul increases in proportion to the
sq root of the quantity of product. Another pricing strategy
considered for comparative purposes is delivered pricing
competitive with diammonium phosphate. Average returns
to manufacturing are calculated under this strategy by using
the above formulas and (Pa ,D2).
Another pricing strategy, found in phosphate fertilizer
marketing, is to establish an fob price and let the buyer pay
the freight. This is probably the simplest strategy and
involves the smallest investment in a marketing
organization. Buyers arrange for their own transportation,
and the producer is relieved of the task of maintaining
delivered prices. The producer maximizes returns to
manufacturing by setting the price Pf at its maximum level
consistent with disposal of a given quantity of product.
This price is determined so as to obtain zero consumption
density on the boundary of the market, Rj miles out. This
means that the delivered product price at this distance must
just equal Pj.
At this distance density is D1( but at any greater distance
density is zero. If a small quantity of product is to be sold,
Pf may exceed P2 so that the quantity DI is purchased
at every point. However, as larger quantities are considered,
Pf is forced below P2. Such lower fob prices have a partially
compensating advantage in that density near the plant
increases to D2
density occurs,
equals P2 ,
The distance at which this increased
, is that at which delivered price just
At any greater distance the blender's price is above P2and
143
-------
he would purchase only the quantity Dl . The relationship
between these two market radii is thus,
P,
= P2 -
or
R, -R2=(P1-P2)/h
so that the difference between the two radii is constant.
Under the fob pricing strategy buyers near the plant pay
the lowest delivered prices and buyers on the edge of the
market pay the highest prices, but since the highest price
cannot exceed PI , all but the most distant buyers pay lower
delivered prices.
Under this fob pricing strategy, average return to
manufacturing is
ARMf = (i.m)Pf
Pf = Pt -ho-hR,
and the quantity of product is calculated as
where
R2 = R, - (Pj - P2)/h> 0.
The procedure for calculating average returns is to vary Ri
and find the resulting values of ARM and X.
Average returns to manufacturing under the four pricing
strategies discussed above are shown in figure A-2 for
different levels of N supplied as 28-14-0. Sales cost is
assumed to be 1 2% of price and transportation is assumed
to be by rail. The average length of haul in rail miles,
ALH*, has been found to closely approximate the
relationship,
ALH*=20+1.13ALH,
for a wide range of U. S. locations. Average transportation
cost for 50-ton rail shipments has been found to closely
approximate the relationship,
ATC = 0.883 + 0.01558ALH*,
for distances less than 350 miles. By substituting the first of
these linear approximations into the second, it is seen that
ho= 1.195
h= 0.0 176.
Consider first the alternative of fob pricing vs delivered
pricing at the high price Pj. The average returns from these
alternatives are,
ARMf = 0.88 [52.47 -1.20 - 0.0176Ri]
ARMf = 0.88(52.47) - 1.20 - 0.0176(2/3^ .
Sales cost under fob pricing is less, but transportation cost
is more in the sense that it is evaluated at the market radius
instead of the average length of haul. Under delivered
pricing, the firm averages out transportation cost by
charging nearby consumers higher prices. The fob pricing
strategy yields the greater average return as long as small
quantities of product are sold. Calculations based on the
above equations show that when market radius is less than
38 miles, fob pricing is the optimum strategy. Figure A-2
shows that fob pricing may again be better when very large
quantities of product are sold. For intermediate quantities,
however, losses up to about $1.90/ton result from fob
instead of delivered pricing.
It may be a natural tendency for a power company to
choose the simplest possible marketing strategy. With fob
pricing the firm need not be concerned with such things as
transportation, field storage, and service representatives.
The company just announces a price and those who want
the product buy it. The cost of this simplicity can be
significant, howevever, as seen in figure A-2.
The average returns which result if the firm markets its
product intensively are shown by the lower curve in figure
A-2. For the size plants to be considered; returns are
$5-6/ton lower if the higher density rather than the low
density is obtained. If very large quantities of product are
sold at a single delivered price, however, it eventually pays
to set the low rather than the high price. Of course, at such
volumes significant revenue is lost if dual zone pricing is not
attempted.
The optimum pricing strategy is clearly seen in figure
A-2 to be dual-zone delivered pricing, though for quantities
of N less than about 280,000 tons/yr (about one million
tons of 28-14-0 product), it pays to maintain only one
zone. Even for twice this much product, there is little
incentive to maintain a dumping zone near the plant. For
very large quantities of product, however, the benefits of
dual-zone pricing are significant. Dual-zone pricing is
optimum if it can be executed, but this pricing strategy is
not stable in the long-run. A tendency exists for product to
be purchased in the low-price zone and resold in the
high-price zone. Such arbitrage is limited only by the added
costs of reselling the product. In some cases reselling costs
may be sufficient to make arbitrage unprofitable, but in
other cases a third zone develops between the two main
zones in which price differences tend to be smoothed out.
The shaded area in figure A-2 represents the expected range
of average returns to manufacturing a given quantity of N
144
-------
in 28-14-0. It is likely that the firm can obtain returns near
the upper end of this range for the byproducts in question.
Formulas for calculating the optimum average returns to
manufacturing for each of the byproducts in question are
summarized in table A-l. These average returns are for a
single delivered price pricing strategy and are valid for
values less than the indicated critical values. For greater
values a dual-zone price strategy tends to be best. Critical
values are expressed as market radius, quantity of N,
quantity of product, and power plant size assuming 3.5%
sulfur coal. In the present study these critical values are not
exceeded, so that delivered pricing competitive with
ammonium nitrate is the best strategy.
Table A-1. Optimum Average Return to Manufacturing
For Alternative Byproducts, Where Values Less Than
The Indicated Critical Values Prevail
Grade
45
Delivered Price, $/ton
P,
Marginal Revenue, $/tona
P!
Critical Radius, mi
Critical Quantity of
Nitrogen, ton/yr
Critical Quantity of
Product, ton/yr
Critical Plant Size, mw
ARM = a-bx'/2
a
b
ALH=cx%
aPi = P! ; P2 = [(1.00P2 - ((USJPj)] /0.75.
bR? = (Pj - P*2) (0.88)/0.0176.
cAssuming 7,000 hr/yi and 3.5% S in coal.
4°
o
e
3
c
o 35
^
c
-------
APPENDIX B
COST ESTIMATES
Table B-1. Summary of Estimated Fixed Investment:3
Process A-Ammonia Scrubbing, 28-14-0 Fertilizer Manufacture
(200-mw existing power unit, 3.5% S in coal;
17.4 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 131,000
Scrubbers and fans (two 3-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 925,000
Stack gas reheat system (4 gas-liquid heat exchangers and circulating pumps) 670,000
Oxidizer system(suIf iter, solution storage, oxidizer, and pumps) 407,000
Subtotal direct investment 2,133,000
Engineering design 213,000
Contractor fees and overhead 321,000
Contingency allowance 213,000
Subtotal fixed investment 2,880,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,184,000
Nitric acid plant (60% nitric acid) 1,900,000
Extraction-filtration (equipment for acidification of phosphate rock,
ammonium sulfate addition, and gypsum filtration) 900,000
Neutralization-prilling (equipment for neutralization, evaporation
prilling, screening, and conveying product) 2,210,000
Bulk storage (storage and shipping buildings, 90 days' storage) 790,000
Waste disposal (gypsum and residual ash disposal system including
settling pond and land) 206,000
Subtotal direct investment 7,190,000
Engineering design 719,000
Contractor fees and overhead 1,012,000
Contingency allowance 719,000
Subtotal fixed investment 9,640,000
Total fixed investment for project 12,520,000
aBasis:
Stack gas reheat to 250 F. by indkect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
146
-------
Table B-2. Summary of Estimated Fixed Investment:3
Process A-Ammonia Scrubbing, 28-14-0 Fertilizer Manufacture
(500-mw new power unit, 2.0% S in coal;
24.8 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 141,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 2,060,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 518.000
Subtotal direct investment 4,219,000
Engineering design 337,000
Contractor fees and overhead 507,000
Contingency allowance 422.000
Subtotal fixed investment 5,485,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,267,000
Nitric acid plant (60% nitric acid) 2,420,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) ._ 980,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 2,720,000
Bulk storage (storage and shipping buildings, 90 days' storage) 1,010,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 225.000
Subtotal direct investment 8,622,000
Engineering design 690,000
Contractor fees and overhead 1,036,000
Contingency alowance 862.000
Subtotal fixed investment 11,210,000
Total fixed investment for project 16,695,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 15,790,000
aBasis:
Stack gas reheat to 250°F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
147
-------
Table B-3. Summary of Estimated Fixed Investment:3
Process A—Ammonia Scrubbing. 28-14-0 Fertilizer Manufacture
(500-mw new power unit, 3.5% S in coal;
43.4 tons/hr fertilizer)
Investment. $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 205,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 2,060,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 768,000
Subtotal direct investment 4,533,000
Engineering design 363,000
Contractor fees and overhead 541,000
Contingency allowance 453,000
Subtotal fixed investment 5,890,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,843,000
Nitric acid plant (60% nitric acid) 3,200,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,100,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 3,830,000
Bulk storage (storage and shipping buildings, 90 days' storage) 1,770,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 243,000
Subtotal direct investment 11,986,000
Engineering design 958,000
Contractor fees and overhead 1,437,000
Contingency allowance 1.199.000
Subtotal fixed investment 15,580,000
Total fixed investment for project 21,470,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 20,565,000
a Basis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
148
-------
Table B-4. Summary of Estimated Fixed Investment:3
Process A—Ammonia Scrubbing. 28-14-0 Fertilizer Manufacture
(500-mw existing power unit, 3.5% S in coal;
43.4 tons/hr fertilizer)
Investment. $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 228,000
Scrubbers and fans (four 3-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 2,150,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 768,000
Subtotal direct investment 4,646,000
Engineering design 465,000
Contractor fees and overhead 654,000
Contingency allowance 465,000
Subtotal fixed investment 6,230,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 2,047,000
Nitric acid plant (60% nitric acid) 3,200,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,100,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 3,830,000
Bulk storage (storage and shipping buildings, 90 days' storage) 1,770,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 243,000
Subtotal direct investment 12,190,000
Engineering design 1,097,000
Contractor fees and overhead 1,584,000
Contingency allowance 1,219,000
Subtotal fixed investment 16,090,000
Total fixed investment for project 22,320,000
a Basis:
Stack gas reheat to 250° F, by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location—1969 costs.
149
-------
Table B-5. Summary of Estimated Fixed Investment:3
Process A-Ammonia Scrubbing, 28-14-0 Fertilizer Manufacture
(500-mw new power unit, 5.0% S in coal;
62.0 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 262,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 2,060,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 991,000
Subtotal direct investment 4,813,000
Engineering design 385,000
Contractor fees and overhead 581,000
Contingency allowance 481,000
Subtotal fixed investment 6,260,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 2,356,000
Nitric acid plant (60% nitric acid) 4,000,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,360,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 4,760,000
Bulk storage (storage and shipping buildings, 90 days' storage) 2,530,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 275,000
Subtotal direct investment 15,281,000
Engineering design 1,222,000
Contractor fees and overhead 1,839,000
Contingency allowance 1,528,000
Subtotal fixed investment 19,870,000
Total fixed investment for project 26,130,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 25,225,000
^Basis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
150
-------
Table B-6. Summary of Estimated Fixed Investment:3
Process A—Ammonia Scrubbing, 28-14-0 Fertilizer Manufacture
(1000-mw new power unit, 3.5% S in coal;
86.8 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 315,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 3,340,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 2,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 1,255,000
Subtotal direct investment 7,410,000
Engineering design 519,000
Contractor fees and overhead 741,000
Contingency allowance 590,000
Subtotal fixed investment 9,260,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 2,831,000
Nitric acid plant (60% nitric acid) 4,480,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,660,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 7,600,000
Bulk storage (storage and shipping buildings, 90 days' storage) 3,320,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 301,000
Subtotal direct investment 20,192,000
Engineering design 1,413,000
Contractor fees and overhead 2,019,000
Contingency allowance 1,616,000
Subtotal fixed investment 25,240,000
Total fixed investment for project 34,500,000
Investment savings for 99% effective electrostatic precipitator (1,550,000)
Net fixed investment for project assuming precipitator savings 32,950,000
aBasis:
Stack gas reheat to 250° F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
151
-------
Table B-7. Summary of Estimated Fixed Investment:3
Process A-Ammonia Scrubbing. 28-14-0 Fertilizer Manufacture
(1000-mw existing power unit, 3.5% S in coal;
86.8 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 350,000
Scrubbers and fans (four 3-stage scrubbers with mist eliminators, exhaust fans
to stack, and pumps) 3,500,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 2,500,000
Oxidizer system (sulfiter, solution storage, oxidizer, and pumps) 1,255,000
Subtotal direct investment 7,605,000
Engineering design 608,000
Contractor fees and overhead 917,000
Contingency allowance 760,000
Subtotal fixed investment 9,890,000
28-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 3,145,000
Nitric acid plant (60% nitric acid) 4,480,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,660,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 7,600,000
Bulk storage (storage and shipping buildings, 90 days' storage) 3,320,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 301,000
Subtotal direct investment 20,506,000
Engineering design 1,640,000
Contractor fees and overhead 2,463,000
Contingency allowance 2,051,000
Subtotal fixed investment 26,660,000
Total fixed investment for project 36,550,000
aBasis:
Stack gas reheat to 250° F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
152
-------
Table B-8. Summary of Estimated Fixed Investment:3
Process B—Ammonia Scrubbing. 26-19-0 Fertilizer Manufacture
(200-mw existing power unit, 3.5% S in coal;
13.1 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 101,000
Scrubbers and fans (two 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 1,015,000
Stack gas reheat system (4 gas-liquid heat exchangers and circulating pumps) 670,000
Acidif ier system (solution storage, stripper, and pumps) 165,000
Subtotal direct investment 1,951,000
Engineering design 195,000
Contractor fees and overhead 293,000
Contingency allowance 195,000
Subtotal fixed investment 2,634,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 909,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 720,000
Nitric acid plant (60% nitric acid) 1,450,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 760,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 1,800,000
Bulk storage (storage and shipping buildings, 90 days' storage) 670,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 206,000
Subtotal direct investment 6,515,000
Engineering design 651,000
Contractor fees and overhead 977,000
Contingency allowance 651,000
Subtotal fixed investment 8,794,000
Total fixed investment for project 11,428,000
"Basis:
Stack gas reheat to 250° F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location—1969 costs.
153
-------
Table B-9. Summary of Estimated Fixed Investment:3
Process B-Ammonia Scrubbing. 26-19-0 Fertilizer Manufacture
(500-mw new power unit, 2.0% S in coal;
18.7 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 123,000
Scrubbers and fans (four 5-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,295,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Acidifier system (solution storage, stripper, and pumps) 220,000
Subtotal direct investment 4,138,000
Engineering design 331,000
Contractor fees and overhead 497,000
Contingency allowance 414,000
Subtotal fixed investment 5,380,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,112,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 890,000
Nitric acid plant (60% nitric acid) 1,800,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 820,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 2,220,000
Bulk storage (storage and shipping buildings, 90 days' storage) 775,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 225,000
Subtotal direct investment 7,842,000
Engineering design 627,000
Contractor fees and overhead 941,000
Contingency allowance 784,000
Subtotal fixed investment "10,194,000
Total fixed investment for project 15,574,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 14,669,000
aBasis:
Stack gas reheat to 2£OT. by indirect gas-iiquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
154
-------
Table B-10. Summary of Estimated Fixed Investment:3
Process B—Ammonia Scrubbing, 26-19-0 Fertilizer Manufacture
(500-mw new power unit, 3.5% S in coal;
32.8 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 175,000
Scrubbers and fans (four 5-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,295,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Acidifier system (solution storage, stripper, and pumps) 308,000
Subtotal direct investment 4,278,000
Engineering design 342,000
Contractor fees and overhead 513,000
Contingency allowance 428,000
Subtotal fixed investment 5,561,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,575,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 970,000
Nitric acid plant (60% nitric acid) 2,650,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 925,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 3,150,000
Bulk storage (storage and shipping buildings, 90 days' storage) 1,355,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 243,000
Subtotal direct investment 10,868,000
Engineering design 869,000
Contractor fees and overhead 1,304,000
Contingency allowance 1,087,000
Subtotal fixed investment 14,128,000
Total fixed investment for project 19,689,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 18,784,000
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
155
-------
Table B-11. Summary of Estimated Fixed Investment:3
Process B-Ammonia Scrubbing. 26-19-0 Fertilizer Manufacture
(500-mw existing power unit, 3.5% S in coal;
32.8 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 158,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,375,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Acidifier system (solution storage, stripper, and pumps) 308,000
Subtotal direct investment 4,341,000
Engineering design 434,000
Contractor fees and overhead 651,000
Contingency allowance 434,000
Subtotal fixed investment 5,860,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,322,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 970,000
Nitric acid plant (60% nitric acid) 2,650,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 925,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 3,150,000
Bulk storage (storage and snipping buildings, 90 days' storage) 1,355,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 243,000
Subtotal direct investment 10,615,000
Engineering design 1,062,000
Contractor fees and overhead 1,592,000
Contingency allowance 1,062,000
Subtotal fixed investment 14,331,000
Total fixed investment for project 20,191,000
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
156
-------
Table B-12. Summary of Estimated Fixed Investment:3
Process B-Ammonia Scrubbing. 26-19-0 Fertilizer Manufacture
(500-mw new power unit, 5.0% S in coal;
46.9 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 216,000
Scrubbers and fans (four 5-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,295,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 1,500,000
Acidifier system (solution storage, stripper, and pumps) 385,000
Subtotal direct investment 4,396,000
Engineering design 352,000
Contractor fees and overhead 528,000
Contingency allowance 440,000
Subtotal fixed investment 5,716,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,944,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 1,200,000
Nitric acid plant (60% nitric acid) 3,300,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,140,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 3,900,000
Bulk storage (storage and shipping buildings, 90 days' storage) 1,940,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 275,000
Subtotal direct investment 13,699,000
Engineering design 1,096,000
Contractor fees and overhead 1,644,000
Contingency allowance 1,370,000
Subtotal fixed investment 17,809,000
Total fixed investment for project 23,525,000
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 22,620,000
aBasis:
Stack gas reheat to 250°F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
157
-------
Table B-13. Summary of Estimated Fixed Investment:3
Process B-Ammonia Scrubbing. 26-19-0 Fertilizer Manufacture
(1000-mw new power unit, 3.5% S in coal;
65. 7 tons I hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 242,000
Scrubbers and fans (four 5-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 3,610,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 2,500,000
Acidifier system (solution storage, stripper, and pumps) 500,000
Subtotal direct investment 6,852,000
Engineering design 480,000
Contractor fees and overhead 685,000
Contingency allowance 548,000
Subtotal fixed investment 8,565,000
26-19-0 Fertilizer Manufacture
Yard, utilities,and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 2,178,000
Sulfuric acid plant for sulfur dioxide feed (93% acid) 1,390,000
Nitric acid plant (60% nitric acid) 3,820,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,400,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 6,300,000
Bulk storage (storage and shipping buildings, 90 days' storage) 2,560,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 301,000
Subtotal direct investment 17,949,000
Engineering design 1,256,000
Contractor fees and overhead 1,795,000
Contingency allowance 1,435,000
Subtotal fixed investment 22,435,000
Total fixed investment for project 31,000,000
I nvestment savings for 99% effective electrostatic precipitator (1,550,000)
Net fixed investment for project assuming precipitator savings 29,450,000
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
158
-------
Table B-14. Summary of Estimated Fixed Investment:3
Process B-Ammonia Scrubbing, 26-19-0 Fertilizer Manufacture
(1000-mw existing power unit, 3.5% S in coal;
65.7 tons/hr fertilizer)
I nvestment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 269,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 3,850,000
Stack gas reheat system (8 gas-liquid heat exchangers and circulating pumps) 2,500,000
Acidifier system (solution storage, stripper, and pumps) 500,000
Subtotal direct investment 7,119,000
Engineering design 570,000
Contractor fees and overhead 854,000
Contingency allowance 712,000
Subtotal fixed investment 9,255,000
26-19-0 Fertilizer Manufacture
Yard, utilities and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 2,421,000
Su If uric acid plant for sulfur dioxide feed (93% acid) 1,390,000
Nitric acid plant (60% nitric acid) 3,820,000
Extraction-filtration (equipment for acidification of phosphate rock, ammonium
sulfate addition, and gypsum filtration) 1,400,000
Neutralization-prilling (equipment for neutralization, evaporation prilling,
screening, and conveying product) 6,300,000
Bulk storage (storage and shipping buildings, 90 days' storage) 2,560,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 301,000
Subtotal direct investment 18,192,000
Engineering design 1,455,000
Contractor fees and overhead 2,183,000
Contingency allowance 1,819,000
Subtotal fixed investment 23,749,000
Total fixed investment for project 32,904,000
"Basis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal.pond distance of 1 mile.
Midwest plant location-1969 costs.
159
-------
Table B-15. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing. 19-14-0 Fertilizer Manufacture
(200-mw existing power unit, 3.5% S in coal;
8.1 to ns I hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 71,000
Scrubbers and fans (two 3-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 925,000
Stack gas reheat system (four gas-liquid heat exchangers and circulating pumps) 670,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 467,000
Subtotal direct investment 2,133,000
Engineering design 213,000
Contractor fees and overhead 321,000
Contingency allowance 213,000
Subtotal fixed investment 2,880,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 639,000
Crystallization-decomposition (double effect crystal I izers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 2,295,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 790,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 625,000
Bulk storage (storage and shipping buildings, 60 days' storage) 450,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 171,000
Subtotal direct investment 4,970,000
Engineering design 497,000
Contractor fees and overhead 745,500
Contingency allowance 497,000
Subtotal fixed investment 6,709,500
Total fixed investment for project 9,589,500
aBasis: o
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile
Midwest plant location-1969 costs.
160
-------
Table B-16. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(500-mw new power unit, 2.0% S in coal;
10.9 tons I hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 87,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,060,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 596,000
Subtotal direct investment 4,243,000
Engineering design 340,000
Contractor fees and overhead 509,000
Contingency allowance 424,000
Subtotal fixed investment 5,516,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 781,000
Crystallization-decomposition (double effect crystallizers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 2,653,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 825,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 760,000
Bulk storage (storage and shipping buildings, 60 days' storage) 600,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 182,000
Subtotal direct investment 5,801,000
Engineering design 464,100
Contractor fees and overhead 696,100
Contingency allowance 580,100
Subtotal fixed investment 7,541,300
Total fixed investment for project 13,057,300
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 12,152,300
aBasis:
Stack gas reheat to 250°F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
161
-------
Table B-17. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(500-mw new power unit, 3.5% S in coal;
19.2 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 123,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,060,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 883,000
Subtotal direct investment 4,566,000
Engineering design 365,000
Contractor fees and overhead 548,000
Contingency allowance 457,000
Subtotal fixed investment 5,936,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,107,000
Crystallization-decomposition (double effect crystallizers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 3,812,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 900,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 1,100,000
Bulk storage (storage and shipping buildings, 60 days' storage) 940,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 193,000
Subtotal direct investment 8,052,000
Engineering design 644,200
Contractor fees and overhead 966,200
Contingency allowance 805,200
Subtotal fixed investment 10,420,600
Total fixed investment for project 16,356,600
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 15,451,600
"Basis:
Stack gas reheat to 250 F- by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
162
-------
Table B-18. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(500-mw existing power unit, 3.5% S in coal;
19.6 tons/hr fertilizer)
Investment, $
Ammonia. Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 111,000
Scrubbers and fans (four 3-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,150,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 883,000
Subtotal direct investment 4,644,000
Engineering design 464,000
Contractor fees and overhead 697,000
Contingency allowance 464,000
Subtotal fixed investment 6,269,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 999,000
Crystallization-decomposition (double effect crystal I izers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 4,064,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 900,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 1,100,000
Bulk storage (storage and shipping buildings, 60 days' storage) 940,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 193,000
Subtotal direct investment 8,193,000
Engineering design 819,300
Contractor fees and overhead 1,229,000
Contingency allowance 819,300
Subtotal fixed investment 11,060,600
Total fixed investment for project 17,329,600
aBasis: o
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwestplant location-1969 costs.
163
-------
Table B-19. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(500-mw new power unit, 5.0% S in coal;
27.3 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 152,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 2,060,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 1,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 1,140,000
Subtotal direct investment 4,852,000
Engineering design 388,000
Contractor fees and overhead 582,000
Contingency allowance 485,000
Subtotal fixed investment 6,307,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,368,000
Crystallization-decomposition (double effect crystal I izers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 4,811,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 1,000,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 1,390,000
Bulk storage (storage and shipping buildings, 60 days' storage) 1,230,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 212,000
Subtotal direct investment 10,011,000
Engineering design 800,900
Contractor fees and overhead 1,201,300
Contingency allowance 1,001,100
Subtotal fixed investment 13,014,300
Total fixed investment for project 19,321,300
Investment savings for 99% effective electrostatic precipitator (905,000)
Net fixed investment for project assuming precipitator savings 18,416,300
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
164
-------
Table B-20. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(1000-mw new power unit, 3.5% S in coal;
37.1 tons/hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 170,000
Scrubbers and fans (four 4-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 3,340,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 2,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 1,440,000
Subtotal direct investment 7,450,000
Engineering design 522,000
Contractor fees and overhead 745,000
Contingency allowance 596,000
Subtotal fixed investment 9,313,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,530,000
Crystallization-decomposition (double effect crystal I izers, centrifuge,
decomposer, and solubilizing tank with heat supply and reclamation
system, and ammonium bisulfate solution storage) 5,863,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 1,100,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 1,870,000
Bulk storage (storage and shipping buildings, 60 days' storage) 1,670,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 228,000
Subtotal direct investment 12,261,000
Engineering design 858,300
Contractor fees and overhead 1,226,100
Contingency allowance 980,900
Subtotal fixed investment 15,326,300
Total fixed investment for project 24,639,300
Investment savings for 99% effective electrostatic precipitator (1,550,000)
Net fixed investment for project assuming precipitator savings 23,089,300
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
165
-------
Table B-21. Summary of Estimated Fixed Investment:3
Process C-Ammonia Scrubbing, 19-14-0 Fertilizer Manufacture
(1000-mw existing power unit, 3.5% S in coal;
38.3 tons I hr fertilizer)
Investment, $
Ammonia Scrubbing
Utilities and storage (ammonia storage and utilities distribution systems) 189,000
Scrubbers and fans (four 3-stage scrubbers with mist eliminators, exhaust fans
to stack, pumps, and ash disposal) 3,500,000
Stack gas reheat system (eight gas-liquid heat exchangers and circulating pumps) 2,500,000
Oxidizer system (solution storage, oxidizer, sulfiter, filter, and pumps) 1,440,000
Subtotal direct investment 7,629,000
Engineering design 610,000
Contractor fees and overhead 916,000
Contingency allowance 763,000
Subtotal fixed investment 9,918,000
19-14-0 Fertilizer Manufacture
Yard, utilities, and storage facilities (raw materials storage, railroad
unloading and shipping, utilities distribution) 1,701,000
Crystallization-decomposition (double effect crystal I izers, centrifuge,
decomposer, and solubilizing tank with heat supplyand reclamation
system, and ammonium bisulfate solution storage) 6,299,000
Extraction-filtration (equipment for acidification of phosphate rock by
ammonium bisulfate addition and gypsum filtration) 1,100,000
Neutralization-granulation (equipment for neutralization, granulation, recycle,
screening, and conveying product) 1,870,000
Bulk storage (storage and shipping buildings, 60 days' storage) 1,670,000
Waste disposal (gypsum and residual ash disposal system including settling
pond and land) 228.000
Subtotal direct investment 12,868,000
Engineering design 1,029,400
Contractor fees and overhead 1,544,200
Contingency allowance 1,286,800
Subtotal fixed investment 16,728,400
Total fixed investment for project 26,646,400
aBasis:
Stack gas reheat to 250 F. by indirect gas-liquid method.
Direct solids disposal as 10% slurry (no return of water but overflow neutralized).
Disposal pond distance of 1 mile.
Midwest plant location-1969 costs.
166
-------
Table B-22. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(200-mw existing power unit, 3.5% S in coal;
1 28, 600 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
45.5 M tons
60.9 M tons
2.5 M tons
48.8 M Ib
243 troy oz
70,000 man-hr
35.00/ton
12.88/ton
46.60/ton
0.20/lb
120/troy oz
4.50/man-hr
aBasis:
Remaining life of power plant—27 years.
Coal burned-554,400 tons/yr-0.792 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$12,520,000 fixed; $875,000 working.
bCost of electricity at power pknt bus bar.
1,592,200
784,400
117,900
9,800
28,900
2,533,200
315,000
12.385
6.100
0.917
0.076
0.225
19.703
2.449
Steam 471,200 M Ib 0.60/M Ib
Water 3,159,600 M gal 0.06/M gal
Electricity 36,617,000 kwh 0.006/kwhb
Maintenance
Labor and material
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
28-1 4-0 fertilizer
282,700
189,600
219,700
564,400
36,000
1,607,400
4,140,600
1,250,000
250,000
321,500
112,500
1 ,934,000
6,074,600
2.198
1.474
1.708
4.389
0.280
1 2.498
32.201
9.720
1.944
2.500
0.875
15.039
47.240
167
-------
Table B-23. Fertilizer Company Economics - Total Venture
AnnujlJVIanufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw new power unit, 2. 0% S in coal;
173,600 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
61.4 M tons
82.2 M tons
3.4 M tons
65.8 M Ib
325 troy oz
76,000 man-hr
640,290 M Ib
4,279,000 M gal
63,147,000 kwh
35.00/ton
12.48/ton
46.60/ton
0.20/lb
120/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
aBasis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr.
Power unit operating strea^n time-^7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$16,695,000 fixed; $1,170,800 working.
"Cost of steam from power plant cycle.
°Cost of electricity at power plant bus bar.
2,150,000
1,025,900
159,700
13,600
39,000
3,388,200
342,000
256,100
214,000
315,700
751,000
43,000
1,921,800
5,310,000
12.385
5.910
0.920
0.076
0.225
19.516
1.970
1.475
1.232
1.819
4.327
0.248
11.071
30.587
Depreciation at 1 0% 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 28- 14-0 fertilizer
1,669,500
333,900
384,400
134,500
2,522,300
7,832,300
9.616
1.923
2.214
0.775
14.528
45.115
168
-------
Table B-24. Fertilizer Company Economics - Total Venture -
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw new power
unit, 3.5% S in coal;
303,800 tons/ yr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Annual quantity
107.5 Mtons
143.9 Mtons
6.0 M tons
115.2M Ib
570 troy oz
98,000 man-hr
1, 11 3,000 Mlb
7,350,000 M gal
82,355,000 kwh
Unit cost, $
35.00/ton
11.88/ton
46.60/ton
0.18/lb
1 20/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Total
annual
cost, $
3,762,500
1,709,500
279,600
20,700
68.400
5,840,700
441,000
448,100
367,500
411,800
966,000
75,000
2,709,400
8,550,100
2,147,000
429,400
541,900
$/ton of
fertilizer
12.385
5.627
0.920
0.068
0.225
19.225
1.452
1.475
1.210
1.355
3.180
0.247
8.919
28,144
7.067
1.413
1.784
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
189.700
3,308,000
0.624
10.888
Total annual manufacturing costs
for 28-14-0 fertilizer
aBasis:
11,858,100
39.032
Remaining life of power plant— 35 years.
Coal burned -1,3 10,000 tons/yr.
Power unit operating stream time-o7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 P.,
Midwest plant location-1969 costs.
Capital investment- $21 ,470,000 fixed;
''Cost of steam from power plant cycle.
cCost of electricity at power plant bus bar.
indirect liquid-gas method.
$1,890,500 working.
169
-------
Table B-25. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
(50Q-mw existing power unit, 3.5% S in coal;
310,800 tons /yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
110.0 Mtons
147.2 Mtons
6.1 Mtons
117.8 M Ib
583 troy oz
98,500 man-hr
35.00/ton
11.88/ton
46.60/ton
0.18/lb
120/troy oz
4.50/man-hr
3,850,000
1,748,700
284,300
21,200
70.000
5,974,200
443,300
12.385
5.627
0.917
0.068
0.225
19.222
1.426
Steam 1,137,600 M Ib 0.50/M Ib
Water 7,519,000 M gal 0.06/M gal
Electricity 83,405,000 kwh 0.005/kwhb
Maintenance
Labor and material
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 28-1 4-0 fertilizer
aBasis:
Remaining life of power plant-32 years.
Coal burned-1,339,600 tons/yr. -0.767 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time— 7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location— 1969 costs.
Capital investment-$22,320,000 fixed; $1,937,700 working.
bCost of electricity at power plant bus bar.
568,800
451,100
417,000
1,000,000
75,000
2,955,200
8,929,400
2,232,000
446,400
591,000
206,900
3,476,300
12,405,700
1.830
1.451
1.342
3.218
0.241
~9^50§
28.730
7.182
1.436
1.901
0.666
11.185
39.915
170
-------
Table B-26. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw new power unit, 5. 0% S in coal;
434,000
Annual quantity
Direct Costs
Delivered raw material
Ammonia 153.9 M tons
Phosphate rock 205.6 M tons
Conditioner 8.6 M tons
Antifoam 164.2Mlb
N itric acid cata lyst 8 1 5 troy oz
Subtotal raw material
Conversion costs
Operating labor and
supervision 1 18,000 man-hr
Utilities
Steam 1,670,000 M Ib
Water 9,943,000 M gal
Electricity 83,475,000 kwh
Maintenance
Labor and material
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 28- 14-0 fertilizer
afiasis:
Remaining life of power plant— 35 years.
Coal burned- 1,3 10,000 tons/yr.
tons/yr fertilizer)
Unit cost. $
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troyoz
4.50/man-hr
0.40/M lbb
0.04/M gal
0.005/kwhc
Total
annual
cost. $
4,618,000
2,442,100
399,300
24,600
97.800
7,581,800
531,000
668,000
397,700
417,400
1,125,000
90.000
3,229,100
10,810,900
2,613,000
522,600
645,800
226.000
4,007,400
14,818,300
$/ton of
fertilizer
10.640
5.627
0.920
0.057
0.225
17.469
1.223
1.539
0.916
0.962
2.592
0.208
7.440
24.909
6.021
1.204
1.488
0.521
9.234
34.143
Power unit operating stream time-^7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250° F., indirect liquid-gas method.
Midwest plant location- 1969 costs.
Capital investment-$26,130,000 fixed; $2,393,100 working,
"Cost of steam from power plant cycle.
cCost of electricity at power plant bus bar.
171
-------
Table B-27. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
---------- Power Plant St^k Gasa-Process A
ounaie ouiuuuii mjiaineu uy oui UUUIMM i VJV»PI • mn* xm*»i» —
(1000-mw new power unit, 3.5% S in coal;
587,500 tons/ yr fertilizer)
Annual nnantilA/ Unit COSt. S
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric 3oirl ratalv*\t
1 v 1 LI IV* UV.IU OCILaiyoL
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
208.4 M tons
278.3 M tons
11.5 M tons
223.4 M Ib
1 1 1 .2 troy oz
1 35,000 man-hr
2,276,000 M Ib
1 2,1 37,000 M gal
1 33,239,000 kwh
30.00/ton
11.88/ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.30/M lbb
0.04/M gal
0.004/kwhc
Depreciation at 10% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
service
costs
Total
annual
cost. $
6,252,000
3,306,200
537,300
33,500
133.400
10,262,400
607,500
682,800
485,500
533,000
1,550,000
1 20,000
3,978,800
14,241,200
3,450,000
690,000
795,800
278,500
5,214,300
19,455,500
$/ton of
fertilizer
10.642
5.627
0.917
0.057
0.225
17.468
1.034
1.162
0.826
0.907
2.638
0.204
6.771
24,239
5.872
1.174
1.354
0.474
8.874
33.113
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr-0.725 Ib/kwh.
Power unit operating stream time-^,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$34,500,000 fixed; $3,244,200 working.
"Cost of steam from power plant cycle.
tost of electricity at power plant bus bar.
172
-------
Table B-28. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(1000-mw existing power unit, 3.5% S in coal;
607,600 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
215.5 M tons
288.5 M tons
12.0M tons
231.OM Ib
1150 troy oz
136,000 man-hr
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troy oz
4.50/man-hr
6,465,000
3,419,000
559,200
34,700
137.000
10,614,900
612,000
10.640
5.627
0.920
0.057
0.225
17.469
1.007
Steam 2,354,000 M Ib 0.45/M Ib
Water 1 2,551 ,000 M gal 0.05/M gal
Electricity 135,339,000 kwh 0.004/kwhb
Maintenance
Labor and material
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 28- 14-0 fertilizer
"Basis:
Remaining life of power plant-32 years.
Coal burned-2,625,000 tons/yr.
Power unit operating stream time-^7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$36,550,000 fixed; $3,358,800 working.
Cost of electricity at power plant bus bar.
1,059,300
627,600
541,300
1,600,000
120rOOO
4,560,200
15,175,100
3,655,000
731,000
912,000
319.200
5,617,200
20,792,300
1.744
1.033
0.891
2.633
0.197
7.505
24.974
6.015
1.203
1.501
0.526
9.245
34.219
173
-------
Table B-29. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(200-mw existing power unit, 3.5% S in coal;
97,100 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
32.1 M tons
59.8 M tons
1.9 M tons
48.0 M Ib
160 troy oz
82,300 man-hr
339,700 M Ib
1,918,300 M gal
28,233,300 kwh
35.00/ton
12.88/ton
46.60/ton
0.20/lb
120/troy oz
4.50/man-hr
0.60/M Ib
0.06/M gal
0.006/kwhb
aBasis:
Remaining life of power plant-27 years.
Coal burned-554,400 tons/yr.
Power unit operating stream time-J.OOO hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$ll,428,000 fixed; $875,000 working.
Cost of electricity at power plant bus bar.
1,124,400
770,800
90,500
9,600
19,200
2,014,500
370,400
203,800
115,100
169,400
515,000
28,000
1,401,700
3,416,200
11.580
7.938
0.932
0.099
0.198
20.747
3.815
2.099
1.185
1.745
5.304
0.288
14.436
35.183
Depreciation at 1 0% 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 26-1 9-0 fertilizer
1,142,800
228,600
280,300
98,100
1,749,800
5,166,000
11.770
2.354
2.887
1.010
18.021
53.204
174
-------
Table B-30. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(500-mw new power unit, 2.0% S in coal;
131,300 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
43.4 M tons
81. OM tons
2.6 M tons
65.0 M Ib
216 troy oz
87,700 man-hr
462,770 M Ib
2,629,620 M gal
50,221, 500 kwh
35.00/ton
12.48/ton
46.60/ton
0.20/lb
120/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Total
annual
cost,$
1,520,500
1,010,900
122,400
13,000
25,900
2,692,700
394,600
185,100
131,500
251,100
690,000
40,000
1,692,300
4,385,000
1,557,400
311,500
338,500
$/ton of
fertilizer
11.580
7.699
0.932
0.099
0.197
20.507
3.005
1.410
1.002
1.912
5.255
0.304
12.888
33.395
11.861
2.372
2.578
Administrative, research, and service.
7% of conversion costs
Subtotal indirect costs
118,500
2,325,900
0.902
17.713
Total annual manufacturing costs
for 26- 19-0 fertilizer
6,710,900
51.111
"Basis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr.
Power unit operating streajn time-^7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indkect liquid-gas method..
Midwest plant location-1969 costs.
Capital investment-$15,574,000 fixed; $1,170,800 working.
bCost of steam from power plant cycle.
tost of electricity at power plant bus bar.
175
-------
Table B-31. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
(500-mw new power unit, 3.5% S in coal;
230,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
76.1 M tons
141.8 M tons
4.6 M tons
113.4M Ib
377 troy oz
101,980man-hr
805,070 M Ib
4,479,300 M gal
61, 293,750 kwh
35.00/ton
1 1 .88/ton
46.60/ton
0.18/lb
1 20/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Total
annual
cost, $
2,663,500
1,684,600
214,400
20,400
45,200
4,628,100
458,900
322,000
224,000
306,500
881,000
65,000
2,257,400
6,885,500
1,968,900
393,800
451,500
$/ton of
fertilizer
11.580
7.324
0.932
0.089
0.197
20.122
2.000
1.400
0.974
1.332
3.830
0.282
9.818
29.940
8.560
1.712
1.963
Administrative, research, and service
7% of conversion costs
Subtotal indirect costs
158,000
2,972,200
0.687
12.922
Total annual manufacturing costs
for 26- 19-0 fertilizer
9,857,700
42.862
aBasis:
Remaining life of power plant-35 years.
Coalburned-1,310,000 tons/yr.
Power unit operating strea^ time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$19,689,000 fixed; $1,890,500 working.
''Cost of steam from power plant cycle.
tost of electricity at power plant bus bar.
176
-------
Table B-32. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw existing power unit, 3.5% S in coal;
235,800 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
78.0 M tons
145.4 M tons
4.7 M tons
116.7Mlb
385 troy oz
102,440 man-hr
35.00/ton
11.88/ton
46.60/ton
0.18/lb
120/troyoz
4.50/man-hr
aBasis:
Remaining life of power plant-32 years.
Coal burned-1,339,600 tons/yr.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas.method.
Midwest plant location—1969 costs.
Capital investment-$20,191,000 fixed; $1,937,700 working.
"Cost of electricity at power plant bus bar.
2,730,600
1,727,000
219,800
21,000
46,200
4,744,600
461,000
11.580
7.324
0.932
0.089
0.197
20.122
1.955
Steam 825,400 M Ib 0.50/M Ib
Water 4,598,300 M gal 0.06/M gal
Electricity 63,660,000 kwh 0.005/kwhb
Maintenance
Labor and material
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 26- 19-0 fertilizer
412,700
275,900
318,300
902,000
65,000
2,434,900
7,179,500
2,019,100
403,800
487,000
170,400
3,080,300
10,259,800
1.750
1.170
1.350
3.825
0.276
10.326
30.448
8.563
1.712
2.065
0.723
13.063
43.511
177
-------
Table B-33. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
(500-mw new power unit, 5.0% S in coal;
328,600 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
108.7 M tons
202.6 M tons
6.6 M tons
161.7 M Ib
540 troy oz
117,500 man-hr
1,148,000 M Ib
6,726,720 M gal
73,720,500 kwh
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troy oz
4.50/man-hr
0.40/M lbb
0.04/M gal
0.005/kwhc
aBasis:
Remaining life of power plant-35 years.
Coalburned-1,310,000 tons/yr.
Power unit operating strea^n time-Q7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$23,525,000 fixed; $2,393,100 working.
"Cost of steam from power plant cycle.
tost of electricity at power plant bus bar.
3,261,700
2,406,700
306,300
24,300
64,800
6,063,800
528,700
459,200
269,100
368,600
1,058,000
90.000
2,773,600
8,837,400
9.926
7.324
0.932
0.074
0.197
18.453
1.609
1.397
0.819
1.122
3.220
0.274
8.441
26.894
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 26- 19-0 fertilizer
2,352,500
470,500
554,700
194,100
3,571,800
12,409,200
7.159
1.432
1.688
0.591
10.870
37.764
178
-------
Table B-34. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(1000-mw new power unit, 3.5% S in coal;
444,000 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
146.9 M tons
273.7 M tons
8.9 M tons
219.3 M Ib
733 troy oz
136,700 man-hr
1,678,300 Mlb
8,680,000 M gal
99,575,000 kwh
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troy oz
4.50/man-hr
0.30/M lbb
0.04/M gal
0.004/kwhc
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$31,000,000 fixed; $3,244,200 working.
bCost of steam from power plant cycle.
cCost of electricity at power plant bus bar.
4,407,100
3,251,900
413,800
32,900
87.900
8,193,600
615,200
503,500
347,200
398,300
1,375,000
120,000
3,359,200
11,552,800
9.926
7.324
0.932
0.074
0.198
18.454
1.386
1.134
0.782
0.897
3.097
0.270
7.566
26.020
Depreciation at 1 0% 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 26- 19-0 fertilizer
3,100,000
620,000
671,800
235,100
4,626,900
16,179,700
6.982
1.397
1.513
0.530
10.422
36.442
179
-------
Table B-35. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
_ _. _,». . —. r» , g
(1000-mw existing power unit, 3.5% S in coal;
460,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
152.2 M tons
283.6 M tons
9.2 M tons
226.8 M Ib
760 troy oz
1 37,700 man-hr
1, 739,500 M Ib
8,988,000 M gal
104,941, 250 kwh
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troyoz
4.50/man-hr
0.45/M Ib
0.05/M gal
0.004/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
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 26- 19-0 fertilizer
service,
costs
Total
annual
cost, $
4,566,000
3,369,200
428,700
34,000
91,200
8,489,100
619,600
782,800
449,400
419,800
1,463,000
120,000
3,854,600
12,343,700
3,290,400
658,100
770,900
269,800
4,989,200
17,332,900
$/ton of
fertilizer
9.926
7.324
0.932
0.074
0.198
18.454
1.347
1.702
0.977
0.912
3.180
0.261
8.379
26.833
7.153
1.431
1.676
0.586
10.846
37.679
aBasis:
Remaining life of power plant-32 years.
Coal burned-2,625,000 tons/yr.
Power unit operating strea^n time-o7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$32,904,000 fixed; $3,358,800 working.
"Cost of electricity at power plant bus bar.
180
-------
Table B-36. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process C
(200-mw existing power unit, 3.5% S in coal;
56,700 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Net heat from boiler
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
14.4 M tons
25.5 M tons
1.1 M tons
69,770 man-hr
358,400 MM Btu
3,930,400 M gal
38,776,500 kwh
35.00/ton
13.88/ton
46.60/ton
4.50/man-hr
0.60/MM Btub
0.06/M gal
0.006/kwhb
aBasis:
Coal burned-554,400 tons/yr.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 25 0° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$9,589,500 fixed; $606,000 working. 0
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
505,400
343,900
51.300
900,600
314,000
215,000
235,900
232,700
417,100
15,900
1,430,600
2,331,200
8.914
6.065
0.905
15.884
5.538
3.792
4.160
4.104
7.356
0.280
25.230
41.114
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service.
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
959,000
191,800
286,100
100,100
1 ,537,000
3,868,200
16.914
3.383
5.046
1.765
27.108
68.222
181
-------
Table B-37. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
_ . _ n m j_ Oj —I _ /^~x.U Di>S*X«AO*» I
(500-mw new power unit, 2.0% S in coal;
76,600 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 1 9.5 M tons 35.00/ton
Phosphate rock 34.4 M tons 1 3.88/ton
Conditioner 1 .5 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 73,720 man-hr 4.50/man-hr
Utilities
Net heat from boiler 484,000 MM Btu 0.40/MM Btub
Water 5,503,700 M gal 0.05/M gal
Electricity 68,061,000 kwh 0.005/kwhb
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-14-0 fertilizer
aBasis:
Coalburned-1,310,000 tons/yr.
Power unit operating streajn time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$13,057,300 fixed; $780,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000° F.
Total
annual
cost, $
682,400
477,500
69,900
1,229,800
331,700
193,600
275,100
340,300
560,000
19,000
1,719,700
2,949,500
1,305,700
261,100
343,900
120.400
2,031,100
4,980,600
$/ton of
fertilizer
8.909
6.234
0.913
16.056
4.330
2.527
3.591
4.443
7.311
0.248
22.450
38.506
17.046
3.409
4.489
1.572
26.516
65.022
182
-------
Table B-38. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
(500-mw new power unit, 3.5% S in coal;
134,000 tons/yr fertilizer)
Annual auantitv Unit cost, $
Direct Costs
Delivered raw material
Ammonia 34.2 M tons 35.00/ton
Phosphate rock 60.2 M tons 12.68/ton
Conditioner 2.7 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 82,580 man-hr 4.50/man-hr
Utilities
Net heat from boiler 847,000 MM Btu 0.40/MM Btub
Water 9,516,800 M gal 0.05/M gal
Electricity 92,481,900 kwh 0.005/kwhb
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service.
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-14-0 fertilizer
Total
annual
cost, $
1,197,000
763,300
125.800
2,086,100
371,600
338,800
475,800
462,400
706,300
33.100
2,388,000
4,474,100
1,635,700
327,100
477,600
167.200
2,607,600
7,081,700
$/ton of
fertilizer
8.933
5.696
0.939
15.568
2.773
2.528
3.551
3.451
5.271
0.247
17.821
33.389
12.207
2.441
3.564
1.248
19.460
52.849
aBasis:
Coalburned-l,310jOOO tons/yr.
Power unit operating strewn time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$16,356,800 fixed; $1,185,000 working. o
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
183
-------
Table B-39. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
----- i .... . i i n i i i ' i " " "'
(500-mw existing power unit, 3.57o S in coal;
137,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 35.0 M tons 35.00/ton
Phosphate rock 6 1 .5 M tons 1 2.68/ton
Conditioner 2.8 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 83,080 man-hr 4.50/man-hr
Utilities
Net heat from boiler 866,000 MM Btu 0.50/MM Btub
Water 9,634,400 M gal 0.06/M gal
Electricity 94,056,900 kwh 0.005/kwhb
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-14-0 fertilizer
Total
annual
cost, $
1,224,200
779,800
130,500
2,134,500
373,900
433,000
578,100
470,300
748,500
33,100
2,636,900
4,771,400
1,733,000
346,600
527,400
184.600
2,791,600
7,563,000
$/ton of
fertilizer
8.936
5.692
0.953
15.581
2.729
3.161
4.220
3.433
5.463
0.241
19.247
34.828
12.650
2.530
3.850
1.347
20.377
55.205
Coal burned-1,339,600 tons/yr.
Power unit operating streap time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$17,329,600 fixed; $1,260,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000° F.
184
-------
Table B-40. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonia
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
(500-mw new power unit, 5.0% S in coal;
191,400 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Net heat from boiler
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
48.8 M tons
86.0 M tons
3.9 M tons
91,660man-hr
1,210,100 MM Btu
13,552,600 M gal
121,410,800 kwh
35.00/ton
12.48/ton
46.60/ton
4.50/man-hr
0.40/MM Btub
0.04/M gal
0.005/kwhb
1,708,000
1,073,300
181,700
2,963,000
412,500
484,000
542,100
607,000
811,900
39.700
2,897,200
5,860,200
8.924
5.608
0.949
15.481
2.155
2.529
2.832
3.171
4.242
0.207
15.136
30.617
Indirect Costs
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-14-0 fertilizer
1,932,100
386,400
579,400
202.800
3,100,700
8,960,900
10.095
2.019
3.027
1.060
16.201
46.818
Coal burned-1,310,000 tons/yr.
Power unit operating strewn time-7,000 hr/yr. Fertilizer plant cm-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$19,321,300 fixed; $1,515,000 working. Q
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
185
-------
Table B-41. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammoniurn
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gas -Process C
(1000-mw new power unit, 3.5% S in coal;
259,500 tons/yr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Net heat from boiler
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Annual quantity
66.2 M tons
116.6 Mtons
5.2 M tons
101,820man-hr
1,694,000 MM Btu
1 9,033,600 M gal
181, 254,500 kwh
Unit cost, $
35.00/ton
1 2.28/ton
46.60/ton
4.50/man-hr
0.30/MM Btub
0.04/M gal
0.004/kwhb
Total
annual
cost, $
2,318,000
1,431,800
242,300
3,992,100
458,200
508,200
761,300
988,200
1,062,200
53,000
3,831,100
7,823,200
$/ton of
fertilizer
8.933
5.518
0.934
15.385
1.766
1.958
2.934
3.808
4.093
0.204
14.763
30.148
Indirect Costs
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
2,463,900
492,800
766,200
268,200
3,991,100
11,814,300
9.495
1.900
2.952
1.033
15.380
45.528
aBasis:
Coal burned-2,53 7,300 tons/yr.
Power unit operating streap time^7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$24,639,300 fixed; $2,010,000 working.
''Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000° F.
186
-------
Table B-42. Fertilizer Company Economics - Total Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
(1000-mw existing power unit, 3.5% S in coal;
268,000 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Net heat from boiler
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
68.4 M tons
120.4 M tons
5.4 M tons
102,820 man-hr
1,642,000 MM Btu
18,722,800 M gal
181,776,000 kwh
35.00/ton
12.08/ton
46.60/ton
4.50/man-hr
0.45/MM Btub
0.05/M gal
0.004/kwhb
aBasis:
Coal burned-2,625,000 tons/yr.
Power unit operating streap time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250^ F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$26,646,400 fixed; $2,175,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 100CT F.
2,394,000
1,454,400
251,600
4,100,000
462,700
738,900
936,100
727.100
1,149,500
52.900
4,067,200
8,167,200
8.933
5.427
0.939
15.299
1.726
2.757
3.493
2.713
4.289
0.197
15.175
30.474
Depreciation at 10% fixed investment
Local taxes and insurance at 2% fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
7% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
2,664,600
532,900
813,400
284.700
4,295,600
12,462,800
9.943
1.988
3.035
1.063
16.029
46.503
187
-------
Table B-43. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
m riuum.c /-uniin-niiuiii vmiimo w~*.~.. . . ~ — v- . . .
(200-mw existing power unit, 3.5% Sin coal;
65,860 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 1 7.4 M tons
Conversion costs
Operating labor and
supervision 1 0,760 man-hr
Utilities
Water 886,700 M gal
Electricity 22,183,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.1% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant— 27 years.
Coalburned-554,400 tons/yr-0.792 Ib/kwh.
Power unit operating stream time— 7,000 hr/yr.
Midwest plant location- 1969 costs.
Capital investment- $2,880,000 fixed; $34,000 working.
°Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.06/M gal
0.006/kwhb
Cost/ton
of ammonium
sulfate. $
22.539
12.396
10.143
Total
annual
cost, $
610,400
48,400
53,200
133,100
115,200
12,000
361,900
972,300
434,900
72,400
4,800
512,100
Total
annual
cost. $
1,484,400
816,400
668,000
Cost/ton
of coal
burned, $
1.101
0.087
0.096
0.240
0.208
0.022
0.653
1.754
0.784
0.130
0.009
0.923
Cost/ton
of coal
burned. $
2.677
1.473
1.204
188
-------
Table B-44. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(200-mw existing power
unit, 3.5% S in coal;
128,600 tons/yr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Annual quantity
28.1 M tons
60.9 M tons
65.9 M tons
2.5 M tons
48.8 M Ib
241 troy oz
59,240 man-hr
471, 200 M Ib
2,272,900 M gal
14,434,000 kwh
Unit cost, $
35.00/ton
12.88/ton
10.14/ton
46.60/ton
0.20/lb
1 20/troy oz
4.50/man-hr
0.60/M lbb
0.06/M gal
0.006/kwhb
Depreciation at 1 0% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
aBasis:
service,
costs
Total
annual
cost, $
981,800
784,400
668,000
117,900
9,800
28,900
2,590,800
266,600
282,700
136,400
86,600
449,200
24,000
1,245,500
3,836,300
964,000
192,800
249,100
124,600
1,530,500
5,366,800
$/ton of
fertilizer
7.635
6.100
5.194
0.917
0.076
0.225
20.147
2.073
2.198
1.061
0.673
3.493
0.187
9.685
29.832
7.496
1.499
1.937
0.969
11.901
41,733
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$9,640,000 fixed; $841,000 working.
''Cost of power and steam from power plant.
189
-------
Table B-45. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process A
(500-mw new power
unit, 2.0% Sin coal;
89,000 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 23.8 M tons
Conversion costs
Operating labor and
supervision 1 3,430 man-hr
Utilities
Water 1,245,000 M gal
Electricity 43,260,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant-35 years.
Coalburned-1,310,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Capital investment-$5,485 ,000 fixed; $54,400 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.05/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
26.094
14.846
11.248
Total
annual
cost, $
833,000
60,400
62,300
216,300
219,400
15,000
573,400
1,406,400
795,300
114,700
6,000
916,000
Total
annual
cost, $
2,322,400
1,321,300
1,001,100
Cost/ton
of coal
burned, $
0.636
0.046
0.048
0.165
0.167
0.011
0.437
1.073
0.607
0.088
0.004
0.699
Cost/ton
of coal
burned, $
1.772
1.008
0.764
190
-------
Table B-46. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw new power unit, 2.0% S in coal;
173,600 tons/yr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Annual quantity
26.4 M tons
82.2 M tons
89.0 M tons
3.4 M tons
65.8 M Ib
325 troy oz
Unit cost, $
35.00/ton
12.48/ton
11.25/ton
46.60/ton
0.20/lb
120/troy oz
Total
annual
cost, $
1,315,000
1,025,900
1,001,100
159,700
13,600
39.000
3,554,300
$/ton of
fertilizer
7.575
5.910
5.767
0.920
0.076
0.225
20.473
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
62,570 man-hr
640,290 M Ib
3,034,000 M gal
19,887,000 kwh
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhb
"Basis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$ll,210,000 fixed; $1,116,400 working.
Cost of power and steam from power plant.
281,600
256,100
151,700
99,400
531,600
28.000
1,348,400
4,902,700
1.622
1.475
0.874
0.573
3.062
0.161
7.767
28.240
Depreciation at 1 0% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28- 14-0 fertilizer
1,121,000
224,200
269,700
134.800
1,749,700
6,652,400
6.457
1.291
1.554
0.777
10.079
38.319
191
-------
Table B-47. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solution3—Process A
(500-mw new power
unit, 3.5% S in coal;
155,925 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 41. 3 M tons
Conversion costs
Operating labor and
supervision 1 3,340 man-hr
Utilities
Water 2,137,000 M gal
Electricity 49,322,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant-35 years.
Coal burned -1,3 10,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-7,000 hr/yr.
Midwest plant location -196 9 costs.
Capital investment-$5,890,000 fixed; $85,000 working.
''Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.05/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
19.974
10.365
9.609
Total
annual
cost, $
1,445,500
60,000
106,800
246,600
235,600
25,000
674,000
2,119,500
854,100
134,800
6,000
994,900
Total
annual
cost, $
3,114,400
1,616,100
1,498,300
Cost/ton
of coal
burned, $
1.103
0.046
0.081
0.188
0.180
0.019
0.514
1.617
0.652
0.103
0.004
0.759
Cost/ton
of coal
burned, $
2.376
1.233
1.143
192
-------
Table B-48. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process A
(500-mw new power unit, 3.5% S in coal;
303,800 tons lyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
66.2 M tons
143.9 M tons
1 55.9 M tons
6.0 M tons
115.2M Ib
570 troy oz
35.00/ton
11.88/ton
9.609/ton
46.60/ton
0.18/lb
120/troyoz
Total
annual
cost, $
2,317,000
.1,709,500
1,498,300
279,600
20,700
68,400
5,893,500
$/ton of
fertilizer
7.627
5.627
4.932
0.920
0.068
0.225
19.399
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
84,660 man-hr
1,112,000 M Ib
5,213,000 M gal
33,033,000 kwh
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhb
aBasis:
Fertilizer plant on-stream time—7,000 hr/yr.
Midwest plant location—1969 costs.
Fertilizer capital investment-$15,580,000 fixed; $1,805,500 working.
"Cost of power and steam from power plant.
381,000
448,100
260,700
165,200
730,400
50,000
2,035,400
7,928,900
1.254
1.475
0.858
0.544
2.404
0.165
6.700
26.099
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.
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28-14-0 fertilizer
1,558,000
311,600
407,100
203.500
2,480,200
10,409,100
5.128
1.026
1.340
0.670
8.164
34.263
193
-------
Table B-49. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process A
(500-mw existing power unit, 3.5% S in coal;
159,500 tons ammonium sulfate/yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 42.2 M tons
Conversion costs
Operating labor and
supervision 1 3,700 man-hr
Utilities
Water 2,188,000 M gal
Electricity 51 ,440,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 4.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
35.00/ton
4.50/man-hr
0.06/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
20.539
10.641
9.898
Total
annual
cost, $
1,477,600
61,600
131,300
257,200
250,000
25,000
725,100
2,202,700
922,000
145,000
6.200
1,073,200
Total
annual
cost, $
3,275,900
1,697,300
1,578,600
Cost/ton
of coal
burned, $
1.103
0.046
0.098
0.192
0.187
0.018
0.541
1.644
0.688
0.108
0.005
0.801
Cost/ton
of coal
burned, $
2.445
1.267
1.178
aBasis:
Remaining life of powei plant—32 years.
Coalburned-1,339,600 tons/yr-0.767 Ib/kwh.
Power unit operating stream time-7,000 hr/yr.
Midwest plant location—1969 costs.
Capital investment-$6,230,000 fixed; $85,000 working.
"Cost of electricity at power plant bus bar.
194
-------
Table B-50. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw existing power unit, 3.5% S in coal;
310,800 tons /yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
67.8 M tons
147.2 M tons
1 59.5 M tons
6.1 M tons
117.8Mlb
583 troy oz
35.00/ton
1 1 .88/ton
9.898/ton
46.60/ton
0.18/lb
1 20/troy oz
Total
annual
cost, $
2,372,400
1,748,700
1,578,600
284,300
21,200
70,000
6,075,200
$/ton of
fertilizer
7.633
5.627
5.079
0.915
0.068
0.225
19.547
Conversion costs
Operating labor and
supervision
Utilities
84,800 man-hr
4.50/man-hr
381,700
1.228
Steam 1 , 1 37,600 M Ib 0.50/M lbb
Water 5,331,000 M gal 0.06/M gal
Electricity 31,965,000 kwh 0.005/kwhb
Maintenance
Labor and material
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,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28- 14-0 fertilizer
568,800
319,800
159,800
750,000
50,000
2,230,100
8,305,300
1,609,000
321,800
446,000
223,000
2,599,800
10,905,100
1.830
1.029
0.514
2.413
0.161
7.175
26.722
5.177
1.035
1.435
0.718
8.365
35.087
"Basis:
Fertilizer plant on-stream time-7,000 hr^yr.
Midwest plant location- 1969 costs.
Fertilizer capital investment-$16,090,000 fixed; $1,852,700 working.
Cost of power and steam from power plant.
195
-------
Table B-51. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
* . AtV.4**l,»O V* _ _ _ A
(500-mw new power
unit, 5. 0% S in coal;
222,810 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 59.0 M tons
Conversion costs
Operating labor and
supervision 13,400man-hr
Utilities
Water 3,028,000 M gal
Electricity 56,000,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
"Basis:
Remaining life of power plant- 35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time- 7,000 hr/yr.
Midwest plant location— 1969 costs.
Capital investment- $6,260,000 fixed: $104,100 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
30.00/ton
4.50/man-hr
0.04/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
16.038
8.612
7.426
Total
annual
cost, $
1,770,000
60,300
121,100
280,000
250,000
30.000
741,400
2,511,400
907,700
148,300
6,000
1,062,000
Total
annual
cost, $
3,573,400
1,918,900
1,654,500
Cost/ton
of coal
burned, $
1.351
0.046
0.092
0.214
0.191
0.023
0.566
1.917
0.693
0.113
0.005
0.811
Cost/ton
of coal
burned, $
2.728
1.465
1.263
196
-------
Table B-52. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process A
(500-mw new power unit, 5.0% S in coal;
434,000 tons /yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
94.9 M tons
205.6 M tons
222.81 M tons
8.6 M tons
164.2M Ib
81 5 troy oz
30.00/ton
11.88/ton
7.426/ton
46.60/ton
0.15/lb
1 20/troy oz
Total
annual
cost, $
2,848,000
2,442,100
1,654,500
399,300
24,600
97,800
7,466,300
$/ton of
fertilizer
6.562
5.627
3.812
0.920
0.057
0.225
17.203
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
104,600 ma n-hr
1,670,000 M Ib
6,915,000 M gal
27,475,000 kwh
4.50/man-hr
0.40/M lbb
0.04/M gal
0.005/kwhb
aBasis:
Fertilizer plant on-stream time—7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$19,870,000 fixed; $2,289,000 working.
Cost of power and steam from power plant.
470,700
668,000
276,600
137,400
875,000
60,000
2,487,700
9,954,000
1.085
1.539
0.637
0.318
2.016
0.138
5.732
22.935
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,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28- 14-0 fertilizer
1,987,000
397,400
497,500
248,800
3,130,700
13,084,700
4.578
0.916
1.146
0.573
7.213
30.148
197
-------
Table B-53. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(1 000-mw new power
unit, 3. 5% Sin coal;
301,560 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 79.8 M tons
Conversion costs
Operating labor and
supervision 1 5,200 man-hr
Utilities
Water 4,123,000 M gal
Electricity 93,250,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant- 3 5 years.
Coal burned-2,537,300 tans/yr-0.725 Ib/kwh.
Power unit operating stream time-7,000 hr/yr.
Midwest plant location- 196 9 costs.
Capital investment-$9,260,000 fixed; $145,800 working.
^Cost of electricity at power pknt bus bar.
Unit cost, $
30.00/ton
4.50/man-hr
0.04/M gal
O.Q04/kwhb
Cost/ton
of ammonium
sulfate, $
16.463
8.522
7.941
Total
annual
cost, $
2,395,200
68,500
164,900
373,000
370,000
40.000
1,016,400
3,411,600
1,342,700
203,300
6,900
1,552,900
Total
annual
cost, $
4,964,500
2,569,900
2,394,600
Cost/ton
of coal
burned, $
0.944
0.027
0.065
0.147
0.146
0.016
0.401
1.345
0.529
0.080
0.003
0.612
Cost/ton
of coal
burned, $
1.957
1.013
0.944
198
-------
Table B-54. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(1000-mw new power unit, 3.5% S in coal;
587,500 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
1 28.6 M tons
278.3 M tons
301.6 M tons
1 1 .5 M tons
223.4 M Ib
111.2 troy oz
30.00/ton
11.88/ton
7.941 /ton
46.60/ton
0.15/lb
120/troyoz
Total
annual
cost, $
3,856,800
3,306,200
2,394,600
537,300
33,500
133,400
10,261,800
$/ton of
fertilizer
6.565
5.627
4.076
0.917
0.057
0.225
17.467
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
119,800 man-hr
2,276,000 M Ib
8,014,000 M gal
39,989,000 kwh
4.50/man-hr
0.30/M lbb
0.04/M gal
0.004/kwhb
aBasis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location—1969 costs.
Fertilizer capital investment-$25,240,000 fixed; $3,098,400 working.
Cost of power and steam from power plant.
539,000
682,800
320,600
160,000
1,180,000
80.000
2,962,400
13,224,200
0.917
1.162
0.546
0.272
2.009
0.136
5.042
22.509
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,
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 28- 14-0 fertilizer
2,524,000
504,800
592,500
296,200
3,917,500
17,141,700
4.296
0.859
1.009
0.504
6.668
29.177
199
-------
Table B-55. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(1000-mw existing power unit, 3.5% S in coal;
311,850 tons ammonium sulfate/yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 82.6 M tons
Conversion costs
Operating labor and
supervision 1 6,000 man-hr
Utilities
Water 4,273,000 M gal
Electricity 98,434,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
30.00/ton
4.50/man-hr
0.05/M gal
0.004/kwhb
Cost/ton
of ammonium
sulfate, $
17.193
8.765
8.428
Total
annual
cost, $
2,478,000
74,700
213,700
393,700
455,000
40.000
1,177..100
3,655,100
1,463,700
235,400
7.500
1,706,600
Total
annual
cost, $
5,361,700
2,733,400
2,628,300
Cost/ton
of coal
burned, $
0.944
0.028
0.082
0.150
0.173
0.015
0.448
1.392
0.558
0.090
0.002
0.650
Cost/ton
of coal
burned, $
2.042
1.041
1.001
Remaining life of power plant-32 years.
Coalburned-2,625,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Capital investment-$9,890,000 fixed; $145,800 working.
"Cost of electricity at power plant bus bar.
200
-------
Table B-56. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(1000-mw existing power unit, 3.5% S in coal;
607,600 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
132.9 M tons
287.8 M tons
311.85Mtons
12.0M tons
231. OM Ib
1 15.0 troy oz
11 9,400 man-hr
2,354,000 M Ib
8,278,000 M gal
36,905,000 kwh
30.00/ton
11.88/ton
8.428/ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.45/M lbb
0.05/M gal
0.004/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, $
3,987,000
3,419,000
2,628,300
559,200
34,700
137,000
10,765,200
537,300
1,059,300
413,900
147,600
1,145,000
80,000
3,383,100
14,148,300
2,666,000
533,200
676,600
$/ton of
fertilizer
6.562
5.627
4.326
0.920
0.057
0.225
17.717
0.884
1.743
0.681
0.243
1.884
0.132
5.567
23.284
4.387
0.878
1.114
Administrative, research, and service,
10% of conversion costs
Subtotal indirect costs
33,800
3,909,600
0.057
6.436
Total annual manufacturing costs
for 28- 14-0 fertilizer
18,057,900
29.720
aBasis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$26,660,000 fixed; $3,213,000 working.
"Cost of power and steam from power plant.
201
-------
Table B-57. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(200-mw existing power unit, 3.5% S in coal;
43,530 tons ammonium sulfate/yr;
30,340 tons sulfur dioxide /yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Conversion costs
Operating labor and
supervision
Utilities
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
11.5 Mtons
11,400man-hr
1 53,500 M gal
1 4,883,300 kwh
35.00/ton
4.50/man-hr
0.06/M gal
0.006/kwhb
Average capital charges at 15.1% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
Total
annual
cost, $
403,000
51,300
9,200
89,300
105,400
7,000
262,200
665,200
397,700
52,400
5,100
455,200
Total
annual
cost, $
Cost/ton
of coal
burned, $
0.727
0.093
0.017
0.161
0.190
0.012
0.473
1.200
0.717
0.095
0.009
0.821
Cost/ton
of coal
burned, $
Total annual operating costs for ammonium
sulfate solution and sulfur
Cost of air pollution control
dioxide
by alternate
wet scrubbing - limestone process
15.167
11.052
1,120,400
816,400
2.021
1.473
Minimum expected transfer price of ammonium sulfate
solution and sulfur dioxide to fertilizer plant
4.115
304,000
0.548
aBasis:
Remaining life of power plant—27 years.
Coal burned-554,400 tons/yr-0.^92 Ib/kwh.
Stack gas reheat from 118°to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$2,634,000 fixed; $34,000 working.
"Cost of electricity at power plant bus bar.
202
-------
Table B-58. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(200-mw existing power unit, 3.5% S in coal;
97,100 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and SO2 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
20.6 M tons
59.8 M tons
73.9 M tons
1 .9 M tons
48.0 M Ib
160 troy oz
70,900 man-hr
339,700 M Ib
1, 764,840 M gal
1 3,350,000 kwh
35.00/ton
12.88/ton
4.12/ton
46.60/ton
0.20/lb
1 20/troy oz
4.50/man-hr
0.60/M lbb
0.06/M gal
0.006/kwhb
Depreciation at 1 0% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
Total
annual
cost, $
721,400
770,800
304,000
90,500
9,600
19,200
1,915,500
319,100
203,800
105,900
80,100
409,600
21.000
1,139,500
3,055,000
879,400
175,900
227,900
$/ton of
fertilizer
7.430
7.938
3.131
0.932
0.099
0.198
19.728
3.286
2.099
1.091
0.825
4.218
0.216
11.735
31.463
9.057
1.812
2.347
Administrative, research, and service,
10% of conversion costs
Subtotal indirect costs
114,000
1,397,200
1.174
14.390
Total annual manufacturing costs
for 26- 19-0 fertilizer
4,452,200
45.853
aBasis:
Fertilizer plant cm-stream time—7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$8,794,000 fixed; $841,000 working.
Cost of power and steam from power plant.
203
-------
Table B-59. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(500-mw new power unit, 2. 0% S in coal;
58,835 tons ammonium sulfate/yr;
41,000 tons sulfur dioxide/yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Conversion costs
Operating labor and
supervision
Utilities
Water
15.5M tons
1 3,000 man-hr
1 23,000 M gal
Electricity 33,673,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
35.00/ton
4. 507 man-hr
0.05/M gal
0.005/kwhb
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating
Subtotal indirect costs
Total annual operating costs for
labor
ammonium
sulfate solution and sulfur dioxide
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
18.816
Total
annual
cost, $
542,500
58,500
6,200
168,400
215,200
10,000
458,300
1,000,800
780,100
91,700
5,900
877,700
Total
annual
cost, $
1,878,500
Cost/ton
of coal
burned, $
0.414
0.045
0.005
0.129
0.164
0.008
0.351
0.765
0.595
0.070
0.004
0.669
Cost/ton
of coal
burned, $
1.434
Cost of air pollution control by alternate
wet scrubbing - limestone process
13.235
1,321,300
1.008
Minimum expected transfer price of ammonium sulfate
solution and sulfur dioxide to fertilizer plant
5.581
557,200
0.426
aBasis:
Remaining life of power plant— 35 years.
Coalburned-1,310,000 tons/yi-g.75 lb/-kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$5,380,000 fixed; $54,800 working.
"Cost of electricity at power plant bus bar.
204
-------
Table B-60. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw new power unit, 2.0% S in coal;
131,300 tons lyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and S02 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
28.0 M tons
81.0Mtons
99.8 M tons
2.6 M tons
64.4 M Ib
21 5 troy oz
74,700 man-hr
462,770 M Ib
2,506,620 M gal
1 6,548,000 kwh
35.00/ton
12.48/ton
5.58/ton
46.60/ton
0.20/lb
120/troyoz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/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, $
978,000
1,010,900
557,200
122,400
13,000
25,900
2,707,400
336,100
185,100
125,300
82,700
474,800
30,000
1,234,000
3,941,400
1,019,400
203,900
246,800
$/ton of
fertilizer
7.449
7.699
4.244
0.932
O.OS9
0.197
20.620
2.560
1.410
0.954
0.630
3.616
0.228
9.398
30.018
7.764
1.553
1.880
Administrative, research, and service,
10% of conversion costs
Subtotal indirect costs
123,400
1,593,500
0.940
12.137
Total annual manufacturing costs
for 26-1 9-0 fertilizer
5,534,900
42,155
"Basis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$10,194,000 fixed; $1,116,000 working.
Cost of power and steam from power plant.
205
-------
Table B-61. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(500-mw new power unit, 3,5% S in coal;
103,000 tons ammonium sulfate/yr;
71,820 tons sulfur dioxide/yr)
Annual Quantity
Direct Costs
Delivered raw material
Ammonia 27,2 M tons
Conversion costs
Operating labor and
supervision 1 3,300 man-hr
Utilities
Water 132,300 M gal
Electricity 33,967,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for ammonium
sulfate solution and sulfur dioxide
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium sulfate
solution and sulfur dioxide to fertilizer plant
"Basis:
Remaining life of power plant-35 years.
Coal burned- 1,3 10,000 tons/yr- 0.75 Ib/kwh.
Stack gas reheat from 118°to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$5,561,000 fixed; $85,000 working.
Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.05/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
13.352
9.246
4.106
Total
annual
cost, $
952,000
59,800
6,600
169,800
222,400
16,000
474,600
1,426,600
806,300
94,900
6,000
907,200
Total
annual
cost, $
2,333,800
1,616,100
717,700
Cost/ton
of coal
burned, $
0.727
0.046
0.005
0.130
0.170
0.012
0.363
1.090
0.615
0.072
0.005
0.692
Cost/ton
of coal
burned, $
1.782
1.234
0.548
206
-------
Table B-62. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw new power unit, 3.5% S in coal;
230,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and SQj at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
48.9 M tons
141.8 M tons
1 74.8 M tons
4.6 M tons
113.4M Ib
377 troy oz
88,680 man-hr
805,070 M Ib
4,347,000 M gal
27,326,250 kwh
35.00/ton
11.88/ton
4. 11 /ton
46.60/ton
0.18/lb
1 20/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/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, $
1,711,500
1,684,600
717,700
214,400
20,400
45,200
4,393,800
399,100
322,000
217,400
136,700
658,600
49,000
1,782,800
6,176,600
1,412,800
282,600
356,600
$/ton of
fertilizer
7.441
7.324
3.120
0.932
0.089
0.197
19.103
1.735
1.400
0.945
0.594
2.864
0.213
7.751
26.854
6.143
1.229
1.550
Administrative, research, and service.
1 0% of conversion costs
Subtotal indirect costs
178,300
2,230,300
0.775
9.697
Total annual manufacturing costs
for 26- 19-0 fertilizer
8,406,900
36.551
aBasis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$14,128,000 fixed; $1,805,000 working.
''Cost of power and steam from power plant.
207
-------
Table B-63. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solution and Sulfur Dioxide -Process B
(500-mw existing power unit, 3.57c b in coal,
105,370 tons ammonium sulfate/ yr;
73,470 tons sulfur
Annual quantity
Direct Costs
Delivered raw material
Ammonia 27.8 M tons
Conversion costs
Operating labor and
supervision 1 3,540 man-hr
Utilities
Water 251, 300 M gal
Electricity 35,640,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution and
sulfur dioxide
Cost of air pollution control by alternate
wet scrubbing limestone process
Minimum expected transfer price of ammonium
sulfate solution and sulfur dioxide to
fertilizer plant
aBasis:
Remaining life of power plant-32 years.
Coalburned-1,339,600 tons/yr-0.767 Ib/kwh.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Power unit on-stream time— 7,000 hr.
Midwest pknt location-1969 costs.
Capital investment-$5,860,000 fixed; $85,000 working.
"Cost of electricity at power plant bus bar.
dioxide/yr)
Unit cost, $
35.00/ton
4.50/man-hr
0.06/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
13.707
9.491
4.216
Total
annual
cost, $
972,500
60,900
15,100
178,200
234,400
16.000
504,600
1,477,100
867,300
100,900
6,100
974,300
Total
annual
cost, $
2,451,400
1,697,300
754,100
Cost/ton
of coal
burned, $
0.726
0.046
0.011
0.133
0.175
0.012
0.377
1.103
0.647
0.075
0.005
0.727
Cost/ton
of coal
burned, $
1.830
1.267
0.563
208
-------
Table B-64. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw existing power unit, 3.5% S in coal;
235,800 tons/ yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and SO2 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
50.2 M tons
1 45.4 M tons
1 78.8 M tons
4.7 M tons
116.7M Ib
385 troy oz
88,900 man-hr
825,400 M Ib
4,347,000 M gal
28,020,000 kwh
35.00/ton
11.88/ton
4.22/ton
46.60/ton
0.18/lb
1 20/troy oz
4.50/man-hr
0.50/M lbb
0.06/M gal
0.005/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, $
1,758,100
1,727,000
754,100
219,800
21,000
46,200
4,526,200
400,100
412,700
260,800
140,100
667,600
49,000
1,930,300
6,456,500
1,433,100
286,600
386,100
$/ton of
fertilizer
7.456
7.324
3.198
0.932
0.089
0.196
19.195
1.697
1.750
1.106
0.594
2.831
0.208
8.186
27.381
6.078
1.215
1.637
Administrative, research, and service,
1 0% of conversion costs
Subtotal indirect costs
193,000
2,298,800
0.819
9.749
Total annual manufacturing costs
for 26- 19-0 fertilizer
8,755,300
37.130
aBasis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$14,331,000 fixed; $1,852,700 working.
Cost of power and steam from power plant.
209
-------
Table B-65. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
___" _ . ** »f . f\_t.-j-* -i O.. !•£«•!* 1°^ irtvirla^—PlT4PP
-------
Table B-66. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw new power unit, 5. 0% S in coal;
328,600 tons/yr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and S02 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Annual quantity
69.9 M tons
202.7 M tons
249.9 M tons
6.6 M tons
161.7 M Ib
540 troy oz
103,900 man-hr
1,1 48,000 M Ib
6,584,760 M gal
39,469,500 kwh
Unit cost, $
30.00/ton
11.88/ton
2.68/ton
46.60/ton
0.15/lb
120/troyoz
4.50/man-hr
0.40/M lbb
0.04/M gal
0.005/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
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 26- 19-0 fertilizer
"Basis:
service.
costs
Total
annual
cost, $
2,094,700
2.406,600
669,600
306,300
24,300
64,800
5,566,300
467,500
459,200
263,400
197,300
829,400
68.000
2,284,800
7,851,100
1,780,900
356,200
457,000
228,500
2,822,600
10,673,700
$/ton of
fertilizer
6.375
7.324
2.038
0.932
0.074
0.197
16.940
1.423
1.397
0.802
0.600
2.524
0.207
6.953
23.893
5.419
1.084
1.391
0.695
8.589
32.482
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$17,809
,000 fixed; $2,289,000 working.
Cost of power and steam from power plant.
211
-------
Table B-67. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solution and Sulfur Dioxidea-Process B
(lOOU-mw new power
unit, 3.5% i in coal,
199,200 tons ammonium sulfate/yr;
138,900 tons sulfur dioxide/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 52.6 M tons
Conversion Costs
Operating labor and
supervision 1 6,000 man-hr
Utilities
Water 244,500 M gal
Electricity 65,367,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution and
sulfur dioxide
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution and sulfur dioxide to
fertilizer plant
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr-0.725 Ib/kwh.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location- 1969 costs.
Capital investment-$8,565,000 fixed; $145,800 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
30.00/ton
4.50/man-hr
0.04/M gal
0.004/kwhb
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
10.899
7.601
3.298
Total
annual
cost, $
1,576,600
72,000
9,800
261,500
342,600
30,000
715,900
2,292,500
1,241,900
143,200
7,200
1,392,300
Total
annual
cost, $
3,684,800
2,569,900
1,114,900
Cost/ton
of coal
burned, $
0.621
0.028
0.004
0.103
0.135
0.012
0.282
0.903
0.490
0.056
0.003
0.549
Cost/ton
of coal
burned, $
1.452
1.013
0.439
212
-------
Table B-68. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(1000-mw new power unit, 3.5% S in coal;
444,000 tons lyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and SO2 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
94.3 M tons
273.7 M tons
338.1 M tons
8.9 M tons
219.3 M Ib
733 troy oz
30.00/ton
11.88/ton
3.30/ton
46.60/ton
0.15/lb
1 20/troy oz
Total
annual
cost, $
2,830,500
3,251,900
1,114,900
413,800
32,900
87,900
7,731,900
$/ton of
fertilizer
6.375
7.324
2.511
0.932
0.074
0.198
17.414
Conversion costs
Operating labor and
supervision
Utilities
120,700 man-hr
4.50/man-hr
"Basis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location—1969 costs.
Fertilizer capital investment-$22,435,000 fixed; $3,098,400 working.
Cost of power and steam from power plant.
543,200
1.223
Steam 1,678,300 M Ib 0.30/M lbb
Water 8,435,500 M gal 0.04/M gal
Electricity 34,207,100 kwh 0.004/kwhb
Maintenance
Labor and material
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,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 26- 19-0 fertilizer
503,500
337,400
136,800
1,032,400
90,000
2,643,300
10,375,200
2,243,500
448,700
528,700
264,300
3,485,200
13,860,400
1.134
0.760
0.308
2.325
0.203
5.953
23.367
5.053
1.011
1.191
0.595
7.850
31.217
213
-------
Table B-69. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(1000-mw existing power unit, 3.5% S in coal;
206,000 tons ammonium sulfate/yr;
143,600 tons sulfur dioxide/ 'yr)
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Ammonia 54.4 M tons
Conversion costs
Operating labor and
supervision 16,100 man-hr
Utilities
Water 264,600 M gal
Electricity 69,546,750 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution and
sulfur dioxide
Cost of air pollution control by alternate
wet scrubbing - limestone process
Minimum expected transfer price of ammonium
sulfate solution and sulfur dioxide to
fertilizer plant
30.00/ton
4.50/man-hr
0.05/M gal
0.004/kwhb
Cost/ton
of ammonium
sulfate and
sulfur
dioxide, $
11.233
7.819
3.414
1,633,500
72,400
13,200
278,200
370,200
30,000
764,000
2,397,500
1,369,700
152,800
7,200
1,529,700
Total
annual
cost,$
3,927,200
2,733,400
1,193,800
Cost/ton
of coal
burned, $
0.622
0.028
0.005
0.106
0.141
0.011
0.291
0.913
0,521
0.058
0.003
0.582
Cost/ton
of coal
burned, $
1.495
1.041
0.454
Remaining life of power plant-32 years.
Coal burned-2,625,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from llff to 250 P., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$9,255,000 fixed; $145,800 working.
bCost of electricity at power plant bus bar.
214
-------
Table B-70. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium Sulfate
Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(1000-mw existing power unit, 3.5% S in coal;
460,000 tons/yr fertilizer)
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate solution
(and S02 at minimum
transfer price)
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
97.8 M tons
283.6 M tons
349.6 M tons
9.2 M tons
226.8 M Ib
760 troy oz
121,000man-hr
1, 739,500 M Ib
8,723,400 M gal
35,394,500 kwh
30.00/ton
1 1 .88/ton
3.41 /ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.45/M lbb
0.05/M gal
0.004/kwhb
Depreciation at 10% of fixed investment
Local taxes and insurance at 2%
Overhead
Plant, 20% of conversion costs
of fixed investment
2,932,500
3,369,200
1,193,800
428,700
34,000
91,200
8,049,400
547,200
782,800
436,200
141,600
1,092,800
90,000
3,090,600
11,140,000
2,374,900
475,000
618,100
$/ton of
fertilizer
6.375
7.324
2.595
0.932
0.074
0.198
17.498
1.190
1.702
0.948
0.308
2.376
0.195
6.719
24.217
5.163
1.032
1.344
Administrative, research, and service,
1 0% of conversion costs
Subtotal indirect costs
309,100
3,777,100
0.672
8.211
Total annual manufacturing costs
for 26- 19-0 fertilizer
14,917,100
32.428
aBasis:
Fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$23,749,000 fixed; $3,213,000 working.
Cost of power and steam from power plant.
215
-------
Table B-71. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process C
(200-mw existing power
unit, 3. 5% Sin coal;
65,860 tons ammonium sulfate lyr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 1 1 .04 M tons
Conversion costs
Operating labor and
supervision 10,170 man-hr
Utilities
Water 776,200 M gal
Electricity 21,094,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.1% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant-27 years.
Coal burned-554,400 tons/yr-0.792 Ib/kwh.
Stack gas reheat from 11!? to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwet plant location-1969 costs.
Capital investment-$2,880,000 fixed; $162,000 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.06/M gal
0.006/kwhb
Cost/ton
of ammonium
sulfate, $
18.848
12.396
6.452
Total
annual
cost, $
386,400
45,800
46,600
126,600
115,200
12,000
346,200
732,600
434,900
69,200
4,600
508,700
Total
annual
cost, $
1,241,300
816,400
424,900
Cost/ton
of coal
burned, $
0.697
0.083
0.084
0.228
0.208
0.022
0.625
1.322
0.784
0.125
0.008
0.917
Cost/ton
of coal
burned, $
2.239
1.473
0.766
216
-------
Table B-72. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process C
(200-mw existing power unit, 3.5% S in coal;
56,700 tons jyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 3.4 M tons 35.00/ton
Phosphate rock 25.5 M tons 13.88/ton
Ammonium sulfate
(solution at minimum
transfer price) 65.9 M tons 6.45/ton
Conditioner 1.1Mtons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 59,600 man-hr 4.50/man-hr
Utilities
Net heat from boiler 358,400 MM Btu 0.60/MM Btu
Water 3,154,200 M gal 0.06/M gal
Electricity 1 7,682,000 kwh 0.006/kwhb
Maintenance
Labor and material
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.
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
Total
annual
cost, $
119,000
343,900
424,900
51,300
939,100
268,200
215,000
189,300
106,100
301,900
3,900
1,084,400
2,023,500
671,000
134,200
216,800
108,400
1,130,400
3,153,900
$/ton of
fertilizer
2.099
6.065
7.494
0.905
16.563
4.730
3.792
3.339
1.871
5.324
0.069
19.125
35.688
1 1 .834
2.367
3.824
1.912
19.937
55.625
fertilizer plant on-stream time—7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$6,709,500 fixed; $444,000 working.
Cost of power and heat from power plant.
217
-------
Table B-73. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(500-mw new power
unit, 2.0% Sin coal;
89,000 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 14.9 M tons
Conversion costs
Operating labor and
supervision 1 2,320 man-hr
Utilities
Water 1,160,900 M gal
Electricity 42,987,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant— 35 years.
Coal burned- 1,3 10,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from lltf3 to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location- 1969 costs.
Capital investment- $5,516,000 fixed; $230,000 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.05/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
22.510
14.846
7.664
Total
annual
cost, $
521,400
55,400
58,000
214,900
220,600
15.000
563,900
1,085,300
799,800
112,800
5.500
918,100
Total
annual
cost, $
2,003,400
1,321,300
682,100
Cost/ton
of coal
burned, $
0.398
0.042
0.044
0.164
0.168
0.011
0.429
0.827
0.611
0.086
0.004
0.701
Cost/ton
of coal
burned, $
1.528
1.008
0.520
218
-------
Table B-74. Economics for Power - Fertilizer Company Cooperative \fenture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
(500-mw new power unit, 2.0% S in coal;
76,600 tons/ yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 4.6 M tons 35.00/ton
Phosphate rock 34.4 M tons 13.88/ton
Ammonium sulfate
(solution at minimum
transfer price) 89.0 M tons 7.66/ton
Conditioner 1.5Mtons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision , 61,400man-hr 4.50/man-hr
Utilities
Net heat from boiler 484,000 MM Btu 0.40/MM Btu
Water 4,342,800 M gal 0.05/M gal
Electricity 25,074,000 kwh 0.005/kwhb
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation at 1 0% of fixed investment
Local taxes and insurance at 2% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and service,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
Total
annual
cost, $
161,000
477,500
682,100
69,900
1,390,500
276,300
193,600
217,100
125,400
339,400
4,000
1,155,800
2,546,300
754,100
150,800
231,200
115,600
1,251,700
3,798,000
$/ton of
fertilizer
2.102
6.234
8.905
0.913
18.154
3.607
2.527
2.834
1.637
4.431
0.052
15.088
33.242
9.845
1.969
3.018
1.509
16.341
49.583
fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$7,541,300 fixed; $550,000 working.
Cost of power and heat from power plant.
219
-------
Table B-75. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process C
(500-mw new power unit, 3.5% S in coal;
155,925 tons ammonium sulfate/yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 26.1 M tons
Conversion costs
Operating labor and
supervision 1 2,590 man-hr
Utilities
Water 1,940,000 M gal
Electricity 48,892,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
35.00/ton
4.50/man-hr
0.05/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
16.499
10.365
6.134
Total
annual
cost, $
913,500
56,700
97,000
244,500
237,400
25,000
660,600
1,574,100
860,700
132,100
5,700
998,500
Total
annual
cost, $
2,572,600
1,616,100
956,500
Cost/ton
of coal
burned, $
0.697
0.043
0.074
0.187
0.181
0.019
0.504
1.201
0.657
0.101
0.004
0.762
Cost/ton
of coal
burned, $
1.963
1.233
0.730
aBasis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 11£P to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$5,936,000 fixed; $335,000 working.
''Cost of electricity at power plant bus bar.
220
-------
Table B-76. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gas3—Process C
(500-mw new power unit, 3.5% S in coal;
134,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 8.1 M tons 35.00/ton
Phosphate rock 60.2 M tons 1 2.68/ton
Ammonium sulfate
(solution at minimum
transfer price) 1 55.9 M tons 6.13/ton
Conditioner 2.7 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 70,000 man-hr 4.50/man-hr
Utilities
Net heat from boiler 847,000 MM Btu 0.40/MM Btu
Water 7,576,800 M gal 0.05/M gal
Electricity 43,589,000 kwh 0.005/kwhb
Maintenance
Labor and material
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,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
Total
annual
cost, $
283,500
763,300
956,500
125,800
2,129,100
315,000
338,800
378,800
217,900
468,900
8,100
1,727,500
3,856,600
1,042,100
208,400
345,500
172,800
1,768,800
5,625,400
$/ton of
fertilizer
2.116
5.696
7-138
0.939
15.889
2.351
2.528
2.827
1.626
3.499
0.060
12.891
28.780
7.777
1.555
2.578
1.290
13.200
41.980
fertilizer plant on-stream time—7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$10,420,800 fixed; $850,000 working.
Cost of power and heat from power plant.
221
-------
Table B-77. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process C
(500-mw existing power
unit, 3. 5% Sin coal;
159,500 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 26.7 M tons
Conversion costs
Operating labor and
supervision 1 2,640 man-hr
Utilities
Water 1 ,940,000 M gal
Electricity 49,942,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
"Basis:
Remaining life of power plant-32 years.
Coalburned-1,339,600 tons/yi-0.767 Ib/kwh.
StacK gas reheat from ll{f to 250°F., indirect liquid-gas method.
Power unit on-stteam time-7,000 hr.
Midwest plant location- 1969 costs.
Capital investment-$6,269,000 fixed; $355,000 working.
Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.06/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
16.964
10.641
6.323
Total
annual
cost, $
933,700
56,900
116,400
249,700
250,800
25,000
698,800
1,632,500
927,800
139,800
5,700
1,073,300
Total
annual
cost, $
2,705,800
1,697,300
1,008,500
Cost/ton
of coal
burned, $
0.697
0.042
0.087
0.186
0.187
0.019
0.521
1.218
0.693
0.104
0.004
0.801
Cost/ton
of coal
burned, $
2.019
1.267
0.752
222
-------
Table B-78. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
(500-mw existing power unit, 3.5% S in coal;
137, 000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 8.3 M tons 35.00/ton
Phosphate rock 61.5 M tons 12.68/ton
Ammonium sulfate
(solution at minimum
transfer price) 1 59.5 M tons 6.32/ton
Conditioner 2.8 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 70,440 man-hr 4.50/man-hr
Utilities
Net heat from boiler 866,000 MM Btu 0.50/MM Btu
Water 7,694,400 M gal 0.06/M gal
Electricity 44,114,000 kwh 0.005/kwhb
Maintenance
Labor and material
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,
1 0% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-1 4-0 fertilizer
Total
annual
cost, $
290,500
779,800
1,008,500
130,500
2,209,300
317,000
433,000
461,700
220,600
497,700
8,100
1,938,100
4,147,400
1,106,100
221,200
387,600
193,800
1,908,700
6,056,100
$/ton of
fertilizer
2.120
5.692
7.361
0.953
16.126
2.314
3.161
3.370
1.610
3.633
0.059
14.147
30.273
8.074
1.614
2.829
1.415
13.932
44.205
fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$ll,060,600 fixed; $905,000 working.
Cost of power and heat from power plant.
223
-------
Table B-79. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
Ammonium Sulfate Solutiona-Process C
(500-mw new power
unit, 5.0% Sin coal;
222,810 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 37.2 M tons
Conversion costs
Operating labor and
supervision 1 2,760 man-hr
Utilities
Water 2,720,800 M gal
Electricity 59,245,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 11 if to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location— 1969 costs.
Capital investment-$6,307,000 fixed: $445,000 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.04/M gal
0.005/kwhb
Cost/ton
of ammonium
sulfate, $
13.984
8.612
5.372
Total
annual
cost, $
1,302,000
57,400
108,800
296,200
252,300
30,000
744,700
2,046,700
914,500
148,900
5,700
1,069,100
Total
annual
cost, $
3,115,800
1,918,900
1,196,900
Cost/ton
of coal
burned, $
0.994
0.044
0.083
0.226
0.193
0.023
0.569
1.563
0.698
0.114
0.004
0.816
Cost/ton
of coal
burned, $
2.379
1.465
0.914
224
-------
Table B-80. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process C
(500-mw new power unit, 5.0% S in coal;
191,400 tons lyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 11.6Mtons 35.00/ton
Phosphate rock 86.0 M tons 1 2.48/ton
Ammonium sulfate
(solution at minimum
transfer price) 222.8 M tons 5.37/ton
Conditioner 3.9 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 78,900 man-hr 4.50/man-hr
Utilities
Net heat from boiler 1,210,100 MM Btu 0.40/MM Btu
Water 10,831,800 M gal 0.04/M gal
Electricity 62,164,900 kwh 0.005/kwhb
Maintenance
Labor and material
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,
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19- 14-0 fertilizer
Total
annual
cost, $
406,000
1,073,300
1,196,900
181,700
2,857,900
355,000
484,000
433,300
310,800
559,600
9.700
2,152,400
5,010,300
1,301,400
260,300
430,500
215,200
2,207,400
7,217,700
$/ton of
fertilizer
2.121
5.608
6.253
0.949
14.931
1.855
2.529
2.264
1.624
2.924
0.051
11.247
26.178
6.799
1.360
2.249
1.124
11.532
37.710
fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$13,014,300 fixed; $1,070,000 working.
Cost of power and heat from power plant.
225
-------
Table B-81. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
to Produce Ammonium Sulfate Solutiona-Process C
(1000-mw new power unit, 3.5% S in coal;
301,560 tons ammonium sulfate/yr)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Conversion costs
Operating labor and
supervision
Utilities
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
50.5 M tons
15,080 ma n-hr
3,880,000 M gal
95,522,000 kwh
35.00/ton
4.50/man-hr
0.04/M gal
0.004/kwhb
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Cost/ton
of ammonium
sulfate, $
Total
annual
cost, $
1,768,500
67,900
155,200
382,100
372,500
40,000
1,017,700
2,786,200
1,350,400
203,500
6,800
1,560,700
Total
annual
cost, $
Cost/ton
of coal
burned, $
0.697
0.027
0.061
0.151
0.147
0.016
0.402
1.099
0.532
0.080
0.003
0.615
Cost/ton
of coal
burned, $
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control
by alternate
wet-limestone scrubbing process
Minimum expected transfer
price of ammonium
sulfate solution to fertilizer plant
14.415
8.522
5.893
4,346,900
2,569,900
1,777,000
1.714
1.013
0.701
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr-0.725 Ib/kwh.
Stack gas reheat from 11 if to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$9,313,000 fixed; $605,000 working.
"Cost of electricity at power plant bus bar.
226
-------
Table B-82. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process C
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Ammonium sulfate
(solution at minimum
transfer price)
Conditioner
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Net heat from boiler
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
(1000-mw new power unit, 3.5% S in coal;
259,500 tons / yr fertilizer)
Annual quantity Unit cost, $
1 5.7 M tons 35.00/ton
1 1 6.6 M tons 12.28/ton
301 .6 M tons 5.89/ton
5.2 M tons 46.60/ton
86,740 man-hr 4.50/man-hr
1,694,000 MM Btu 0.30/MM Btu
1 5,1 53,600 M gal 0.04/M gal
85,732,500 kwh 0.004/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, $
549,500
1,431,800
1,777,000
242,300
4,000,600
390,300
508,200
606,100
342,900
689,700
13,000
2,550,200
6,550,800
1,532,600
306,500
510,000
$/ton of
fertilizer
2.118
5.518
6.848
0.934
15.418
1.504
1.958
2.336
1.321
2.658
0.050
9.827
25.245
5.906
1.181
1.965
Administrative, research, and service,
1 0% of conversion costs
Subtotal indirect costs
255,000
2,604,100
0.982
10.036
Total annual manufacturing costs
for 19- 14-0 fertilizer
9,154,900
35.281
fertilizer plant on-stream time—7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$15,326,300 fixed; $1,405,000 working.
Cost of power and heat from power plant.
227
-------
Table B-83. Economics for Power - Fertilizer Company Cooperative Venture
Average Annual Operating Costs for Scrubbing Power Plant Stack Gas
(1000-mw existing power
unit, 3. 5% Sin coal;
311,850 tons ammonium sulfate/yr)
Annual quantity
Direct Costs
Delivered raw material
Ammonia 52.2 M tons
Conversion costs
Operating labor and
supervision 15,180 man-hr
Utilities
Water 3,880,000 M gal
Electricity 97,622,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating costs for
ammonium sulfate solution
Cost of air pollution control by alternate
wet-limestone scrubbing process
Minimum expected transfer price of ammonium
sulfate solution to fertilizer plant
aBasis:
Remaining life of power plant-32 years.
Coal burned-2,625,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 11 if to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr.
Midwest plant location— 1969 costs.
Capital investment-$9,918,000 fixed; $640,000 working.
"Cost of electricity at power plant bus bar.
Unit cost, $
35.00/ton
4.50/man-hr
0.05/M gal
OJD04/kwhb
Cost/ton
of ammonium
sulfate, $
14.780
8.765
6.015
Total
annual
cost, $
1,827,000
68,300
194,000
390,500
396,700
40,000
1,089,500
2,916,500
1,467,900
217,900
6,800
1,692,600
Total
annual
cost, $
4,609,100
2,733,400
1,875,700
Cost/ton
of coal
burned, $
0.697
0.026
0.074
0.149
0.151
0.015
0.415
1.112
0.559
0.083
0.003
0.645
Cost/ton
of coal
burned, $
1.757
1.041
0.716
228
-------
Table B-84. Economics for Power - Fertilizer Company Cooperative Venture
Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process C
(1000-mw existing power unit, 3.5% S in coal;
268,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 1 6.2 M tons 35.00/ton
Phosphate rock 1 20.4 M tons 1 2.08/ton
Ammonium sulfate
(solution at minimum
transfer price) 31 1.9 M tons 6.01/ton
Conditioner 5.4 M tons 46.60/ton
Subtotal raw material
Conversion costs
Operating labor and
supervision 87,640 man-hr 4.50/man-hr
Utilities
Net heat from boiler 1,642,000 MM Btu 0.45/MM Btu
Water 14,842,800 M gal 0.05/M gal
Electricity 84,154,000 kwh 0.004/kwhb
Maintenance
Labor and material
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.
10% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 19-14-0 fertilizer
Total
annual
cost, $
567,000
1,454,400
1,875,700
251,600
4,148,700
394,400
738,900
742,100
336,600
752,800
13,000
2,977,800
7,126,500
1,672,800
334,600
595,500
297,800
2,900,700
10,027,200
$/ton of
fertilizer
2.116
5.427
6.999
0.939
15.481
1.472
2.757
2.769
1.256
2.809
0.048
11.111
26.592
6.242
1.248
2.222
1.111
10.823
37.415
fertilizer plant on-stream time-7,000 hr/yr.
Midwest plant location-1969 costs.
Fertilizer capital investment-$16,728,400 fixed; $1,535,000 working,
Cost of power and heat from power plant.
229
-------
Table B-85. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
(200-mw existing power unit, 3.5% S in coal;
128,600 tons fyr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion Costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
45.5 M tons
60.9 M tons
2.5 M tons
48.8 M Ib
243 troy oz
70,000 man-hr
471,200Mlb
3,1 59,600 M gal
36,61 7,000 kwh
35.00/ton
12.88/ton
46.60/ton
0.20/lb
120/troyoz
4,50/man-hr
0,60/M Ib
0.06/M gal
0.006/kwhb
Average capital charges at 15.1% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
service,
costs
Cost/ton
of coal
burned, $
11.777
Total
annual
cost, $
1,592,200
784,400
117,900
9,800
28.900
2,533,200
315,000
282,700
189,600
219,700
564,400
36,000
1,607,400
4,140,600
1,890,500
321,500
176,800
2,388,800
Total
annual
cost, $
6,529,400
$/ton of
fertilizer
12.385
6.100
0.917
0.076
0.225
19.703
2.449
2.198
1.474
1.708
4.389
0.280
12.498
32.201
14.701
2.500
1.375
18.576
$/ton of
fertilizer
50.777
aBasis:
Remaining life of power plant-27 years.
Coal burned-554,400 tons/yr-0.792 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$12,520,000 fixed; $875,000 working.
''Cost of electricity at power plant bus bar.
230
-------
Table B-86. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gas3—Process A
(500-mw new power unit, 2. 0% S in coal;
173,600 tons/ yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
61.4 Mtons
82.2 M tons
3.4 M tons
65.8 M Ib
325 troy oz
76,000 man-hr
640,290 M Ib
4,279,000 M gal
63,1 47,000 kwh
35.00/ton
12.48/ton
46.60/ton
0.20/lb
120/troy oz
4.50/man-hr
0.40/M Ibb
0.05/M gal
0.005/kwhc
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28-14-0 fertilizer
service.
costs
Cost/ton
of coal
burned, $
6.356
Total
annual
cost, $
2,150,000
1,025,900
159,700
13,600
39,000
3,388,200
342,000
256,100
214,000
315,700
751,000
43,000
1,921,800
5,310,000
2,420,800
384,400
211,400
3,016,600
Total
annual
cost, $
8,326,600
$/ton of
fertilizer
12.385
5.910
0.920
0.076
0.225
19.516
1.970
1.475
1.232
1.819
4.327
0.248
11.071
30.587
13.943
2.214
1.218
1 7.375
$/ton of
fertilizer
47.962
aBasis:
Remaining life of power plant-35 years.
Coalburned-1,310,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-J.OOO hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$16,695,000 fixed; $1,170,800 working.
"Cost of steam from power cycle.
cCost of electricity at power plant bus bar.
231
-------
Table B-87. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw new power unit, 3.5% S in coal;
303,800 tons /yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate Rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
107.5 M tons
143.9 M tons
6.0 M tons
115.2M Ib
570 troy oz
98,000 man-hr
35.00/ton
11.88/ton
46.60/ton
0.18/lb
120/troy oz
4.50/man-hr
aBasis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$21,470,000 fixed; $1,8"90,500 working.
"Cost of steam from power cycle.
'Cost of electricity at power plant bus bar.
3,762,500
1,709,500
279,600
20,700
68,400
5,840,700
441,000
12.385
5.627
0.920
0.068
0.225
19.225
1.452
Steam 1, 11 2,000 M Ib
Water 7,350,000 M gal
Electricity 82,355,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5%of 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 28-1 4-0 fertilizer
0.40/M lbb
0.05/M gal
0.005/kwhc
Cost/ton
of coal
burned, $
9.544
448,100
367,500
411,800
966,000
75,000
2,709,400
8,550,100
3,113,200
541,900
298,000
3,953,100
Total
annual
cost, $
12,503,200
1.475
1.210
1.355
3.180
0.247
8.919
28.144
10.247
1.784
0.981
13.012
$/ton of
fertilizer
41.156
232
-------
Table B-88. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process A
(500-mw existing power unit, 3.5% S in coal;
310,800 tons/yr fertilizer)
Annual Quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion Costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
1 1 0.0 M tons
1 47.2 M tons
6.1 M tons
117.8 M Ib
583 troy oz
98,500 man-hr
1,1 37,600 M Ib
7,51 9,000 M gal
83,405,000 kwh
35.00/ton
11.88/ton
46.60/ton
0.18/lb
1 20/troy oz
4.50/man-hr
0.50/M Ib
0.06/M gal
0.005/kwhb
Average capital charges at 14.8% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
1 1 % of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
service,
costs
Cost/ton
of coal
burned, $
9.815
Total
annual
cost, $
3,850,000
1,748,700
284,300
21,200
70,000
5,974,200
443,300
568,800
451,100
417,000
1,000,000
75,000
2,955,200
8,929,400
3,303,400
591,000
325,100
4,219,500
Total
annual
cost, $
13,148,900
$/ton of
fertilizer
12.387
5.627
0.915
0.068
0.225
19.222
1.426
1.830
1.451
1.342
3.218
0.241
9.508
28.730
10.629
1.901
1.046
13.576
$/ton of
fertilizer
42.306
"Basis:
Remaining life of power plant-32 years.
Coalburned-1,339,600 tons/yr-0.767 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$22,320,000 fixed; $1,937,700 working.
Cost of electricity at power plant bus bar.
233
-------
Table B-89. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
(500-mw new power unit, 5.0% S in coal;
434,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
153.9 Mtons
206.6 M tons
8.6 M tons
164.2Mib
815 troy oz
118,000 man-hr
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troy oz
4.50/man-hr
"Basis:
Remaining life of power plant—35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-o7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$26,130,000 fixed; $2,393,100 working.
"Cost of steam from power cycle.
cCost of electricity at power plant bus bar.
4,618,000
2,442,100
399,300
24,600
97,800
7,581,800
531,000
10.640
5.627
0.920
0.057
0.225
17.469
1.223
Steam 1,670,000 M Ib
Water 9,943,000 M gal
Electricity 83,475,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% of 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 28-14-0 fertilizer
0.40/M lbb
0.04/M gal
0.005/kwhc
Cost/ton
of coal
burned, $
11.909
668,000
397,700
417,400
1,125,000
90,000
3,229,100
10,810,900
3,788,800
645,800
355,200
4,789,800
Total
annual
cost, $
15,600,700
1.539
0.916
0.962
2.592
0.208
7.440
24.909
8.730
1.488
0.818
11.036
$/ton of
fertilizer
35.945
234
-------
Table B-90. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa—Process A
(1000-mw new power unit, 3.5% S in coal;
587,500 tons /yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
208.4 M tons
278.3 M tons
11.5 M tons
223.4 M Ib
11 1.2 troy oz
135,000 ma n-hr
2,276,000 M Ib
1 2,1 37,000 M gal
1 33,239,000 kwh
30.00/ton
11.88/ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.30/M lbb
0.04/M gal
0.004/kwhc
Average capital charges at 14.5% of fixed investment
Overhead
Plant, 20% of conversion costs
Administrative, research, and
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
service.
costs
Cost/ton
of coal
burned, $
8.070
Total
annual
cost, $
6,252,000
3,306,200
537,300
33,500
133,400
10,262,400
607,500
682,800
485,500
533,000
1,550,000
120,000
3,978,800
14,241,200
5,002,500
795,800
437,700
6,236,000
Total
annual
cost, $
20,477,200
$/ton of
fertilizer
10.642
5.627
0.917
0.057
0.225
17.468
1.034
1.162
0.826
0.907
2.638
0.204
6.771
24.239
8.515
1.354
0.745
10.614
$/ton of
fertilizer
34.853
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr-0.725 Ib/kwh.
Power unit operating stream time-7,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Midwest plant location-1969 costs.
Capital investment-$34,500,000 fixed; $3,244,200 working.
Cost of steam from power cycle.
tost of electricity at power plant bus bar.
235
-------
Table B-91. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 28-14-0 Fertilizer Made with Ammonium
(1000-mw existing power unit, 3.5% S in coal;
607,600 tons/yr fertilizer)
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Water
Electricity
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8
Overhead
21 5.5 M tons
287.8 M tons
12.0 M tons
231. OM Ib
1 1 50 troy oz
1 36,000 man-hr
2,354,000 M Ib
12,551, DOOM gal
1 35,339,000 kwh
i% of fixed investment
30.00/ton
11.88/ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.45/M Ib
0.05/M gal
0.004/kwhb
Plant, 20% of conversion costs
Administrative, research, and
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing
for 28- 14-0 fertilizer
service,
costs
Cost/ton
of coal
burned, $
8.380
6,465,000
3,419,000
559,200
34,700
137,000
10,614,900
612,000
1,059,300
627,600
541,300
1,600,000
120,000
4,560,200
15,175,100
5,409,400
912,000
501,600
6,823,000
Total
annual
cost, $
21,998,100
$/ton of
fertilizer
10.640
5.627
0.920
0.057
0.225
17.469
1.007
1.744
1.033
0.891
2.633
0.197
7.505
24.974
8.903
1.501
0.826
1 1 .230
$/ton of
fertilizer
36.204
aBasis:
Remaining life of power plant—32 years.
Coal burned-2,625,000 tons/yr-0.75 Ib/kwh.
Power unit operating stream time-^,000 hr/yr. Fertilizer plant on-stream time-7,000 hr/yr.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Midwest plant location—1969 costs.
Capital investment-$36,550,000 fixed; $3,358,800 working.
Cost of electricity at power plant bus bar.
236
-------
Table B-92. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
Sulfate Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(200-mw existing power unit, 3.5% S in coal;
97,100 tons/yr fertilizer)
Annual quantity
Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
32.1 M tons
59.8 M tons
1.9 M tons
48.00 M Ib
160 troy oz
82,300 man-hr
35.00/ton
12.88/ton
46.60/ton
0.20/lb
120/troyoz
4.50/man-hr
aBasis:
Remaining life of power plant-27 years.
Coal burned-554,400 tons/yr-0.792 Ib/kwh.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$ll,428,000 fixed; $875,000 working.
"Cost of electricity at power plant bus bar.
1,124,400
770,800
90,500
9,600
19,200
2,014,500
370,400
11.580
7.938
0.932
0.099
0.198
20.747
3.815
Steam 339,700 M Ib
Water 1,918,300 M gal
Electricity 28,233,300 kwh
Maintenance
Labor and material
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
Administrative, research, and service,
1 1% of conversion costs
Subtotal indirect costs
Total annual manufacturing costs
for 26- 19-0 fertilizer
0.60/M Ib
0.06/M gal
0.006/kwhb
Cost/ton
of coal
burned, $
10.058
203,800
115,100
169,400
515,000
28,000
1,401,700
3,416,200
1,725,600
280,300
154,200
2,160,100
Total
annual
cost, $
5,576,300
2.099
1.185
1.745
5.304
0.288
14.436
35.183
17.772
2.887
1.588
22.247
$/ton of
fertilizer
57.430
237
-------
Table B-93. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
Sulfate Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(500-mw new power unit, 2.0% S in coal;
1 31 , 300 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 43.4 M tons
Phosphate rock 81 .0 M tons
Conditioner 2.6 M tons
Antifoam 65.0 M Ib
Nitric acid catalyst 216 troy oz
Subtotal raw material
Conversion costs
Operating labor and
supervision 87,700 man-hr
Utilities
Steam 462,770 M Ib
Water 2,629,620 M gal
Electricity 50,221,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% 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 26- 19-0 fertilizer
35.00/ton
12.48/ton
46.60/ton
0.20/lb
1 20/troy oz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
Cost/ton
of coal
burned, $
5.472
Total
annual
cost, $
1,520,500
1,010,900
122,400
13,000
25,900
2,692,700
394,600
185,100
131,500
251,100
690,000
40,000
1,692,300
4,385,000
2,258,200
338,500
186.200
2,782,900
Total
annual
cost, $
7,167,900
$/ton of
fertilizer
11.580
7.699
0.932
0.099
0.197
20.507
3.005
1.410
1.002
1.912
5.255
0.304
12.888
33.395
17.198
2.578
1.418
21.194
$/ton of
fertilizer
54.589
^Basis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hi.
Midwest plant location-1969 costs.
Capital investment-$15,S74,000 fixed; $1,170,800 working.
"Cost of steam from power plant cycle.
cCost of electricity at power plant bus bar.
238
-------
Table B-94. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
Suit ate Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(500-mw new power unit, 3.5% S in coal;
230,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 76. 1 M tons
Phosphate rock 141.8 M tons
Conditioner 4.6 M tons
Antifoam 113.4Mlb
Nitric acid catalyst 377 troy oz
Subtotal raw material
Conversion costs
Operating labor and
supervision 101,980 man-hr
Utilities
Steam 805,070 M Ib
Water 4,479,300 M gal
Electricity 61,293,750 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% 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 26- 19-0 fertilizer
35.00/ton
11.88/ton
46.60/ton
0.18/lb
120/troyoz
4.50/man-hr
0.40/M lbb
0.05/M gal
0.005/kwhc
Cost/ton
of coal
burned, $
7.240
Total
annual
cost, $
2,663,500
1,684,600
214,400
20,400
45,200
4,628,100
458,900
322,000
224,000
306,500
881,000
65.000
2,257,400
6,885,500
1,899,500
451,500
248.300
2,599,300
Total
annual
cost, $
9,484,800
$/ton of
fertilizer
11.580
7.324
0.932
0.089
0.197
20.122
2.000
1.400
0.974
1.332
3.830
0.282
9.818
29.940
8.258
1.963
1.079
11.300
$/ton of
fertilizer
41.240
aBasis:
Remaining life of power plant-35 years.
Coal burned-1,310,000 t^ns/yr-O^S Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$19,689,000 fixed; $1,890,500 working.
"Cost of steam from power plant bus bar.
cCost of electricity at power plant bus bar.
239
-------
Table B-95. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
(500-mw existing power unit, 3.5% S in coal;
235,800 tons lyr fertilizer)
Annual quantity Unit cost, $
Total
annual
cost, $
$/ton of
fertilizer
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
78.0 M tons
145.4 M tons
4.7 M tons
116.7M Ib
385 troy oz
102,440 man-hr
35.00/ton
11.88/ton
46.60/ton
0.18/lb
120/troy oz
4.50/man-hr
aBasis:
Remaining life of power plant-32 years.
Coal burned-1,339,600 tons/yi-0.167 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$20,191,000 fixed; $1,937,700 working.
''Cost of electricity at power plant bus bar.
2,730,600
1,727,000
219,800
21,000
46,200
4,744,600
461,000
11.580
7.324
0.932
0.089
0.197
20.122
1.955
Steam 825,400 M Ib
Water 4,598,300 M gal
Electricity 63,660,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% 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 26-1 9-0 fertilizer
0.50/M Ib
0.06/M gal
0.005/kwhb
Cost/ton
of coal
burned, $
8.154
412,700
275,900
318,300
902,000
65,000
2,434,900
7,179,500
2,988,300
487,000
267,800
3,743,100
Total
annual
cost, $
10,922,600
1.750
1.170
1.350
3.825
0.276
10.326
30.448
12.673
2.065
1.136
15.874
$/ton of
fertilizer
46.322
240
-------
Table B-96. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
Sulfate Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa-Process B
(500-mw new power unit, 5.0% S in coal;
328,600 tons/ yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 108.7 M tons
Phosphate rock 202.6 M tons
Conditioner 6.6 M tons
Antifoam 161.7Mlb
Nitric acid catalyst 540 troy oz
Subtotal raw material
Conversion costs
Operating labor and
supervision 1 1 7,500 man-hr
Utilities
Steam 1,1 48,000 Mlb
Water 6,726,720 M gal
Electricity 73,720,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% 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 26- 19-0 fertilizer
30.00/ton
11.88/ton
46.60/ton
0.15/lb
120/troy oz
4.50/man-hr
0.40/M lbb
0.04/M gal
0.005/kwhc
Cost/ton
of coal
burned, $
10.006
Total
annual
cost, $
3,261,700
2,406,700
306,300
24,300
64,800
6,063,800
528,700
459,200
269,100
368,600
1,058,000
90,000
2,773,600
8,837,400
3,411,100
554,700
305.100
4,270,900
Total
annual
cost, $
13,108,300
$/ton of
fertilizer
9.926
7.324
0.932
0.074
0.197
18.453
1.609
1.397
0.819
1.122
3.220
0.274
8.441
26.894
10.381
1.688
0.928
12.997
$/ton of
fertilizer
39.891
"Basis:
Remaining life of power plant—35 years.
Coal burned-1,310,000 tgns/yr-^.75 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$23,525,000 fixed; $2,393,100 working.
Cost of steam from power plant cycle.
tost of electricity at power plant bus bar.
241
-------
Table B-97. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
ouiiatc OUIULIUII aim ounui lyiuAiuc yyutoiiicu My «-»«" yj^-'-a • — —
(1000-mw new power unit, 3,5% S in coal;
444,000 tons lyr fertilizer)
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Antifoam
Nitric acid catalyst
Subtotal raw material
Annual quantity
146.9M tons
273.7 M tons
8.9 M tons
219.3 Mlb
733 troy oz
Unit cost, $
30.00/ton
11.88/ton
46.60/ton
0.15/lb
1 20/troy oz
Total
annual
cost, $
4,407,100
3,251,900
413,800
32,900
87,900
8,193,600
$/ton of
fertilizer
9.926
7.324
0.932
0.074
0.198
18.454
Conversion costs
Operating labor and
supervision
Utilities
136,700 man-hr
4.50/man-hr
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tons/yr-0.725 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$31,000,000 fixed; $3,244,200 working.
^Cost of steam from power plant cycle.
tost of electricity at power plant bus bar.
615,200
1.386
Steam 1,678,300 Mlb
Water 8,680,000 M gal
Electricity 99,575,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.5% 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 26-1 9-0 fertilizer
0.30/M lbb
0.04/M gal
0.004/kwhc
Cost/ton
of coal
burned, $
6.735
503,500
347,200
398,300
1,375,000
120,000
3,359,200
11,552,800
4,495,000
671,800
369,500
5,536,300
Total
annual
cost, $
17,089,100
1.134
0.782
0.897
3.097
0.270
7.566
26.020
10.124
1.513
0.832
12.469
$/ton of
fertilizer
38.489
242
-------
Table B-98. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 26-19-0 Fertilizer Made with Ammonium
Sulfate Solution and Sulfur Dioxide Obtained by Scrubbing Power Plant Stack Gasa—Process B
(1000-mw existing power unit, 3.5% S in coal;
460,000 tons/yr fertilizer)
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Ammonia 1 52.2 M tons
Phosphate rock 283.6 M tons
Conditioner 9.2 M tons
Antifoam 226.8 M Ib
Nitric acid catalyst 760 troy oz
Subtotal raw material
Conversion costs
Operating labor and
supervision 137,700 man-hr
Utilities
Steam 1. 739,500 M Ib
Water 8,988,000 M gal
Electricity 104,941,250 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.8% 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 26- 19-0 fertilizer
30.00/ton
11.88/ton
46.60/ton
0.15/lb
1 20/troy oz
4.50/man-hr
0.45/M Ib
0.05/M gal
0.004/kwhb
Cost/ton
of coal
burned, $
7.013
4,566,000
3,369,200
428,700
34,000
91,200
8,489,100
619,600
782,800
449,400
419,800
1,463,000
120.000
3,854,600
12,343,700
4,869,800
770,900
424,000
6,064,700
Total
annual
cost, $
18,408,400
$/ton of
fertilizer
9.926
7.324
0.932
0.074
0.198
18.454
1.347
1.702
0.977
0.912
3.180
0.261
8.379
26.833
10.586
1.676
0.921
13.183
$/ton of
fertilizer
40.016
Remaining life of power plant-32 years.
Coalburned-2,625,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 118? to 25(f F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$32,904,000 fixed; $3,358,800 working.
''Cost of electricity at power plant bus bar.
243
-------
Table B-99. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
r Cornhhinn Power Plant Stack Gasd-Process C
auiraiH ami
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
(200-mw existing power unit, 3.5% S in coal;
56,700 tons/yr fertilizer)
Annual quantity Unit cost, $
1 4.4 M tons 35.00/ton
25.5 M tons 13.88/ton
1.1 M tons 46.60/ton
Total
annual
cost, $
505,400
343,900
51,300
900,600
$/ton of
fertilizer
8.914
6.065
0.905
15.884
Conversion costs
Operating labor and
supervision
Utilities
69,770 man-hr
4,50/man-hr
aBasis:
Remaining life of powei plant—27 years.
Coal burned-554,400 toiy/yr-O.^S Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$9,589,500 fixed; $606,000 working.
''Cost of electricity at power plant bus bar. and heat from boiler exhaust gas at 1000° F.
314,000
5.538
Net heat from boiler 358,400 MM Btu
Water 3,930,400 M gal
Electricity 38,776,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 15.1% of 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 19- 14-0 fertilizer
0.60/MM Btub
0.06/M gal
0.006/kwhb
Cost/ton
of coal
burned, $
7.617
215,000
235,900
232,700
417,100
15,900
1,430,600
2,331,200
1,448,000
286,100
157,400
1,891,500
Total
annual
cost, $
4,222,700
3.792
4.160
4.104
7.356
0.280
25.230
41.114
25.538
5.046
2.776
33.360
$/ton of
fertilizer
74.474
244
-------
Table B-100. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
(500-mw new power unit, 2. 0% S in coal;
76,600 tons/yr fertilizer)
Annual quantity Unit cost, $
1 9.5 M tons 35.00/ton
34.4 M tons 13.88/ton
1.5Mtons 46.60/ton
Total
annual
cost, $
682,400
477,500
69,900
1,229,800
$/ton of
fertilizer
8.909
6.234
0.913
16.056
Conversion costs
Operating labor and
supervision
Utilities
73,720 man-hr
4.50/man-hr
aBasis:
Remaining life of power plant-35 years.
Coalburned-1,310,000 tgns/yr-0^75 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.,
Power unit on-streara time—7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$13,057,300 fixed; $780,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
331,700
4.330
Net heat from boiler 484,000 MM Btu
Water 5,503,700 M gal
E lectricity 68,06 1 ,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 14.5% of 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 19- 14-0 fertilizer
0.40/MM Btub
0.05/M gal
0.005/kwhb
Cost/ton
of coal
burned, $
4.104
193,600
275,100
340,300
560,000
19,000
1,719,700
2,949,500
1,893,300
343,900
189,200
2,426,400
Total
annual
cost, $
5,375,900
2.527
3.591
4.443
7.311
0.248
22.450
38.506
24.717
4.489
2.470
31.676
$/ton of
fertilizer
70.182
245
-------
Table B-101. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made wtth Ammonium
- - - - - »....:_., power p|ant stack Gas-Process C
JUIIcHC QsJIU LIvMi wuicmicvj »jy w\*i «»*»*•• •a-—--— - ,
(500-mw new power unit, 3.5% S in coal;
134,000 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 34.2 M tons
Phosphate rock 60.2 M tons
Conditionpr 2 7 M tons
V^VJI IU 1 LIU! IG1 ^•»ivifc»^»i**
Subtotal raw material
Conversion costs
Operating labor and
supervision 82,580 man-hr
Utilities
Net heat from boiler 847,000 MM Btu
Water 9,516,800 M gal
E lectricity 92,48 1 ,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 14.5% of 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 19- 14-0 fertilizer
35.00/ton
12.68/ton
46.60/ton
4.50/man-hr
0.40/MM Btub
0.05/M gal
0.005/kwhb
Cost/ton
of coal
burned, $
5.791
Total
annual
cost, $
1,197,000
763,300
125,000
2,086,100
371,600
338,800
475,800
462,400
706,300
33,100
2,388,000
4,474,100
2,371,700
477,600
262,700
3,112,000
Total
annual
cost, $
7,586,100
$/ton of
fertilizer
8.933
5.696
0.939
15.568
2.773
2.528
3.551
3.451
5.271
0.247
17.821
33.389
17.699
3.564
1.960
23.223
$/ton of
fertilizer
56.612
Remaining life of power plant-35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 11 if to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$16,356,800 fixed; $1,185,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
246
-------
Table B-102. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
(500-mw existing power unit, 3.5% S in coal;
137,000 tons/yr fertilizer)
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
35.0 M tons 35.00/ton
61. 5 M tons 12.68/ton
2.8 M tons 46.60/ton
1,224,200
779,800
130,500
2,134,500
$/ton
fertilizer
8.936
5.692
0.953
15.581
Conversion costs
Operating labor and
supervision
Utilities
83,080 man-hr
4.50/man-hr
"Basis:
Remaining life of power plant—32 years.
Coal burned-1,339,600 tons/yr-0.75 Ib/kwh.
Stack gas reheat from llff to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hi. Fertilizer plant on-stream time- 7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$17,329,600 fixed; $1,260,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000 F.
373,900
2.729
Net heat from boiler 866,000 MM Btu
Water 9,634,400 M gal
Electricity 94,056,900 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 14.8% of 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 19- 14-0 fertilizer
0.50/MM Btub
0.06/M gal
0.005/kwhb
Cost/ton
of coal
burned, $
6.087
433,000
578,100
470,300
748,500
33.100
2,636,900
4,771,400
2,564,800
527,400
290,100
3,382,300
Total
annual
cost, $
8,153,700
3.161
4.220
3.433
5.463
0.241
19.247
34.828
18.721
3.850
2.117
24.688
$/ton of
fertilizer
59.516
247
-------
Table B-103. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
" •' ~ • • ~- • • • ».-.-:. Power Plant Stack Gas0—Process I
jungle ouiutiun v/uianicu uy «joi UUUIUM • »»»««' • •— •
(500-mw new power unit, 5.0% S in coal;
191,400 tons/yr fertilizer)
Annual quantity Unit cost, $
Direct Costs
Delivered raw material
Ammonia 48.8 M tons
Phosphate rock 86.0 M tons
Conditioner 3.9 M tons
Subtotal raw material
Conversion costs
Operating labor and
supervision 91,660man-hr
Utilities
Net heat from boiler 1,210,100 MM Btu
Water 13,552,600 M gal
Electricity 121,410,800 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 14.5% of 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 19- 14-0 fertilizer
35.00/ton
1 2.48/ton
46.60/ton
4.50/man-hr
0.40/MM Btub
0.04/M gal
0.005/kwhb
Cost/ton
of coal
burned, $
7.298
Total
annual
cost, $
1,708,000
1,073,300
181,700
2,963,000
412,500
484,000
542,100
607,000
811,900
39,700
2,897,200
5,860,200
2,801,600
579,400
318,700
3,699,700
Total
annual
cost, $
9,559,900
$/ton of
fertilizer
8.924
5.608
0.949
15.481
2.155
2.529
2.832
3.171
3.960
0.207
15.136
30.617
14.637
3.027
1.665
19.329
$/ton of
fertilizer
49.946
aBasis:
Remaining life of power plant—35 years.
Coal burned-1,310,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from 118° to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$19,321,300 fixed; $1,515,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000° F.
248
-------
Table B-104. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made with Ammonium
Sulfate Solution Obtained by Scrubbing Power Plant Stack Gasa-Process C
Direct Costs
Delivered raw material
Ammonia
Phosphate rock
Conditioner
Subtotal raw material
(1000-mw new power unit, 3.5% S in coal;
259,500 tons/yr fertilizer)
Annual quantity Unit cost, $
66.2 M tons 35.00/ton
1 1 6,6 M tons 12.28/ton
5.2 M tons 46.68/ton
Total
annual
cost, $
2,318,000
1,431,800
242,300
3,992,100
$/ton of
fertilizer
8.933
5.518
0.934
15.385
Conversion costs
Operating labor ad
supervision
Utilities
101,820 man-hr
4.50/man-hr
aBasis:
Remaining life of power plant-35 years.
Coal burned-2,537,300 tgns/yr-0.,75 Ib/kwh.
Stack gas reheat from 118 to 250 F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location—1969 costs.
Capital investment-$24,639,300 fixed; $2,010,000 working. Q
"Cost of electricity at power plant bus bar and heat form boiler exhaust gas at 1000 F.
458,200
1.766
Net heat from boiler 1,694,000 MM Btu
Water 1 9,033,600 M gal
Electricity 181,254,500 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Level ized capital charges at 14.5% of 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 19- 14-0 fertilizer
0.30/MM Btub
0.04/M gal
0.004/kwhb
Cost/ton
of coal
burned, $
4.959
508,200
761,300
988,200
1,062,200
53,000
3,831,100
7,823,200
3,572,700
766,200
421,400
4,760,300
Total
annual
cost, $
12,583,500
1.958
2.934
3.808
4.093
0.204
14.763
30.148
13.767
2.952
1.624
18.343
$/ton of
fertilizer
48.491
249
-------
Table B-105. Power Company Economics - Total Venture
Average Annual Manufacturing Costs for 19-14-0 Fertilizer Made
_ ~_ . . 11 o I-I-: — - On,Airar Plant SstarK 1138
OUlTaTB OUIUIIUM \->mqiiic" "T wi»*"~"'a • ..j 1
(1000-mw existing power unit, 3.5% i m coat,
268,000 tons/yr fertilizer)
Annual Quantity Unit cost' $
Direct Costs
Delivered raw material
Ammonia 68.4 M tons
Phosphate rock 1 20.4 M tons
Conditioner 5.4 M tons
Subtotal raw material
Conversion costs
Operating labor and
supervision 102,820 man-hr
Utilities
Net heat from boiler 1 ,642,000 MM Btu
Water 18,722,800 M gal
Electricity 181,776,000 kwh
Maintenance
Labor and material
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Levelized capital charges at 14.8% of 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 19- 14-0 fertilizer
35.00/ton
12.08/ton
46.60/ton
4.50/man-hr
0.45/MM Btub
0.05/M gal
0.004/kwhb
Cost/ton
of coal
burned, $
5.094
Total
annual
cost, $
2,394,000
1,454,400
251,600
4,100,000
462,700
738,900
936,100
727,100
1,149,500
52,900
4,067,200
8,167,200
3,943,700
813,400
447,400
5,204,500
Total
annual
cost, $
13,371,700
$/ton of
fertilizer
8.933
5.427
0.939
15.299
1.726
2.757
3.493
2.713
4.289
0.197
15.175
30.474
14.715
3.035
1.669
19.419
$/ton of
fertilizer
49.893
aBasis:
Remaining life of power plant-32 years.
Coal burned-2,625,000 tons/yr-0.75 Ib/kwh.
Stack gas reheat from llfiP to 250° F., indirect liquid-gas method.
Power unit on-stream time-7,000 hr. Fertilizer plant on-stream time-7,000 hr.
Midwest plant location-1969 costs.
Capital investment-$26,646,400 fixed; $2,175,000 working.
"Cost of electricity at power plant bus bar and heat from boiler exhaust gas at 1000° F.
250
-------
Table B-106
PROCESS A, NONREGULATED FERTILIZER CO. ECONOMICS, 200 MW., EXISTING UNIT, 3.5« 5 IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT =
TOTAL INITIAL INVESTMENT =
OVERALL INTEREST RATE OF RETURN WITH PAYMENT -
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT =
12520000
13395000
1.5*
NEG
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION
KW-MR/ TONS/YEAR
KW FERTILIZER
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
C3STt TION CONTROL,
J/YEAP t/YEAR
NET FERTILIZER
MFG COST,
I/YEAR
NET
FERTILIZER
SALES
REVENUE,
*/YEAR
GROSS INCOME,
*/YEAR
NET INCOME AFTER TAXES,
»/YEAR
WITH
PAYMENT
WITHOUT
PAYMENT
WITH
PAYMENT
WITHOUT
PAYMENT
WITH
PAYMENT
WITHOUT
PAYMENT
CUMULATIVE CASH FLOW,
t
WITH
PAYMENT
WITHOUT
PAYMENT
ANNUAL RETURN ON
INITIAL INVESTMENT,
WITH
PAYMENT
WITHOUT
PAYMENT
9 7000
10 7000
11 5000
12 5000
ii 5000
14 5000
15 5000
16 3500
17 3500
18 3500
11 3500
70 1500
21 15DO
22 1500
73 1500
24 1500
75 1500
76 1500
27 1500
28 1500
7.9 1500
11 iscn
11 1511
12 1500
11 1500
34 1500
15 1500
128600 6083900
128600 6083900
91700 4921100
91700 4921100
91700 4921100
91700 4921100
91700 4921100
64200 4018100
64200 4018100
64200 4018100
64200 2766100
64700 2766100
27600 1490600
27600 1490600
27600 1490600
27600 1490600
27600 1490600
77600 1490600
77600 1490600
27600 1490600
27600 1490600
27600 1490600
77600 1490600
27600 1490600
27600 1490600
27600 1490600
77600 1490600
1087900
1067700
947100
927000
906800
H86600
866400
762900
742800
772600
702400-
682200
553000
532HOO
512600
492400
472300
452100
431900
411700
391600
371400
351200
331000
310900
7.90700
770500
4996000
5016200
3974000
3994100
4014300
4034500
4054700
3255200
3775300
3295500
2063700
2083900
937600
957800
978000
998200
1018300
1038500
1058700
1078900
1099000
1119200
1139400
1159600
1179700
1199900
1220100
6083900
6083900
4921100
4921100
4921100
4921100
4921100
4018100
4018100
4018100
2766100
2766100
1490600
1490600
1490600
1490600
1490600
1490600
1490600
1490600
1490600
1490600
1-490600
1490600
1490600
1490600
1490600
5460400
5460400
3930300
3930300
3930300
3930300
3930300
2774100
2774100
2774100
2774100
2774100
1R09400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
464400 623500)
444200 623500)
437001 990800) (
638001 990800) I
84000) 990800) (
1042001 9908001 I
1244001 990800) (
481100) 1244000) I
5012001 1244000) I
521400) 1244000) (
710400 8000
690200 8000
271800 281200)
251600 2812001
231400 281200)
211200 281200)
191100 281200)
170900 281200)
150700 281200)
130500 281200)
110400 281200)
90200 281200)
70000 281200)
49800 281200)
29700 2812001
9500 281200)
10700) 2812001
232200 3117501
222100 311750)
218501 4954001
31900) 495400)
42000) 495400)
52100) 495400)
62200) 495400)
2405501 622000)
250600) 622000)
2607001 6220001
355200 4000
345100 4000
135900 140600)
125800 140600)
115700 140600)
105600 140600)
95550 140600)
85450 140600)
75350 140600)
65250 140600)
55200 140600)
45100 140600)
35000 1406001
24900 140600)
14850 1406001
4750 1406001
5350) 1406001
1484200 940250
1474100 940250
1230150 756600
1220100 756600
1210000 756600
1199900 756600
1189800 756600
1011450 630000
1001400 610000
991300 630000
155200 4000
145100 4000
135900 I 140600)
125800 140600)
115700 140600)
105600 140600)
95550 140600)
85450 140600)
75350 140600)
65250 140600)
55200 140600)
45100 1406001
35000 140600)
24900 1406001
14850 140600)
4750 140600)
53501 140600)
1484200
295U300
4188450
5403550
6618550
781 1450
9008">50
10019700
11021100
12017400
12367600
12712700
12848600
12974400
13090100
13195700
13291250
13376700
13452050
13517300
13572500
13617600
13657600
13677500
13692350
13697100
13691750
940250
1880500
2637100
3393700
4150300
4906900
5663500
6293500
6923500
7553500
7557500
7561500
7420900
7280300
7139700
6999100
6858500
6717900
6577300
6436700
6296100
6155500
6014900
5874300
5733700
5591100
5452500
1.73
1.66
2.65 0.03
2.58 0.03
1.01
0.94
0.86
0.79
0.71
0. 64
0.56
0.49
O.41
0.34
0.26
0.19
0.11
0.04
TOTAL 79000
2343500 ( 141350001
1171750 ( 7067500)
AVG= 0.32
-------
Table B-107
PROCESS A. NONREGULATEO FERTILIZER CO. ECONOMICS, 500 MW., NEK UNIT, 2.0* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 16695000
TOTAL INITIAL INVESTMENT « $ 17865800
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 9.3*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEG
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
ND PAYOUT WITHOUT PAYMENT
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
3
9
10
ii
IZ
13
14
15
16
17
18
19
70
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
ANNUAL TOTAL FERTILIZER
OPERA- FERTILIZER COMPANY FOR
TION MFG. AIR POLLU-
KH-HR/ TONS/YEAR COST, TION CONTROL,
KW FERTILIZER «/YEAR S/YESR
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
173600
173600
173600
173600
173600
173600
173600
173600
173600
173600
123900
123900
123900
123900
123900
86700
86700
86700
86700
86700
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
4676400
4676400
4676400
4676400
4676400
3523400
3523400
3523400
3523400
3523400
189B900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1B98900
1898900
1898900
1898900
1800000
1772800
1749100
1718800
1690600
1663400
1635900
1608700
1581200
1553800
1379800
1352300
1325100
1297900
1270400
1114100
1086700
1059200
1032000
1004500
827100
799800
772400
745100
717700
690400
663000
635500
608300
530800
553600
526100
498900
471400
444200
NET FERTILIZER
MFG COST, NET
J/YEAR FERTILIZER
SALES
WITH WITHOUT REVENUE,
PAYMENT PAYMENT t/YEAR
6032300
6059500
6083200
6113500
6141700
6168900
6196400
6223600
6251100
6278500
3296600
3324100
3351300
3378500
3406000
2409300
2436700
2464200
2491400
2518900
1071800
1099100
1126500
1153800
1181200
1208500
1235900
1263400
1290600
1318100
1345300
1372800
1400000
1427500
1454700
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
7832300
4676400
4676400
4676400
4676400
4676400
3523400
3523400
3523400
3523400
3523400
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
1898900
7301600
7301600
7301600
7301600
7301600
7301600
7301600
7301600
7301600
7301600
5268200
5268200
5268200
5268200
5268200
3721200
3721200
3721200
3721200
3721200
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
GROSS INCOME, NET INCOME AFTER TAXES,
S/YEAR J/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
1269300
1242100
1218400
1188100
1159900
1132700
1105200
1078000
1050500
1023100
1971600
1944100
1916900
1889700
1862200
1311900
1284500
1257000
1229800
1202300
551200
523900
496500
469200
441800
414500
387100
359600
332400
304900
277700
250200
223000
195500
168300
5307001
5307001
5307001
5307001
5307001
530700)
530700)
530700)
530700)
530700)
591800
591800
591800
591800
591800
197800
197800
197800
197800
197800
275900)
275900)
275900)
275900)
275900)
275900)
275900)
275900)
275900)
2759001
275900)
275900)
275900)
275900)
275900)
634650
621050
609200
594050
579950
566350
552600
539000
525250
511550
985800
972050
958450
944850
931100
655950
642250
628500
614900
601150
275600 (
261950 (
248250 I
234600 (
220900 I
207250 I
193550 <
179800 t
166200 I
152450 (
138850 I
125100 (
111500 <
97750 (
84150 I
265350)
265350)
265350)
265350)
265350)
265350)
265350)
265350)
265350)
265350)
295900
295900
295900
295900
295900
98900
98900
98900
98900
98900
137950)
1379501
137950)
137950)
137950)
137950)
1379501
137950)
1379501
1379501
1379501
137950)
137950)
137950)
137950)
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2304150
7290550
2278700
2263550
2249450
2235850
2222100
2208500
2194750
2181050
985800
972050
958450
944850
931100
655950
642250
628500
614900
601150
275600
261950
248250
234600
220900
207250
193550
179800
166200
15P450
13SB50
125100
111500
97750
84150
1404150
1404150
1404150
L404150
1404150
1404150
1404150
1404150
1404150
1404150
295900
295900
295900
295900
295900
98900
98900
98900
98900
98900
( 137950)
( 137950)
( 137950)
( 137950)
( 137950)
( 137950)
( 137950)
( 137950)
( 137950)
( 1379501
( 137950)
I 137950)
( 137950)
1 137950)
( 137950)
ANNUAL RETURN ON
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
$ *
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
2304150
4594700
6873400
9136950
11386400
13622250
15844350
18052850
20247600
22428650
23414450
24386500
25344950
26289800
27220900
27876850
28519100
29147600
29762500
30363650
30639250
30901200
31149450
31384050
31604950
31812200
32005750
32185550
32351750
32504200
32643050
32768150
32879650
32977400
33061550
1404150
2808300
4212450
5616600
7020750
8424900
9829050
11233200
12637350
14041500
14337400
14633300
14929200
15225100
15521000
15619900
15718800
15817700
15916600
16015500
15877550
15739600
15601650
15463700
15325750
15187800
15049850
14911900
14773950
14636000
14498050
14360100
14222150
14084200
13946250
3.55
3.48
3.41
3.33
3.25
3.17
3.09
3.02
2.94
2.86
5.52
5.44
5.36
5.29
5.21
3.67
3.59
3.52
3.44
3.36
1.54
1.47
1.39
1.31
1.24
1.16
1.08
1.01
0.93
0.85
0.78
0.70
0.62
0.55
0.47
1.66
1.66
1.66
1.66
1.66
0.55
0.55
0.55
0.55
0.55
TOTAL 135000 3347000
147805500 142308000
32733100 ( 5497500) 16366550 I 27487501
-------
Table B-108
PROCESS A, NONREGULATED FERTILIZER CO. ECONOMICS, 500 HW., MEN UNIT, 3.5* S IN COAL. 28^14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT
TOTAL INITIAL INVESTMENT
OVERALL INTEREST RATE OF RETURN KITH PAYMENT
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT
21470000
23360500
13.OX
5.7*
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
6.1
8.7
YEARS ANNUAL
AFTER OPERA-
POWFR TION
UNIT KW-HR/ TONS/YEAR
START KW FERTILIZER
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
20
21
22
23
24
25
26
27
28
29
10
31
32
33
34
35
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
303800
303800
303800
303800
303800
303800
303800
303800
303800
303800
217000
217000
217000
217000
217000
151900
151900
151900
151900
151900
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
COST, TION CONTROL,
t/YEAR J/Y6AR
11858100
11858100
11858100
11858100
11858100
11858100
11858100
11858100
11858100
11858100
7296300
7296300
7296300
7296300
7296300
5434500
5434500
5434500
5434500
5434500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2150200
2119600
2089200
2058700
2028100
1997500
1967100
1936600
1906000
1875600
1640100
1610000
1579400
1549000
1518400
1311600
1281200
1250600
1220100
1189700
952200
921600
89UOO
860700
830100
799500
769200
738400
708100
677400
647100
616500
585900
555600
525000
NET FERTILIZER
MFG COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
9707900
9738500
9768900
9799400
9830000
9860600
9891000
9921500
9952100
9982500
5656200
5686300
5716900
5747300
5777900
4122900
4153300
4183900
4214400
4244800
1899300
1929900
1960400
1990800
2021400
2052000
2082300
2113100
2143400
2174100
2204400
2235000
2265600
2295900
2326500
11858100
11858100
11858100
11853100
11858100
11858100
11858100
11858100
11858100
11858100
7296300
7296300
7296300
7296300
7296300
5434500
5434500
5434500
5434500
5434500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
2851500
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
9052000
9052000
9052000
9052000
9052000
6415000
6415000
6415000
6415000
6415000
2820000
2820300
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
2820000
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
2784100
2753500
2723100
2692600
2662000
2631400
2601000
2570500
2539900
2509500
3395800
3365700
3335100
3304700
3274100
2292100
2261700
2231100
2200600
2170200
920700
990100
859600
829200
798600
768000
737700
706900
676600
645900
615600
585000
554400
524100
493500
633900
633900
633900
633900
633900
633900
633900
633900
633900
633900
1755700
1755700
1755700
1755700
1755700
980500
980500
980500
980500
980500
315001
315001
315001
315001
31500)
315001
315001
31500)
315001
31500)
31500)
31500)
31500)
31500)
315001
1392050
1376750
1361550
1346300
1331000
1315700
1300500
1285250
1269950
1254750
1697900
1.682850
1667550
1652350
1637050
1146050
1130850
1115550
1100300
1085100
460350 I
445050 (
429800 (
414600 (
399300 I
384000 1
368850 (
353450 (
338300 |
322950 (
307800 I
292500 (
277200 1
262050 (
246750 1
316950
316950
316950
316950
316950
316950
3169SO
316950
316950
316950
877850
877850
877850
877850
877851
490250
490250
490250
490250
490250
15750)
157501
15750)
15750)
15750)
15750)
15750)
15750)
15750)
157501
15750)
15750)
15750)
157501
15750)
CASH FLOW,
«/YEAR
WITH WITHOUT
PAYMENT PAYMENT
3539050
3523750
3508550
3493300
3478000
3462700
3447500
3432250
3416950
3401750
1697900
1682850
1667550
1652350
1637050
1146050
1130850
1115550
1100300
1085100
460350
445050
429800
414600
399300
384000
368850
353450
338300
322950
307800
292500
277200
262050
246750 (
2463950
2463950
2463950
2463950
2463950
2463950
2463950
2463950
2463950
2463950
877850
877850
877850
877850
877850
490250
490250
490250
490250
490250
15750)
15750)
157501
157501
157501
157501
15750)
15750)
15750)
15750)
15750)
15750)
15750)
15750)
157501
CUMULATIVE
t
WITH
PAYMENT
3539050
7062800
10571350
14064650
17542650
21005350
24452850
27885100
31302050
34703800
36401700
38084550
39752100
41404450
43041500
44187550
45318400
46433950
47534250
48619350
49079700
49524750
49954550
50369150
50768450
51152450
51521300
51874750
52213050
52536000
52843800
53136300
53413500
53675550
53922300
CASH FLOW,
WITHOUT
PAYMENT
2463950
4927900
7391850
9855800
12319750
14783700
17247650
19711600
22175550
24639500
25517350
26395200
27273050
28150900
29028750
29519000
30009250
30499500
30989750
31480000
31464250
31448500
31432750
31417000
31401250
31385500
31369750
31354000
31338250
31322500
31306750
31291000
31275250
31259500
31243750
ANNUAL RETURN ON
INITIAL INVESTMENT,
X
WITH WITHOUT
PAYMENT PAYMENT
5.96
5.89
5.83
5.76
5.70
5. 63
5.57
5.50
5.44
5.37
7.27
7.20
7.14
7.07
7.01
4.91
4.84
4.78
4.71
4.65
1.97
1.91
1.84
1.77
1.71
1.64
1.58
1.51
1.45
1.38
1.32
1.25
1.19
1.12
1.06
.36
.36
.36
.36
.36
.36
.36
.36
.36
.36
.76
3.76
3.76
3.76
3.76
2.10
2.10
2.10
2.10
2.10
TOTAL 135000 5862000
1.20
-------
Table B-109
PROCESS A, NCINREGULATED FERTILIZER CD. ECONOMICS, 500 HW., EXISTING UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 22320000
TOTAL INITIAL INVESTMENT = « 24257700
OVERALL INTEREST RATE OF RETURN WITH PAYMENT - 11.0%
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = 1.4%
YEARS RE8UIRED FOR PAYOUT W!iH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITH >J' PAYMENT:
6.4
9.8
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
20
21
22
23
24
?5
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
7000
7000
Tooo1
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
310900
310800
310800
310800
310800
310800
310800
222000
222000
222000
222000
222000
155400
155400
155400
155400
155400
66800
66800
66800
66800
66800
66800
66800
66800
66800
66800
66800
66800
66800
66800
66X00
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
COST, TION CONTROL,
J/YEAR I/YEAR
12410000
12410000
12410000
12410000
12410000
12410000
12410000
9877100
9877100
9877100
76451-00
7645100
5692000
5692000
5692000
5692000
5692000
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
2261500
2226100
2191000
2155600
2120500
2085100
2050000
1804000
1768900
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1061200
1025900
990700
955400
920200
884900
849700
814300
779200
743800
708700
673300
638200
602800
567700
NET FERTILIZER
MFG COST,
»/YEAR
WITH WITHOUT
PAYMENT PAYMENT
10148500
10183900
10219000
10254400
10289500
10324900
10360000
8073100
8108200
8143600
5946800
5982100
4244400
4279700
4314900
4350200
4385400
2181900
2217200
2252400
2287700
2322900
2393400
2428800
2463900
2499300
2534400
2569800
2604900
2640300
2675400
12410000
12410000
12410000
12410000
12410000
12410000
12410000
9877100
9877100
9877100
7645100
7645100
5692000
5692000
5692000
5692000
5692000
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
3243100
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
12764600
12764600
12764600
12764600
12764600
12764600
12764600
9253000
9253000
9253000
9253000
9253000
6561000
6561000
6561000
6561000
6561000
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2893800
2883800
GROSS INCOME, NET INCOME AFTER TAXES,
$/YEAR */YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
2616100
2580700
2545600
2510200
2475100
2439700
2404600
1179900 (
1144800 I
1109400 1
3306200
3270900
2316600
2281300
2246100
2210800
2175600
701900
666600
631400
596100
560900
525600
490400
455000
419900
384500
349400
314000
278900 (
243500 1
208400 (
354600
354600
354600
354600
354600
354600
354600
624100)
624100)
624100)
1607900
1607900
869000
869000
869000
869000
869000
3593001
3593001
3593001
3593001
3593001
359300)
359300)
359300)
359300)
3593001
359300)
359300)
359300)
359300)
359300)
1308050
1290350
1272800
1255100
1237550
1219850
1202300
589950 (
572400 (
554700 1
1653100
1635450
1158300
1140650
1123050
1105400
10B7800
350950
333300
315700
298050
280450
262800
245200
227500
209950
192250
174700
157000
139450
121750 (
104200 I
177300
177300
177300
177300
177300
177300
177300
312050)
312050)
312050)
803950
803950
434500
434500
434500
434500
434500
179650)
179650)
179650)
179650)
179650)
179650)
1796501
1796501
1796501
1796501
1796501
179650)
179650)
179650)
1796501
CASH FLOW,
«/YE»R
WITH WITHOUT
PAYMENT PAYMENT
3540050
3522350
3504800
1487100
3469550
3451850
3434300
2821950
2804400
2786700
1653100
1635450
1158300
1140650
1123050
1105400
1087800
350950
333300
315700
298050
?')04'50
26? 900
245200
227500
209950
192250
174700
157000
139450
121750
104200
2409300
2409300
2409300
2409300
2409300
2409300
2409300
1919950
1919950
1919950
803950
803950
434500
434500
434500
434500
434500
( 179650)
( 179650)
179650)
179650)
1796501
179650)
179650)
179650)
179650)
1796501
179650)
179650)
179650)
( 179650)
ANNUAL RETURN ON
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
$ *
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
3540050
7062400
10567200
14054300
17523850
20975700
24410000
27231950
30036350
32823050
34476150
36111600
37269900
38410550
39533600
40639000
41726800
42077750
42411050
42726750
43024800
43305250
43813250
44040750
44250700
44442950
44617650
44774650
44914100
45035850
45140050
2409300
4818600
7227900
9637200
12046500
14455800
16865100
18785050
20705000
22624950
23428900
24232850
24667350
25101850
25536350
25970850
26405350
26225700
26046050
25866400
25686750
25507100
25147800
24968150
24788500
24608850
24429200
24249550
24069900
23890250
23710600
5.39
5.32
5.25
5.17
5.10
5.03
4.96
2.43
2.36
2.29
6.81
6.74
4.77
4.70
4.63
4.56
4.48
1.45
1.37
1.30
1.23
1.16
1 . 08
1.01
0.94
0.87
0.79
0.72
0.65
0.57
0.50
0.43
0.73
0.73
0.73
0.73
0.73
0.73
0.73
3.31
3.31
1.79
1.79
1.79
1.79
1.T9
TOTAL 114000 5064600 208898000
42858900 166039100 208898000 211679200
AVG= 2.94
0.18
-------
Table B-110
PROCESS A, NONREGULATEO FERTILIZER CO. ECONOMICS. 500 MM., NEW UNIT. 5.0« S IN COM., 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT . S 26130000
TOTAL INITIAL INVESTMENT « $ 28523100
OVERALL INTEREST RATE OF RETURN HITH PAYMENT = 17.4*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = 11.41
YEARS REQUIRED FOR PAYOUT HITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT!
5.0
6.6
YEARS
AFTER
POHFR
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
31
32
33
34
35
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
ANNUAL TOTAL FERTILIZER
OPERA- FERTILIZER COMPANY FOR
TION MFG. AIR POLLU-
KH-HR/ TONS/YEAR COST, TION CONTROL,
KW FERTILIZER S/YEAR $/YEAR
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
434000
434000
434000
434000
434000
434000
434000
434000
434000
434000
309800
309800
309800
309800
309800
217000
217000
217000
217000
217000
92800
92800
92800
92800
92800
92800
92800
9280O
92800
92800
92800
92800
92800
92800
92800
14818300
14818300
14318300
14818300
14818300
14818300
14818300
14818300
14818300
14818300
9148200
9148200
9148200
9148200
9148200
6794900
6794900
6794900
6794900
6794900
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3527800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1803000
1769500
1512100
1478400
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
910300
B76800
843100
809600
776200
742500
708800
675300
641800
608100
NET FERTILIZER
MFG COST,
S/YEAR
HITH WITHOUT
PAYMENT PAYMENT
I23U800
12345300
12379000
12412500
12446200
12479700
12513400
12546800
12580300
12614000
7244300
7278000
7311500
7345200
7378700
5282800
5316500
5350000
5383600
5417100
2444600
2478100
2510900
2545300
2578800
2612500
2646000
2679700
2713200
2746600
2780300
Z814000
2847500
2881000
2914700
14818300
14818300
14818300
14818300
14818300
14818300
14818300
14818300
14818300
14818300
9148200
9148200
9148200
9148200
9148200
6794900
6794900
6794900
6794900
6794900
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
3522800
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
17516200
17516200
17516200
17516200
17516200
17516200
17516200
17516200
17516200
17516200
12726600
12726600
12726600
12726600
12726600
9051000
9051000
9051000
9051000
9051000
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
GROSS INCOME, NET INCOME AFTER TAXES,
*/YEAR S/YEAR
HITH WITHOUT HITH HITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
5204400
5170900
5137200
5103700
5070000
5036500
5002800
4969400
4935900
4902200
5482300
5448600
5415100
5381400
5347900
3768200
3734500
3701000
3667400
3633900
1499300
1466500
1432100
1398600
1364900
1331400
1297700
1264200
1230800
1197100
U63400
1129900
1096400
1062700
2697900
2697900
2697900
2697900
2697900
2697900
2697900
2697900
2697900
2697900
3578400
3578400
3578400
3578400
3578400
2256100
2256100
2256100
2256100
2256100
454600
454600
454600
454600
454600
454600
454600
454600
454600
454600
454600
454600
454600
454600
2602200
2585450
2568600
2551850
2535000
2518250
2501400
2484700
2467950
2451100
2741150
2724300
2707550
2690700
2673950
1884100
1367250
1850500
1833700
1816950
766400
749650
733250
716050
699300
682450
665700
648850
632100
615400
598556
581700
564950
548200
531350
1348950
1348950
1348950
1348950
1348950
1348950
1348950
1348950
1348950
1348950
1789200
1789200
1789200
1789200
1789200
1128050
1128050
1128050
1128050
1128050
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
CASH FLOH,
S/YEAR
HITH WITHOUT
PAYMENT PAYMENT
5215200
5198450
5181600
5164850
5148000
5131250
5114400
5097700
5080950
5064100
2741150
2724300
2707550
2690700
2673950
1884100
1967250
1850500
1833700
1S16950
766400
749650
733250
716050
699300
682450
665700
648850
632100
615400
59B550
581700
564950
548200
531350
3961950
3961950
3961950
3961950
3961950
3961950
3961950
3961950
3961950
3961950
1789200
1789200
1789200
1789200
1789200
1128050
1128050
1128050
1123050
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
227300
CUMULATIVE
S
HITH
PAYMENT
5215200
10413650
15595250
20760100
25908100
31039350
36153750
41251450
46332400
51396500
54137650
56861950
59569500
62260200
64934150
68685500
70536000
72369700
74186650
75702700
76435950
77152000
77851300
78533750
79199450
79848300
80480400
81095ROO
81694350
82276050
82841000
83389200
83920550
CASH FLOH,
HITHOUT
PAYMENT
3961950
7923900
11885850
15847800
19809750
23771700
27733650
31695600
35657550
39619500
41408700
43197900
44987100
46776300
48565500
50821600
51949650
53077700
54205750
54660350
54887650
55H4950
55342250
55569550
55796850
56024150
56251450
56478750
56706050
56933350
57160650
57387950
57615250
ANNUAL RETURN ON
INITIAL INVESTMENT,
%
HITH HITHOUT
PAYMENT PAYMENT
9.12
9.06
9.01
8.95
8.89
8.83
8.77
8.71
8.65
8.59
9.61
9.55
9.49
9.43
9.37
6.55
6.49
6.43
6.37
2.63
2.57
2.51
2.45
2.39
2.33
2.27
2.22
2.16
2.10
2.04
1.98
1.92
1.86
4.73
4.73
4.73
4.73
4.73
4.73
4.73
4.73
4.73
4.73
6.27
6.27
6.27
6.27
6.27
3.95
3.95
3.95
3.95
3.95
0. 80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.30
o.ao
0.80
0.80
0.80
0.80
0.80
TOTAL 135000 8366000 280740500
52610600 228129900 280740500 343711000 115581100
10
-------
to
u>
Os
Table B-111
PROCESS A, NONREGULATED FERTILIZER CO. ECONOMICS, 1000 MW. , NEW UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT » $ 34500000
TOTAL INITIAL INVESTMENT = I 37744200
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 17.9*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT - 12.0?
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
4.9
6.4
YEARS
AFTER
POWER
UNIT
START
I
2
3
4
5
ft
7
a
9
10
11
12
13
14
15
16
17
18
19
?0
21
22
23
24
25
26
27
28
29
30
31
12
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
taoa
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
TONS/YEAR
FERTILIZER
587500
587500
587500
587500
597500
587500
587500
587500
587500
587500
419700
419700
419700
419700
419700
293800
293800
293800
293800
293800
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
MFG.
COST,
t/YEAR
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
11984900
11984900
11984900
11984900
11984900
8894900
8894900
8894900
8894900
8894900
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
AIR POLLU-
TION CONTROL,
t/YEAR
3362400
3317000
3271900
3226500
3181200
3135800
3090700
3045400
3000000
2954900
2565100
2519800
2474500
2429300
2384000
2053500
2008400
1963100
1917700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1179500
1134200
1088800
1043700
998400
953000
907700
862500
NET FERTILIZER
MFG COST,
*/YEAR
WITH
PAYMENT
16088400
16133800
16178900
16224300
16269600
16315000
16360100
16405400
16450800
16495900
9419800
9465100
9510400
9555600
9600900
6841400
6886500
6931800
4977200
7022500
3107100
3152400
3197800
3242900
3288200
3333600
3378900
3424100
3469400
3514800
3559900
3605200
3650600
3695900
3741100
WITHOUT
PAYMENT
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
19450800
11984900
11984900
11984900
11984900
11984900
8894900
8894900
8894900
8894900
8894900
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
4603600
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
16972700
16972700
16972700
16972700
16972700
12098700
12098700
12098700
12098700
12098700
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
GROSS INCOME,
*/YEAR
WITH
PAYMENT
7182500
7137100
7092000
7046600
7001300
6955900
6910800
6865500
6820100
6775000
7552900
7507600
7462300
7417100
7371800
5257300
5212200
5166900
5121500
5076200
2259400
2214100
2168700
2123600
2078300
2032900
1987600
1942400
1897100
1851700
1806600
1761300
1715900
1670600
1625400
WITHOUT
PAYMENT
3820100
3820100
3820100
3820100
3820100
3820100
3820100
3820100
3820100
3820100
4987800
4987800
4987800
4987800
4987800
3203800
3203800
3203800
3203800
3203800
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
762900
NET INCOME AFTER TAXiS,
t/YEAR
WITH
PAYMENT
3591250
3568550
3546000
3523300
3500650
3477950
3455400
3432750
3410050
3387500
3776450
3753800
3731150
3708550
3685900
2628650
2606100
2583450
2560750
2538100
1129700
1107050
1084350
1061800
1039150
1016450
993800
971200
948550
925850
903300
880650
857950
835300
812700
W I THOUT
PAYMENT
1910050
1910050
1910050
1910050
19100SO
1910050
1910050
1910050
19100 SO
19100SO
2493900
2493900
2493900
2493900
2493900
1601900
1601900
1601900
1601900
1601900
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
CASH FLOW,
$/YEAR
•(ITH
PAYMENT
7041250
7018550
6996000
6973300
6950650
6927950
6905400
6882750
6860050
6837500
3776450
3753800
3731150
3708550
3685900
2628650
2606100
2583450
2560750
2538100
1129700
1107050
1084350
1061800
1039150
1016450
993800
971200
948550
925850
903300
880650
857950
835300
812700
WITHOUT
PAYMENT
5360050
5360050
5360050
5360050
5360050
5360050
5360050
5360050
5360050
5360050
2493900
2493900
2493900
2493900
2493900
1601900
1601900
1601900
1601900
1601900
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
381450
CUMULATIVE CASH FLOW,
(
WITH
PAYMENT
7041250
14059800
21055800
28029100
34979750
41907700
48813100
55695850
62555900
69393400
73169850
76923650
80654800
84363350
88049250
90677900
93284000
95867450
98428200
100966300
102096000
103203050
104287400
105349200
106388350
107404800
108398600
109369800
110318350
111244200
112147500
113028150
113886100
114721400
115534100
WITHOUT
PAYMENT
5360050
10720100
16080150
21440200
26800250
32160300
37520350
42880400
48240450
53600500
56094400
58588300
61082200
63576100
66070000
67671900
69273800
70875700
72477600
74079500
74460950
74842400
75223850
75605300
75986750
76368200
76749650
77131100
77512550
77894000
78275450
78656900
79038350
79419800
79801250
ANNUAL RETURN ON
INITIAL INVESTMENT,
t
WITH
PAYMENT
9.51
9.45
9.39
9.33
9.27
9.21
9.15
9.09
9.03
8.97
10.01
9.95
9.89
9.83
9.77
6.96
6.90
6.84
6.78
6.72
2.99
2.93
2.87
2.81
2.75
2.69
2.63
2.57
2.51
2.45
2.39
2.33
2.27
2.21
2.15
WITHOUT
PAYMENT
5.06
5.06
5.06
5.06
5.06
5.06
5.06
5.06
5,06
5.06
6.61
6.61
6.61
6.61
6.61
4.24
4.24
4.24
4.24
4.24
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
1.01
— on —
1.01
I. 01
1.01
1.01
TOTAL 135000 11337000
71465700 296495300 367961000 458563500 162068200
AVG= 6.13
-------
Table B-112
PROCESS A, NONREGULATED FERTILIZER CO. ECONOMICS, 1000 MM., EXISTING UNIT, 3.5? S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT - t 36550000
TOTAL INITIAL INVESTMENT = » 39908800
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 15.6*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = 9.1*
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS' REQUIRED FOR PAYOUT WITHOUT PAYMENT:
5.2
6.9
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
H
9
10
11
12
13
1*
15
16
17
18
19
20
21
22
?3
24
25
?6
27
28
29
30
31
1?
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KM
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FDR
TONS/YEAR
FERTILIZER
607600
607600
607600
607600
607600
607600
607600
433800
433800
433800
433800
433800
303700
303700
303700
303700
303700
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
MFG.
COST,
t/YEAR
20792300
20792300
20792300
20792300
20792300
20792300
20792300
16433000
/6433000
15433000
12778000
12778000
9515600
9515600
9515600
9515600
9515600
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
AIR POLLU-
TION CONTROL,
t/YEAR
3587300
3533800
3480600
3427200
3373900
3319900
3267200
2857000
2803800
2750300
2696900
2643600
2294300
2241100
2187600
2134400
2080900
1685300
1632000
1578600
1525300
1471900
1418600
1365200
13H900
1258500
1205000
1151800
1098300
1045100
991600
938400
NET FERTILIZER
MFC COST,
t/YEAR
WITH
PAYMENT
17205000
17258500
17311700
17365100
17418400
17472400
17525100
13576000
13629200
13682700
10081 100
10134400
7221300
7274500
7328000
7381200
7434700
3230800
3284100
3337500
3390800
3444200
3497500
3550900
3604200
3657600
3711100
3764300
3317800
3871000
3924500
3977700
WITHOUT
PAYMENT
20792300
20792300
20792300
20792300
20792300
20792300
20792300
164330,00
16433000
16433000
12778000
12778000
9515600
9515600
9515600
9515600
9515600
4916100
4916100
4916100
4916100
4916100
491610D
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
4916100
NET
FERTILIZER
SALES
REVENUE,
t/YE»R
24018400
24018400
24018400
24018400
24018400
24018400
24018400
17508200
17508200
17508200
17508200
17508200
12488100
12488100
12488100
12488100
12488100
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
GROSS INCOME,
t/YEAR
WITH
PAYMENT
6813400
6759900
6706700
6653300
6600000
6546000
6493300
3932200
3879000
3825500
7427100
7373800
5266800
5213600
5160100
5106900
5053400
2291900
2238600
2185200
2131900
2078500
2025200
1971800
1918500
1865100
1811600
1758400
1704900
1651700
1598200
1545000
WITHOUT
PAYMENT
3226100
3226100
3226100
3226100
3226100
3226100
3226100
1075200
1075200
1075200
4730200
4730200
2972500
2972500
2972500
2972500
2972500
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
606600
NET INCOME AFTER TAXES,
t/YEAR
WITH
PAYMENT
3406700
3379950
3353350
3326650
3300000
3273000
3246650
1966100
1939500
1912750
3713550
3686900
2633400
2606800
2580050
2553450
2526700
1145950
1119300
1092600
1065950
1039250
1012600
985900
959250
932550
905800
879200
852450
825850
799100
772500
WITHOUT
PAYMENT
1613050
1613050
1613050
1613050
1613050
1613050
1613050
537600
537600
537600
2365100
2365100
1486250
1486250
1486250
1486250
1486250
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
CASH FLOW,
t/YEAR
WITH
PAYMENT
7061700
7034950
7008350
6981650
6955000
6928000
6901650
5621100
5594500
5567750
3713550
3686900
2631400
2606800
2580050
2553450
2526700
1145950
1119300
1092600
1065950
1039250
1012600
985900
959250
932550
905800
879200
852450
825850
799100
772500
WITHOUT
PAYMENT
5268050
5268050
5268050
5268050
5268050
5268050
5268050
4192600
4192600
4192600
2365100
2365100
1486250
1486250
1486250
1486250
1486250
303300
303300
303300
303300
303300
303300
303300
303300
303300
303300
303360
303300
303300
303300
303300
CUMULATIVE
t
WITH
PAYMENT
7061700
14096650
21105000
28086650
35041650
41969650
48871300
54492400
60086900
65654650
69368200
73055100
75688500
78295300
80875350
83428800
85955500
87101450
88220750
89313350
90379300
91418550
92431150
93417050
94376300
95308850
96214650
97093850
97946300
98772150
99571250
100343750
CASH FLOW,
WITHOUT
PAYMENT
5268050
10536100
15804150
21072200
26340250
31608300
36876350
41068950
45261550
49454150
51819250
54184350
55670600
57156850
58643100
60129350
61615600
61918900
62222200
62525500
62828800
63132100
63435400
63738700
64042000
64345300
64648600
64951900
65255200
65558500
65361800
66165100
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH
PAYMENT
8.54
8.47
8.40
8.34
8.27
8.20
8.14
4.93
4.86
4.79
9.31
9.24
6.60
6.53
6.46
6.40
6.33
2.87
2.80
2.74
2.67
2.60
2.54
2.47
2.40
2.34
2.27
2.20
2.14
2.07
2.00
1.94
WITHOUT
PAYMENT
4.04
4.04
4.04
4.04
4.04
4.04
4.04
1.35
1.35
1.35
5.93
5.93
3.72
3.72
3.72
3.72
3.72
0.76
0.76
0.76
0.76
0.76
0. 76
0.76
0.76
0.76
0.76
0.76
0.76
0.76
0.76
0.76
TOTAL 114000
68357300 273363300
127587500
2.32
N>
l/l
-------
to
I/I
IX
Table B-113
PROCESS B, NONREGULATED FERTILIZER CD. ECONOMICS, 200 MW., EXISTING UNIT, 3.51 S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = ( 11428000
TOTAL INITIAL INVESTMENT = t 12303000
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 0.51
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEC
YEARS REQUIRED FOR PAYOUT KITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
YEARS
4FTER
POWER
UNIT
START
1
2
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
TOTAL
FERTILIZER
MFG.
COST,
t/YEAR
PAYMENT TO NET FERTILIZER
FERTILIZER MFC COST,
COMPANY FOR t/YEAR
AIR POLLU-
TION CONTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
GROSS INCOME, NET INCOME AFTER TAXES,
t/YEAR t/VEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
CASH FLOW, CUMULATIVE CASH FLOW,
t/YEAR t
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH WITHOUT
PAYMENT PAYMENT
t 7000
10 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 350«
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
28 1500
21 1500
30 1500
31 1500
32 1500
33 1500
34 1500
35 1500
97100 5157200
97100 5157200
69500 4217600
69500 4217600
69500 4217600
69500 4217600
69500 4217600
48600 3484000
48600 3484000
48600 3484000
43600 2341200
48600 2341200
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20HOO 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
20800 1292500
1087900
1067700
947100
927000
906800
886600
866400
762900
742800
722600
702400
682200
553000
532800
512600
492400
472300
452100
431900
411700
391600
371400
351200
331000
310900
290700
270500
4069300
4089500
3270500
3290600
3310800
3331000
3351200
2721100
2741200
2761400
1638800
1659000
739500
759700
779900
800100
820200
840400
860600
880800
900900
921100
941300
961500
981600
1001800
1022000
5157200
5157200
4217600
4217600
4217600
4217600
4217600
3484000
3484000
3484000
2341200
2341200
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
1292500
4386000
4386000
3162300 (
3162300 1
3162300
3162300
3162300
2225400
2225400
2225400
2225400
2225400
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000 I
963000 1
963000 1
316700 ( 771200)
296500 ( 7712001
1082001 ( 1055300) (
128300) 1055300) I
14B500) 1055300) (
168700) 1055300) (
188900) 10553001 (
495700) 1258600) 1
515800) 1258600) (
536000) 12586001 (
586600 115800)
566400 115800)
223500 3295001
203300 329500)
183100 329500)
162900 329500)
142800 329500)
122600 329500)
102400 329500)
82200 329500)
62100 329500)
41900 329500)
21700 329500)
1500 3295001
18600) 3295001 (
38800) 3295001 (
59000) 329500) (
158350 ( 385600)
148250 ( 3856001
54100) 1 5276501
641501 I 5276501
74250) ( 527650)
84350) I 527650)
94450) 527650)
2478501 629300)
257900) 629300)
268000) 629300)
2933001 5790C;
283200 57900-1
111T50 1647561
101650 1647501
91550 164750)
81450 164750)
71400 164750)
61300 164750)
51200 1647501
41100 1647501
31050 1647501
20950 164750)
10850 1647501
750 164750)
9300) 1647501
19400) 164750)
29500) 1647501
1301150 757200
1291050 757200
1088700 615150
1078650 615150
1068550 615150
1058450 615150
1048350 615150
894950 513500
R84900 513500
874800 513500
293300 57900]
283200 57900)
111750 164750)
101650 164750)
91550 1647501
81450 164750)
71400 164750)
61300 164750)
51200 1647501
41100 1647501
31050 1647SOI
20950 164750)
10850 164750)
750 164750)
( 9300) 164750)
( 19400) 164750)
( 29500) 164750)
1301150
2592200
3680900
4759550
5828100
6B86550
7934900
8829850
9714750
10589550
10882850
11166050
11277800
11379450
11471000
11552450
11623850
11685150
11736350
11777450
11808500
H 829450
840300
11841050
11831750
U812350
11782850
757200
1514400
2129550
2744700
3359850
3975000
4590150
5103650
5617150
6130650
6072750
6014850
5850100
5685350
5520600
5355850
5191100
5026350
4861600
4696850
4532100
4367350
4202600
4037850
3873100
3708350
3543600
1.29
1.20
2.38
2.30
0.91
0.83
0.74
0.66
0.58
0.50
0.42
0.33
0.25
0.17
0.09
0.01
TOTAL 79000
-------
Table B-114
PROCESS B. NONREGULATEO FERTILIZER CO. ECONOMICS, 500 MW., NEW UNIT, 2.01 S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = » 15574000
TOTAL INITIAL INVESTMENT = » 167*4800
OVERALL INTEREST RATE OF RETURN WITH PAVMENT = 8.3*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEG
YEARS REQUIRED FOR PAYOUT WITH PAYMENT!
NO PAYOUT WITHOUT PAYMENT
7.8
YEARS ANNUAL
AFTER OPERA-
POWER TION
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
9 7000
6 7000
7 7000
a 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
1 5 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
31 1500
32 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILIZER
131500
131500
131500
131500
131500
131500
131500
131500
131500
131500
93900
93900
93900
93900
93900
65800
65800
65800
65800
65SOO
28200
28200
28ZOO
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
CDST, TION CONTROL,
WYEAR WYEAR
6711500 1800000
6711500 1772800
6711500 1749100
6711500 1718800
6711500 1690600
6711500 1663400
6711500 1635900
6711500 1608700
6711500 1581200
6711500 1553800
3943100 1379800
3943300 1352300
3943300 1325100
3943300 1297900
3943300 1270400
2999300 1114100
2999300 1086700
2999300 1059200
2999300 103JOOO
2999300 1004500
1655500 827100
1655500 799800
1655500 772400
1655500 745100
1655500 717700
1655500 690400
1655500 663000
1655500 635500
L655500 608300
1655500 580800
1655500 553600
1655500 526100
1655500 499900
1655500 471400
1655500 444200
NET FERTILIZER
MFG COST,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
4911500 6711500
4938700 6711500
4962400 6711500
4992700 6711500
5020900 6711500
504B100 6711500
5075600 6711500
5102800 6711500
5130300 6711500
5157700 6711500
2563500 3943300
2591000 3943300
2618200 3943300
2645400 3943300
2672900 3943300
1885200 2999300
1912600 2999300
1940100 2999300
1967300 2999300
1994800 2999300
828400 1655500
855700 1655500
883100 1655500
910400 1655500
937800 1655500
965100 1655500
992500 1655500
1020000 1655500
1047200 1655500
1074700 1655500
1101900 1655500
1129400 1655500
1156600 1655500
1184100 1655500
1211300 1655500
NET GROSS INCOME,
FERTILIZER t/YEAR
SALES
REVENUE, WITH WITHOUT
$/YEAR PAYMENT PAYMENT
5896500 985000
5896500 957800
5896500 934100
5896500 903800
5896500 875600
5896500 848400
5896500 820900
5896500 793700
5896500 766200
5896500 738800
4246200 1682700
4246200 1655200
4246200 1628000
4246200 1600800
4246200 1573300
2997200 1112000
2997200 1084600
2997200 1057100
299T200 1029900
2997200 1002400
1301400 473000
1301400 445700
1301400 418300
1301400 391000
1301400 363600
1301400 336300
1301400 308900
1301400 281400
1301400 254200
1301400 226700
1301400 199500
1301400 172000
1301400 144800
1301400 117300
1301400 90100
( 815000)
{ 8150001
8150001
815000)
815000)
815000)
815000)
815000)
815000)
815000)
302900
302900
302900
302900
302900
< 2100)
t 2100)
( 2100)
( 2100)
( 2100)
t 354100)
1 354100)
( 3541001
I 354100)
I 354100)
( 354100)
( 354100)
( 3541001
I 354100)
( 354100)
I 354100)
( 354100)
( 354100)
1 354100)
I 354100)
NET INCOME AFTER TAXES,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
492500
478900
467050
451900
437800
424200
410450
396850
383100
369400
841350
827600
814000
800400
786650
556000
542300
528550
514950
501200
236500
222850
209150
195500
181800
168150
154450
140700
127100
113350
99750
86000
72400
58650
45050
407500)
407500)
407500)
4075001
407500)
407500)
4075001
407500)
4075001
407500)
151450
151450
151450
151450
151450
1050)
10501
1050)
1050)
1050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
177050)
CASH FLOW,
*/YE4R
WITH WITHOUT
PAYMENT PAYMENT
2049900 1149900
2036300 1149900
2024450 1149900
2009300 1149900
1995200 1149900
1981600 1149900
1967850 1149900
1954250 1149900
1940500 1149900
1926800 1149900
841350 151450
827600 151450
8140.00 151450
800400 151450
786650 151450
556000 1050)
542300 1050)
528550 1050)
514950 1050)
501200 1050)
236500 177050)
222850 177050)
209150 1770501
195500 177050)
181800 177050)
168150 177050)
154450 177050)
140700 177050)
127100 1770501
113350 177050)
99750 177050)
86000 177050)
72400 177050)
58650 177050)
45050 177050)
CUMULATIVE
$
WITH
PAYMENT
2049900
4086200
6110650
8119950
10115150
12096750
14064600
16018850
17959350
19886150
20727500
21555100
22369100
23169500
23956150
25054450
25583000
26097950
26599150
26835650
27058500
27267650
27463150
27644950
27813100
27967550
28108250
28235350
28346700
28448450
28534450
28606850
28665500
28710550
CASH FLOW,
WITHOUT
PAYMENT
1149900
2299800
3449700
4599600
5749500
6899400
8049300
9199200
10349100
11499000
11650450
11801900
11953350
12104800
12256250
12254150
12253100
12252050
12251000
12073950
11896900
11719850
11542800
11365750
11188700
11011650
10834600
10657550
10480500
10303450
10126400
9949350
9772300
9595250
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH WITHOUT
•PAYMENT PAYMENT
2.94
2.86
2.79
2.70
2.61
2.53
2.45
2.37
2.29
2.21
5.02 0.90
4.94 0.90
4.86 0.90
4.78 0.90
4.70 0.90
3.32
3.24
3.16
3.08
2.99
1.41
1.33
1.25
1.17
1.09
1.00
0.92
0.84
0.76
0.68
0.60 '
0.51
0.43
0.35
0.27
TOTAL 135000 2536500 126660500
N)
-------
Table B-115
PROCESS B, NONREGULATED FERTILIZER CO. ECONOMICS, 500 MW., NEM UNIT, 3.5* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 19689000
TOTAL INITIAL INVESTMENT = $ 21579500
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 12.5J
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT • 4.0»
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
6.3
9.4
YEARS
AFTER
POKER
UNIT
START
1
2
3
4
5
6
7
B
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
25
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TONS/YEAR
FERTILIZER
230000
230000
230000
230000
230000
230000
230000
230000
230000
230000
164300
164300
164300
164300
164100
115000
115000
115000
115000
115000
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
49300
TOTAL
FERTILIZER
MFG.
COST,
J/YEAR
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
5965100
5965100
5965100
5965100
5965100
4476100
4476100
4476100
4476100
4476100
2385300"
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300_
2385300
2385300
2385300
2385300
2385300
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
FERTILIZER
COMPANY FOR
AIR POLLU-
TION CONTROL,
*/YEAR
2150200
2119600
2089200
2058700
2028100
1997500
1967100
1936600
1906000
1875600
1640100
1610000
1579400
1549000
1518400
1311600
1281200
1250600
1220100
1189700
952200
921600
891100
860700
830100
799500
769200
738400
708100
677400
647100
616500
585900
555600
525000
NET FERTILIZER
NFG COST,
«/YEAR
WITH WITHOUT
PAYMENT PAYMENT
7707500
7738100
7768500
7799000
7829600
7860200
7890600
7921100
7951700
7982100
4325000
4355100
4385700
4416100
4446700
3164500
3194900
3225500
3256000
3286400
1433100
1463700
1494200
1524600
1555200
1585800
1616100
1646900
1677200
1707900
1738200
1768800
1799400
1829700
1860300
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
9857700
5965100
5965100
5965100
5965100
5965100
4476100
4476100
4476100
4476100
4476100
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
2385300
NET
FERTILIZER
SALES
REVENUE,
»/YEAR
10129200
10129200
10129200
10129200
10129200
10129200
10129200
10129200
10129200
10129200
7317900
7317900
7317900
7317900
73 7900
5173900
5173900
5173900
5173900
5173900
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
GROSS INCOME,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2421700
2391100
2360700
2330200
2299600
2269000
2238600
2208100
2177500
2147100
2992900
2962800
2932200
2901800
2871200
2009400
1979000
1948400
1917900
1887500
823900
793300
762800
732400
701800
671200
640900
610100
579800
549100
518800
488200
457600
427300
396700
271500
271500
271500
271500
271500
271500
271500
271500
271500
271500
1352800
1352800
1352800
1352800
1352800
697800
697800
697800
697800
697800
128300)
1283001
128300)
128300)
128300)
1283001
1283001
128300)
128300)
1283001
1283001
128300)
128300)
1283001
I 128300)
NET INCOME AFTER TAXES,
»/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1210850
1195550
1180350
1165100
1149800
1134500
1119300
1104050
1088750
1073550
1496450
1481400
1466100
1450900
1435600
1004700
989500
974200
958950
943750
411950
396650
381400
366200
350900
335600
320450
305050
289900
274550
259400
244100
228800
213650
198350
135750
135750
135750
135750
135750
135750
135750
135750
135750
135750
676400
676400
676400
676400
676400
348900
348900
348900
348900
348900
1 64156)
641501
641501
641501
641501
641501
64150)
64150)
641501
64150)
64150)
64150)
64150)
64150)
64150)
CASH FLOW,
»/YEA«
WITH WITHOUT
PAYMENT PAYMENT
3179750
3164450
3149250
3134000
3118700
3103400
3088200
3072950
3057650
3042450
1496450
1481400
1466100
1450900
1435610
1004700
989500
974200
958950
043750
411950
396650
381400
366200
350900
335600
320450
305050
2B9900
274550
244100
228800
213650
198350
2104650
2104650
2104650
2104650
2104650
2104650
2104650
2104650
2104650
2104650
676400
676400
676400
676400
676400
348900
348900
348900
348900
348900
64150)
64150)
64150)
64150)
64150)
64150)
64150)
641501
64150)
64150)
641501
64150)
64150)
64150)
64150)
CUMULATIVE
$
WITH
PAYMENT
3179750
6344200
9493450
12627450
15746150
18849550
21937750
25010700
28068350
31110800
32607250
34088650
35554750
37005650
38441250
39445950
40435450
41409650
42368600
43312350
43724300
44120950
44502350
44868550
45219450
45555050
45875500
46180550
46470450
46745000
47004400
47248500
47477300
47690950
47889300
CASH FLOW,
WITHOUT
PAYMENT
2104650
4209300
6313950
8418600
10523250
12627900
14732550
16837200
18941850
21046500
21722900
22399300
23075700
23752100
24428500
24777400
25126300
25475200
25824100
26173000
26108850
26044700
25980550
25916400
25852250
25788100
25723950
25659800
25595650
25531500
25467350
25403200
25339050
25274900
25210750
ANNUAL
INITIAL
WITH
PAYMENT
5.61
5.54
5.47
5.40
5.33
5.26
5.19
5.12
5.05
4.97
6.93
6.86
6.79
6.72
6.65
4.66
4.59
4.51
4.44
4.37
1.91
1.84
1.77
1.70
1.63
1.56
1.48
1.41
1.34
1.27
1.20
1.13
1.06
0.99
0.92
RETURN ON
INVESTMENT,
%
WITHOUT
PAYMENT
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
3.13
3.13
3.13
3.13
3.13
1.62
1.62
1.62
1.62
1.62
TOTAL 135000 4436000 186562500
AVG=
-------
Table B-116
PROCESS Bt NflNREGULATEO FERTILIZER CO. ECONOMICS, 500 HW., EXISTING UNIT, 3.5J S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 20191000
TOTAL INITIAL INVESTMENT - $ 22128700
OVERALL INTEREST RATE OF RETURN WITH PAYMENT * 11.1?
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = 0.8%
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YF.ARS REOUIRED FOR PAYOUT WITHOUT PAYMENT:
YEARS ANNUAL
AFTER OPERA-
POWER TION
UNIT KW-HR/
START KW
1
2
3
4 7000
5 7000
6 7000
7 7000
R 7000
9 7000
10 7000
11 5000
12 5000
13 5000
1* 5000
15 5000
16 3500
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
73 1500
2* 1500
25 1500
26 1500
27 1500
78 1500
79 1500
30 1500
31 1500
12 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILIZER
235800
235800
235800
235800
235800
235800
235800
168200
168200
168200
168200
168200
117900
117900
117900
117900
117900
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
COST, TION CONTROL,
S/YEAR »/YEAR
10240200 2261500
10240200 2226100
10240200 2191000
10240200 2155600
10240200 2120500
10240200 2085100
10240200 2050000
8309000 1804000
8309000 1768900
8309000 1733500
6289900 1698300
6289900 1663000
4657600 1447600
4657600 1412300
4657600 1377100
4657600 1341800
4657600 1306600
2473300 I06I200
2473300 1025900
2473300 990700
2473300 955400
2473300 920200
2473300 684900
2473300 849700
2473300 814300
2473300 779200
2473300 743800
2473300 708700
2473300 673300
2473300 638200
2473300 602800
2473300 567700
NET FERTILIZER
MFC COST,
S/YEAR
WITH WITHOUT
PAYMENT PAYMENT
7978700 10240200
8014100 10240200
8049200 10240200
8084600 10240200
8119700 10240200
8155100 10240200
8190200 10240200
6505000 8309000
6540100 8309000
6575500 8309000
4591600 6289900
4626900 6289900
3210000 4657600
3245300 4657600
3280500 4657600
3315800 4657600
3351000 4657600
1412100 2473300
1447400 2473300
1482600 2473300
1517900 2473300
1553100 2473300
1588400 2473300
1623600 2473300
1659000 2473300
1694100 7.473300
1729500 2473300
1764600 2473300
1800000 2473300
1835100 2473300
1870500 2473300
1905600 2473300
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
10375200
10375200
10375200
10375200
10375200
10375200
10375200
7486600
7486600
7486600
7486600
7486600
5300800
5300800
5300800
5300800
5300800
2310400
231040C
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
GROSS INCOME,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
2396500 135000
2361100 135000
2326000 135000
2290600 135000
2255500 135000
2.220100 135000
2185000 135000
981600 822400)
946500 ( 8224001
911100 ( 8224001
2895000 1196700
2859700 U96700
2090800 643200
2055500 643200
2020300 643200
1985000 643ZOO
1949800 643200
898300 1629001
863000 162900)
827800 162900)
792500 162900)
757300 162900)
722000 162900)
686800 162900)
651400 162900)
616300 1629001
580900 162900)
545800 162900)
510400 1 162900)
475300 ( 162900)
439900 ( 162900)
404800 ( 162900)
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
1198250
1180550
1163000
1145300
1127750
1110050
1092500
490800
473250
455550
1447500
1429850
1045400
1027750
1010150
992500
974900
449150
431500
413900
396250
378650
361000
343400
325700
308150
290450
272900
255200.
237650
219950
202400
67500
67500
67500
67500
67500
67500
67500
411200)
411200)
411200)
598350
598350
321600
321600
321600
321600
321600
814501
81450)
81450)
81450)
814501
81450)
81450)
81450)
61450)
81450)
81450)
81450)
814501
81450)
81450)
CASH FLOW, CUMULATIVE
t/YEAR , $
WITH WITHOUT WITH
PAYMENT PAYMENT PAYMENT
3217350
3199650
3182100
3164400
3146850
3129150
^111600
7509900
2492350
2474650
1447500
1479850
1045400
1027750
1010150
992500
974900
449150
431500
413900
396250
378650
361000
343400
325700
308150
290450
277900
255200
237650
219950
207400
2086600 3217350
2086600 6417000
2086600 9599100
2086600 12763500
2086600 15910350
2086600 19039500
7.086600 22151100
1607900 24661000
1607900 27153350
1607900 29628000
598350 31075500
598350 32505350
321600 33550750
321600 34578500
321600 35588650
321600 36581150
321600 37556050
814501 38005200
81450) 38436700
814501 38850600
814501 39246850
81450) 39625500
81450) 39986500
81450) 40329900
81450) 40655600
61450) 40963750
81450) 41254200
91450) 41527100
81450) 4178230C
81450) 42019950
81450) 42239900
81450) 42442300
CASH FLOW,
WITHOUT
PAYMENT
2086600
41T3200
6259800
8346400
10433000
12519600
14606200
16214100
17822000
19429900
20028250
20626600
20948200
21269800
21591400
21913000
22234600
22153150
22071700
21990250
21908800
21827350
21745900
21664450
21583000
21501550
£1420100
21338650
21257200
21175750
21094300
21012850
ANNUAL RETURN ON
INITIAL INVESTMENT,
%
WITH WITHOUT
"AYMENT PAYMENT
5.41 0.31
5.33 0.31
5.26 0.31
5.18 0.31
5.10 0.31
5.02 0.31
4.94 0.31
2. 22
2.14
2.06
6.54 2.70
6.46 2.70
4.72 1.45
4.64 1.45
4.56 1.45
4.49 1.45
4.41 1.45
2.03
1.95
1.87
1.79
.71
.63
.55
.47
.39
.31
.23
.15
1.07
0.99
0.91
TOTAL U4000 3838600 169575700
to
-------
K>
Table B-117
PROCESS B, NONREGULATED FERTILIZER CO. ECONOMICS, 500 MW., NEW UNIT, 5.0* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 23525000
TOTAL INITIAL INVESTMENT = t 25918100
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 16.5J
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT « 9.61
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
5.2
7.2
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
ft
9
10
11
12
13
14
15
16
17
in
19
20
21
22
23
?4
25
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
I5no
1500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
TONS/YEAR
FERTILIZER
328600
328600
328600
328600
328600
328600
328600
328600
328600
328600
234700
234700
234700
234700
234700
164300
164300
164300
164300
164300
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
MFG.
COST,
t/YEAR
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
7581600
7581600
7581600
7581600
7581600
5666200
5666200
5666200
5666200
5666700
2986400
2986400
2986400
2986400
2986400
2986400
2986400
29B6400
2986400
2986400
2986400
2986400
2986400
2986400
29B6400
AIR POLLU-
TION CONTROL,
t/YEAR
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1B03000
1769500
1512100
1478400
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
910300
876800
843100
809600
776200
742500
708800
675300
641800
608100
NET FERTILIZER
MFC COST,
«/YEAR
WITH
PAYMENT
9907600
9941100
9974800
10008300
10042000
10075500
10109200
10142600
10176100
10209800
5677700
5711400
5744900
5778600
5812100
4154100
4187800
4221300
4254900
4288400
1908200
1941700
1974500
2008900
2042400
2076100
2109600
2143300
2176800
2210200
2243900
2277600
2311100
2344600
2378300
WITHOUT
PAYMENT
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
12414100
7581600
7581600
7581600
7581600
7581600
5666200
5666200
5666200
5666200
5666200
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
2986400
NET
FERTILIZER
SALES
REVENUE,
«/YEAR
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
10329100
10329100
10329100
10329100
10329100
7317900
7317900
7317900
7317900
7317900
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
GROSS INCOME,
$/YEAR
WITH
PAYMENT
4356900
4323400
4289700
4256200
4222500
4189000
4155300
4121900
4088400
4054700
4651400
4617700
4584200
4550500
4517000
3163800
3130100
3096600
3063000
3029500
1293600
1260100
1227300
1192900
1159400
1125700
1092200
1058500
1025000
991600
957900
924200
890700
857200
823500
WITHOUT
PAYMENT
1850400
1850400
1850400
1850400
1850400
1850400
1850400
1850400
1850400
1850400
2747500
2747500
2747500
2747500
2747500
1651700
1651700
1651700
1651700
1651700
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
215400
NET INCOME AFTER TAXES,
S/YEAR
WITH
PAYMENT
2178450
2161700
2144850
2128100
2111250
2094500
2077650
2060950
2044200
2027350
2325700
2308850
2292100
2275250
2258500
1581900
1565050
1548300
1531500
1514750
646800
630050
613650
596450
579700
562850
546100
529250
512500
495800
478950
462100
445350
428600
411750
W I THOUT
PAYMENT
925200
925200
925200
925200
925200
925200
925200
925200
925200
925200
1373750
1373750
1373750
1373750
1373750
825850
825850
825850
825850
825850
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
CASH FLOW,
t/YEAR
UITH
PAYMENT
4530950
4514200
4497350
4480600
4463750
4447000
4430150
4413450
4396700
4379850
2325700
2308850
2292100
2775250
2258500
15819(10
1565050
1548300
1531500
1514750
646800
630050
613650
596450
579700
562850
546100
529250
512500
495800
478950
462100
445350
428600
411750
WITHOUT
PAYMENT
3277700
3277700
3277700
3277700
3277700
3277700
3277700
3277700
3277700
3277700
13T3Y50
1373750
1373750
1373750
1373750
825850
825850
825850
825850
825850
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
107700
CUMULATIVE CASH FLOW,
t
WITH
PAYMENT
4530950
9045150
13542500
18023100
22486850
26933850
31364000
35777450
40174150
44554000
46879700
49188550
51480650
53755900
56014400
57596300
59161350
60709650
62241150
63755900
64402700
65032750
65646400
66242850
66822550
67385400
67931500
68460750
68973250
69469050
69948000
70410100
70855450
71284050
71695800
WITHOUT
PAYMENT
3277700
6555400
9833100
13110800
16388500
19666200
22943900
26221600
29499300
32777000
34150750
35524500
36898250
38272000
39645750
40471600
41297450
42123300
42949150
43775000
43882700
43990400
44098100
44205800
44313500
44421200
44528900
44636600
44744300
44852000
44959700
45067400
45175100
45282800
45390500
ANNUAL RETURN ON
INITIAL INVESTMENT,
T
WITH
PAYMENT
8.41
8.34
8.28
8.21
8.15
§708
8.02
7.95
7.89
7.82
8797
8.91
8.84
8.78
8.71
6.10
6.04
5.97
5.91
5.84
2.50
2.43
2.37
2.30
2.24
2.17
2.11
2.04
1.98
1.91
1.85
1.78
1.72
1.65
1.59
WITHOUT
PAYMENT
3.57
3.57
3.57
3.57
3.57
3.5*
3.57
3.57
3.57
3.57
5.30
5.30
5.30
5.30
5.30
3.19
3.19
3.19
3.19
3.19
0.42
0.42
0.42
0.42
0.42
0.42
0.42
0.42
0.42
0.42
5742
0.42
0.42
0.42
0.42
TOTAL 135000 6337000 235)76000 52610600 182565400 235176000 27B907000 96341600
AVG= 5.31
-------
Table B-118
PROCESS Bt NONREGULATEO FERTILIZER CO. ECCNCMICS, 1000 MW., NEW UNIT, 3.5* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 31000000
TOTAL INITIAL INVESTMENT = $ 34244200
OVERALL INTEREST RATE OF RETURN WITH PAYMENT = 17.3%
OVERALL INTEREST R4TE OF RETURN WITHOUT PAYMENT - 10.5*
YEARS R60UIRED FOR PAYOLT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
5.1
6.9
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
~
7
a
9
10
It
12
13
14
15
16
17
IB
19
20
21
22
73
24
25
26
27
28
29
10
31
32
33
34
35
ANNUAL
OPERA-
TION
KU-HR /
KM
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FCR
TONS/YEAR
FERTILIZER
444000
4440CO
444000
4440CO
4440CC
444000
444 OCO
4440CO
444CCC
444000
3180CC
31BCCO
318000
318CCC
3180CO
222000
2220CO
222000
222000
222000
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
952CO
95200
95200
952CO
MFG.
COST,
*/YEAR
162094CO
16205400
16209400
16205400
16209400
16209400
16209400
16209400
16209400
16209400
9864200
9864200
9864200
9864200
9864200
7361000
7361CCO
7361000
7361COO
7361COO
3867400
3867400
3867400
3867400
3867400
3661400
3867400
38674CO
3867400
3867400
3867400
3867400
3867400
3867400
3867400
AIR POLLU-
TICN CCHTPCL,
$/YFAR
3562400
3317000
3271900
32265CC
3183200
313E6GC
3090700
3C45400
3CCCOOO
2954900
25651CO
2519800
247450C
2429300
2384000
2C53500
2C08400
1963100
i5mcc
1872400
1496500
1451200
14C58CO
1360700
1315400
1270000
1224700
11755CC
1134200
1C888CC
1C437CO
598400
553CCC
907700
862500
NET FERTILIZER
MFC COST,
i/YEAR
WITH
PAYMENT
12847000
12892400
12937500
12982900
13028200
13C7360C
13118700
1316400C
13209400
13254500
7299100
7344400
738970C
7434900
7480200
5307500
5352600
5397900
5443300
5488600
2370900
2416200
2461.600
2506700
255200C
2597400
2642700
2687900
2733200
2778600
2823700
2869000
2914400
2959700
3004900
WITHOUT
PAYMENT
16209400
16209400
16209400
16209400
16209400
16209400
16209400
16209400
16209400
16209400
9864200
9864200
9864200
9864200
9864200
7361000
7361000
7361000
7361000
7361000
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
3867400
NET
FERTILIZER
. SALES
REVENUE,
i/YEAR
18994300
18994300
18994300
38994300
18994300
38994300
18994300
18994300
18994300
18994300
13829800
13829800
13829800
13829800
13829800
9792400
9792400
9792400
9792400
9792400
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
GROSS INCOME,
»/YEAR
WITH
PAYMENT
6147300
6101900
6056800
6011400
5966100
592070C
5875600
5830300
5784900
5739800
6530700
6485400
6440100
6394900
6349600
4484900
4439800
4394500
4349100
4303800
1934000
1888700
1843300
1798200
1752900
1707500
1662200
1617000
1571700
1526300
1481200
1435900
1390500
1345200
1300000
WITHOUT
PAYMENT
2784900
2784900
2784900
2784900
2784900
2784900
2784900
2784900
2784900
2784900
3965600
3965600
3965600
3965600
3965600
2431400
2431400
2431400
2431400
2431400
437500
437500
437500
437500
437500
437500
43 75 00
437500
437500
437500
437500
437500
437500
437500
437500
NET INCOME AFTER TAXES,
$/YEAR
WITH
PAYMENT
3073650
3050950
3028400
3005700
2983050
2960350
2937800
2915150
2892450
2869900
3265350
3242700
3220050
3197450
3174800
2242450
2219900
2197250
2174550
2151900
967000
944350
921650
899100
876450
853750
831100
808500
785850
763150
740600
717950
695250
672600
650000
WITHOUT
PAYMEK
1392450
1392450
1392450
1392450
1392450
1392450
1392450
1392450
1392450
1392450
1982800
1982300
1982800
1982800
1982800
1215700
1215700
1215700
1215700
1215700
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
CASH FLOW,
t/YEAR
WITH
PAYMENT
6173650
61 5095C
6128400
61C5700
6083050
6060350
6037800
6015150
5992450
5969900
3265350
3242700
3220050
3197450
3174800
2242450
2219900
2197250
2174550
21. 5190C
967000
944350
921650
899100
876450
853750
831100
808500
785850
763150
740600
717950
695250
672600
650000
WITHOUT
PAYMENT
4492450
4492450
4492450
449245C
449245C
449245C
4492450
449245C
449245C
449245C
1982800
1982800
1982600
1982600
19828CC
1215700
121570C
12157CC
1215700
12157CC
21 673C
21875C
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
218750
CUMULATIVE
i
W ITH
PAYMENT
6173650
12324600
18453000
24558700
30641750
367C2100
42739900
48755050
54747500
60717400
63982750
67225450
70445500
73642950
76817750
79060200
81280100
83477350
85651900
873C3300
S8770800
B9715150
90636800
9J535900
92412350
93266100
94057200
949C5700
95651550
96454700
97195300
97913250
98608500
99281100
99931100
CASH FLOW,
WITHOUT
PAYMENT
4492450
8984900
13477350
17969800
'22462250
26954700
314^7150
35939600
40432050
445245CO
469C73CO
48850100
5C8725CO
528557CO
54836500
56C54ZCO
57769500
5E48560C
597C13CO
6C5'7COO
61) 35750
6135450C
61573250
61752COO
62C1C750
62229500
62446250
626(7000
62885750
631C4500
63323250
63542000
63760750
63979500
64158250
ANNUAL RETURN ON
INITIAL INVESTMENT,
t
WITH
PAYMENT
8.98
8.91
8.84
8.73
8.71
8.64
8.58
8.51
8.45
8.38
9.54
9.47
9.40
9.34
9.27
6.55
6.48
6.42
6.35
6.28
2.8?
2.76
2.69
2.63
2.56
2.49
2.43
2.36
2.29
2.23
2.16
2.10
2.03
1.96
1.90
WITHOUT
PAYMENT
4.07
4.07
4.07
4.07
4.07
4.07
4.07
4.07
4.07
4.07
5.79
5.79
5.79
5.79
5.79
3.55
3.55
3.55
3.55
3.55
0.64
0.64
0.64
0.64
0.64
0.64
0. 6i
0.64
0.64
0.64
0.6«
0.64
0.64
0.64
0.64
TOTAL 135000 8568CCO 306231000
71465700 234765300 306231000 372627500 137862200
68531100
AVG= 5.75
-------
Table B-119
PROCESS 8, NONREGULATED FERTILIZER CO. ECONOMICS, 1000 MW., EXISTING UNIT, 3.51 5 IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT == $ 32904000
TOTAL INITIAL INVESTMENT = « 36262800
OVERALL INTEREST RATE OF RETURN WITH PAYMENT * 15.lt
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT - 7.5*
YEARS REQUIRED FOR PAYOUT WITH PAYMENT:
YEARS REQUIRED FOR PAYOUT WITHOUT PAYMENT:
YEARS
HFTFR
POWER
UNIT
START
1
2
3
4
5
6
7
*
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
26
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
7000
7000
7000
7000
7DOO
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
460000
460000
460000
460000
460000
460000
460000
328600
328600
328600
328600
323600
230000
230000
230000
230000
230000
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
COST, TION CONTROL,
t/YFAR S/YFAR
17332900
17332900
17332900
17332900
17332900
17332900
17332900
13854800
13354800
13854800
10564400
10564400
7881100
7881100
7881100
7881100
7881100
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
3587300
3533800
3480600
3427200
3373900
3319900
3267200
2857000
2803800
2750300
2696900
2643600
2294300
2241100
2187600
2134400
2080900
1685300
1632000
1578600
1525300
1471900
1418600
1365200
1311900
125S500
1205000
1151800
1098300
1045100
991600
938400
NET FERTILIZER
NFG COST,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
13745600
13799100
13852300
13905700
13959000
14013000
14065700
10997800
11051000
11104500
7867500
7920800
5586800
5640000
5693500
5746700
5800200
2451500
2504800
2558200
2611500
2664900
2718200
2771600
2824900
2878300
2931800
2985000
3038500
3091700
3145ZOO
3198400
17332900
17332900
17332900
17332900
17332900
17332900
17332900
13854800
13854800
13854800
10564400
10564400
7881100
7881100
7881100
788UOO
7881100
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
4136800
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
19642000
19642000
19642000
19642000
19642000
19642000
19642000
14264500
14264500
14264500
14264500
14264500
10129200
10129200
10129200
10129200
10129200
4448300
4448300
4448300
4448300
444B3DD
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
GROSS INCOME, NET INCOME AFTER TAXES,
$/YEAR (/YEAR
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
5896400
5842900
5789700
5736300
5683000
5629000
5576300
3266700
3213500
3160000
6397000
6343700
4542400
4489200
4435700
4382500
4329000
1996800
1943500
1890100
1836800
1783400
1730100
1676700
1623400
1570000
1516500
1463300
1409800
1356600
1303100
1249900
2309100
2309100
2309100
2309100
2309100
2309100
2309100
409700
409700
409700
3700100
3700100
2248100
2248100
2248100
2248100
2248100
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
311500
2948200
2921450
2894850
2868150
2841500
2814500
2788150
1633350
1606750
1580000
3198500
3171850
2271200
2244600
2217850
2191250
2164500
998400
971750
945050
918400
891700
865050
838350
811700
785000
758250
731650
704900
678300
651550
624950
1154550
1154550
1154550
1154550
1154550
1154550
1154550
204850
204850
204850
1850050
1850050
1124050
1124050
1124050
1124050
1124050
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
CASH FLOW,
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
6238600
6211850
6185250
6158550
6131900
6104900
607S550
49>3750
4897150
".870400
3198500
3171850
2271200
2244600
2217850
2191250
2154500
913400
971750
945050
918400
891700
865050
818350
811700
785000
758250
731650
704900
678300
651550
624950
4444950
4444950
4444950
4444950
4444950
4444950
4444950
3495250
3495250
3495250
1850050
1850050
1124050
1124050
1124050
1124050
1124050
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
155750
ANNUAL RETURN ON
CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
$ X
WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
6238600
12450450
18635700
24794250
30926150
37031050
43109600
48033350
52930500
57800900
60999400
64171250
68687050
70904900
73096150
75260650
76259050
77230800
76175850
79094250
79985950
80851000
81689350
82501050
83286050
84044300
84775950
85480850
86159150
86810700
87435650
4444950
8889900
13334850
17779800
22224750
26669700
31114650
34609900
38105150
41600400
43450450
45300500
47548600
48672650
49796700
50920750
51076500
51232250
51388000
51543750
51699500
51855250
52011000
52166750
52322500
52478250
52634000
52789750
52945500
53101 250
532570OO-
8.13
8.06
7.98
7.91
7.84
7.76
7.69
4.50
4.43
4.36
8.82
8.75
6. 26
6.19
6.12
6.04
5.97
2.75
2.68
2.61
2.53
2.46
2.39
2.31
2.24
2.16
2.09
2.02
1.94
1.87
1.80
1.72
3.18
3.18
3.18
3.18
3.18
3.18
3.18
0.56
0.56
0.56
5.10
5.10
3.10
3.10
3.10
3.10
3.10
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
0.43
TOTAL 114000 7490500 285481000
68357300 217123700
326187000 109063300
»VG= 4.70
-------
Table B-120
PROCESS C, NONREGULATEO FERTILIZER CC. ECCNOMICS. 200 MW., EXISTING UNIT, 3.5* S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 9589500
TOTAL INITIAL INVESTMENT - $ 10195500
CVERALL INTEREST RATE OF RETURN WITH PAYMENT - N6G
OVERALL INTEREST RATE OF RETURN WITHOUT 'PAYMENT = NEC
NO PSYOUT WITH PAYMENT
NO PAYOUT WITHOUT PAYMENT
ALTERNATIVE
WET -LIMESTONE
PROCESS
COST AS
YEAH S
AFTER
POWER
UNIT
START
1
7
3
4
5
A
^
8
4NNUAL TOTAL
OPFR4- FERTILIZER
TION MFG.
KW-HR/ TONS/YEAR COST,
KW FERTILIZER $/YEAR
PAYMENT TO NET FERTILIZER
FERTILIZER MFC COST,
COMPANY FOR t/YEAR
AIR PCLLU-
TICN CCKTROL, WITH WITHOUT
t/YEAR PAYMENT PAYMENT
ANNUAL RETURN ON
NET GROSS INCOME, NET INCOME AFTER TAXES. f.ASH FLOW, CUMULATIVE CSSH FLOW, INITIAL INVESTMENT,
FERTILIZER I/YEAR t/YEAR */YEAR t J
SALES
REVENUE, WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
S/YEAR PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
9 7000 56700 3868200 1C87900 2780300 3868200 1987300
to 7000 567CC '"86F2CO 1C677CO 2600500 3668210 1987*00
11 5000 405CC 3217000 947100 2769900 32)7000 J A? 94 00
12 5000 405CC 3217000 9270CO 2290000 321 7COO 142t400
13 5000 405CO 3217000 9C6800 2310200 3217000 1428400
14 5000 40500 3217COO 886600 2330400 3217COO 1428400
15 500C 405CO ??'7COO Ett4CC 2350600 321 7COO 1^25400
16 ?500 284CO 7704000 762900 1941100 2704000 1007^00
17 3500 28400 2704000 7428CC 1961200 2704000 1007300
IB 3500 284CC 2704000 7226CO 19B1400 2704000 1007300
19 3500 284CO 1745000 702400 1042600 1745000 1007300
70 3500 284CO 1745000 68220C 1 06280C 1745000 1007300
71 1500 12200 9S58CO 553000 442800 995800 437000
72 1500 12200 995800 532800 463000 995800 437000
73 1500 12200 9958CO 5126CC 483200 995800 437000
7* 1500 12200 995800 492400 503400 995800 437000
75 1500 12200 995800 47230C 523500 995800 437000
76 1500 1220C C958CO 4521CC 543700 995800 437000
77 1500 12200 995800 431900 563900 995800 43700T
78 1500 12200 995800 411 7CC 58410C 995800 4370uJ
79 1500 122CC 995800 391600 604200 995800 437000
30 1500 12200 995800 371400 624400 995800 437000
31 1500 122CO 595800 3512CC 644600 995800 437000
37 1500 12200 995800 331000 664800 995800 437000
33 1500 12200 995800 31C9CO 68490C 995800 437000
3H 1500 12200 "95800 29C7CC 705100 995800 437000
35 1500 12200 C95800 270500 725300 995800 437000
793000)
8133001
34 ibOOJ
861600 t
881800)
9020001
'JJ2200 )
933300)
953900)
974100)
35300)
55500)
5800)
26000)
46200 )
66400)
86500)
106700 )
126900)
147100 )
167200)
\87400)
207600)
227800)
247900)
268100)
288300)
1880900)
1880900 )
1. 789*00)
1788600)
1788600)
1783600)
173S600 )
1696700)
1696700 >
1696700)
7377CO)
737700)
5588CO)
558600)
558800)
5568CO)
558800)
5588CO)
5588CO)
558800)
5536CO)
553809)
553800 >
558800)
558800)
558800)
5588CO)
396500 )
4066CO)
420750)
430800)
440900)
451000)
461ICC)
4o6900)
476950)
487050)
17650)
27750)
2900)
13000)
23100)
33200)
43250)
5335C)
63450)
73550)
836CC)
)3700)
1 038CC)
113900)
123950)
13405C)
144150)
9404501 567450
940450) 5S?i50
S943CJO) 53W700
894300) 52R150
894300) 518050
894300 1 507950
5943CC) 4°7B50
H46350) 497050
848350) 482000
848350) 471900
368850) 1 17650)
368850) 1 27750)
279400) ( 2900)
279400) ( 13000)
J794CO) ( 23100)
279400) ( 33200)
279400) ( 43250)
2794CO) ( 53350)
279400) < 634501
279400) ( 73550)
279400) ( 83600)
!7'400I < 9^700)
279400) ( 113900)
2794001 ( 123050)
2794COI ( 134050)
279400) ( 144150)
18500 56?450 18500
IS'.CC ! 11.4*00 37000
64tDO 1£<:3CCC lC'.t5G
64650 21P1150 166300
64650 26^9200 230950
6465C 3JC7150 2S5600
64i50 3705000 360250
llCeOC 4197050 470850
1106JC 4679C50 5E145C
110600 5150950 692050
366650) 5133300 323200
368850) 51P5550 ( 45650)
279400) ?102650 ( 325050)
27940C) 5C69650 ( 6C445C)
2794JO) 5066550 ( 883850)
279400) 5033350 ( 1163250)
27940C) 49S0100 [ 144265C)
279400) 4936750 ( 1722050)
27940C) 4873300 ( 20C1450)
279400) 47=9750 C 2260850)
279400) 4716150 ( 2560250)
279400) 462245C ( 2839650)
279400) 45! 8650 ( 3119656)
279400) 4404750 I 3358450)
279400 426CI100 ( 3677850)
2794UO) <-146750 ( 3957250)
279400) 4002600 ( 4236650)
TOTAL 79000
22708100 ( 11173800) ( 27652300) ( 5536900) ( 138?6150)
4002600 ( 4236650)
-------
Table B-121
PROCESS C, NONREGULATEO FERTILIZER CC. ECCMCMICS, 500 MW., NEW UNIT, 2.0* S II COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = t 13057300
TOTAL INITIAL INVESTMENT = t 13837300
OVERALL INTEREST BATE OF RETURN WITH PAYMENT = NEG
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEG
NO PAYCUT KITH PAYMENT
NO PAYOUT WITHOUT PAYMENT
YFARS ANNUAL
AFTER CIPERA-
POWFR TION
UNIT KW-HR/
START KM
1 7000
2 7000
3 7000
4 7000
5 7000
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
JO 3500
71 1500
2? 1500
23 1500
24 1500
25 1500
?6 1500
?7 1500
7fl 1500
29 1500
30 1500
31 1500
32 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILIZER
766CO
76600
76600
76600
76600
76600
76600
76600
766CC
76600
54700
547CC
54700
547CC
547CC
3B300
33300
383CO
38300
383CQ
16400
164CO
164CO
16400
16400
16400
16400
164CC
16400
16400
164CC
16400
164CO
164 CO
16400
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
T3TAL FERTILIZER
FERTILIZER CCKPAdY FQR
MFG. AIR POLLU-
COST. T ION CONTROL,
$/YEAR S/YEAR
498C700 1800000
4980700 1772800
498C7CO 1749100
498C7CO 1718800
4980700 1690600
4980700 16634CC
498C700 1635900
4980700 16C8700
498C700 15812CC
4980700 1553800
2850300 137980C
285C3CO 1352300
2850300 1325100
M50300 1297900
285C300 1270400
2201500 H14100
2201500 1CB47CC
220! 500 1C59200
2201500 1C32000
2201500 1C04500
1258700 827100
1258700 799800
125E7CO 772400
1258700 745100
1256700 7177CC
1258700 690400
1258700 643000
1258700 63550C
1258700 608300
1258700 5808CO
12587CO 5536CO
1258700 526100
12587CO 498900
1258700 471400
1258700 4442CO
NET FERTILIZER ANNUAL RETURN ON
MFG COST, NET GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLCW, INITIAL INVESTMENT,
t/YEAR FERTILIZER $/YEAR I/YEAR $/Y EAR * *
SALES
WITH WITHOUT REVENUE, WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
PAYMENT PAYMENT $/YEAR PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT PAYMENT
3180700
3207900
3231600
3261900
3290100
3317300
3344800
337200C
3399500
3426900
147050C
1498000
152S200
1552400
1579900
1087400
1114800
1142300
1169500
1197000
431600
458900
486300
513600
541000
568300
59570C
623200
650400
677900
705100
732600
759800
787300
814500
4980700 2667200 5135001 2313500) 256750) ( 11567501 1048980 148SBO 1048980 148980
4980700 2667200 5407001 2313500) 270350) I 1156750) 1035380 148980 2084360 297960
4980700 2667200 564400) 2313500) 282200) ( 1156750) 1023530 148980 31C7890 446940
4980700 2667200 594700) 2313500) 297350) ( 1156750) 100B380 148980 4116270 595920
4980700 2667200 622900) 2313500) 311450) 1 11567501 994230 148980 5H0550 744900
4980700 2667200 650100) 2313500) 325050) ( 11567501 980680 14fl?8C 6051230 893880
4980700 2667200 677600) 2313500) 338800) ( 11567501 966930 148980 7058160 1042860
4980700 2667200 704800) 2313500) 3524001 ( 11S6750) 953330 148S80 8011490 1191840
4980700 2667200 732300) 2313500) 366150) ( U5675CI 939580 14898C 8951070 1340820
4980700 2667200 759700) 2313500) ( 379850) ( 1156750) 925880 148980 9876950 1489800
2850300 1917800 447300 932500) 223650 ( 466250) 2?3f50 466250) 10100600 1023550 1.62
2650300 1917800 419800 932500) 2C9900 ( 466250) 209900 466250) 10310500 557300 1.52
2B50300 1917800 392600 932500) 196300 ( 466250! 196300 466250) 105C6800 S1C50 1.42
2850300 1917600 365400 932500) 182700 ( 466250) 1P2700 466250) 10689500 375200) 1.32
2850300 1917800 337900 932500) 168950 ( 466250) 16B950 466250) 10858450 841450) 1.22
2201500 1352000 237200 849500) 118600 ( 424750) 118600 424750) 11109350 1690950) 0.86
2201500 1352000 209700 8495001 104850 1 424750) 104850 424750) 11214200 2115700) 0.76
2201500 1352000 182500 849500) 91250 ( 424750) 91250 424750) 11305450 2540450) 0.66
2201500 1352000 155000 849500) 77500 ( 424750) 77500 424750) 11382950 2965200) 0.56
12587.00 585500 153900 673200) 76950 I 336600) 76950 336600) 11459SOO 33016CO) 0.56
1258700 585500 126600 673200) 63300 ( 336600) f3300 336600) 11523200 3638400) 0.46
1253700 585500 99200 673200) 49600 ( 336600) 49600 33640C) 1)572800 3975COO) 0.36
1258700 585500 71900 673200) 35950 ( 336600) 35950 336600) 116CB750 4311600) 0.26
1.258700 585500 44500 673200) 22250 I 336600) 22250 336600) 11631000 4648200) 0.16
1258700 585500 17200 673200) 8600 ( 336600) 6600 336600) 11639600 4984800) 0.06
1258700 585500 10200) 673200) 5100) ( 336600) 5100) 336600) 11634500 53214CO)
1258700 585500 37700) 673200) 18850) ( 336600) 16850) 336600) 116?5650 5658COO)
1258700 585500 64900) 673200) 32450) < 336600) 32450) 336600) 11583200 5994600)
1258700 585500 92400) 673200) 46200) ( 336600) 46200) 336SOC1 11537COO 6331200)
1258700 585500 119600) 673200) 598CO) ( 336600) 59800) 336600) 11477200 6667600)
1258700 585500 147100) 673200) ( 73550) ( 336600) 73550) 33660C) 114C3650 70C4400)
1258700 585500 174300) 673200) ( 87150) ( 33660C) 87150) 336600) 11316500 73410CO)
1258700 585500 201800) 673200) ( 100900) ( 336600) 100900) 336600) 11215600 ( 7677600)
1258700 585500 229000). 673200) ( 114500) ( 336600) 1145001 3366CC) lllCUOO ( 8014200)
TOTAL 135000 1477000
11101100 ( 6014200)
-------
Table B-122
PROCESS Ci NCNREGULATED FERTILIZER CO. ECONOMICS, 500 MW., NEW UNIT, 3. 5X S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 16356800
TOTAL INITIAL INVESTMENT = $ 17541600
CVERALL INTEREST P«T£ CF RETURN WITH PAYMENT = 0.4*
OVERALL INTEREST RATE OF RETURN WITHOUT PAYMENT = NEG
YEARS RBWIREC FOR FAYCUT WITH PAYMENT:
NO PAYOLT MTHCLT PAYfEKT
TEAKS ANNUAL
AFTER OPERA-
POKER TION
UNIT KW-HR/ TONS/YEAR
START KW FERTILIZER
) 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 TOCO
10 7000
11 5000
12 50CC
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 15CC
29 1500
30 1500
31 150C
32 1500
33 1500
34 1500
35 1500
134CCO
134000
1340CC
1340CO
1340CO
1340CC
134000
134CCO
134CCO
134000
95700
957CO
95700
957CC
S57CQ
67CCC
67CCC
67000
670CO
67CCO
2»700
267CC
267CO
287CO
287CC
28700
28700
28700
28700
2E7CC
287CO
287CO
267CC
2B700
287CO
ALTERNATIVE
KET-LIHESTCNE
PPCCESS
COST AS
FAYCENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. JIR PCLLU-
COST, TION CONTROL,
t/YE*R J/YEAR
7081700 2150200
7081700 2H960C
7C81700 2C892CC
7C81700 2058700
7C81700 2C28100
7C817CO 1997500
7091700 1967100
7C817CO 193«fCC
7C817CO 1906000
7081700 16756CC
4173500 164C1CC
4173500 1610000
417-500 15794CC
'1735CO 154SCCC
4172500 15184CO
31812CO 13116CC
3181200 1281200
3131200 1Z50600
3181200 122UCC
3181200 1189700
1758500 9522CC
1758500 921600
1758500 891100
175S5CO 860700
175E5CO 830100
1758500 799500
175S5CC 16S2CC
17565CO 738400
1758500 ICeiCO
175E5CO 6774CC
17S8500 647100
1758500 6l£5CO
1758500 5859CO
1758500 555600
17565CO 525CCC
NET FERTILIZER
MFC COST,
J/YEAR
KITH WITHOUT
PAYMENT PAYMENT
4931500
496210C
4992500
502300C
5C536CC
5084200
511460C
5145100
5175700
5206100
2533400
2563500
259410C
2624500
265510C
186960C
1900000
193960C
1961100
1991500
80630C
836900
867400
89780C
928400
959000
989300
1020100
1C5C40C
1081100
11 11 40 6
1142000
1175600
1202900
1233500
7081700
7CR1700
7081700
7091700
7081700
7081700
70817CO
7081700
7081700
7081700
4! 73 5 00
4173500
4173500
4173500
4173500
31812CO
3181200
3181200
3181200
3181200
1758500
1758500
1758500
1758500
1758500
1758500
1753500
1758500
, 1758500
1758500
1758500
17585CC
1758500
1758500
1758500
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
4596200
4596200
4596200
4596200
4596200
4596200
45962CO
4596200
45962CO
4596200
3314100
3314100
33141 00
3314100
3314100
2340300
2340300
2 3403 CO
2340300
2340300
1017700
1017700
1017700
1017700
1017700
1C17700
1017700
1017700
1017700
1017700
1017700
1017700
1017700
1C17700
1017700
GROSS INCOME,
WYEAR
WITH WITHOUT
PAYMENT PAYMENT
3353001 2485500)
3659001 2485500)
396300) 2485500)
426800) 2485500)
457400) 2485500)
488000) 2485500)
518400) 2485500)
548900) 2485500)
579500) 24855CO)
609900) 24855001
780700 859400)
75060C 659400)
720000 859400)
689600 6594CO)
659000 8594CO)
470700 840900)
440300 840900)
409700 840900)
379200 840900)
348800 640900)
Z11400 740800)
180800 740800)
150300 740800)
119900 740800)
89300 74C8CO)
58700 740800)
28400 740800)
( 2400) 74C8CO)
32700) 740800)
63400) 7408CO)
124300) 740800)
1549001 74C800)
185200) 740800)
215800) 740800)
NET INCOME AFTER TAXES.
t/YEAR
WITH WITHOUT
PAYMENT PAYMENT
167650) 1242750)
182950) 1242750)
198150) 1242750)
213400) 1242750)
228700) 1242750)
244000) 1242750)
259200) 1242750)
274450) 1242750
289750) 1242750)
( 304950) 1242750)
390350 4297CO)
375300 429700)
360000 429700)
344800 429700)
329500 429700)
235350 420450)
220150 420450)
204850 420450)
199600 «20450>
174400 420450)
105700 370400)
S04CO 370400)
75150 370400)
59S5C 370400)
44650 37040CI
29350 370400)
14200 31C4CCI
( 1200) 370400)
( 16350) 370400)
( 317CO) 370400)
( 46850) 370400)
( 62150) 370400)
1 77450) 370400)
I 92600) ( 370400)
I 1079CO) ! 37040C)
CASH FLOrt,
S/YEAR
WITH HITHCLT
PAYMENT PAYMENT
1468030 39293C
1452730 392930
1437530 3929JO
1422280 39ZS3C
1406980 392930
137648C 392S30
13H230 392930
1345930 392S3C
1330730 392S3C
390350 4297CO)
375300 42970C)
360000 4297001
344800 42970C)
32950C 429700)
235350 420450)
220150 420450
2C4850 420450)
189600 4.-0450)
174400 420450
10570C 370400)
90400 370400)
75150 3/C40C)
59950 370400)
44650 37040C)
Z<=350 37040C)
14200 370400)
1200) 370400)
16350) 370400)
31700) 370400
46650 > 370400)
62150) 370400)
77450) 37C400)
92600) 370400)
1C7900) 37040C)
CUMULATIVE
S
WITH
PAYMENT
14«EC30
2920760
4358290
5760570
7187550
99557! C
11316940
12662870
'.ss'neoo
14363950
1475925C
15119250
J?«4C50
\5793550
16028900
16249C50
16453900
16643500
] 6917900
16923600
17014COO
17089150
17149100
17193750
1 7225! do
17237300
17234100
17219750
171 88C50
17^1'UOO
17079050
17CC1600
169C9COO
16801100
CASh FLCW,
WITHOUT
PAYMENT
392930
785860
1178790
J571720
1964650
2750510
314344C
3536370
3929300
3499600
3C69900
2640200
221C5CC
1780600
1360250
S399CC
519450
99000
321450)
691850 )
K62250)
1432650)
18C3050 )
2173450
2543850)
2914250 )
32S465C)
365505C)
4025450)
43^5650)
4766250 )
5136650)
55C7C50)
5877450)
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH WITHOUT
PAYMENT PAYMENT
2.23
2.14
2.05
1.97
1.88
1.34
1.26
1.17
1.03
0.99
0.60
0.52
0.43
0.34
0.25
O.t7
o.oa
TOTAL 135000 25840CO 133966000
»VG= 0.07
-------
00
Table B-123
PROCESS C, NONR6GLLATEO FERTILIZER CC. ECCIVCMICS, 500 KM., EXISTING UNIT, 3.5* S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = * 17329600
TOTAL INITIAL INVESTMENT « $ 18589600
CVERALL INTEREST ROTE CF RETURN WITH PAYMENT = NEG
OVERALL INTEREST RATE Of RETURN WITHOUT PAYMENT = NEG
NO PSYCLT klTH PAYMENT
NO PAYOUT hlTHOUT PAYMENT
YEARS AK'NUAL
AFTER OPERA-
POWER TION
UNIT KN-HR/
START KW
1
2
3
4 7000
5 7000
6 7000
7 7000
B 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 ?500
18 3500
19 3500
20 3500
21 1500
22 1500
23 1500
24 1500
25 1500
26 150C
27 1500
28 15CO
29 150C
30 1500
31 1500
32 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILI ZEk
137000
137000
137CCO
137CCO
1370CO
137CCC
1370CO
979CC
979CC
97900
979CO
579CC
68500
t£5CC
685CC
685CO
6E5CC
29400
294CO
294CO
29400
29400
2 94 CO
29400
294CC
294QC
294CO
294CC
29400
29400
294CC
29400
TOTAL
FERTILIZER
MFG.
COST,
t/YEAR
7563000
7563000
7563CCO
7563000
7563000
7563COO
7563000
615E1CO
61S81CO
6198100
4465100
4465100
3400500
340C500
340C500
3400500
34CC5CO
1676400
18764CO
187£4CO
1876400
18764CO
1874400
1876400
187(400
1876400
1876400
18764CO
1876400
18764CO
1876400
1876400
ALTERNATIVE
WET-LI MESTCNE
PROCESS
CCST (3
PAYMENT TO
FERTILIZER
COMPANY FOR
AIR POLLL-
TICN CONTROL,
I/YEAR
2261500
222610C
21910CC
21556CC
212C5CO
2C85100
2050000
18040CO
1768900
1733500
16SE3CC
1663000
K476CC
141230C
1377100
13418CO
13C66CO
1061200
1025900
990700
955400
5JC2CC
884900
84?7CC
8143CC
779200
7 *
WITH kIThOLT WITH WITHOUT
PAYMENT PAYMENT PAYMENT PAYMENT
142971C JC8960
2841720 597920
4236180 896880
561294C 1195840
6972150 1494800
8313660 1793760
9637620 2CS272C
10867680 2420730
12080190 2748840
1327EOOO 3C769CC
13585750 25385CO 1.67
13878850 2CCC1CC 1.58
14098050 1495500 1.18
14??9tOO 950900 1.08
144E3550 48630C 0.99
14649850 18300) 0.89
147=t3'50 5225CO) 0.80
14912C5C 940000) 0.61
15007900 1357100) 0.52
15CE6150 17742CO) 0.42
15146750 R191?00) 0.33
(.5189750 2608400) 0.23
i;?i;ico 3c25!bc> o.!4
1EJ2285C 3442600) 0.04
15212900 3859700)
151E5400 4276800)
151'0200 46S39CCI
15077450 51HOOO)
145^7COC 5528100)
14B99000 =S452CCI
1478?300 6362300)
1465CC50 67154CC)
TOTAL 114000
82755100 1256140CC
77396000 ( 5359100) { 48218000) ( 2679550) ( 24109000)
J4650C5C ( 6779400)
-------
Table B-124
PROCESS C. NGNR66ULAT60 FERTILI7FR CO. ECONOMICS, 500 MW., NEW UNIT, 5. OS S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED IWesriHENr . $ 17542900
TOTAL INITIAL INVESTMENT = $ 19057900
CVEPALL INTEREST RATE OF RETURN WITH PAYMENT - '.IS!
OVtRALL INTEREST RATE OF FEURN WITHOUT PAYMENT = NEC
YEARS ftECUIRED FOS P4YPI/T WITH PAYMENT:
NO PAYOLT UITHCUT PAYMENT
11.0
YFARS ANNUAL
SFTER OPERA-
POWER TION
UNIT KW-HR/
START KW
1 7000
•> 7000
1 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 70CO
10 7000
11 5000
1 5000
1 5000
1 5000
1 5000
1 3500
17 3500
18 3500
1° 1500
70 1500
71 \ 500
27 1500
71 1500
74 1500
75 1500
7.6 1.500
77 1500
7S I5CO
79 1500
10 1500
11 1500
17 1500
11 1500
14 1500
15 1500
TONS /YEAR
FERTILIZER
19J.4CO
191400
191400
19i400
1914CO
191400
191400
1914CO
191400
191400
1367CO
1367CO
136700
1367CC
1367CO
957CC
957CC
95700
957CO
95700
41000
410CO
41000
41000
410CO
41000
41000
41000
41000
41CCO
41000
410CO
410CO
41000
410CO
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
Trmt. FERTILIZER
FERTILIZER COMPANY FOR
«FG. AIR FCLLU-
CDST, TION CONTROL,
S/YE« S/YF.AR
8=60900 2506500
8=60900 2473000
8=6C=00 24393'00
8960900 2405800
8=6C9CO 23721CO
896C9CO 2338600
8960900 2304900
8=60900 2271ECC
8=60900 2238000
8=60900 22C4300
53517CO l=C39CO
5351700 1870200
5351700 18367CC
5351700 18C30CC
5351700 1769500
404=500 151Z1CO
4C4=500 1478400
4049500 1444900
4C4C.500 X113CC
4C49500 1377800
7'98000 . 1C78200
2'96000 " 1C447CO
21=6000 1011900
2IS8CCO 977500
21. = 8CCO 944000
21 98000 910300
71 9POOO S768CC
2J98COO 843100
2198000 8.C96CC
2'9SOCO 776,2CC
73=8000 742500
2198000 7C88C
-------
Table B-125
PROCESS C. NONRESULATED FERTILIZER CO. ECONOMICS, 1000 MW. , NEW UNIT, 3.51 S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = 4 24639300
TOTAL INITIAL INVESTMENT - $ 36649300
OVERALL INTEREST RATE OF RETURN WITH PAYMENT •= 4. OJ
OVERALL INTEREST RATE OF RETLRN WITHOUT PAYMENT = NCG
YEARS RECUIRED FOR PAYOUT WITH PAYMENT:
NO PAYOUT WITHOUT PAYMENT
YFAR S ANNUAL
1FTFR OPER4-
POWFR TION
UNIT KW-HR/
START KH
1 7000
7 7000
* 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
10 70CO
11 5000
\2 5000
13 5000
14 5000
15 5000
16 3500
17 3500
IS 3500
19 3500
70 3500
21 1500
2? 1 500
23 1500
?4 1500
75 1500
26 1500
77 1500
78 1500
29 1500
30 1500
11 1500
3? 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILIZER
259500
259500
2S95CO
259500
259500
259500
259500
259500
259500
259500
135400
1S54CC
1854CO
1854CC
1854CO
129800
1298CO
129800
129800
1298CO
55600
5560C
556CO
55600
556CO
55600
55600
556CC
5560C
5560C
556CC
55600
5560C
55600
55600
ALTERNATIVE
WET-LIMESTONE
PROCESS
COST AS
PAYMENT TO
TOTAL FERTILIZER
FERTILIZER COMPANY FOR
MFG. AIR POLLU-
COST, TICK CONTROL,
$/YEAR S/YEAR
1181430,. 3362400
11814300 33170CO
11814300 3271900
11814300 3226500
11B14300 3181200
11814300 3135800
11814300 3090700
11814300 3045400
11814300 3COCCCC
11814300 2954900
7098900 25651CO
7C9P900 251S8CC
7098900 2474500
7C98900 24293CO
7C98900 2384000
5353300 2053500
535230C 2CC64CC
5353300 1963100
5353300 19177CO
5353300 18724CC
2E10500 1496500
289C500 14512CC
288C500 1405800
2830500 1360700
288C500 131S4CC
2880500 1270000
2880500 12247CO
283C5QO 11795CC
2830500 1134200
2830500 1C888CO
268C500 1C43700
2B80500 998400
288C500 9530CC
2830500 907700
2880500 8625CO
NET FERTILIZER
MFC COST,
*/YEAR
WITH WITHOUT
PAYMENT PAYMENT
8451900
8497300
8542400
85878CC
863310C
867850C
8723600
8768900
8814300
8859400
4533800
4579100
4624400
466960C
4714900
3299800
3344900
3390200
3435600
3480900
1384000
1429300
1474700
1519800
1565100
1610500
1655800
1701000
1746300
1791700
1836600
1882100
1927500
1972800
2018000
11814300
11814300
11814300
11814300
11814300
11814300
J1814300
11814300
11814300
11814300
7098900
7098900
7098900
70=8900
7098900
5353300
5353300
5353300
5353300
5353300
2880500
288C500
2880500
2880500
2880500
2380500
2880500
2880500
2880500
2880500
2380500
28S05CO
2880500
2880500
2880500
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
3677700
8677700
8677700
8677700
8677700
8677700
8677700
S677700
8677700
8677700
6286900
6286900
6286900
6286900
6286900
445600C
4456000
445600C
4456000
4456000
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
1949300
GROSS INCOME,
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
225800 ( 3136600)
180400 31366001
135300 3136600)
39900 3136600)
44600 3136600)
( 800) 3136600)
( 45900) 3136600)
( 91200) 3136600)
1 1.36600) 3136600)
( 181700) 3136600)
1753100 812000)
1707800 812000)
1662500 81.2000)
1617300 812000)
1572000 812000)
1156200 897300)
1111100 397300)
1065800 897300)
1020400 897300)
975100 897300)
565300 931200)
5JOOOO 931200)
474600 931200)
429500 931200)
384200 931200)
338800 531200)
29354)0 931200)
248300 931200)
203000 531200)
157600 931200)
112500 531200)
67200 931200)
21800 931200)
( 23500) 931200)
< 63700) 931200)
NET INCOME AFTER TAXES.
$/YEAR
WITH WITHOUT
PAYMENT PAYMENT
112900
90200
67650
44950
22300
( 400)
( 22950)
( 45600 )
( 68300)
I 90850)
876550
85390C
831250
808650
78600C
578100
555550
532900
510200
487550
282650
260000
237300
214750
192100
169400
146750
124150
101500
78800
5625C
336pO
109'00
I 11750)
< 34350)
1568300)
156B3CO)
1568300)
1568300)
1568300)
1568300)
1568300)
1568300)
15683CO)
1568300)
4060CO)
4060CO)
406000)
4060001
406000)
448650)
<4B65G>
4486501
448650)
448650)
465600)
465600)
465600)
465600 )
4656CC)
465600)
465600)
465600)
465600)
465600)
465600)
465600 I
4656CO)
465600)
465600)
CASH FLOW,
»/Y EAR
WITH WITHOUT
PAYMENT PAYMENT
2576330 89563C
7.554130 895630
2531580 895630
2508380 895630
2486230 895*30
7463530 845630
2440980 89563C
2418330 895630
23°5630 895630
2373030 895630
876550 ( 406COO)
853900 406CCC)
831250 406000)
808650 40600C.)
786000 40600CI
578100 4486501
555550 448650)
532900 448650)
510700 448650)
4B7550 448650)
782650 465600)
760000 465600)
737300 465t>00>
2)4750 465600)
192100 4656CC)
169400 465600)
146750 465600)
124150 465600)
101500 465600)
78300 465600)
56250 465600)
33600 465600)
10900 465300)
( 11750) 465600)
( 34350) 465600)
CUMULATIVE
t
WITH
PAYMENT
2576830
513C960
7662540
J0171420
1265765C
15121' 80
17562160
19960490
22376120
74749200
25625750
26479650
27310900
28119550
23905550
29483650
3CC39200
30572100
?)Cf2300
31 5(9850
3!35J500
32112500
32349300
32564550
V 7566? C
32376050
33072800
33196950
33798450
33377250
33433500
37467100
33478000
33466250
33431900
ANNUAL RETURN ON
CASH FLCW, INITIAL INVESTMENT,
%
klTHOUT WITH WITHOUT
PAYMENT PAYMENT PAYMENT
8S563C 0.42
1791260 0.34
2686690 0.25
356252C 0.17
4478)50 0.08
537.3780
6269410
7165C40
3060670
8956300
85503CC 3.29
8144300 3.20
7738300 3.12
73323CO 3.03
6926300 2.95
6477650 2.17
6029000 2.08
5580350 2.00
5131700 1.91
4683050 1.83
4217450 1.06
3751E5C 0.98
3286250 0.89
282C650 0.81
2355C5C 0.77
1939450 0.64
14Z3B5C 0.55
958250 0.47
492650 0.38
27C50 0.30
t 438550) 0.21
{ 904150) 0.13
( 1369750) 0.04
I 1835350
I 23C09501
TOTAL 135000 5005000
714657CO 152145800 223611500 169731000
17585200 ( 53B80500)
8792600 ( 26940250)
33431=00 ( J3C095C)
-------
Table B-126
PROCESS Ci N^REGULATED FERTILIZER CO- ECONOMICS, 1000 MW., EXISTING UNIT* 3.51 S IN COALi 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT =
TOTAL INITIAL INVESTMENT =
CVERALL INTEREST BATE CF PETURN WITH PAYMENT -
OVERALL INTEREST RATE OF RETtRN WITHOUT PAYMENT =
26646400
28821400
2.5*
NEG
YEARS RECUIREC FOR PAYOUT WITH PAYMENT:
NO PAYOIT UTHCLT PAYPEIvT
11.8
ALTERNATIVE
HET-LICESTCNE
PROCESS
COST AS
FAYPENT TC
YEARS ANNUAL TOTAL FERTILIZER
AFTER OPERA- FERTILIZER COMPANY F
POKER TION MFG. AID POLLU-
NET FERTILIZER
MFG COST,
I/YEAR
NET
FERTILIZER
SALES
GROSS INCOME,
J/YEAR
NET INCOME AFTER TAXES,
t/YEAR
CASH FLOM,
J/YEAR
CUMULATIVE CASH FLCK,
I
ANNUAL RETURN ON
INITIAL INVESTMENT
*
UNIT KW-HR/
START KM
1
2
3
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
10 7000
11 9000
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 15CO
26 1 500
27 1500
28 1500
29 1500
30 150C
31 1500
32 1500
33 1500
34 1500
35 1500
TONS/YEAR COST,
FERTILIZER J/YEAR
268000 12462900
268000 124629CO
Z68CCO 12462900
268000 12462900
268CCC 12442900
268CCO 12462900
S680CO 12462900
1914CC 10111400
191400 101H400
1914CO 10111400
1914CG 7446700
191400 7446700
1340CC 562J300
U40CO 5622300
134000 5622300
13«OCC 56223CO
134000 5622300
57400 30342CO
574CC 3036200
57400 3036200
574CC 30342CO
57400 3036200
57400 3036200
574CC '3034200
57400 3036200
574CC 3034200
574CO 303(200
57400 303(200
574CC 303(200
574CC 3036200
574CO 3C362CO
574CO 3C36JCO
TION CONTROL,
J/YEAR
3587300
35336CC
3480600
34272CO
33739CC
3319900
3267ZCO
2857000
2803800
215C3CC
2696900
Z6436CC
Z2943CO
2241100
21876GC
2134400
2080900
168E3CC
1632000
157E4CC
15253CC
1471900
141E6CC
1365200
1311900
125ESCC
1205000
11518CC
1C98300
1045100
991600
938400
KITH
PAYMENT
8875600
8929100
8982300
9C3570C
9089000
9143000
9195700
7254400
7307600
7361100
4749800
480310C
3328000
3381200
343470C
3487900
3541400
1350900
1404200
145760C
1510900
1564300
161760C
1671000
1724300
1777700
1831200
188440C
1937900
1991100
2C44600
2097800
WITHOUT
PAYMENT
12462900
12462900
12462900
12462900
12462900
12462900
124629CO
10111400
10111400
10111400
7446700
7446700
5622300
5622300
5622300
5622300
5622300
3036200
3036200
3036200
3036200
3036200
30362 OC
3036200
3036200
3036200
3036200
3036200
3036200
3036200
3C36200
3036200
REVENUE,
I/YEAR
8951200
8951200
8951200
8951200
8951200
8951200
8951200
6482700
6482700
6482700
6482700
6482700
4596200
4596200
4596200
4596200
45962CO
2011300
2011300
2011300
2011300
2011300
2011300
2011300
2C11300
2011300
2011300
2011300
2011300
2011300
2011300
2011300
WITH WITHOUT
PAYMENT PAYMENT
75600 < 3511700)
22100 3511700)
311001 35117CO)
84500) 35117001
137800) 35117CO)
191800) 35117CO)
244500) 3511700)
771700) -626700)
824900) 3628700)
878400) 3628700)
1732900 964000)
1679600 964000)
1268200 1C26100)
1215000 1C26100)
1161500 1026100)
1108300 1C26100)
1054800 1026100)
660400 1024900)
607100 1C24900I
553700 1024900)
500400 1C2«9CO>
447000 1C24900)
393700 1024900)
340300 1G24900)
287000 1024900)
233600 1024900)
180100 1C24900)
126900 1024900)
73400 1C24900)
20200 1C24900)
( 33300) 1024900)
( 865001 1C24900)
WITH WITHOUT
PAYMENT PAYMENT
37800 1755850)
11050 1755850)
( 15550) 1755850)
( 42250) 1755850)
( 68900) 1755850)
( 959001 17558501
( 122250) 1755850)
( 385850) 1614350)
( 412450) 1814350)
( 439200) 1S14350)
866450 4820001
839800 482000)
634100 513050)
607500 513050)
580750 513050)
554150 513050)
527400 513050)
330200 E1245C)
303550 512450)
276850 512450)
2S02CC 512450)
223500 512450)
196850 512450)
17C150 512450)
143500 512450 )
116800 512450)
90050 512450)
63450 512450)
367CO 512450)
10100 512450)
( 16650) 512450)
( 43290) 5124501
WITH HlThCLT
PAYMENT PAYMENT
27C244C 9C8790
2675690 908790
26*9090 9Ct7iC
2622390 9Gb790
2595740 908790
2568740 908790
2542390 908790
2278790 85C290
2252190 35029C
2225440 850290
866450 ( 4S2000)
839800 ( 4820JO)
6C7500 5UC5C)
580750 513050)
554150 513C5C)
5?7400 513050)
3C3550 512450
276B50 512450)
250200 512«50)
223500 512450)
196850 512450)
170150 5U45O
143500 512450)
116800 512450)
90050 512450
63450 5124501
36700 512450)
10100 51245C)
I 16650) 512450)
( 43250) 512450)
WITH
PAYMENT
2702440
5378J30
BC27220
10649610
13245350
15814C90
18356480
20635270
22861460
25112900
25979350
26819150
28060750
286*1500
291?5650
29723050
3C356BOC
30653650
3C663e5iO
31107350
31304200
31474350
31617850
31734450
31824700
318S8150
31924850
31934950
33918300
31815050
WITHGUT
PAY^E^T
908790
1S37580
272637C
363516C
4543950
5452740
63<1520
7211820
8Ct2)lC
8912400
8430400
794S
( 766250)
( 12787001
< 179H50)
( 23C3600)
KITH WITHOUT
PAYMENT PAYMENT
0.13
0.04
3.01
J.9J.
2.11
2.01
1.92
1.83
1.05
0.96
0.87
0.78
0.6B
0.59
0.50
0.41
0.31
a. 2 2 —
0.13
0.04
TOTAL 114000 43640CO 206122400
68357300 137765100 206122400 148222400
5228650 ( 28950000)
31875C50 1 230360G)
AVG= 0.57
-------
-J
K)
Table B-127
PROCESS A. COOPERATIVE ECONOMICS! 200 MH., EXISTING UNIT, 3.51 S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $
TOTAL INITIAL INVESTMENT = i
OVERALL INTEREST RATE OF RETURN WITH DEDUCT -
OVERALL INTFREST RATE OF RETURN WITHOUT DEDUCT =
NET NH3
ALTERNATE SCRUBBING
TOTAL NH3 WET-LIME- COST IF
YEARS
AFTER
POWER
UNIT
START
1
7.
3
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KH FERTILIZER
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO.,$/YEAR
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
S/YEAR
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
S/YEAR
9640000
10431000
NEC
NEG
NET FERTILIZER MFG
COST USINC (NH412S04
FROM POWER PLANT,
$/YEAR
WITH WITHOUT
DEDUCT DEDUCT
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NO PAYOUT WITH DEDUCT
NO PAYOUT WITHOUT DEDUCT
ANNUAL RETURN ON
GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
*/YEAR t/YEAR J/YEAR $ \
WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT
8
9 7000 128600 1781500 1087900 693600
10 7000 138600 1759300 1067700 691600
LI 5060 91700 1464900 94710(1 5l7UdU
12 5000 91700 1442700 927000 515700
14 5000 91700 1398400 686600 511800
15 5000 91700 1376100 866400 509700
17 3500 64200 1121300 742800 378500
18 3500 64200 1099100 722600 376500
19 3500 64200 1076800 702400 374400
?0 350O 64200 1054800 682200 372600
21 1500 27666 738906 553»06 185966
?2 1500 27600 716600 532800 183800
23 1500 27600 694600 512600 182000
25 1500 27600 650100 472^00 177800
26 I -io6 27600
-------
Table B-128
PROCESS A, COOPERATIVE ECONOMICSt 500 MW.T NEW UNIT, 2.0* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 11210000
TOTAL INITIAL INVESTMENT = S 12326400
OVERALL INTEREST RATE OF RETURN HITH DEDUCT = 7.3*
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = NEC
YEARS REQUIRED FOR PAYOUT WITH DEDUCT!
HO PAYOUT WITHOUT DEDUCT
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
10 7000
12 5000
13 5000
14 5000
15 5000
17 3500
18 3500
19 3500
20 3500
21 1*66
22 1500
23 1500
24 1500
25 500
26 500
27 500
28 500
29 500
30 500
31 1500
32 1500
33 1500
34 1500
35 1500
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
TONS/YEAR FOR POWER
173600 2892800
173600 2860100
173600 2827800
173600 2795100
173600 2762500
173600 2729800
173600 2697400
173600 2664700
173600 2632000
173600 2599600
123900 2142100
123900 2109400
123900 2077000
123900 2044300
86700 1675200
86700 1642600
86700 1609900
86700 1577500
37566 1117&06
37200 1085000
37200 1052300
37200 1019900
37200 987200
37200 954500
37200 922100
37200 889400
37200 856800
37200 824100
37200 791700
37200 759000
37200 726400
37200 693900
37200 661300
ALTERNATE
WET-LIME-
STONE PRO-
POLLUTION
CONTROL
COST,
1800000
1772800
1749100
1718800
1690600
1663466
1635900
1608700
1581200
1553800
1379800
1352300
1325100
1297900
1270400
1086700
1059200
1032000
1004500
827100
799800
772400
745100
717700
690400
663000
635500
608300
580800
S53&66
526100
498900
471400
444200
NET NH3
SCRUBBING
COST IF
DEDUCTION
WET-LIME-
STONE PRO-
CESS COST,
1092800
1087300
1078700
1076300
1071900
1066406
1061500
1056000
1050800
1045800
794900
789800
784300
779100
773900
588500
583400
577900
573000
285200
279900
274800
269500
Z64100
259100
253900
248500
243300
2 JO 1(1 (3
232900
227500
222500
217100
NET FERTILIZER MFG
COST USING (NH4)2S04
$/YEAR
WITH
DEDUCT
6744200
6738700
6730100
6727700
6723300
6717806
6712900
6707400
6702200
6697200
4230700
4225600
4220100
4214900
4209700
3174500
3169400
3163900
3159000
1675300
1670500
1665200
1660100
1654800
1&44400
1639200
1633800
1628600
1618200
1612800
1607800
1602400
FERTILIZER
SALES
WITHOUT REVENUE,
DEDUCT */YEAR
8544200 7301600
8511500 7301600
8479200 7301600
8446500 7301600
8413900 7301600
&3'fl!260 ?30l606
8348800 7301600
8316100 7301600
8283400 7301600
8251000 7301600
5610500 5268200
5577900 5268200
5545200 5268200
5512800 5268200
5480100 5268200
4261200 3721200
4228600 3721200
4L95900 3721200
4163500 3721200
2470300 1623000
2437600 1623000
2405200 1623000
2372500 1623000
2307400 1623000
2274700 1623000
2242100 1623000
2209400 1623000
2144300 1623000
2111700 1623000
2079200 1623000
2046600 1623000
GROSS INCOME,
S/YEAR
HITH HITHOUT
DEDUCT DEDUCT
557400 1242600)
562900 1209900)
571500 1177600)
573900 1144900)
578300 1112300)
583800 1079600)
588700 1047200)
594200 10145001
599400 981800)
604400 949400)
1037500 342300)
1042600 309700)
1048100 277000)
1058500 211900)
546700 540000)
551800 507400)
557300 474700)
562200 442300)
47500) 8473001
42200) 814600)
37100) 782200)
31800) 749500)
21400) 684400)
16200) 651700)
{ 108001 619100)
( 5600) 586400)
4800 521300)
10200 488700)
15200 456200)
20600 423600)
NET INCOME AFTER TAXES,
t/YEAR
WITH HI THOUT
OFDUCT DEDUCT
278700 621300)
281450 6049501
285750 588800)
286950 572450)
289150 556150)
294350 523600)
297100 507250)
299700 490900)
302200 4747001
518750 1711501
521300 154850)
524050 1385001
529250 1059501
273350 270000)
275900 253700)
278650 237350)
281100 221150)
237501 423650)
21100) 407300)
18550) 391100)
15900) 374750)
10700) 3422001
81001 325850)
5400) 309550)
2800) 293200)
2400 260650)
5100 2443501
7600 228100)
10300 2118001
CASH FLOW,
*/YEAR
WITH WITHOUT
DEDUCT DEDUCT
1399700 499700
1402450 516050
1406750 532200
1407950 548550
1410150 564850
1412900 581200
1415350 597400
1418100 613750
1420700 630100
1423200 646300
518750 171150)
521300 1548501
524050 138500)
526650 122300)
529250 1059501
275900 253700)
278650 2373501
281100 221150)
23750) 23650)
21100) 07300)
18550) 91100)
15900) 74750)
10700) 342200)
8100) 325850)
2800) 293200)
2001 277000)
2400 260650)
5100 244350)
7600 228100)
CUMULATIVE
WITH
DEDUCT
1399700
2802150
5616850
7027000
9855250
11273350
12694050
14117250
14636000
15157300
15681350
16208000
16737250
17281400
17557300
17835950
18117050
18066900
18027250
18011350
17987450
17979350
17971150
17970950
17973350
17978450
17986050
CASH FLOW,
WITHOUT
DEDUCT
499700
1015750
2096500
2661350
3242550
3839950
4453700
5083800
5730100
5558950
5404100
5265600
5143300
5037350
4481100
4227400
3990050
3768900
2905300
2106900
1732150
1031550
705700
396150
102950
( 174050)
1 434700)
I 679050)
( 907150)
1 1118950)
ANNUAL RETURN ON
INITIAL INVESTMENT,
I
WITH WITHOUT
DEDUCT DEDUCT
2.26
2.28
2.32
2.33
2.35
2.37
2.39
2.41
2.43
2.45
4.21
4.23
4.25
4.27
2.22
2.24
2.26
2.28
0.02
0.04
0.06
O.OB
N)
CJ
-------
Table B-129
PROCESS 4, COOPERATIVE ECONOMICS i 500 MW. , NEW UNIT, 3.51 S IN COAL* Z8-14-0 FERTILIZER PRODUCTION
YFAot; ANNUAL
AFTFH OPERA-
^OWE1* TIHN
UNIT KW-HB/
2 70f>0
3 7000
4 7000
5 7000
A 7000
7 7000
8 7000
9 7000
11 5000
12 5000
13 5000
14 SOOO
15 5000
17 3500
18 3500
19 3500
20 3500
21 1500
22 1500
24 1500
25 1500
26 1500
28 1500
29 1500
30 IS 00
31 1500
32 1SOO
33 1500
34 1500
35 1500
OVERALL
TONS/YFI"
303800
3^3800
301500
303flOr>
3C3800
303800
303800
303800
217000
217000
217000
?17000
21700D
151900
151900
151900
151900
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
65300
INTEREST RATE
TOTAL NH3
COST TNCL
RFGUL.RQ!
FOR POWER
•1692000
3657000
3621900
3586900
3552000
3517000
3482100
3447000
2688500
2653500
2618600
2583400
?54;1500
2109600
2004600
1299700
1229600
1194600
1159700
1089800
1054600
1019700
984800
949800
914900
879700
844800
FIXED INVESTMENT = t
OF RETURN WITH DEDUCT =
NET NH3
WET-LIME- COST IF
STONE PRO- DEDUCTION
POLLUTION WET-LIME-
CONTROL STO«E PRO-
COST, CESS COST,
2089200 1567800
2058700 1563200
2028100 1558HOO
1997500 1554500
1967100 1549900
1906000 1541000
1875600 1536400
1640100 1048400
1610000 1043500
1579400 1039200
1549000 1034400
1513400 1031100
1261200 825400
1220100 819400
1189700 814900
921600 378100
360700 368900
830100 364500
799500 360200
736400 351400
708100 346500
677400 342300
647100 337700'
616500 333300
585900 329000
555600 324100
525000 319800
15580000 YEA3S REQUIRED FOR PAYOUT WITH DEDUCT: 6.1
13. 2?
NET FERTILIZER MFC
COST USING (NH4)2S04 ANNUAL RETURN ON
$/YEAR FERTILIZER $/Y£AR S/YEAR ft/YEAR t *
SALES
WITH WITHOUT REVENUE, WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WI THOUT WITH WITHOUT
DEDUCT DEDUCT S/YEAR DEDUCT DEDUCT DEDUCT DUCT DEDUCT DEDUCT
10483200 12602800 12492000 2008800 ( 110800) 1004400 S5400) 2567400 150Z600 5122650 2987750 5.78
10474000 12532700 12492000 2018000 ( 40700) 1009003 203501 2567000 1537650 10254350 6045500 5.80
10472300 12500400 12492000 2019700 ( 8400) 1009850 420T] 2567850 155380Q 12822200 7599300 5.81
10456300 12392900 12492000 2035700 99100 1017850 49550 2575850 1607550 20543050 12369550 5.85 0.29
10451800 12357800 12492000 2040200 134200 1020100 67100 25 781 00 1625100 23121150 13994650 5,87 0.39
10447200 12322800 12492000 2044800 169200 10?240Q 84600 25P0400 1642600 25701550 15637250 5.88 0.49
6581100 8221200 905LOOO 2469900 829800 1234950 416900 1234950 *• 14900 26936500 16052150 7.10 2.39
6567100 8116100 9051000 2483900 934900 1241950 467450 124C950 467450 30655400 17401850 7,14 Z.69
6 562 BOO 808 12 00 9051000 2488200 969800 l?44 JT1 484900 1244100 4849OQ 31899500 17886750 7.16 2.79
4950800 6201400 6415000 1464200 213600 732100 106800 732100 106HOO 34089150 18154700 4.21 0.61
4946200 6166300 6415000 1468800 248700 734400 124350 734400 124350 34823550 18279050 4.22 0.72
4941700 6131400 6415000 1473300 283600 736650 141800 7366^0 141800 35560200 18420950 4.24 0.82
2537600 3459200 2820000 282400 ( 639200) 141200 319600) 141200 319600) 35840450 17764200 0.81
2528400 3389100 2820000 291600 ( 569100) 145800 284550) 145800 2B4550) 36129700 17177550 0.84
2524000 3354100 2820000 296000 1 534100) 148000 267050) 143000 267050) 36277700 16910500 0.85
2519700 3319200 2820000 300300 { 499200) 150150 249600) 150150 249600) 36427850 16660900 0.86
2510900 3249300 2820000 309100 ( 429300) 154550 214650) 154550 214650) 36734900 16214150 0.89
2506000 3214100 2820000 314000 ( 394100) 157000 197050) 157000 197050) 36891900 16017100 0.90
2501800 3179200 2820000 318200 ( 359200) 159100 179600) 159100 179600) 37051000 15837500 0.92
2497200 3144300 2820000 322800 ( 324300) 161400 162150) 161400 162150) 37212400 15675350 0.93
2492800 3109300 2820000 327200 ( 289300) 163600 144650) 163600 144650) 37376000 15530700 0.94
2488500 3074400 2820000 331500 ( 2544001 165750 127200) 165750 1272001 37541750 15403500 0.95
2483600 3039200 2820000 336400 1 2192001 168200 109600) 16H200 109600) 37709950 15293900 0.97
2479300 3004300 2820000 340700 1 184300) 170350 92150) 170350 92150) 37880300 15201750 0.98
199949400 245306500
-------
Table B-130
PROCESS A, COOPERATIVE ECONOMICS, 500 MU., EXISTING UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = t 16090000
TOTAL INITIAL INVESTMENT - i 171)42700
OVERALL INTEREST RATE OF RETURN HITH DEDUCT « 10.4X
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT - NEC
YEARS REQUIRED FOR PAYOUT WITH DEDUCT:
NO PAYOUT WITHOUT DEDUCT
YEARS ANNUAL
AFTER OPERA-
POHER TION
UNI T KW-HR/
1
2
3
4 7000
5 7000
6 7000
7 7000
a 7000
9 7000
10 7000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
IB 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
31 1500
32 1500
33 1500
34 1500
35 1500
TOTAL NH3
SCRUBBING
COST INCL
REGUL.ROI
TONS/YEAR FOR POWER
310800 3921300
310800 3880800
310800 3840400
310800 3799900
310800 3759300
310800 3718700
310800 3678400
222000 2975000
222000 2934600
222000 2894100
222000 2853500
155400 2336000
155400 2295400
155400 2254800
155400 2214300
155400 2173900
66800 1472400
66800 1431800
66800 1391400
66800 1350900
66800 1310300
66806 Iziaooo
66800 1229400
66800 1188900
66800 1107900
66800 1067400
66800 1026800
66800 986500
66800 945900
66800 905400
ALTERNATE
WET-LI HE-
STONE PRO-
POLLUTION
CONTROL
COST,
2261500
2226100
2191000
2155600
2120500
2085100
2050000
1768900
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1025900
990700
955400
920200
849700
814300
743800
673300
638200
602800
567700
NET NH3
SCRUBBING
COST IF
DEDUCTION
WET-LIME-
STONE PRO-
CESS COST,
1659800
1654700
1649400
1644300
1638800
1633600
1628400
1206100
1201100
1195800
1190500
888400
883100
877700
872500
867300
405900
400700
395500
390100
379700
374600
364100
358700
353500
348300
343100
337700
NET FERTILIZER MFC
COST USING INH4>2S04
FROM POWER PLANT,
$/YEAR
WITH WITHOUT
DEDUCT DEDUCT
10993200 13254700
10988100 13214200
10982800 13173800
10977700 13133300
10972200 13092700
10967000 13052100
10961800 13011800
7005000 8703300
6999700 8662700
5218300 6665900
5213000 6625300
5207600 6584700
5202400 6544200
5197200 6503800
2672300 3733500
2667000 3692900
2661800 3652500
2656600 3612000
2651200 3571400
2646200 3531100
2640800 3490500
2625200 3369000
2619800 3328500
2614600 3287900
2609400 3247600
2604200 3207000
2598800 3166500
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
12764600
12764600
12764600
12764600
12764600
12764600
12764600
9253000
9253000
9253000
6561000
6561000
6561000
6561000
6561000
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
2883800
GROSS INCOME,
S/YEAR
WITH WITHOUT
DEDUCT DEDJCT
1771400 490100)
1776500 4496001
1781800 409200)
1786900 3687001
1792400 328100)
1797600 287500)
1B02800 247200)
628700 1140200)
2248000 549700
2253300 590300
1342700 104900)
1348000 64300)
1353400 23700)
1358600 16800
1363800 57200
211500 849700)
216800 809100)
222000 7687001
227200 728200)
232600 6876001
237600 647300)
243000 606700)
248100 566200)
258600 4B5200I
264000 444700)
269200 4041001
274400 3638001
279600 323200)
2B5000 2827001
NET INCOME AFTER TAXES,
S/YEAR
WITH WITHOUT
DEDUCT DEDUCT
885700 245050)
888250 224800)
890900 204600)
893450 1843501
896200 164050)
898800 143750)
901400 123600)
314350 5701001
1124000 274850
1126650 295150
671350 52450)
674000 32150)
676700 11850)
679300 8400
681900 2S600
105750 424850)
108400 404550)
111000 384350)
113600 364100)
116300 343800)
118800 323650)
121500 303350)
124050 283100)
129100 2426001
132000 222j*0l
134600 202050)
137200 181900)
139800 161600)
142500 141350)
CASH FLOW, CUMULATIVE
S/YEAR
WITH WITHOUT WITH
DEDUCT DEDUCT DEDUCT
2494700
2497250
2499900
2502450
2505200
2507800
2510400
1923350
1925850
1124000
1126650
671350 1
674000 (
676700 1
679300
681900
105750 (
108400 1
111000 1
116300 (
118800 (
121500 (
124050 (
126700 (
129300 (
132660 (
137200 (
139800 (
142500 1
1363950 2494700
1384200 4991950
1404400 7491850
1424650 9994300
1444950 12499500
1465250 15007300
1485400 17517700
1038900 21361700
1059100 23287550
274850 24411550
295150 25538200
524501 26209550
321501 26883550
11850) 27560250
6400 28239550
28600 28921450
424850) 29027200
4045501 29135600
3843501 29246600
3438001 29476500
3236^0) 295"9$3dd
3033501 29716800
283100) 29840850
262900) 29967550
242600) 30096850
222350* 36228855
181960) 30500650
161600) 30640450
141350) 30782950
CASH FLOW,
S
WITHOUT
DEDUCT
1363950
2748150
4152550
5577200
7022150
8487400
9972800
12030350
13089450
13364300
13659450
13607000
13574850
13563000
13571400
13600000
13175150
12770600
12386250
12022150
11678350
11354700
11051350
10768250
10505350
10262750
10040440
9838350
9656450
9494850
9353500
ANNUAL RETURN ON
*
WITH WITHOUT
DEDUCT DEDUCT
4.94
4.95
4.97
4.98
4.99
5.01
5.02
1.75
1.77
6.26 1.53
6.28 1.64
3.74
3.76
3.77
3.79 0.05
3.80 0.16
0.59
0.60
0.62
0.63
0.65
0.68
0.69
0.71
0.72
O.T4
0.75
0.76
0.78
0.79
14692950 ( 6736500)
to
-------
Table B-131
PROCESS A, COOPERATIVE ECONOMICS, 500 MW., NEK UNIT, 5.01 S [N COAL, 28-14-0 FERTILIZER PRODUCTION
YEARS
AFTER
POWER
UNIT
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
n —
22
23
24
25
26
27
28
29
30
31
32
33
34
35
0
ANNUAL
OPERA-
TION
KW-HR/
TOGO
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
T553 —
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
FIXED INVESTMENT = $
TOTAL INITIAL INVESTMENT = *
OVERALL INTEREST RATE OF RETURN WITH DEDUCT «
VERALL INTEREST RATE OF RETURN WITHOUT DEDUCT -
NET NH3
ALTERNATE SCRUBBING
TOTAL NH3 WET-LINE- COST IF
SCRUBBING STONE PRO- DEDUCTION
PONS/YEAR
434000
434000
434000
434000
434000
434000
434000
434000
434000
309800
309BOO
309800
309800
309800
217000
217000
217000
217000
217000
9T5o3 —
92800
92900
92800
92800
92800
92800
92800
92800
92800
92800
92800
92800
92800
COST INCL
REGUL.ROI
FOR POWER
CO.,$/YEAR
4224500
4187200
4150000
4075600
4038500
4001300
3964100
3926800
3B89600
3140900
3103600
3066400
3029200
2991900
2410600
2373400
2336200
2298900
1473600
1436300
1399100
1361900
1324600
1250400
1213100
1175900
1138700
1101400
1064200
1027000
989700
952500
POLLUTION
CONTROL
COST,
(/YEAR
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1803000
1769500
1512100
1478400
1444900
1411300
1377800
1078200
1 044700
1011900
977500
944000
876800
843100
809600
776200
742500
708800
675300
64 1 800
608100
WET-LIME-
STONE PRO-
CESS COST,
J/YEAR
1718000
1714200
1710700
1707000
1703500
1699900
1696400
1692600
1688800
1685300
1233400
1229700
1226200
1222400
898500
895000
891300
887600
883900
394400
391600
387200
384400
380600
373600
370000
366300
362500
358900
355400
351700
347900
344400
19870000
22159000
18. 9*
11.01
NET FERTIL
COST USING
»/YEAR
WITH
DEDUCT
13121200
13117400
13113900
13110200
13106700
13103100
13099600
13095800
13092000
13088500
8328800
8325200
9321500
B31BOOO
8314200
6177100
6173600
6169900
6166200
3143900
3140100
3135700
3132900
3129100
3122100
3118500
3114800
3111000
3107400
3103900
3100200
3096400
3092900
1ZER MFG
-------
Table B-132
PROCESS ft, COOPERATIVE ECONOMICS, 1000 HH.t NEW UNIT* 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = $ 25240000
TOTAL INITIAL INVESTMENT = $ 28338400
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = 19.81
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = 11.8*
VEARS REQUIRED FOR PAYOUT WITH DEDUCT:
YEARS REQUIRED FOR PAYOUT WITHOUT DEDUCT:
4.6
6.5
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
-6
7
8
9
10
11
12
13
1*
15
16
17
IB
19
20
21
22
23
2*
25
26
27
26
29
30
31
32
33
3*
35
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
587500
587500
587500
587500
587500
5T7500
587500
587500
587500
41970O
419700
419700
419700
419700
293800
293800
293600
293800
293800
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
126300
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.R01
FOR POWER
5936700
5881600
5826600
5771500
5716600
5661506
5606400
5551500
5496300
4420200
4365100
4310200
4255100
4200100
3404400
3349300
3294400
3239300
3184400
2106700
2051600
1996700
1941600
1886700
1831600
1776400
1721500
1666400
1611500
1556400
1501300
1446300
1391200
1336300
ALTERNATE
WET-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
3362400
3317000
3271900
3226500
3181200
3135800
3090700
3045400
3000000
2565100
2519800
2474500
2429300
2384000
2053500
2008400
1963100
1917700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1179500
1134200
1088800
1043700
998400
953000
907700
862500
NET NH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LI HE-
STONE PRO-
CESS COST,
2574300
2564600
2554700
2545000
2535400
2525700
2515700
2506100
2496300
1855100
1845300
1835700
1816100
1350900
1340900
1331300
1321600
1312000
610200
600400
590900
580900
571300
551700
542000
532200
522700
512700
502900
493300
483500
473800
NET FERTILIZER MFC
COST USING (NH412S04
FROM POKER PLANT,
S/VEAR
WITH WITHOUT
OEOUCT DEDUCT
17306900
17297200
17287300
17277600
17268000
17258300
17248300
17238700
17228900
17219100
11017700
11007900
10998300
10978700
8151900
8141900
8132300
8122600
8113000
3934700
3924900
3915400
3905400
3895800
3876200
3866500
3847200
3827400
3817800
3808000
3798300
20669300
20614200
20559200
20504100
20449200
20394100
20339000
20284100
20228900
20174000
13582800
13527700
13472800
13362700
10205400
10150300
10095400
10040300
9985400
5431200
5376100
5321200
5266100
5100900
5046000
4936000
4825800
4770800
4715700
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
23270900
16972700
16972700
16972700
16972700
12098700
12098700
12098700
12098700
12098700
5366506
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
GROSS INCOME,
*/YEAR
WITH WITHOUT
DEDUCT DEDUCT
5964000
5973700
5983600
5993300
6002900
6012600
6022600
6032200
6042000
6051800
5955000
5964800
5974400
5984300
5994000
3946800
3956800
3966400
3976100
3985700
1431800 I
1441600 (
1451100
1461100
1470700
1490300
1500000
1509800
1519300
1539100
1548700
1558500
1568200
2601600
2656700
2711700
2 766 BOO
2821700
2S76BOO
2931900
2986800
042000
096900
445000
499900
555000
3610000
1893300
1948400
2003300
2058400
2113300
64766*
96001
45300
100400
155300
210400
365600
320500
375600
430500
540700
595700
650800
705700
»/YEAR
WITH WITHOUT
OEOUCT OEOUCT
2982000
2986650
2991SOO
2996650
3001450
3006300
3011300
3016100
3021000
3025900
2982400
2987200
2992150
2997000
1978400
1983200
1988050
1992850
715900 I
720800 I
725550
730550
735350
745150
750000
754900
759650
769550
774350
779250
784100
1300800
1328350
1355850
1383400
1438400
1465950
1493400
1521000
1548450
1722500
1749950
1777500
1805000
1001650
1029200
1056650
323501
4BOO)
22650
50200
77650
132800
160250
187800
215250
270350
297850
325400
352850
CASH FLOW,
*/YEAR
WITH WITHOUT
DEDUCT DEDUCT
5506000
5510850
5515800
5520650
5530300
5535300
5540100
5545000
5549900
2982400
2987200
2992150
2997000
1983200
1988050
1992850
715900 (
720800 1
725550
730550
735350
745150
750000
754900
759650
769550
774350
779250
784100
3824800
3852350
3879850
3907400
3962400
3989950
4017400
4045000
4072450
1722500
1749950
1777500
1805000
946650
1001650
1029200
1056650
32350)
4800)
22650
50200
77650
132800
160250
187800
215250
242800
270350
297850
325400
352850
CUMULATIVE CASH FLOW,
t
WITH WITHOUT
DEDUCT DEDUCT
5506000
11016850
16532650
22053300
33109050
38644350
44184450
49729450
55279350
61239250
64226450
67218600
70215600
72189000
74167400
76150600
78138650
80131500
80847400
B156B200
82293750
83024300
83759650
85245000
85995000
86749900
87509550
88274200
89043750
89818100
90597350
91381450
3824800
7677150
11557000
1 5464400
23361650
27351600
31369000
35414000
39486450
42903900
44653850
46431350
48236350
49183000
50157200
51158850
5218B050
53244700
53212350
53207550
53230200
53280400
53358050
53596050
53756300
53944100
54159350
54402150
54672500
54970350
55295750
5564B600
ANNUAL RETURN ON
INITIAL INVESTMENT,
X
WITH WITHOUT
DEDUCT OEOUCT
10.52
10.54
10.56
10.57
10.61
10.63
10.64
10.66
10.68
10.52
10.54
10.56
10.58
6.96
6.98
7.00
7.02
7.03
2.53
2.54
2.56
2.58
2.59
2.63
2.65
2.66
2.68
2.70
2.72
2.73
2.75
2.77
4.59
4.69
4.78
4.88
5.08
5.17
5.27
5.37
5.46
6.09
6.18
6.27
6.37
3.34
3.44
3.53
3.63
3.73
o.os
0.18
0.27
0.37
0.47
0.57
0.66
0.76
6.86 '~
0.95
1.05
1.15
1.25
135000 11337000 120734800
326280600 397746300
to
-------
TableB-133
PROCESS A, COOPERATIVE ECONOMICS, 1000 MH.i EXISTING UNIT, 3.5* S IN COA
FIXED INVESTMENT = t 26660000
TOTAL INITIAL INVESTMENT - f 29873000
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = 17.5*
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT - B.3J
YEARS REQUIRED FOR PAYOUT WITH DEDUCT:
YEARS REQUIRED FOR PAYOUT WITHOUT DEDUCT:
4.8
6.9
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
7
s
9
10
12
13
14
15
16
17
18
19
20
21
22
23
24
25
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KH-HR/ TONS/YEAR
KW FERTILIZER
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
607600
607600
607600
607600
607600
607600
607600
433800
433800
433800
433800
303700
303700
303700
303700
303700
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO. ,*/YEAR
6390300
6326000
6261800
6197500
6133200
6069000
6004500
4846900
4782700
471B400
4654100
3797800
3733600
3669300
3605000
3540600
2379300
2315000
2250700
2186500
2122200
2057900
1993600
1929400
1665100
1800600
1736400
1672100
1607800
1543500
1479300
ALTERNATE
WET-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
t/YEAR
3587300
3533800
3480600
3427ZDO
3373900
3319900
3267200
2803800
2750300
2696900
2643600
2294300
2241100
2187600
2134400
20B0900
1632000
1578600
1525300
1471900
1365200
1311900
1258500
1205000
1151800
1098300
1045100
991600
938400
NET NH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LI ME-
STC1NE PRO-
CESS COST,
•/YEAR
2803000
2792.200
2781200
2770300
2759300
2749100
2737300
2043100
2032400
2021500
2010500
1503500
1492500
1481700
1470600
1459700
683000
672100
661200
650300
628400
617500
606600
595600
573800
562700
551900
540900
NET FERTILIZER MFC
COST USING (NH4I2S04
FROM POWER PLANT,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
18232600
18221800
18210800
18199900
18188900
18178700
18166900
14252600
14241900
11565000
11554000
8561700
8550700
8539900
8528800
8517900
4310200
4299300
4288400
4277500
4255600
4233800
4222800
4201000
4189900
4179100
4168100
21819900
21755600
21691400
21627100
21562800
21498600
21434100
17056400
16992200
14261900
14197600
10856000
10791800
10727500
10663200
10598800
5942200
5877900
5813700
5749400
5620800
5492300
5427809
5299300
5235000
5170700
5106500
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
24018400
24018400
24018400
24018400
24018400
24018400
24018400
17508200
17508200
17508200
17508200
12488100
12488100
12488100
12488100
w»m
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
GROSS INCOME,
$/YEAR
WITH WITHOUT
DEDUCT DEDUCT
5785800
5807600
5818500
5829500
5839700
5851500
3255600
3266300
5943200
5954200
3926400
3937400
3948200
3959300
3970200
1212500
1223400
1234300
.;?««oo
1267100
1278000
1288900
1299900
1321700
1332800
1343600
1354600
2198500
2327000
2391300
2455600
2519800
2584300
451800
516000
3246300
3310600
1632100
1696300
1760600
1824900
1889300
419500)
3552001
291000)
2267001
98100)
33900k
30400
94900
223400
287700
352000
416200
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
2892900
2903800
2909250
2914750
2919850
2925750
2971600
2977100
1963200
1968700
1974100
1979650
1985100
606250
611700
617150
622600
633550
639000
644450
649950
660850
666400
671800
677300
1099250
1131400
1163500
1195650
1227800
1259900
1292150
1623150
1655300
816050
848150
880300
912450
944650
209750)
177600)
145500)
113350)
49050)
16950)
15200
47450
1 1 1700
143850
176000
208100
CASH FLOW,
*/YEAR
WITH WITHOUT
DEDUCT DEDUCT
5558900
5564300
5569800
5575250
5580750
5585850
5591750
2971600
2977100
1963200
1968700
1974100
1979650
1985100
611700
617150
622600
633550
639000
644450
649950
660850
666400
671800
677300
3765250
3797400
3829500
3893800
3925900
3958150
2891900
2924000
1623150
816050
848150
880300
912450
177600)
145500)
113350)
49050)
16950)
15200
47450
111700
143850
176000
208100
CUMULATIVE CASH FLOW,
$
WITH WITHOUT
DEDUCT DEDUCT
5558900
11123200
16693000
27849000
33434850
39026600
47608650
51907800
54879400
59819700
61788400
63762500
65742150
69545950
70163100
70785700
72047350
72686350
73330800
73980750
75297050
75963450
76635250
77312550
3765250
7562650
11392150
19147600
23073500
2T031650
32783300
35707300
37330450
39801800
40649950
41530250
42442700
43145450
42758100
42612600
42499250
42418050
42369000
42352050
42367250
42414700
4249*250
42605950
42749800
42925800
43133900
ANNUAL RETURN ON
INITIAL INVESTMENT,
I
WITH WITHOUT
DEDUCT DEDUCT
9.68
9.70
9.72
9.76
9.77
9.79
5.45
5.47
9.95
6.57
6.59
6.61
6.63
2.61
2.03
2.05
2.07
2.08
2.10
2.12
2.14
2.16
2.18
2.1?
2.21
2.23
2.25
2.27
3.68
3.79
3.89
4.00
4.11
4.22
4.33
0.76
0.86
5.43
5.54
2T73
2.84
2.95
3.05
3.16
0.05
0.16
•0777
0.37
0.48
0.59
0.70
9692200 114581300
-------
TableB-134
PROCESS 8, COOPERATIVE ECONOMICS, 200 MU., EXISTING UNIT, 3.5* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = J 8794000
TOTAL INITIAL INVESTMENT - f 9635000
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = NEC
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = NEG
NO PAYOUT KITH DEDUCT
NO PAYOUT WITHOUT DEDUCT
YEARS
AFTER
POWER
UNIT
I
2
3
ft
5
6
7
TOTAL NH3
SCRUBBING
ANNUAL OPERATING
OPERA- COST INCL
TION REGUL.ROI
KW-HR/ TONS/YEAR FOR POWER
'
ALTERNATE
WET-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
NET MH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
J/YEAR
NET FERTILIZER MFG
COST USING (NH4I2S04
FROM POWER PLANT,
«/YEAR
WITH WITHOUT
DEDUCT DEDUCT
ANNUAL RETURN ON
NET GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
FERTILIZER S/YEAR S/YEAR */YEAR 1 «
SALES
REVENUE, WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
0 DEDUCT
9 7000 97100 1422400 1087900 334500 45177OO 5605600 4386000
10 7000 97100 1402200 1067700 334500 4517700 5585400 4386000
12 5000 69500 1171900 927000 244900 3659000 4586000 3162300
13 5000 69500 1151700 906800 244900 3659000 4565800 3162300
14 5000 69500 1131400 886600 244800 3658900 4545500 3162300
15 5000 69500 1111200 866400 244800 3658900 4525300 3162300
16 3500 48600 943600 762900 180700 2992200 3755100 2225400
18 3500 48600 903000 722600 180400 2991900 3714500 2225400
19 3500 48600 882900 702400 180500 2112600 2815000 2225400
20 3500 48600 862300 6B2200 180100 21L2200 2794400 2225400
21 1500 20800 633200 553000 80200 1147300 1700300 963OOO
22 1 500 20800 613000 532800 80200 1 147300 1680100 963000
23 1500 20800 592800 512600 80200 1147300 1659900 963000
24 1500 20800 572500 492400 80100 1147200 1639600 963000
25 1500 20800 552300 472300 80000 1147100 1619400 96300O
26 1500 20800 531900 452100 79800 1146900 1599000 963000
27 1500 20800 511700 431900 79800 1146900 1578800 963000
28 1500 20800 491300 411700 79600 1146700 1558400 963000
29 1500 20800 471200 391600 79600 1146700 1538300 963000
30 1500 20800 450800 371400 79400 1146500 1517900 963000
33 1500 20800 39OIOO 310900 79200 1146300 1457200 963000
3$ 1500 20800 369800 290700 79100 1067100 1357800 963000
35 1500 20800 349500 270500 79000 1067100 1337600 963000
1317001
497000)
496700*
496700)
496600)
496600)
766800)
766500)
112800
113200
l84300i
1843001
184300)
184200)
184100)
183900)
183700)
183700)
183500)
183300)
104100)
1041001
1199400) ( 65850)
14^41001 1 2485001
14237001 1 248350)
14035001 1 248350)
1383200) < 248300)
1363000) 1 248300)
1529700) 1 383400)
1489100) 1 383250)
5896 001 56400
5690001 56600
737300) ( 92150)
717100) 1 92150)
696900) ( 92150)
676600) f 92100)
656400) ( 920501
636000) ( 919501
6158001 ( 91950)
595400) I 918501
575300) ( 91850)
554900) 1 91750)
494200) < 91650)
394800) f 52050)
374600) 1 520501
609800)
599700)
722050)
711850)
701750)
691600)
681500)
764850)
744550)
294800)
284500)
358550)
348450)
338300)
328200)
307900)
297700)
287650)
277456)
247100)
197400)
187300)
813550
813550
630900
631050
631050
631100
631100
496000
496150
56400
56600
92150)
92150)
92100)
92050)
91950)
91850)
91850)
91750)
91650)
520501
52050J
269600 813550
279700 1627100
157350 2258000
167550 2889050
177650 3520100
187800 4151200
197900 4782300
114550 5278300
134850 6270500
294800) 6326900
2B4500) 6383500
368650) 6291350
358550) 6199200
348450) 6107050
338300) 6014950
32B200) 5922900
3180001 5830950
307900) 5739000
297700) 5647150
287650) 5555300
277450) 5463550
2473501 5371800
2471001 5188500
197400) 5136450
1B7300I 5084400
269600
549300
706650
874200
1051850
1239650
1437550
1552100
1811600
1516800 0.59
1232300 O.S9
863650
505100
156650
181650)
509850)
8278501
1135750)
1433450)
1721100)
1998550)
22£59Bol "
2770150)
2967550)
3154850)
50B4400 < 3154850)
to
5!
-------
Table B-135
PROCESS B, COOPERATIVE ECONOMICS, 500 HH., NEW UNIT, 2.0« S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT > t 10194000
TOTAL INITIAL INVESTMENT = t 11310400
OVERALL INTEREST RATE OF RETURN MITH DEDUCT =" 4.4*
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = NEC
YEARS REQUIRED FOR PAVOUT KITH DEDUCT:
NO PAYOUT WITHOUT DEDUCT
YEARS ANNUAL
AFTER OPERA-
POWER TION
UNIT KW-HR/
START KW
I 7000
2 7000
3 7000
4 7000
5 7000
7 7000
8 7000
LO 7000
U 5000
13 5000
14 5000
15 5000
16 3500
8 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
31 15*66
32 1500
33 1500
34 1500
35 1500
TONS /YEAR
FERTILIZER
131500
131500
131500
131500
131500
131500
131500
131500
93900
9 39 00
93900
93900
65800
65800
65800
65800
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
28200
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO..S/YEAR
2504300
2472300
2441100
240B200
2376200
2312100
2280LOO
2216100
1893100
1829000
1797000
1765000
1505700
1441600
1409600
1377500
1021900
989900
957900
925800
893800
861700
829700
797700
765600
733600
669500
637500
605500
573500
ALTERNATE
WET-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
*/YEAR
1800000
1772800
1749100
1718800
1690600
1635900
1608700
1553800
1379800
1352300
1325100
1297900
1270400
1114100
1059200
1032000
1004500
827100
799800
772400
745100
717700
690400
663000
635500
608300
580800
553*60
526100
498900
471400
444200
NET NH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
t/YEAR
704300
699500
692000
689400
685600
676200
671400
662300
513300
503900
499100
§94600
91600
382400
377600
373000
194800
190100
185500
180700
176100
171300
166700
162200
157300
152BOO
148000
143400
138600
134100
129300
NET FERTILIZER MFC
COST USING (NH4I2S04
FROM POWER PLANT,
I/YEAR
WITH WITHOUT
DEDUCT DEDUCT
5682600 7482600
5677800 7450600
5670300 7419400
5667700 7386500
5663900 7354500
5654500 7290400
5649700 7258400
5640600 7194400
3532700 4912500
352S200 4880500
3518500 4B16400
3514000 4784400
2669600 3728800
2664800 3696800
2660200 3664700
J440100 2267200
1435400 2235200
1430800 2203200
1426000 2171100
1421400 2139100
1412000 2075000
1407500 2043000
1402600 2010900
1398100 1978900
1388700 1914800
I 38 3 900 1882800
1379400 1850800
1374600 1818800
NET
FERTILIZER
SALES
REVENUE,
t/YEAft
5896500
5896500
5696500
5896500
5896500
5896500
5896500
5896500
4246200
4246200
4246200
4246200
2997200
2997200
2997200
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
GROSS INCOME.
$/YEAR
WITH WITHOUT
DEDUCT DEDUCT
213900 15861CO)
218700 15541001
226200 1522900)
228800 1490000)
232600 1458000)
242000 1393900)
246800 1361900)
255900 1297900)
713500 666300)
722900 602200)
727700 5702001
732200 538200)
318400 795700)
327600 731600)
332400 699600)
337000 667500)
138700) 9658061
134000) 933800)
129400) 901800)
124600) 869700)
120000) 837700)
110600) 773600)
106100) 741600)
101200) 709500)
96700) 677500)
87300) 613400)
82500) 581400)
78000) 549400)
732001 517400)
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
106950 793050)
109350 777050)
113100 761450)
114400 7450001
116300 729000)
121000 696950)
123400 680950)
127950 648950)
356750 333150)
361450 3011001
363850 285100)
366100 2691001
163800 365800)
166200 349800)
168500 333750)
1 693501 482900)
( 67000) 466900)
I 64700) 450900)
1 623001 434850)
( 60000) 41B850)
< 55300) 386800)
( 53050) 370800)
( 50600) 354750)
( 48350) 338750)
1 43650) 306700)
* 41250) 290700)
( 39000) 274700)
( 36600) 258700)
CASH FLOW,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
1126350 226350
1128750 242350
1132500 257950
1133800 274400
1135700 290400
1142800 338450
1147350 370450
356750 ( 3331501
359000 317150)
361450 301100)
363850 285100)
366100 269100)
163800 365800)
166200 349800)
168500 333750)
67000) 466900)
64700) 450900)
62300) 434850)
60000) 418850)
55300) 3868001
53050) 370800)
50600) 354750)
48350) 338750)
43650) 306700)
41250) 290700)
39000) 274700)
36600) 2587001
CUMULATIVE CASH FLOW,
$
WITH WITHOUT
DEDUCT DEDUCT
1126350 226350
2255100 468700
3387600 726650
4521400 1001050
7935600 1920300
9078400 2258750
11370800 2983650
11727550 2650500
12086550 2333350
12448000 2032250
12811850 1747150
13177950 1478050
13662500 332600
13828700 17200)
13997200 350950)
L3927850 833850)
13860850 1300750)
13796150 1751650)
13733850 2186500)
13673850 2605350)
13560950 3394950
13507900 3765750
13457300 4120500
13408950 4459250
13319350 5088700
13278100 5379400
13239100 5654100
13202500 5912800)
ANNUAL RETURN ON
INITIAL INVESTMENT,
Z
WITH WITHOUT
DEDUCT DEDUCT
0.95
0.97
1.00
1.01
1.03
1.07
1.09
1.13
3.15
3.17
3.20
3.22
3.24
1.41
1.45
1.47
1.49
-------
Table B-136
B, COOPERATIVE: F.CONOMICS, 500 MM.» NEW UNIT. 3.5? S IN COAL. 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = » 14128000
TOTAL INITIAL INVESTMENT = $ 15933500
OVERALL INTEREST RATE OF RETURN WITH OEOUCT = 11.9X
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = NEG
YEARS REQUIRED FOR PAYOUT WITH DEDUCT:
NO PAYOUT WITHOUT DEDUCT
YEARS ANNUAL
AFTER OPERA-
POWER TION
UNIT KW-HR/
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
9 7000
9 7000
10 7000
U 5000
12 000
13 000
14 000
15 000
16 500
17 500
18 500
19 500
?0 500
21 500
22 1500
23 1500
24 1500
25 1*>OD
26 500
27 500
28 500
20 500
30 500
31 500
32 500
33 500
34 500
35 1500
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
RE GUI. RO I
TONS/YEAR FOR POWER
230000 3003700
230000 2970600
230000 2937500
230000 2904500
230000 2871400
230000 2838300
230000 2005300
23QOOO 2772200
230000 2739100
230000 2706000
164300 2239400
164300 2206300
164300 2173200
164300 2140200
164300 2107100
115000 1754300
115000 1721200
115000 1689200
115000 1655100
115000 162POOO
49300 1141800
49300 1108800
49300 1075700
49300 1042600
49300 1009600
49300 976500
49300 943400
49300 910300
49300 877300
49300 844200
49300 811100
49300 778100
49300 745000
49300 711900
WFT-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
2150200
2119600
2089200
2058700
2028100
1997500
1967100
1936600
1906000
1875600
1640100
1610000
1579400
1549000
1518400
1311600
1281200
1250600
1220100
1199700
952200
921600
891100
860700
830100
799500
769200
738400
708100
677400
647100
616500
505900
555600
NET NH3
COST IF
DEDUCTION
TAKEN FDR
HFT-LIME-
STONE PRO-
CESS COST,
853500
851000
848300
845800
843300
840800
838200
835600
833100
830400
599300
596300
593800
591200
588700
442700
440000
437600
435000
432300
189600
187200
184600
181900
179500
177000
174200
171900
169200
166800
164000
161600
159100
156300
NET FERTILIZER MFG
COST USING (NH412SD4
FROM POWER PLANT,
J/YEAR
WITH WITHOUT
OEDUCT DEDUCT
8542500 10692700
8540000 10659600
8537300 10626500
8534800 10593500
8532300 10560400
8529800 10527300
8527200 10494300
8524600 10461200
8522100 10428100
8519400 10395000
5341700 6981800
5338700 6948700
5336200 6915600
5333600 6882600
5331100 6849500
3994200 5275400
3991800 5242400
3989200 5209300
3986500 5176200
2113300 3034900
2110700 3001800
2108000 2968700
2105600 2935700
2100300 2869500
2093000 2836400
2095300 2803400
2092900 2770300
2087700 2704200
2085200 2671100
2082400 2638000
NET
FERTILIZER
SALES
REVENUE*
10129200
101292DO
10129200
10129200
10129200
10129200
10129200
10129200
10129200
10129200
7317900
7317900
7317900
7317900
7317900
5173900
5173900
5173900
5173900
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
GROSS INCOME,
S/YEAR
WITH WITHOUT
1586700 563500)
1589200 530400)
1591900 497300)
1594400 464300}
1596900 431200)
1599400 398100)
1602000 365100]
1604600 332000)
1607100 298900)
1609800 265800)
1976200 336100
1979200 369200
1981700 402300
1984300 435300
1986800 468400
1177000 134600)
1179700 101500)
11B2100 68500)
1184700 35400)
1187400 2300)
141300 8109001
143700 777900)
146300 744800)
149000 711700)
151400 6787001
153900 645600)
156700 6125001
159000 579400)
161700 546400)
164100 513300)
169300 447200)
171800 414100)
174600 381000)
NET INCnMF AFTER TAXFS,
$/YFA«
WITH WITHOUT
DEDUCT DFOUCT
793350 281750)
794600 265200)
795950 248650)
797?OQ 232150)
798450 215600)
799700 99050)
801000 82550)
802300 66000)
803550 49450)
304900 32900)
989600 84600
990850 20lf*0
588500 673001
589850 507501
591050 34250)
592350 17700)
593700 1150)
70650 405450 )
71350 3889501
73150 372400)
74500 355850)
75700 3393501
76950 3228001
78350 3062501
79500 289700)
80850 2732001
8?050 256650)
83450 240100)
84650 2236001
85900 207050)
87300 1905001
CASH FLOHt
t/YEAR
WITH WITHOUT
DEDUCT DEOUC
2206150 1131050
2207400 1147600
2208750 1164150
2210000 1180650
2211250 1197200
2212500 1213750
2213800 1230250
2215100 1246800
2216350 1263350
88100 168050
89600 184600
90850 201150
3400 234200
9850 507501
1050 34250)
2350 177001
3700 11501
0650 405450)
1850 388950)
3150 372400)
4500 355850)
5700 3393501
6950 3228001
8350 306250)
9500 2897001
80850 2732001
82050 2566501
83450 240100)
84650 223600)
85900 207050)
87300 190500)
CUMULATIVE
$
WITH
U
2206150
4413550
6622300
8832300
11043550
13256050
15469850
17684950
19901300
23107100
24096700
25O87550
27073100
28251450
28842500
29434850
30028550
30099200
30171050
30244200
30318700
30394400
30471350
30549700
30629200
30710050
30792100
30875550
30960200
31046100
31133400
CASH FLOWt
WITHOUT
1131050
2278650
3442800
4623450
5820650
7034400
8264650
9511450
10774800
12054700
12222750
12407350
12608500
12826150
13060350
12942300
12908050
12890350
12889200
12483750
12094800
11722400
11366550
11027200
10704406
10398150
10108450
9835250
9578600
9338S66
9114900
8907850
8717350
ANNUAL RETURN ON
INITIAL INVESTMENT*
*
WITH WITHOUT
4.98
4.99
5.00
5.00
5.01
5.02
5.03
5.04
5.04
5.05
6.20 1.05
6.21 1.16
6.22 1.26
6.23 1.37
6.23 1.47
3.70
3.71
3.72
3.73
0.44
0.45
0.46
0.4?
0.48
' 0.4ft
0.49
0.50
0.51
0.51
""T}75"2
0.53
0.54
0.55
to
00
-------
to
00
N)
Table B-137
PROCESS B, COOPERATIVE ECONOMICS, 500 MH., EXISTIdtf UNIT, 3.5« S IN COAL, 26-19-0 FERTILIZER PRODUCTION
fIXED INVESTMENT
TOTAt fNITIAL INVESTMENT
OVERALL INTEREST RATE OP RETURN WITH DEDUCT
14331000
16183700
10.IX
YEARS REQUIRED FOR PAYOUT WITH DEDUCT:
NO PAYOUT WITHOUT DEDUCT
YEARS
AFTER
POWER
UNIT
START
1
2
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO., t/YEAR
NET NH3
ALTERNATE SCRUBBING
WET-LIME- COST IF
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
t/YEAR
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
t/YEAR
NEG
NET FERTILIZER MFC
COST USING (NHM2S04
FROM POWER PLANT, NET
•/YEAR FERTILIZER
SALES
WITH WITHOUT REVENUE,
DEDUCT DEDUCT t/YEAR
ANNUAL RETURN ON
GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
t/VEAR t/VEAR »/YEAR t t
WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
10 7000
11 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
31 1500
32 1500
33 1500
34 1500
35 1500
235800 3140400
235800 3102300
235800 3064300
235800 3026200
235800 2988100
235800 2950100
235800 2912000
168200 2443900
168200 2367800
168200 23297QO
168200 2291700
117900 1921100
117900 1883000
117900 1845000
117900 1806900
117900 1768900
50500 1265700
50500 1227600
50500 1189600
50500 1151500
50500 1103400
50500 1075400
50500 1037300
50500 999200
50500 961200
50500 923700
50500 885100
50500 847000
50500 808900
50500 770900
50500 732800
2261500
2226100
2191000
2155600
2120500
2085100
2050000
1804000
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1061200
1025900
990700
955400
920200
884900
849700
814300
779200
743800
708700
673300
638200
602800
567700
878900
876200
873300
870600
867600
865000
862000
639900
637000
634300
631400
628700
473500
470700
467900
465100
462300
204500
201700
198900
196100
183200
190500
187600
184900
182000
179900
176400
173700
170700
168100
165100
8828500
8825800
8822900
8820200
8817200
8814600
8811600
6988900
6983300
5547300
4184900
41821QO
4179300
4176500
4173700
2144400
2141600
2138800
2136000
2123100
2130400
2127500
2124800
2121900
2119800
2116300
2113600
2110600
2108000
2105000
11090000
11051900
11013900
10975800
10937700
10899700
10861600
8792900
8716800
7245600
5632500
5594400
5556400
5518300
5480300
3205600
3167500
3129500
3091400
3043300
3015300
2977200
2939100
2901 LOO
2863600
2825000
2786900
2748800
2710800
2672700
10375200
10375200
10375200
10375200
10375200
10375200
10375200
7486600
7486600
7486600
5300800
5300800
5300800
5300800
5300800
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
1546700 714800)
1549400 6767001
1552300 6387001
1555000 600600)
1558000 562500)
1560600 524500)
1563600 486400)
497700 13063001
500600 1268300)
503300 12302001
1939300 241000
1942000 279000
1118700 293600)
1121500 2556001
1124300 217500)
1127100 179500)
166000 895200)
168800 857100)
171600 8191001
174400 781000)
187300 7329.00)
180000 704900)
182900 666800)
185600 628700)
188500 590700)
190600 5532001
194100 514600)
196800 476500)
199800 438400)
202400 400400)
205400 362300)
773350 357400)
774700 338350)
776150 319350)
777500 300300)
779000 281250)
780300 262250)
781800 243200)
248850 653150)
250300 634150)
251650 615100)
969650 120500
971000 139500
559350 146800)
560750 127800)
562150 108750)
561550 89750)
83000 447600)
84400 428550)
85800 409550J
87200 3905001
91450 333400]
92800 314350)
94250 295350)
95300 276600)
97056 5573001
98400 238250)
99900 219200)
101200 Z00200)
102700 181150)
2206450 1075700
2207800 1094750
2209250 1113750
2210600 1132800
2212100 1151850
2213400 1170850
2214900 1189900
1681950 779950
1683400 798950
1684750 818000
969650 120500
971000 139500
557950 165850)
559350 146800)
560750 127800)
562150 108750)
563550 89750)
83000 44760O)
84400 4285501
85800 409550)
87200 390500)
90000 3524501
91450 333400)
92800 314350)
94250 295350)
"57050 25740&*
98400 238250)
99900 219200)
101200 200200)
102700 181150)
2206450 1075700
4414250 2170450
6623500 3284200
8814100 4417000
11046200 5568850
13259600 6739700
15474500 7929600
17156450 8709550
18839850 9508500
20524600 10326500
21494250 10447000
22465250 10586500
23023200 10420650
24143300 10146050
24705450 10037300
25269000 9947550
25352000 9499950
25436400 9071400
25522200 8661850
25609400 8271350
25703050 7904900
25793056 7552450
25884500 7219050
25977300 6904700
26071550 6609350
•2676-3*00 6lTf54?o—
26362300 5837200
26462200 5618000
26563400 5417800
26666100 5236650
4.78
4.79
4.80
4.80
4.81
4.82
4.83
1.54
1.55
1.55
5.99 0.74
6.00 0,86
3.45
3.46
3.46
3.47
3.48
0.51
0.52
0.53
0.54
0.58
0.56
0.57
0.57
0.58
0.59
0.60
0.61
0.62
0.63
0.63
146549200 189408100
24670200 t IBI88700)
12335100 t 9094350)
-------
Table B-138
PROCESS Bt COOPERATIVE ECONOMICS* 500 MW. » NEW UNIT* 5.0? S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = t 17609000
TOTAL INITIAL INVESTMENT * t 20098000
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = 17.4t
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = 7.9»
YEARS REQUIRED FOR PATOUT KITH DEDUCT:
YEARS REQUIRED FDR PAYOUT WITHOUT DEDUCT:
5.0
7.6
YEARS
AFTER
POHER
UNIT
START
1
2
3
4
9
6
7
8
9
10
11
12
13
14
15
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
Kit FERTILIZER
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
328600
328600
328600
328600
§28600
28600
328600
328600
328600
328600
234700
234700
234700
234700
234700
164300
164300
164300
164300
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
70400
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POHER
CO. ,«/YEAR
3244300
3210400
3176500
3142600
3108700
3074800
3040900
3007000
2973100
2939200
2429300
2395400
2361500
2327600
2293700
1859200
1825300
1791400
1757500
1213300
1179400
1145500
1111600
1077700
1043800
1009900
976000
942100
908200
874300
840400
806500
772600
738700
ALTERNATE
WET-LIME-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
t/YEAR
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1803000
1769500
1478400
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
91030O
876800
843100
809600
776200
742500
7D8800
675300
641 BOO
608100
NET NH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
S/YEAR
737800
737400
737200
736800
736600
736200
736000
735500
735100
734900
525400
525200
524800
524600
524200
380800
380400
380100
379700
135100
134700
133600
134100
133700
133500
133100
132900
132500
132000
131800
131600
131200
130800
130600
NET FERTILIZER MFG
COST USING INH4I2S04
FROM POWER PLANT,
*/YEAR
WITH WITHOUT
DEDUCT DEDUCT
10746900
10746500
10746300
10745700
10745300
10745100
10744200
10744000
6725800
6725600
6725200
6725000
6724600
5013600
5013200
5012900
5012500
2570300
2569900
2568800
2569300
2568900
2568300
2568100
2567700
2567200
2567000
2566800
2566400
2566000
2565800
13253400
13219500
13185600
13117800
13083900
13050000
12948300
8629700
8595800
8528000
8494100
6492000
6458100
6424200
6390300
3648500
3614600
3580700
3546800
3512900
3445100
3411200
3377300
3343400
3309500
3275600
3241700
3207800
3173900
NET
FERTILIZER
SALES
REVENUE,
i/YCAR
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
10329100
10329100
10329100
7317900
7317900
7317900
7317900
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3201800
GROSS INCOME,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
3517600
3518000
3518200
3518600
3518800
3519200
3519400
3519900
3520500
3603300
3603500
3604500
2304300
2304700
2305000
2305400
631500
631900
633000
632500
632900
633500
633700
634100
634600
634800
635000
635400 (
635800 (
636000
1011100
1045000
1078900
1112800
1146700
1180660
1214500
1248400
1316200
1699400
1733300
1835000
825900
859800
893700
927600
446700)
412800)
378900)
345000)
311100)
243300)
209400}
175500)
141600)
107700)
73800)
39900)
6000)
27900
NET INCOME AFTER TAXES,
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
1758800
1759000
1759100
1759300
1759400
1759600
1759700
1759950
1760150
1760250
1801650
1801750
1801950
1802250
1152150
1152350
1152500
1152700
315750 (
315950
316500
316250
316450
316750
316850
317050
317300
317400
317500
317700
317900
318000
505550
522500
539450
556400
573350
590300
607250
624200
641150
658100
849700
866650
883600
900550
917500
412950
429900
446850
463800
223350)
206400)
189450)
172500)
155550)
121650)
104700)
87750)
70800)
53850)
36900)
19950)
30001
13950
CASH FLOW,
»/YEAR
WITH WITHOUT
DEDUCT DEDUCT
3539700
3539900
3540000
3540200
3540300
3540500
3540600
3540850
3541050
3541150
1801650
1801750
1801950
1802050
1802250
1152150
1152350
1152500
1152700
315750
315950
316500
316250
316450
316750
316850
317050
317300
3 17400
317500
317700
317900
318000
2286450
2303400
2320350
2337300
2354250
2371200
2388150
2405100
2422050
2439000
849700
866650
883600
900550
917500
412950
429900
446850
463800
223350)
206400)
189450)
172500)
155550)
121650)
104700)
877501
70800)
53850)
36900)
19950)
3000)
13950
CUMULATIVE CASH FLOW,
t
WITH WITHOUT
DEDUCT OEOUCT
3539700
7079600
10619600
14159800
17700100
21240600
24781200
28322050
31863100
35404250
37205900
39007650
40809600
42611650
44413900
46718100
47870450
49022950
50175650
50491400
50807350
51123850
51440100
51756550
52389850
52706700
53023750
53341050
53658450
53975950
54293650
54611550
54929550
2286450
4589850
6910200
9247500
11601750
13972950
16361100
18766200
21188250
23627250
24476950
25343600
26227200
27127750
28045250
28854200
29284100
29730950
30194750
29971400
29765000
29575550
29403050
29247500
28987250
28882550
28794800
28724000
28670150
28633250
28613300
28610300
28624250
ANNUAL RETURN ON
INITIAL INVESTMENT,
S
WITH WITHOUT
DEDUCT DEDUCT
8.75
8.75
8.75
8.75
8.75
8.76
8.76
8.76
8.76
8.76
8.96
8.96
8.97
8.97
8.97
5.73
5.73
5.73
5.74
1.57
1.57
1.57
1.57
1.57
1.58
1.58
1.58
1.58
1.58
1.58
1.58
1.58
1.58
2.52
2.60
2.68
2.77
2.85
2.94
3.02
3.11
3.19
3.27
4.23
4.31
4.40
4.48
4.57
2.05
2.14
2.22
2.31
0.07
8S
-------
Table B-139
PROCESS B, COOPERATIVE ECONOMICS, 1000 MW., NEW UNIT, 3.5* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT - $ 22435000
TOTAL INITIAL INVESTMENT - t 25533400
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = 18.7*
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = 9.0*
YEARS REQUIRED FOR PAYOUT WITH DEDUCT!
YEARS REQUIRED FOR PAYOUT WITHOUT DEDUCT:
4.8
7.3
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 7OOO
11 5000
12 5000
13 5000
14 5000
15 5000
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
31 1500
32 1500
33 1500
34 1500
35 1500
TONS/YEAR
FERTILIZER
4440CO
444000
444000
444000
444000
444000
444000
444000
444000
318000
318000
318000
318000
318000
222000
222000
222000
222000
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
95200
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO., I/YEAR
4691300
4640300
4589400
4538400
4487500
4436500
4385600
4334600
4283600
3514300
3463400
3412400
3361400
3310500
2694100
2643100
2592100
2541200
1773400
1722500
1671500
1620500
1569600
1518600
1467700
1416700
1365700
1314800
1263800
1212900
1161900
1110900
1060000
ALTERNATE
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST,
i/YEAR
3362400
3317000
3271900
3226500
3181200
313580O
3090700
3045400
3000000
2565100
2519800
2474500
2429300
2384000
2053500
2008400
1963100
1917700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1179500
1134200
1088800
1043700
998400
953000
907700
862500
NET NH3
SCRUBBING
COST IF
DEDUCTION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
S/YEAR
1328900
1323300
1317500
1311900
1306300
1300700
1294900
1289200
1283600
949200
943600
937900
932100
926500
691500
685700
680000
674400
668800
276900
271300
265700
259800
254200
248600
243000
237200
231500
226000
220100
214500
208900
/203200
197500
NET FERTILIZER MFC
COST USING (NH4)2S04
FROM POWER PLANT,
ANNUAL RETURN ON
NET GROSS INCOME, NET INCOME AFTER TAXES, CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
SALES
WITH WITHOUT REVENUE, WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT WITH WITHOUT
OEDUCT DEDUCT I/YEAR DEDUCT DEDUCT DEDUCT DEDUCT OEDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT
14099700 17462100
14094100 17411100
14088300 17360200
14082700 17309200
14077100 17258300
14071500 17207300
14065700 7156400
14060000 7105400
14054400 7054400
8862200 1427300
8856600 11376400
8850900 11325400
8845100 11274400
8839500 11223500
6587400 8640900
6581600 8590000
6575900 8539000
6570300 8488000
6564700 8437100
3349400 4800600
3337900 4698600
3332300 4647700
3326700 4596700
3321100 4545800
3315300 4494800
3309600 4443800
3304100 4392900
3298200 4341900
3292600 4291000
3287000 4240000
3281300 4189000
3275600 4138100
8994300 4894600 1532200 2447300 766100 4690800 3009600 4690800 3009600 9.58 3.00
8994300 900200 1583200 2450100 791600 4693600 3035100 9384400 6044700 9.60 3.10
8994300 906000 1634100 2453000 817050 4696500 3060550 14080900 9105250 9.61 3.20
8994300 917200 1736000 2458600 868000 4702100 3111500 23482300 15302800 9.63 3.40
8994300 928600 1837900 2464300 918950 4707800 3162450 32895000 21602250 9.65 3.60
3829800 973200 2453400 2486600 1226700 2486600 1226700 52005850 33670500 9.74 4.80
3829800 978900 2504400 2489450 1252200 2489450 1252200 54495300 34922700 9.75 4.90
3829800 984700 2555400 2492350 1277700 2492350 1277700 56987650 36200400 9.76 5.00
3829800 990300 2606300 2495150 1303150 2495150 1303150 59482800 37503550 9.77 5.10
9792400 205000 1151500 1602500 575750 1602500 575750 61085300 38079300 6.28 2.25
9792400 210800 1202400 1605400 601200 1605400 601200 62690700 38680500 6.29 2.35
9792400 3216500 1253400 1608250 626700 1608250 626700 64298950 39307200 6.30 2.45
9792400 3222100 1304400 1611050 652200 1611050 652200 65910000 39959400 6.31 2.55
9792400 3227700 1355300 1613850 677650 1613850 677650 67523850 40637050 6.32 2.65
4304900 955500 495700) 477750 2478501 477750 < 247850) 68476550 40115900 1.87
43D4900 961100 44470OI 480550 222350) 480550 I 222350) 68957100 39893550 1.88
4304900 967000 393700) 483500 196850) 483500 ( 196850) 69440600 39696700 1.89
4304900 972600 3428001 486300 1714001 486300 ( 171400) 69926900 39525300 1.90
4304900 978200 2918001 489100 145900) 489100 1 145900) 70416000 39379400 1.92
4304900 983800 240900) 491900 120450) 491900 I 1204501 70907900 39258950 1.93
4304900 989600 189900) 494800 94950) 494800 ( 94950) 71402700 39164000 1.94
4304900 995300 138900) 497650 69450) 497650 ( 69450) 71900350 39094550 1.95
4304900 1000800 1 88000) 500400 44000) 500400 1 44000) 72400750 39050550 1.96
4304900 1006700 ( 37000) 503350 18500) 50335* 1 1850(5) 729b4lo6 390SJ050 1.97 " —
4304900 1012300 13900 506150 6950 506150 6950 73410250 39039000 1.98 0.03
4304900 1017900 64900 508950 32450 508950 32450 73919200 39071450 1.99 O.li
4304900 1023600 115900 511800 57950 511800 57950 74431000 39129400 2.00 0.23
4304900 1029300 166800 514650 83400 514650 83400 74945650 39212800 2.02 0.33
267606200 339071900
-------
Table B-140
PROCESS B, COOPERATIVE ECONOMICS, 1000 «W., EXISTING UNIT, 3.5* S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = *
TOTAL INITIAL INVESTMENT = $
OVERALL INTEREST RATE OF RETURN WITH DEDUCT =
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT =
NET NH3
ALTERNATE SCRUBBING
TOTAL NH3 WET-LIME- COST IF
SCRUBBING STONE PRO- DEDUCTION
YEARS ANNUAL OPERATING CESS AIR TAKEN FOR
A-FTER OPERA- COST INCL POLLUTION WET-LI HE-
POWER TTON REGUL.ROI CONTROL STONE PRO-
UNIT KH-HR/ TONS/YEAR FOR POWER COST, CESS COST,
START KW FERTIL IZER CO. »$/YEAR t/YEAR $/YEAR
I
2
3
4 7000 460000
5 7000 460000
6 7000 460000
7 7000 460000
9 7000 460000
10 7000 460000
11 5000 328600
12 5000 328600
13 5000 328600
14 5000 328600
15 5000 328600
16 3500 230000
17 3500 230000
18 3500 230000
19 3500 230000
20 3500 230000
21 1500 98500
22 1500 98500
23 1500 98500
24 1500 98500
25 1500 98500
26 1500 98500
27 1500 98500
28 1500 98500
29 1500 98500
30 1500 98500
31 1500 98500
32 1500 98500
33 1500 98500
34 1500 98500
35 1500 98500
5031100 3587300 1443 BOO
4971000 3533800 1437200
4848500 3427200 1421300
4730600 3319900 1410700
4670500 3267200 1403300
3907400 2857000 1050400
3847200 2803800 1043400
3787100 2750300 1036800
3727000 2696900 1030100
3064200 2294300 769900
3004100 2241100 763000
2944000 2187600 756400
2883900 2134400 749500
2823700 2080900 742800
2007700 1685300 322400
1947600 1632000 315600
1887500 1578600 308900
1827400 1525300 302100
1767300 1471900 295400
ITBTZBtf 1418600 288600
1647100 1365200 281900
1587000 1311900 275100
1526800 1258500 268300
1466700 1205000 261700
1406600 1151800 254800
1346500 1098300 248200
1286400 1045100 241300
1226200 991600 234600
1166200 938400 227800
23749000
26962000
15. 6*
3.3?
COST USING
FROM POWER
VYEAR
WITH
DEDUCT
15168600
15162000
15146100
15141600
15135500
15128100
11953400
11946400
11939800
9558200
9551400
7120500
7113600
7107000
7100100
7093400
3632100
3625300
3618600
3611800
3605100
3598300
3591600
3584800
3578000
3571400
3564500
3557900
3551000
3544300
3537500
(NH4I2SQ4
PLANT.
WITHOUT
DEDUCT
18755900
18695800
18455400
18395300
14810400
14750200
14690100
12255100
12195000
9414800
9354700
9294600
9234500
5317400
5257300
5197200
5137100
5077000
5016900
4956800
4896700
4836500
4776400
4716300
4656200
4596100
4535900
4475900
NFT
FERTILIZER
SALES
REVENUE,
$/YEAR
19642000
19642000
19642000
19642000
14264500
14264500
14264500
14264500
14264500
10129200
10129200
10129200
10129200
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
GROSS INCOME,
WYEAR
WITH WITHOUT
DEDUCT DEDUCT
4473400
44BOOOO
4495900
4500400
4506500
4513900
2311100
2318100
2324700
4706300
4713100
3008700
3015600
3022200
3029100
816200
823000
829700
836500
843200
850000
856700
863500
876900
883800
890400
897300
904000
910800
886100
946200
1068700
1126500
1186600
1246700
I 4857001
( 4256001
2C09400
2069500
714400
774500
834600
894700
8691001
809000)
748900 )
688800)
6287001
5686001
508500)
4484001
328100)
2680QO}
2 079 dO )
1478001
( 8760O1
( 27600)
YEARS REQUIRED
YEARS REQUIRED FOR
NET INCOME AFTER TAXES,
S/YEAR
WITH WITHOUT
DEDUCT DEDUCT
2236700 443050
2240000 473100
2243450 503150
2247950 534350
2250200 563250
2253250 593300
2256950 623350
1159050 t 242850)
1162350 1 212800)
2353150 1004700
2356550 1034750
1504350 357200
1507800 387250
1511100 417300
1514550 447350
1517900 477450
408100 4345501
411500 404500)
414850 3744501
418250 344400)
425000 284300)
428350 254250)
431T50 224200)
438450 164050)
441900 134000)
445200 103950)
448650 73900)
452000 43800)
455400 13800)
FOR PAYOUT WITH DEDUCT:
PAYOUT WITHOUT DEDUCT:
CASH FLOW,
*/YEAR
KITH WITHOUT
DEDUCT DEDUCT
4614900 2848000
4618350 2878050
4622850 2909250
4625100 2938150
4628150 2968200
4631850 2998250
3530450 2101950
3533950 2132050
3537250 2162100
2353150 1004700
2356550 1034750
1504350 357200
1507800 387250
1511100 417300
1517900 477450
408100 434550)
411500 404500)
418250 344400)
421600 314350)
425000 284300)
428350 2542501
431750 2242001
435150 1941001
438450 1640501
441900 134000)
445200 103950)
448650 739001
452000 43800)
455400 13800)
5.1
8.6
CUMULATIVE
WITH
DEDUCT
4611600
9226500
13844850
18467700
23092800
27720950
32352800
35883250
39417200
42954450
45307600
49168500
50676300
52187400
55219850
55627950
56039450
56872550
57294150
57719150
58147500
58579250
59014400
59452850
59894750
60339950
60788600
61240600
61696000
CASH FLOW,
$
WITHOUT
DEDUCT
2817950
5665950
8544000
11453250
14391400
17359600
20357850
22459800
24591850
26T53950
27758650
29150600
29537850
29955150
30879950
30445400
30040900
29322050
29007700
' 28723400
28469150
28244950
28050850
27886800
27752800
27648850
27574950
27531150
27517350
ANNUAL RETURN ON
INITIAL INVESTMENT,
%
WITH WITHOUT
DEDUCT DEDUCT
8.30 1.64
8.31 1.75
8.32 1.87
8.34 1.98
8.35 2.09
8.36 2.20
8.37 2.31
4.29
4.30
4.31
8.73 3.73
5.58 1.32
5.59 1.44
5.60 1.55
5.62 1.66
5.63 1.77
1.51
1.53
1.54
1.55
1.56
t:ss
1.59
1.60
1.61
1.63
1.64
1.65
1.66
1.68
1.69
ts>
00
-------
Table B-141
PROCESS c, COHPERATIVE ECONOMICS, ?oo MW., EXISTING UNIT, 3.5* s INI COALI 19-14-0 FERTILIZER PRODUCTION
AFTER
POWFR
UNIT
rni
OVERALL INTEREST RATE
HVF.RAlt INTEREST RATE OF
SCftlJieirMG
OPERA- mST INCL
TION REGUL.RQI
FIXED INVESTMENT = 1
FAL INITIAL INVESTMENT = t
OF RETURN WITH DEDUCT =
RETURN WITHOUT DEDUCT =
NET NH3
ALTERNATE SCRUBBING
STQNF PRO- DEDUCTION
POLLUTION MET-LIME-
CQNTRni STONE PRO-
COST, CESS COST,
6709500
7153500
NEG
NET,
COST USING
-------
Table B-142
C, COOPERATIVE ECONOMICS, 5QO MW., NFW UNIT, Z.Ot S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = s 7541300
TOTAL INITIAL INVESTMENT = * 8091300
OVERALL INTEREST RATE OF RFTURN WITH DEDUCT = MFC
HVFUALl INTEREST RATE HF RFTURN WITHOUT DEDUCT = NFG
NO PAYOUT WITH DEDUCT
140 PAYHUT WITHOUT DFOUCT
AFTER DPFRA-
POWER TION
TOTAL NH3
SCRUBBING
COST INCL
RF.GUL.ROI
ALTERNATE
HET-LIMF-
STONF PRO-
POLLUTION
CONTROL
COST,
NET NH3
SCRUBBING
COST IF
DEDUCTION
WET-LIME-
STONE PRO-
CESS COST,
NET FFRTILI 7ER. MFG
COST USING 1NH417S04
t/YEAR
WITH WITHOUT
DEDUCT DEDUCT
FERTILIZER
SALES
REVENUE,
t/YEAR
t/YEAR */'
WITH WITHOUT WITH
DEDUCT DEDUCT DEDUCT
ANNUAL RETURN ON
fFAR WYEAR * ?
WITHOUT WITH WITHOUT Wl TH WITHOUT WITH WITHOUT
1 7000 76600 2 "577100 1800000
2 7000 76600 2544500 1772800
3 7000 76600 2511800 1749100
4 7000 76600 7479200 171 8800
5 7000 76600 2446500 1690600
6 7000 76600 7413800 1663400
8 7000 76600 2348500 1608700
10 7000 76600 2283200 1553800
11 5000 54700 1949600 1379800
1? 5000 54700 1916900 1 357300
13 5000 54700 1884300 1325100
14 5000 54700 1851600 1297900
15 5000 54700 IB 18900 1270400
16 3500 38300 1551 400 1114100
17 3500 33300 1518700 1086700
19 3500 38300 1453400 1032000
20 3500 38300 1470800 1004500
71 1500 16400 1057900 8? 71 00
22 1500 16400 1020300 799900
23 1500 1*400 98 7600 777400
24 1500 16400 954900 745100
?5 1500 1*400 q 72 300 717700
26 1500 1 6400 839600 690400
27 1500 16400 857000 6 ft 3000
23 1500 16400 824300 635500
30 1 500 16400 759000 "580800
31 1500 16400 726300 553600
32 1500 16400 693700 526100
13 1500 16400 661000 498900
34 1500 16400 628400 471400
71700 391970D 5692500 2667200 ( 12525001
62700 3878700 5627800 2667200 ( 1211500 t
60400 3976400 5595200 2667200 ( 1209200 J
55900 3371900 5562500 2667200 ( 1204700)
50400 3866400 5529800 2667200 { 1199200)
39800 3 35 5 800 5464500 P667200 ( 1188600)
29400 3845400 5399700 7667200 1 1178200)
69800 2408000 3787800 1917800 ( 490200)
64600 2402800 3755100 1917300 t 485000)
59?. 00 2397400 3722500 1917800 ( 479600)
53700 7391900 3689800 1917800 { 474100)
48500 2386700 3657100 1917800 ( 468900)
37000 1856100 2942800 1352000 ( 504100)
21400 1845500 2877500 1352000 ( 493500)
16300 1840400 2844900 1352030 t 488400)
20500 1036700 1836500 585500 ( 451200)
15200 1031400 1803800 585500 ( 445900)
09800 1026000 1771100 585500 ( 440500)
04600 1020800 1738500 5B5500 ( 435300)
99200 1015 400 1705800 585500 ( 42990Q)
94000 1010200 1673200 585500 ( 424700)
88800 1005000 1640500 585500 ( 419500)
78200 994400 1575200 585500 < 408900)
67600 983800 1509900 585500 ( 398300)
62100 978300 1477200 585500 t 392300)
57000 973200 1444600 585500 ( 387700)
51500 967700 1411900 585500 ( 382200)
3025900)
30253001
2960600)
2928000)
28953001
2862600)
2797300)
2732000)
1870000)
1837300)
1804700)
1772000)
1739300)
1623500)
1590800)
1525500)
14929001
1251000)
1218300)
1185600)
1153000)
1087700)
1055000)
989700)
924400)
891700)
859100)
826400)
612950)
626250)
605750)
604600)
599600)
594300)
589100)
245100)
2425001
7.39800)
237050)
254700)
252050)
246750)
244200)
228250)
275600}
27?950)
720250)
717650}
214950}
212350)
2097501
204450)
701700)
199150)
196400)
1911001
1
!
12950
12650
80300
64000
31 300
98A50
66000
3*000
18650
073-50
86000
11750
95400
62750
46450
41800
25500
09150
9?800
7iS500
60150
43850
27500
94850
67200
45850
tt3200
141180
127880
148390
149530
151730
154530
159830
165010
245100)
242500)
239800)
237050)
2344fO)
254700)
252050)
746750)
744200)
228750)
225600)
222950)
220250)
717650)
214950)
212350)
209750)
704450}
201700)
199150)
191850)
191 100)
7588701
58520)
26170)
09870)
93520)
77170)
44520)
118701
35000)
18650)
02350)
860001
696501
11750)
95400)
62750)
46450)
41800)
25500)
09150)
92800)
76500)
60150)
43850)
27500)
94850)
78500)
29550)
137001
141180
269060
417440
566970
718750
873280
1190190
1517600
1272500
1030000
790200
553150
318700
64000
1880501
6343001
928500)
1 156750)
1382350)
1605300)
1875550)
2043200)
2258150)
24705001
2680750)
3091750)
32934501
3689000)
3882850)
4073950)
7588701
1517340)
2243510)
2953380)
36469001
4324070)
5629460)
6869550)
7804550)
87232001
9625550)
0511551)
1381200)
2192950)
2988350)
4530200)
52766501
59184501
65439501
71531001
77459001
3322400)
8R87550)
94264001
9953900)
0959950)
I4394$0l
2346500)
'27760501
£3189250)
C 61*611001 ( lt(,15250l ( 3073{"i')OI I 40T3OSOI ( 23189250)
NJ
00
-------
Table B-143
^o'o I*-A. , MEW UNII , 3.5? s IN cnALi 19-1 4-0 PERT I LIZ PR PRODUCT ION
THTAL INITIAL 1MVFSTMFNT =
HVFRALl (NTFK'FST (* AT r OF RETURN WITH ORHJCT =
HfftLl. INTEKFST QUF (IF RF.TU«N WITHOUT OFDUCT =
11270400
NFG
NFS
NO PAYOUT WITH DEDUCT
NH PAYOUT WITHOUT DEDUCT
NET MH3
TCJTAL NH3 MFT-LIME- COST IF N
• \Q $ ANNUAL OTP AT I MG CESS AIR T1KEN FG8 F*
Fj-FB nPFRA- rnST INf.v. POLLUTION WET-l T^E-
n«£R T1QM ^CGUL.Hni CONTROL STONE PRQ-
1 7000 L 34000 3innmo ? I 502 GO 1 039 ROD
2 7000 114000 315'f*CO 21 19600 lf.35?00
3 7000 134000 3119700 20H920Q L 030 500
4 7000 1 34000 3^84500 ?Q58700 1C? 5 800
6 7000 L 34000 3 'H 42 TO 1997500 1016700
7 7000 1340^0 ;» 979 100 1967100 1012000
<> 7000 1?4000 290HHOQ 1906CQO IC02800
0 7000 134000 2371600 1875600 99SOOO
I 5000 95700 ^3^6100 1640100 756000
2 500D 95700 2360900 1610000 750900
3 5000 95700 23?5900 1579400 746400
4 5000 95700 2 290 600 1549000 741600
6 3500 6 7OOO 1B7IJSOO 131 1600 567? 00
7 3500 67000 1H4 *79Q 1 2H1POO 562500
9 3500 67000 1773400 1220100 553300
0 *500 67000 173(!?00 11R9700 546500
1 1 500 ?Q700 122 ni)0 952200 271100
2 L500 ?8700 ll
-------
Table B-144
PROCESS Ct COOPFRATIVE ECONOMICS, 500 MH., EXISTING UNIT, 3.51 S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXPO INVESTMENT = S
TOTAL INITIAL INVESTMENT = *
nVESALI. INTEREST RATE OF
AFTER
POWER
UNIT
I
3
OPERA-
TION
KW-HR/ TONS/YEAR
TOTAL NH3
SCRUBBING
COST TNCL
REGUL.ROt
FOR POWER
RETURN WITHOUT DEDUCT =
NET NH3
ALTERNATE SCRUBBING
WET-LIME-
STONE PRQ-
POLLUTION
CONTROL
COST,
CF1ST !F
DEDUCTION
WET-LIME-
STONE PRO-
CESS COST,
11060600
11965600
NEC
NET FERTIL
COST UStNG
S/YEAR
WITH
DEDUCT
ZER MEG
(NH4J2SH4
*
WITHOUT
DEDUCT
FERTILIZER
SALES
REVENUE,
t/YEAR
WYEAR t/YEAR
WITH WITHOUT WITH WITHOUT
U
NH PAYOUT WITH OEOUCT
NO PAYOUT WITHOUT DEDUCT
ANNUAL
CASH FLOW, CUMUL ATIVE CASH FLOW, INITIAL
t/YEAR t
WITH WITHOUT WITH WITHOUT WITH
DEDUCT DEDUCT DEDUC T DEDUCT DEDUCT
RETURN ON
INVESTMENT,
WITHOUT
DEDUCT
4 7000 137000 3357800 2261500 1096300 6143900 8405400 4695000
5 7000 137000 3317200 2226100 1091100 6138700 8364800 4695000
6 700b 137000 3276600 2191000 1085600 6133200 8324200 4695000
7 7000 137000 3236100 2155600 1080500 6128100 8283700 4695000
9 7000 137000 3154900 2085100 1069800 6117400 8202500 4695000
10 7000 137000 3114400 2050000 1064400 6112000 8162000 4695000
11 5000 97900 2614SOO 1804000 810800 4949900 6753900 3388300
14 5000 97900 2493200 1698300 794900 3827900 5526200 3338300
15 ->00n 97900 2452600 1663000 789600 3822600 5485600 3388300
16 3500 68500 2057400 1447600 609800 2930300 4377900 2391300
16 3500 68500 1976300 1377100 599200 2919700 4296800 7391300
19 3500 68500 1935700 1341800 593900 2914400 4256200 Z391300
?0 3500 68500 1895200 1306600 588600 2909100 4215700 2391300
H 1500" 29400 1356500 1061200 295300 1586000 2647200 1042ZOO
22 1500 29400 1315900 1025900 290000 1580700 2606600 1042200
23 1500 29400 1275400 990700 284700 1575400 2566100 1042200
24 1500 79400 1234900 955400 279500 1570200 2525600 1042200
25 1500 29400 1194300 920200 274100 1564800 2485000 1042200
26 1500 29400 1153700 884900 268800 1559500 2444400 1042200
27 1500 29400 1113200 849700 263500 1554200 240^900 1042200
28 1500 29400 1072600 914300 758300 1549000 2363300 1042200
2g 1500 29400 1032100 779200 252900 1543600 2322800 1042200
30 1500 29400 991500 743800 247700 1538400 2282200 1042200
31 1500 29400 951000 708700 242300 1 533000 2241700 1042200
33 1500 29400 869800 638200 231600 1522300 2160500 1042200
35 1500 29400 788700 567700 221000 151 1700 2079400 1042200
1448900)
1443700)
1438200
14331001
14224001
U17000)
15616001
15562001
1551000)
439600)
434300
539000
528400
523100)
517800
543800
538500)
533200)
528000)
5226001
512000)
506800)
501400)
496200)
490100)
469500)
3710400)
3669800)
3629200)
3588700)
3507500)
34670001
3365600)
33251001
3284500)
2137900)
2097300)
1986600)
1905500)
18649001
1824400)
1605000)
1564400)
15239001
1483400)
1442800)
1402200)
1361700)
1321100)
1280600)
12400001
1199500)
1118300)
1037200)
724450)
7218501
7191001
7165501
711200)
708500)
780800)
778100)
775500)
219800)
217150)
269500)
264200)
261550)
2589001
271900)
269250)
266600)
764000)
261300)
258650)
756000)
253400)
2507001
2481001
245400)
2400501
234750)
1855200)
1834900)
1814600)
794350)
753'50)
7335001
6R2BOQ1
667550)
642250)
068950)
1048650)
993300)
9577501
932450)
9127001
802500)
782200)
7619501
741700)
7214001
701100)
680850)
660550)
640300)
67.0000)
5997501
559150)
5186001
381610
384210
386960
389510
394860
397560
325260
330560
219800)
217150)
269500)
764200)
261550)
75R900)
2719^6)
269250)
266600)
264000)
261300)
258650)
256000)
253400)
250700)
248100)
745400)
240050)
234750)
749140) 391610
728840) 765820
708540) 1152780
688290) 1542290
647690) 2329410
627440) 2726970
576740) 3052230
536190) 3710750
1068950) 3490950
1048650) 3273800
993300) 3004300
952750) 2473200
932450) 2211650
802500) 1680850
782200) 1411600
761950) 1145000
741700) 831000
721400) 619700
701100) 361050
680850) 105050
660550) 148350)
640300) 399050)
620000) 647150)
599750) 8925*0)
559150) 1375400)
5H600I 18476501
7491401
1477980)
2186570)
2874810)
4190490)
4817910)
5394670)
6487350)
7556300)
8604950)
9598250)
11524050)
12456500)
141712001
14953400)
15715350)
16457050)
1717S450)
17879550)
18560400)
19220950)
19861250)
20481250)
zioeioo'51
22219600)
23277100)
00
VO
-------
NJ
s
Table B-145
PROCESS C, COOPERATIVE ECONOMICS* 500 MW.f NEW UNIT, 5.0* S IN COAL* 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT = 1 11235900
TOTAL INITIAL INVESTMENT = t 12305900
OVERALL INTEREST RATE OF RETURN WITH DEDUCT = NEG
OVERALL INTEREST RATE OF RETURN WITHOUT DEDUCT = NEC
NO PAYOUT WITH DEDUCT
NO PAYOUT WITHOUT DEDUCT
/EARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/ TONS/YEAR
KW FERTILIZER
TOTAL NH3
SCRUBBING
OPERATING
COST INCL
REGUL.ROI
FOR POWER
CO.,«/YEAR
ALTERNATE
WET-LINE-
STONE PRO-
CESS AIR
POLLUTION
CONTROL
COST.
NET NH3
SCRUBBING
COST IF
DEDUCT ION
TAKEN FOR
WET-LIME-
STONE PRO-
CESS COST,
t/YEAR
NET FERTILIZER HFG
COST USING CJH4I2S04
FROM POWER PLANT,
t/YEAR
WITH
DEDUCT
WITHOUT
DEDUCT
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
GROSS INCOME,
t/YEAR
M ITH
DEDUCT
WITHOUT
DEDUCT
NET INCOME AFTER TAXES,
t/YEAR
WITH
DEDUCT
WITHOUT
DEDUCT
CASH FLOW,
t/YEAR
WITH
DEDUCT
WITHOUT
DEDUCT
CUMULATIVE CASH FLOW,
WITH
OEOUCT
WITHOUT
DEDUCT
ANNUAL RETURN ON
INITIAL INVESTMENT,
*
WITH
DEDUCT
WITHOUT
DEDUCT
1 7000 191400 3771700 2506500 1265200 7002300 9508800 6482700
2 7000 191400 3734300 2473000 1261300 6998400 9471400 6482700
3 7000 191400 3696900 2439300 1257600 6994700 9434000 6482700
4 7000 191400 3659400 2405800 1253600 6990700 9396500 6482700
5 7000 191400 3621900 237Z100 1249800 6986900 9359000 6482700
6 7000 191400 3584500 2338600 1.245900 6983000 9321600 6482700
7 7000 191400 3547100 2304900 12*2200 6979300 9284200 6482700
9 7000 191400 3472200 2238000 1234200 6971300 9209300 6482700
10 7000 191400 3434800 2204300 1230500 696760-0 9171900 6482700
11 5000 136700 28 J 8400 1903900 914500 4439300 6343200 684700
12 5000 136700 2780900 1 8702 00 910700 4435500 6305700 684700
13 SOOO 136700 2743500 1 836700 906800 4431600 6268300 6B4700
14 5000 136700 2706000 1803000 903000 4427BOO 6230800 684700
15 5000 136700 2668600 1769500 899100 4423900 6193400 684700
16 3500 95700 2186700 1512100 674600 3349700 4861800 314100
17 3500 95700 2149200 J 478400 670800 3345900 4824300 3314100
18 3500 95700 2111 800 1444900 666900 3342000 4786900 3314100
19 3500 95700 2074300 1411300 663000 3338100 4749400 3314100
20 3500 95700 2036900 1 377800 659100 - 3334200 4712000 3314100
2T F50~0~ 41000 1380600 1078200 302400 1.759X00 2837300 1446100
22 1500 41000 1343100 J 044700 298400 1755100 2799800 1446100
23 J500 41000 1305700 1011900 293800 1750500 2762400 1446100
24 T-500 41000 '-1268200 97^500 290700 1747400 2724900 1446100
25 1500 41000 1230800 944000 28.6800 1743500 2687500 1446100
26 1500 4lOOO 11 93400 910300 283100 1739800 2650100 1446100
27 I 500 41000 1155900 876800 279100 1735800 2612600 1446100
28 1 500 41000 1113500 843100 275*00 1732100 2575200 1446100
29 1500 41000 1081000 809600 271400 1728100 2537700 1446100
30 1500 41000 1043600 776200 267400 1724100 2500300 1446100
31 1 500 41006 IC06100 742500 263600 1720300 2462800 1446100
32 1 500 41000 968700 708BOO 259900 1716600 2425400 1446100
33 1500 41000 931300 675300 256000 1712700 2386000 1446100
3* 1500 41000 893800 641800 252000 1708700 2350500 1446100
35 1 500 41000 856400 608100 248300 1705000 2313100 1446100
5196001
515700)
512000 )
508000)
5042.00*
500300 *
496600)
492600)
488600)
4B4900)
245400
249200
253100
256900
260800
35600)
318001
27900)
24000 )
20100)
313000)
3090001
304400)
301300*
297400)
293700)
289700 1
286000)
282000)
278000.
274200)
270500)
266600)
2626001
258900)
30261001
2988700)
2951300)
2913800)
28763001
2838900 >
2801500)
2764100)
2726600 )
2689200)
1658500)
1621000)
1583600)
1546100)
1508700)
15477001
15102001
1472800)
1435300)
13979001
1391200)
1353700)
1316300)
1278800)
1241400)
1204000)
1166500)
1129100*
1091600)
1054200)
1 C16700)
9793001
941900 )
904400)
867000)
259800)
257850)
256000)
2540001
252100)
?50150)
24
156500)
' 54500)
152200)
150650)
148700)
146850 )
1448501
143000)
141000)
139000)
137100)
135250)
133300)
1313001
t29450>
1513050)
1494350)
1475650 )
1456900)
1438150)
1419450)
1400750)
13820501
13633CO)
1344600)
829250 )
810500)
791600)
773050 )
754350)
773850)
755100)
736400 )
717650)
698950)
695600)
676850)
658150)
639400)
6207CO
602000 )
5832501
564550>
545800)
527KO)
508350)
489650)
470950)
45220C*
433500)
863790
B 65740
667590
869590
871490
873440
B77290
879290.
8811 40
122700
12*600
126550
128450
130400
17800)
159001
13950)
12000)
100501
156500)
154500)
152200)
1 50650)
143700)
146850)
1 448 50 >
143000)
141000)
•> 330001
137100)
135250)
333300)
131300)
129450 )
389460) 863790
37076C) 1729530
352060 2597120
333310) 3466710
314560) 4338200
295B60I 5211640
25646O 6964220
239710) 7843510
2210101 8724650
829250 8847350
610500) 8971950
791.900) 9098500
773050) 9226950
754350) 9357350
773850) 9339550
75510C) 9323650
736400) 9309700
717650) 9297700
695600) 9J 31150
676850) 8976650
65815 C) 8824450
639400) B673300
620700) 8525100
602000) 8378250
583250* 8233400
564550) 8090400
54?GOO> 7949400
527tOO) 7B10400
SC6350) 7673300
489650) 7538050
470950) 7404750
452200 7273450
433500) 7144000
389460)
760220 )
1112280*
1445590J
1760150)
2056010)
2333170)
2591630*
2831340)
3052350*
3361600) -65
4692100* .01
5483900) .03
6256950* .04
701 1300 * .06
7785150)
8540250*
9276650)
9994300*
11388850*
12065700*
12723850*
13363250*
13983950*
14585950)
15169200*
15733750)
16279550*
168066501
17315000)
17804650)
182756001
187278001
191613001
134696300 187306900 126512500
8183800* t 60794400* ( 4091900) ( 30397200)
7144000 ( 19161300)
-------
Table B-146
PROCESS C, COOPERATIVE ECONOMICS, 1000 MW.. NEW UNIT, 1.5t S IN C3AL, 19-14-0 FERTILIZER PRODUCTION
FIXFO INVESTMENT = * 153?6300
T1TAL INITIAL INVESTMENT = $ 16731300
OVERALL INTEREST RATE OE RETURN WITH DEDUCT = NEG
OVERALL INTERFST RATE Cff RETURN WITHOUT DEDUCT = NEG
NO PAYOUT WITH DEDUCT
NO PAYOUT WITHOUT DEDUCT
NET
ALTERNATE SCR
TOTAL NH3 WET-LIME- CO*
SCRUBBING STONE PRO- DEC
YEARS ANNUAL OPERATING CESS AIR TAK
AFTER fl»ERA- COST INCL POLLUTION HE
POWER TION REGUL.ROI CONTROL $TC
UNIT KW-4R/ TONS/YEAR FOR POWER COST, CF
NH3
UR6ING
UCTION COST USING (NH4J2SD4
FN FOR FROM POWER PLANT,
-LIME- «/YEAR FF*
NF PRO-
S COST, WITH WITHOUT R
1 7000 259500 5315400 3362400
2 7000 759500 5260100 33 L 7000
3 7000 259500 5204700 3271900
4 7000 25t>*>00 5149400 3226500
5 7000 2SQ500 5094100 3181200
6 7000 259500 5038800 3135800
8 7000 259500 4928100 3045400
9 7000 250500 48T?800 3000000
11 5000 185400 3975700 2565100
12 5000 185400 3920400 2519800
13 5000 185400 3865000 2474500
14 5000 185400 3809700 2429300
15 5000 185400 3754400 2384000
16 3500 129800 3094900 2053500
17 3500 129800 3039500 2008400
18 3500 129800 2984200 1963100
19 3500 129900 2928900 1917700
20 3500 129800 7873500 1872400
NET
TRUER
ALES
VENUE,
YFAR
953000 9331000 12693400 8677700
943100 9321100 12638100 8677700
932800 9310800 12582700 8677700
922900 9300900 12527400 8677700
912900 9790900 12472100 8677700
903000 9281000 12416800 8677700
897700 9?_70700 12361400 8677730
882700 9260700 12306100 8677700
872800 9? 50800 12250800 8677700
400600 5866700 8386500 6286900
390500 5856600 8331100 6286900
380400 5846500 8275800 6286900
370400 5R36500 8220500 6286900
031100 4421700 6430100 4456000
021100 4411700 6374800 456000
011200 4401800 6319500 456000
001100 4391700 6264100 456000
21 1500 55600 1975800 1496500 479300 2330300 3826800
23 1500 55600 1865200 1405800
24 1500 55600 1809900 1360700
25 1500 55600 1754500 1315400
26 1500 55600 1699200 1270000
28 1500 55600 1598500 1179500
29 1500 55600 1533200 1134200
30 1500 55600 1477900 1088800
459400 2310400 3716200
439100 2290100 3605500
949300
949300
S49300
949300
479200 2280200 3550200 949300
419200 2270200 3494900 1949300
409000 2260000 3439500 1949300
399000 2250000 3384200 1949300
3H91QO 2240100 3328900 1949300
31 1500 55600 1311900 953000 358900 2209900 3162900
34 1500 55600 1256600 907700 348900 2199900 3107600
35 1500 55600 1201200 862500 338700 2189700 3052200
949300
949300
949300
949300
GROSS INCOME.
WYE Aft
WITH WITHOUT
DEDUCT DEDUCT
653300)
6434001
6331001
623200)
613200)
603300)
5930001
583000)
573100)
5678001
410200
420200
430300
440400
450400
24000
34300
44300
54200
64300
381000)
371000)
361100)
3509001
340800)
330900)
320900)
310700)
300700)
2908001
270500)
2606001
250600)
240400)
4015700)
39604001
3905000)
3849700)
379*400)
3739100)
36837001
3628400)
35731001
3517700)
2154900)
2099600)
2044200)
1988900)
1933600)
2029500)
1974100)
1918800)
1863500)
L808100)
1877500)
18222001
1766900)
1711600)
1656200)
1600900)
15456001
14902001
1434900J
13796001
1268900)
1213600)
1158300)
1102900)
t/YEAR
WITH WITHOUT
DEDUCT DFDUCT
321700)
3165501
M160fn
306600)
301650)
296500)
2915001
286550)
281400)
205100
210100
215150
225200
12000
17150
22150
27100
32150
185500)
180550)
1754501
170400)
r 165450)
160450)
155350)
1503501
145400)
135250!
130300)
125300)
120200)
ANNUAL RETURN ON
CASH FLOW, CUMULATIVE CASH FLOW, INITIAL INVESTMENT,
S/YEAR * %
•JTTH WITHOUT WITH WITHOUT WITH WITHOUT
3EDUCT DEDUCT DEDUCT DEDUCT DEDUCT DEDUCT
1980200) 1210930
19575001 1216080
1974S50) 1221030
1897200 1226030
1869550 17.30980
1841850) 1236130
1814?00) 1241130
] 7865501 1246080
1758850 12*51230
1077450) 205100
1049ROO] 210100
1027100) 215150
9668001 225200
1014750 12000
987050) 17150
959400) 22150
931750) 27100
9040501 32150
911100) (
803450) {
8S5800) (
828100) '(
8004"JO (
772800) (
745100) (
717450 (
'jHOBnil t
634450) I
604800) (
579150) (
551450) 1
905001
85500)
805501
75450)
70400)
65450)
60450)
55350)
50350)
45410)
40 inn)
35250)
303001
25300)
20200)
447570) 2416910
4198701 3632990
392220) 4854020
364570) 6080050
336920) 7311030
281570) 9788290
253920) 11034370
2262701 12285600
1077450) 12490700
1049800) 12700800
1022100) 12915950
994450) 13136150
966800) 13361350
1014750! 13373350
987050) 13390500
9594003 13412650
9317501 13439750
904050) 13471900
938750) 13281400
883450) 12915350
855800) 12739900
828100) 12569500
800450) 12404050
772800) 12243600
7451001 12088250
717450) 11937900
689800) 1 1797500
662I5Q) 11652200
634450) 11516950
606800) 11386650
579150) 11261350
5514501 1 11411 50
475220)
922790)
1342660)
1734880)
20994501
2436370)
3027160)
3291080)
35073001
4584750) 1.23
56345501 1,26
7651100) 1,32
8617900) 1.35
96326501 0,07
106197001 0,10
11579100) 0,13
12510850) 0.16
13414900) 0,19
14353650)
16148200)
17004000)
17832100)
186325501
194053501
20150450)
208'67900)
215577001
22219S50)
22854300)
23461100)
24040250)
24591700)
to
vO
-------
Table B-147
PRClfESS C, COOPERATIVE FCGNOfMCS, 1000 MW., EXISTING UNIT, 3.5X S IN COAL* 19-14-0 FERTILIZER PRODUCTION
FIX60 INVESTMENT = $ 16728400
TOTAL INITIAL INVESTMENT = $ 1826}4()0
OVERALL INTFREST RATE OF 3FTURN WITH DEDUCT = NEC
OVERALL INTFREST RATE OF RETURN WITHOUT DEDUCT - NEG
NO PAYOUT WITH DEDUCT
Mfl PAYOUT WITHOUT DEDUCT
YFARS
A.FTF3
POWFR
UNIT
START
ANNUAL
DPFRA-
TIQN
KW-HR/ TONS/YEAR
NET NH3
ALTERNATE SCRUBBING
TOTAL NH3 WET-LIME- COST IF
SCRUBBING STONE PRO- DEDUCTION
COST INCL
REGUL.ROI
FOR POWER
POLLUTION WET-UMF-
CONTROL STONF PRO-
COST, CESS COST,
NET FERTILIZER .MFC
COST USING INH412S04
J/YEAR
WI TH
DEDUCT
WITHOUT
DEDUCT
NET
FERTILIZER
SALES
REVENUE
S/YEAR
GROSS INCOME,
S/YEAR
WITH
DEDUCT
WITHOUT
DEDUCT
WITH
DEDUCT
WITHOUT
DEDUCT
CASH FLOW,
t/YFAR
WITH
DEDUCT
WITHOUT
DEDUCT
CUMULATIVE CASH FLOW,
ANNUAL RETURN ON
INITIAL INVESTMENT,
WITH
DEDUCT
WITHOUT
DEDUCT
WITH
DEDUCT
WITHOUT
DEDUCT
4 7000 268000 5640500 .1587300 2051200 10204700 13792000 8951200
5 7000 268000 5576300 3533800 204? 500 10194000 13727800 8951200
6 7000 2
7 7000 2
8 7000 2
9 7000 2
10 7000
11 5000
12 5000
13 5000
14 5000
15 5000
16 3500
17 3500
18 3500
19 3500 1
70 3500 1
21 1500
22 1500
23 1500
24 1500
25 1500
26 1500
27 1500
29 1500
?9 1500
30 1500
31 1500
37 1500
33 1500
34 1500
35 1500 *
8000 5512000 3480600 2031400 10182900 13663500 8951200
8000 5447700 3427200 2020500 10172000 13599200 8951200
8000 5319000 3319900 1999100 10150600 13470500 8951200
1400 4367000 2857000 1510000 8130000 10987000 6482700
1400 "1302800 2803800 1499000 8119000 10922800 6482700
1400 4238500 2750300 1488200 8108200 10858500 6482700
1400 4174200 2696900 1477300 6424500 9121400 6482700
1400 4110000 2643600 1466400 6413600 9057200 6482700
4000 3385800 2294300 1091 500 4844200 7138500 4596200
4000 3321500 2241100 1080400 4833100 7074200 4596200
4000 3257200 2187600 1069600 4822300 7009900 4596200
4000 31 93000 2134400 1058600 481 1300 6945700 4596200
4000 3128700 2080900 1047300 4800500 6881400 4596200
7400 2208300 1685300 523000 2567500 4252800 2011300
7400 2144000 1632000 512000 2556500 4188500 2011300
7400 2079800 1578600 501200 2545700 4124300 2011300
7400 2015500 1525300 490200 2534700 4060000 2011300
7400 1951200 471900 479300 2523800 3995700 2011300
7400 1887000 418600 468400 2512900 3931500 2011300
7400 1822700 1365200 457500 2502000 3867200 201 1300
7400 1758400 1311900 446500 2491000 3802900 2011300
7400 1694100 1258500 435600 2480100 3738600 2011300
7400 1629900 1205000 424900 2469400 3674400 2011300
7400 1565600 1151800 413800 2458300 3610100 2011300
7400 1501300 1098300 403000 2447500 3545800 2011300
7400 1437000 1045100 391900 2436400 3481500 2011300
7400 1372800 991600 381200 2425700 3417300 2011300
7400 1308500 938400 370100 2414600 3353000 2011300
12535001
1242800)
1231700)
1220300)
1209800)
1199400)
1188000)
1647300)
1636300)
1625500)
58200
69100
248000)
236900)
226100)
215100)
204300)
545200)
534400)
523400)
512500)
501600)
490700)
468 BOO)
458100)
436200)
4251001
414400)
403300)
4840800)
4776600)
4712300)
4648000}
4583700)
4519300)
4455200)
4504300)
4440100)
4375800)
2638700)
2574500*
25423001
24780001
24137001
2349500)
2285200)
2241500)
2177200)
2113000)
2048700)
1984400)
1920200)
1855900)
1727300)
1663100)
1534500)
1470200)
1406000)
1341700)
626750) ( 24204001 1046090
621400) ( 23883001 1051440
615850)^
610400)
604900)
599700)
594000)
373650)
818150)
R127'iOJ
29100
34550
124000)
1 18450)
113050)
107550)
102150)
277600)
267700)
261700)
256750)
245350)
2398501
734400)
279050)
21BIOO)
212550)
207200)
701650)
2356150) 1056990
2324000) 1062440
2291B50) 1067940
22596501 1073140
2227600) 1078840
22521501 849190
22P0050) 854690
21879001 860090
1319350) 29100
1287250) 14550
1271150)
1239000)
1206850)
11747501
1142600)
1083600)
1056500)
10243501
992200)
927950)
895800)
863650)
331550)
767250)
735100)
703000)
670350)
124000J
118450)
1130501
107550)
102150)
278100)
272600)
2672001
261700)
256250)
250800}
?45350)
239850)
234400)
229050)
2U100)
212550)
207200)
201650)
747560) 1046090
715460) 2097530
683310) 3154520
651160) 4216960
619010) 5284900
5868101 6358040
554760) 7436880
5793101 8286070
5472101 9140760
515060) 10000850
1319350) 10029950
1287250) 10064500
127U501 9940500
1239000) 9822050
1206850) 9709000
1142600) 9499300
11207501 9221200
1088600) 894B600
10565001 8681400
10243501 8419700
992200) 8163450
9601001 7912650
927950) 7667300
895800) 7427450
863650) 7193050
931550) 6964000
799400) 6740500
767750) 6522400
735100) 6309850
703000) 61026SO
670850) 5901000
747560)
1463020)
2146330)
2797490)
3416500)
40033101
45580701
51373801
5684590)
61996501
7519000) 0.16
8806250) 0. 19
10077400)
U316400)
12523250)
148406001
15961350)
17049950)
18106450)
19130800)
201230001
21083l6ot '
22011050)
22906850)
23770500)
24602050)
25401450)
26168700}
26903800)
27606800)
28277650)
169877200 238234500
( 216548001
t 1082 T400) ( 45006050)
5901000 ( 282776501
-------
Table B-148
PROCESS A, REGULATED POWER CO. ECONOMICS, 200 MW., EXISTING UNIT, 3.5* S IN C3AL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 12520000
YFA*S
AFTER
POWER
JMIT
START
A^MUAL
OPERA-
TION
KW-HR/
KW
TONS/YEAR
FERTILIZER
TOTAL NH(3>
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
$/YE AR
NET
FERTILIZER
SALES
REVENUE,
*/YEAR
NET ANNUAL
INCREASE
•DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST F3R WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
S/YEAR
ANMUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUBBING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS! USING
NH(3) SCRUB-
BING-FERTILI-
ZE* INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
t
3
4
5
6
7
R
9
10
11
12
13
14
15
1 6
17
18
19
?0
22
23
24
25
26
27
78
79
3!)
32
33
34
35
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
128600
128600
91700
91703
91700
91700
91700
64200
64200
64200
64200
6420D
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
27600
7837300
7740700
6470000
6373500
6277000
6180500
608*000
5074400
4977900
4881400
4784800
4688300
3299600
3203100
3106600
3010100
2913600
2817100
2720500
2624000
2527500
2453000
2334500
2238000
2141500
2045000
1948400
5460400
5460400
3930300
3930300
3930300
3930300
3930300
2774100
2774100
2774100
2774100
2774100
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
1209400
2376900
2230300
2539700
2443200
2346703
2250200
2153700
2300300
2203800
2107300
2010700
1914200
2090200
1993700
1897200
1800700
1704200
1607700
1511100
1414600
1318100
1243600
1125100
1028600
932100
835600
739000
2376900
4657200
7196900
9640100
11986800
14237000
16390700
18691000
20894800
23002100
25012800
26927000
29017200
31010900
32908100
34708300
36413000
38020700
39531800
40946400
42264500
43508100
44633200
45661800
46593900
47429500
48168500
1087900
1067700
947100
927000
906800
386600
866400
762900
742800
722600
702400
682200
553000
532800
512600
492400
472300
452100
431900
411700
391600
371400
351200
331000
310900
290700
270500
( 1289000)
1212600)
1592600)
1516200)
1439900)
1363600 )
1287300)
1537400)
1461000')
1384700)
1308300)
1232000)
1537200)
1460900 )
1384600)
1308300)
1231900)
1155600)
1079200)
1002900)
926500)
872200 )
773900)
697600)
621200)
544900)
468500)
1289000)
2501600)
4094200)
5&10400)
7050300)
8413900)
9701200)
11238600)
12699600)
14084300)
15392600)
1&S2463D)
18161800)
19622700)
21007300)
22315600)
23547500)
24? 03166)
25782300)
26785200)
27711700)
28583900)
29357800)
30055400)
30676600)
31221500)
31690000)
T1T4L
79000
1450700
110752300
62583800
48168500
16478500 ( 31690000)
to
*o
OJ
PRFSFMT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
19423200
7219400
-------
K)
Table B-149
PROCESS A, REGULATED PqWER CO. ECONOMICSi 500 MW., NEW UNIT, 2.0* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 16695000
VFARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION
KH-HR/
KM
TONS/YEAR
PERTILIZER
TOTAL NH(3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
RCI FOR PCW-
ER COMPANY,
S/YEAR
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
S
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST FDR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
S/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3>
SCRUBBING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3> SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
1
2
3
4
5
6
7
8
9
10
11
12 '
13
1*
15
16
17
18
19
20
21
22
?3
24
25
26
27
28
29
30
31
32
33
34
35
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
173600
173600
173600
173600
173600
1736CO
173600
173600
173600
173600
123900
123900
123900
123900
123900
86700
86700
86700
86700
86700
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
37200
10062900
9963600
9864400
9765200
9666000
95668CO
9467600
9368300
9269100
9169900
7570500
7471300
7372100
7272900
7173600
5909000
5809800
5710600
5611400
5512200
3768000
3668800
3569600
3470400
3371200
3272000
3172700
3073500
2974300
2875100
2775900
2676700
25774CO
2478200
2379000
7301600
7301600
7301600
7301600
7301600
7301600
7301600
7301600
73C1600
7301600
5268200
5268200
5268200
5268200
5268200
3721200
3721200
3721200
3721200
3721200
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
1623000
2761300
2662000
2562800
2463600
2364400
2265200
2166000
2066700
1967500
1868300
2302300
2203100
2103900
2004700
1905400
2187800
2088600
1989400
1890200
1791000
2145000
2045800
1946600
1847400
1748200
1649000
1549700
1450500
1351300
1252100
1152900
1053700
954400
855200
756000
2761300
5423300
7986100
10449700
12814100
15079300
17245300
19312000
21279500
23147800
25450100
2765320C
29757100
31761800
33667200
35855000
37943600
39933000
41823200
43614200
45759200
47805000
49751600
51599000
53347200
54996200
56545900
57996400
59347700
60599800
61752700
62806400
63760800
64616000
65372000
1800000
1772800
1749100
1718800
1690600
1663400
1635900
1608700
1581200
1553800
1379800
1352300
1325100
1297900
1270400
1114100
1086700
1059200
1032000
1004500
827100
799800
772400
745100
717700
690400
663000
635500
608300
580800
553600
526100
498900
471400
444200
( 961300)
889200)
813700)
744800)
673800)
601800)
5301CO)
458000)
386300)
314500)
922566)
850800)
778800)
706800 )
635000)
1073700)
1001900)
9302001
858200)
786500)
1317900)
1246000)
1174200)
11023CO)
1030500)
958600)
8867CO)
815000)
743COO)
671300)
599300)
527600)
455500)
383800)
311800)
961300)
1850500)
2664200)
3409000 )
4082800)
4684600)
5214700)
5672700)
6059000)
6373500)
7296666*
8146800)
8925600)
9632400)
10267400)
11341100)
12343000)
13273200)
14131400)
14917900)
16235800)
17481800)
18656000)
19758300)
20788800)
21747400)
22634100)
23449100)
24192100)
24863400)
25462700)
25990300)
26445800)
26829600)
27141400)
TOTAL 1350CO
3347000
207680000
142308000
65372000
38230600 I 271414CO)
PRESENT WORTH IF DISCCUNTED AT 10* TO INITIAL YEAR
21453300
14120000
-------
Table B-150
PROCESS A, PECULATED POWER CO. ECONOMICS, 500 MM., NEW UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 21*70000
YFARS
4FTFR
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
25
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
70CO
7000
7000
7000
7000
7000
7000
70CO
700C
7000
500C
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
150C
1500
1500
J. 500
1.560
150C
1500
1500
1 500
1500
1500
1500
1500
1500
TOTAL NHI3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING NET
REGULATED FERTILIZER
ROI FOR POW- SALES
TGNS/YEAR ER COMPANY, REVENUE,
FERTILIZER t/YEAR S/YEAR
303600
303800
3038QO
303300
303800
303800
303300
303800
30.3800
303300
217000
217000
217000
217CCO
217000
151900
151900
151900
151900
151900
65300
65300
65300
65300
653CO
65300
65300
6 '300
65300
65300
65300
65300
65300
65300
65300
14736100
14608600
14480800
14353300
14225600
14C98100
1397060C
13955200
1.3715400
13587700
11025900
1C898400
10770700
10643200
105155CO
8508800
8381200
8253500
8126000
79983CO
5259200
51317CO
5004000
4876500
4748800
4621300
4493800
4366100
4238600
411 0800
398330C
3855800
3728100
3600600
3472900
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
12492000
9051000
SC51000
9C51000
9051000
SC51000
6415000
6415000
6415000
6415000
6415000
282COOO
2820000
282COOO
2820000
2820000
2820000
2820000
282COOO
282COOO
2820000
282COOO
282COOO
2820000
2820000
2820000
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
2244100
2116600
1988800
1861300
1733600
1606100
1478600
1463200
1223400
1095700
1974900
1847400
1719700
1592200
1464500
2093800
1966200
1838500
1711000
1583300
2439200
2311700
2184000
2056500
1928800
1801300
1673800
15461 00
1418600
1290800
1163300
1035800
908100
780600
652900
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
CUMULATIVE PROCESS IN-
NET INCREASE CLUOING REG-
(DECREASEI ULATED ROI
COST OF FOR POWER
POWER, COMPANY,
$ t/YEAR
2244100
4360700
6349500
8210800
9944400
11550500
13029100
14492300
15715700
16811400
18786300
20633700
22353400
23945600
25410100
275C3900
29470100
31308600
33019600
34602900
37042100
39353800
41537800
4359430C
45523100
47324400
48998200
50544300
51962900
53253700
54417000
55452800
56360900
57141500
57794400
2150200 (
2119600
2089200
2058700
2028100
1997500
1967100
1936600
1906000
1875600
1640100 (
1610000 1
1579400 (
1549000 {
1518400
1311600 1
1281200 (
1250600 (
1220100 (
1189700 {
952200 (
921600 (
891100 {
860700 (
830100 (
799500 (
769200 (
738400 (
7 08 100 (
677400 (
647100 (
616500 (
585900 t
555600 (
525000 {
ANNUAL SAV- CUMULATIVE
INGS (LOSS) SAVINGS
US I KG NHI3) (LOSS) USING
SCRUBBING- NH(3) SCRUB-
FERTILIZER BING-FERTILI-
INSTEAD OF ZER INSTEAD
WET-LIME- OF WET-LIME-
STONE STONE
SCRUBBING, SCRUBBING,
t t
93900)
3000
1004CO
197400
294500
391400
488500
473400
682600
779900
334800)
237400)
140300)
432CO)
53900
782200)
685000)
587900)
490900)
393600)
1487000)
13901CO)
1292900)
1195800)
10987CO)
1001800)
9046CO)
807700)
710500)
613400)
516200)
419300 )
322200)
225000 )
127900)
I 93900)
( 90900)
9500
206900
501400
892800
1381300
1854700
2537300
3317200
2982400
2745000
2604700
2561500
2615400
1833200
1148200
560300
69400
324200)
1811200 )
3201300)
4494200)
5690000)
67887CO)
7790500)
8695100)
9502800)
10213300)
10826700)
11342WO) •
11762200)
12084400)
12309400)
12437300)
TOTAL 135000
5862000
302344400
24455COOO
57794400
45357100 ( 12437300)
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
17156200
16864800
-------
Table B-151
PROCESS A, REGULATED POWER CO. ECONOMICS, 500 HW., EXISTING UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER
FIXED INVESTMENT: $ 22320000
YEARS
AFTER
POWER
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/
KM
TONS/YEAR
FERTILIZER
TOTAL NH(3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLJDING
REGULATED
ROI FOR POW-
ER COMPANY,
*/YEAR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWERt
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
CUMULATIVE
NET INCREASE
(DECREASE I
COST OF
POWER,
ANNUAL SAV-
INGS (LOSS)
USING NH(3>
SCRUBBING-
PROCESS IN- FERTILIZER
CLUDING REG- INSTEAD OF
ULATED ROI WET-LIME-
FOR POWER STONE
COMPANY, SCRUBBING,
S/VEAR $
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
16
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
310800
310800
310800
310800
310800
310800
310800
222000
222000
222000
222000
222000
155400
155400
155400
155400
155400
66800
66800
66300
66800
66800
66800
66800
66800
66800
66300
66800
66300
66800
66300
66800
15473600
15328400
15183400
15038400
14893200
14748100
14603100
11904100
11758900
11613700
11468800
11323800
9206700
9061500
8916500
8771600
8626400
6001200
5856200
5711200
5566100
5420900
5275900
5130900
4985700
4840600
4695600
4550600
4405400
4260200
4115300
3970300
12764600
12764600
12764600
12764600
12764600
12764600
12764600
9253000
9253000
9253000
9253000
9253000
6561000
6561000
6561000
6561000
6561000
2883800
2883800
28 83 800
2883800
2883800
2883800
2883800
2883800
2883800
2883300
2883800
2883800
2883800
2883800
2883800
2709000
2563800
2418800
2273800
2128600
1993500
1838500
2651100
2505900
2360700
2215800
2070800
2645700
2500500
23555PO
2210600
2065400
3117400
2972400
2827400
2682300
2537100
2392100
2247100
2101900
1956800
1811800
1666800
1521600
1376400
1231500
1086500
2709000
5272800
7691600
9965400
12094000
14077500
15916000
18567100
21073000
23433700
25649500
27720300
30366000
32866500
35222000
37432600
39498000
42615400
45587800
48415200
51097500
53634600
56026700
58273800
60375700
62332500
64144300
65811100
67332700
68709100
69940600
71027100
2261500
2226100
2191000
2155600
2120500
2085100
2050000
1304000
1768900
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1061200
1025900
990700
955400
920200
884900
849700
814300
779200
743800
708700
673300
638200
602800
567700
447500)
337700)
227800)
118200)
8100)
101600
211500
847100)
737000)
627200)
517500)
407800)
1198100)
10882001
978400)
868800)
758800)
2056200)
1946500)
1836700)
1726900)
1616900)
1507200)
1397400)
1287600)
1177600)
1068000)
958100)
848300)
738200)
628700)
518800)
447500)
785200)
1013000)
1131200)
1139300)
1037700)
826200)
1673300)
2410300)
3037500)
3555000)
3962800)
5160900)
6249100)
7227500)
8096300)
8855100)
10911300)
12857800)
14694500)
16421400)
18038300)
19545500)
20942900)
22230500)
23408100)
24476100)
25434200)
26282500)
27020700)
27649400)
28168200)
TOTAL 114000
5064600
282706300
211679200
71027100
42858900 ( 28168200)
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
22400000
16933200
-------
Table B-152
PROCESS At REGULATED t>UWER CC . ECONOMIC1
500 MW. , NEW UNIT, 5.0* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 26130000
YFARS
AFTER
POWFR
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
1 6
17
18
19
20
?1
2?
73
24
25
2ft
27
28
29
^0
31
32
33
34
35
ANNUAL
OPER A-
T UN
Krf-HR/
KW
7000
7000
7000
7000
7000
7000
7000
700C
7000
7000
5000
5000
5000
5000
50CO
3500
3500
3500
35CC
3500
1500
15CO
1500
1500
1500
1500
1 500
1500
1500
1 500
1 500
1500
1500
1500
1500
TCNS/YEAR
FERTILIZER
434CCC
434000
434000
434000
434000
4340CC
434000
434000
434UOO
434000
3C9300
309800
309800
30S800
309800
217000
217000
217000
217000
2ncco
92800
92800
92300
92800
92800
92800
92800
92800
92800
92SOO
92800
92300
923CO
92800
92300
TCTAL NHO>
SCWJBBING-
FERTILI ZER
MFG. COST
INCLUDING
REGULATED
SOI FOR POW-
ER COMPANY,
S/YEAR
13 31 82 CO
13162900
78007700
17852300
17697200
17541800
173864CC
17231200
3, 7C75900
16920700
13684900
535295CC
.1 3374400
13219000
13C63800
10534500
10379200
10224000
10068600
99135CO
6451700
62963CO
614110C
5985800
5830600
5675200
5519800
5364700
5209300
5054100
4898800
4743400
45P82CO
4432800
4277700
NET
FERTILI ZER
SALES
REVENUE,
$/YEAR
17516200
1751*200
17516200
17516200
17516200
17516200
17516200 (
17516200 (
17516200 (
17516200 (
12726600
12726600
12726600
12726600
1272 66CO
9051000
9051000
S051000
9051000
9C5] 000
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
3977400
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
802000
646700
493500
336100
181000
25600
1 29800)
235000)
440300 )
595500)
958300
802900
647800
492400
33720C
1483500
1328200
1173000
1017600
8S2500
2474300
?318900
2163700
2008400
1853200
1697800
1542400
1387300
1231900
1076700
921400
766000
610800
455400
300300
CUMULATIVE
NET INCREASE
( DECREASE)
COST OF
POWER,
$
802000
1448700
5.940200
2276300
2457300
2482900
2353100
2C68100
1627800
1032300
1990600
2793500
3441300
3933700
4270900
575440C
7082600
8255600
9273200
10135700
12610000
14928900
17C92600
19101000
20954200
22652000
24J9440C
25581700
26813600
27890300
28811700
29577700
30J88500
30643900
30944200
ALTERNATIVE
OPERATING
COST FOR h£T
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
$/YEAR
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
18367CO
1803000
1769500
1512100
1478400
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
910300
876300
843100
809600
776200
742500
708800 (
675300
641800
6C8100
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUBS ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
17C45CO
1826300
1S47800
2069700
2191100
2313000
2434700
25565CC
2678300
2799300
945600
'067300
1188900
1310600
1432300
28600
150200
271900
3937CO
515300
1396100)
1274200)'
1151800)
1030900)
9C92CO)
787500 )
665600)
5442CO)
422300)
3CC500)
178900 )
57200)
645CO
186400
307800
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SCPU8-
BING-FERTIL I-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
17C450C
3530800
5478600
7548300
9739400
120524QC
14487100
17043600
19721900
22521700
23467300
24534600
25723500
27034100
28466400
28495000
28645200
28917100
29310800
29826KC
23430000
27155800
26004000
24973300
24063900
23276400
22610800
22066600
21644300
21343800
211.64900
21107700
21172200
21358600
21666400
TOTAL 135000
8366000
374655200
243711000
3C944200
52610600
21666400
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
5324900
19662100
-------
to
^5
00
Table B-153
PROCESS A, REGULATED POWER CO. ECONOMICS, 1000 fW., NEW UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 34500000
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
is
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KM
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
150C
1500
1500
1500
1500
TCNS/YEAR
FERTILIZER
581500
587500
587500
587500
587500
5875CO
5875CO
587500
5875CO
587500
419700
419700
419700
419700
419700
293800
293800
293300
293800
293800
126300
126300
126300
126300
1263CO
124300
126300
126300
126300
126300
126300
126300
126300
126300
126300
TCTAL NHI3I
SCRUBS ING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
S/YEAR
24C62600
23857500
23652600
234475CO
23242500
23037400
22832500
22627400
22422300
22217400
17967000
17762000
17557100
17352000
17146900
13826000
13621100
13416000
13211000
13006100
8467100
8262000
8057100
7852000
7646900
7441900
7237000
7C31900
6826800
6621900
6416800
6211700
6C06900
5801800
5596700
NET
FERTILIZER
SALES
REVENUE,
*/YEAR
23270900
2327C900
23270900
23270900
2327C900 (
23270900 (
23270900 (
23270900 (
23270900 <
23270900 (
16972700
16972700
16972700
16972700
16972700
12098700
12098700
12098700
12098700
12C98700
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
5366500
53665 CO
5366500
5366500
5366500
5366500
NET ANNUAL
INCREASE
(DECREASE!
COST OF
POWER,
$
791700
536600
381700
176600
28400)
233500)
438400)
643500)
848600) (
1053500) (
994300 (
789300
584400
379300
174200
1727300
1522400
1317300
1112300
907400
3100600
2895500
2690600
2485500
2280400
2075400
1870500
1665400
1460300
1255400
1050300
845200
640400
435300
230200
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
791700
1378300
1760000
1936600
1908200
1674700
1236300
592800
255800)
1309300)
315000)
474300
1058700
1438000
1612200
3339500
4861900
6179200
7291500
8198900
11299500
14195000
16885600
19371100
21651500
23726900
25597400
27262800
28723100
29978500
31028800
31874000
32514400
32949700
33179900
ALTERNATIVE
OPERATING
COST FOR NET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
t/YEAR
3362400
3317000
3271900
3226500
3181200
3135800
3090700
3045400
3000000
2954900
2565100
2519800
2474500
2429300
2384000
2053500
2008400
1963100
1917700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1179500
1134200
1088800
1043700
998400
953000
907700
862500
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCR UBB ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
25707CO
2730400
2890200
3049900
3209600
33693CO
3529100
3688900
3848600
4008400
157C8CO
1730500
1890100
2050000
2209800
326200
4860CO
645800
8C54CO
965000
1604100 )
1444300)
1284800)
1124800)
965000)
805400)
645800)
485900)
326100)
166600)
66CO)
153200
312600
472400
632300
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3> SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET- LIME-
STONE
SCRUBBING,
$
25707CO
5301100
8191300
11241200
14450800
17820100
21349200
25038100
288867CO
32895100
34465900
36196400
38086500
40136500
42346300
42672500
43158500
43804300
44609700
455747CO
43970600
425263CO
41241500
40116700
391517CC
38346300
37700500
37214600
36888500
36721900
36M5300
36868500
37181100
37653500
38285800
TOTAL 135000 11337000
491743400
458563500
33179900
71465700
38285800
PRESENT WORTH IF DISCOUNTED AT 10? TO INITIAL YEAR
4594800
26463500
-------
Table B-154
PROCESS A, REGULATED POWER CO. ECONOMICS, 1000 MW., EXISTING UNIT, 3.5* S IN COAL, 28-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: * 36550000
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
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
TONS/YEAR
FERTIL IZER
607600
607600
607600
607600
607600
607600
607600
433800
433800
433800
433300
433800
303700
303700
303700
303700
303700
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
130100
TOTAL NH<3>
SCRUBBING-
FERTILI ZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
I/YEAR
25799300
25561800
25324200
25086500
24848900
24611400
24373900
19795500
19557800
19320300
19082700
18345200
15264800
150270QO
14789500
14551900
14314400
9429100
9191300
8953800
8581900
8478700
8241200
8003400
7765900
7528400
7290800
7053300
6815500
6578000
6340500
6102900
NET
FERTILIZER
SALES
REVENUE,
$/YEAR
24018400
24018400
24018400
24018400
24018400
24018400
24018400
17508200
17508200
17508200
17508200
17508200
12488100
12488100
12488100
12488100
12488100
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
5522700
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
1780903
1543400
1305800
1068100
830500
593000
355500
2287300
2049600
1812100
1574500
1337000
2776700
2538900
2301400
2063800
1826300
3906400
3668600
3431100
3059200
2956000
2718500
2480700
2243200
2005700
1768100
1530600
1292800
1055300
817800
580200
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
1780900
3324300
4630100
5698200
6528700
7121700
7477200
9764500
11814100
13626200
15200700
16537700
19314400
21853300
24154700
26218500
28044800
31951200
35619800
39050900
42110100
45066100
47784600
50265300
52508500
54514200
56282300
57812900
59105700
60161000
60978800
61559000
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
C3MPANY,
$/YEAR
3587300
3533800
3480600
3427200
3373900
3319900
3267200
2857000
2803800
2750300
2696900
2643600
2294300 (
2241100 (
2187600 (
2134400
2080900
1635300
1632000
1578600
1525300
1471900
1418600
1365200
1311900
1258500
1205000
1151800
1098300
1045100
991600
938400
ANNUAL SAV-
INGS (LOSS)
USING NHI3)
SCRUBS ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
1806400
1990400
2174800
2359100
2543400
2726900
2911700
569700
754200
93820&
1122400
1306600
482400)
297800)
113800)
70600
254600
2221100)
2036600)
1852500)
1533900)
1484100)
1299900)
1115500)
931300)
747200)
563100)
378800)
194500 )
10200)
173800
358200
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SC RUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
*
1806400
3796800
5971600
8330700
10874100
13601000
16512700
17082400
17836600
18774800
19897200
21203800
20721400
20423600
20309800
20380400
20635000
18413900
16377300
14524800
12990900
11506800
10206900
9091400
8160100
7412900
6849800
6471000
6276500
6266300
6440100
6798300
TOTAL 114000
9892200
462509800
400950800
61559000
68357300
6798300
to
PRESENT WORTH If DISCOUNTED AT 10* TO INITIAL YEAR
16058000
26919700
-------
Table B-155
PROCESS 8. REGULATED POWER CD. ECONOMICS, 200 MW., EXISTING UNIT, 3.5* S IN COAL. 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENTS $ 11428000
YPARS ANNUAL
AFTER OPERA-
POWER TION
UNIT KW-HR/
START KW
TONS/YEAR
FERTILIZER
TOTAL NH(3>
SCRUBSING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
$/YEAR
NET
FERTILIZER
SALES
REVENUE,
$/YEAR
NET ANNJ AL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE PR3CESS
NET INCREASE CLUDING REG-
SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
1
2
3
4
5
6
7
8
9
10
11
12
13
1*
15
16
17
18
19
20
21
22
23
24
25
26
27
?fl
29
30
31
32
33
34
35
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
97100
97100
69500
69500
69500
69500
69500
48600
48600
48600
48600
48600
20800
20800
20800
20800
20300
20800
20800
20800
20800
20800
20800
20800
20800
20800
20800
6755000
6667000
5629600
5541600
5453600
5365600
5277600
4447200
4359300
4271300
4183300
4095300
2944000
2856000
2768000
2680100
2592100
2504100
2416100
2328100
2240100
2152200
2064200
1976200
1888200
1800200
1712200
4386000
4386000
3162300
3162300
3162300
3162300
3162300
2225400
2225400
2225400
2225400
2225400
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
963000
2369000
2281000
2467300
2379300
2291300
2203300
2115300
2221800
2133900
2045900
1957900
1869900
1931003
1893000
1805000
1717100
1629100
1541100
1453100
1365100
1277100
1189200
1101200
1013200
925200
837200
7492 00
2369000
4650000
7117300
9496600
11787900
13991200
16106500
18328300
20462200
22508100
24466000
26335900
28316900
30209900
32014900
33732000
35361100
36902200
38355300
39720400
40997500
42186700
43287900
44301100
45226300
46063500
46812700
1087900
1067700
947100
927000
906800
886600
866400
762900
742800
722600
702400
682200
553000
532800
512600
492400
472300
452100
431900
411700
391600
371400
351200
331000
310900
290700
270500
12811001
1213300)
1520200)
1452300)
1384500)
1316700)
1248900)
1458900)
1391100)
1323300)
1255500)
1187700)
1428000)
1360200)
1292400)
1224700)
1156800)
1089000)
1021200)
953400)
885500)
817800)
750000)
682200)
614300)
« 546500)
« 478700)
1281100)
2494400)
4014600)
5466900)
6851400)
8168100)
9417000)
10875900)
12267000)
13590300)
14845800)
16033500)
17461500)
18821700)
20114100)
21338800)
22495600)
23584600)
24605800)
25559200)
26444700)
27262500)
28012566)
28694700)
29309000)
29855500)
30334200)
TOTAL
79000
1096700
96968200
50155500
46812700
16478500 ( 30334200)
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
18957200
7219400
-------
Table B-156
PROCESS B. REGULATED POWER CO. ECONOMICS, 50C Mh. , NEW UNIT, 2.0? S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 15574000
YFARS
AFTER
PGWFR
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/
K.W
TONS/YEAR
TOTAL NH(3)
SCRUBS ING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
FERTILIZER S/YEAR
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATI VE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
S/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCR USB ING-
FERTIL IZER
INSTEAD CF
HET-LIME-
STCNE
SCRUBBING,
i
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SCRU8-
BING-FERTILI-
ZER INSTEAD
OF WET-tlME-
STONE
SCRUBBING,
$
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IB
19
20
21
22
23
24
75
26
?7
28
29
30
31
32
33
34
35
7000
7000
7000
70CO
7000
7000
7000
7000
7000
7000
5000
5000
5000
50CO
5000
3500
3500
3500
3500
3500
1500
1500
X500
J. 500
150C
1500
1500
1500
1500
150C
1500
1500
1500
1500
1500
1315CO
131500
131500
131500
131500
131500
131500
131500
131500
131500
93900
S39CO
93900
93900
93900
65800
658CO
65800
65800
65800
28200
28200
28200
28200
28200
28200
28200
26200
28200
28200
28200
28200
28200
28200
28200
87882CO
8695600
8603100
85105CO
8417900
8325400
6232800
8140300
8C47700
7955100
6639700
654710C
6454600
6362000
6269400
5222000
5129400
5036800
4944300
4851700
3397500
3304900
3212400
31J9800
3027200
29347CO
2842100
2749600
2657000
2564400
2471900
2379300
2286800
2194200
2101600
5896500
5896500
5896500
5896500
5896500
5896500
5896500
5896500
5896500
5896500
4246200
4246200
4246200
4246200
4246200
2997200
2997200
2997200
2997200
2997200
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
1301400
13C1400
1301400
1301400
1301400
2891700
2799100
2706600
2614000
2521400
2428900
2336300
2243800
2151200
2058600
2393500
2300900
2208400
2115800
2023200
2224800
2132200
2039600
1947100
1854500
2096100
2003500
1911000
1818400
1725800
1633300
1540700
1448200
1355600
1263000
1170500
1077900
985400
892800
800200
2891700
5690800
8397400
11011400
13532800
15961700
18298000
20541800
22693000
24751600
27145100
29446000
31654400
33770200
35793400
38018200
40150400
42190000
44137100
45991600
48C87700
50091200
52002200
53620600
55546400
571 79700
58720400
60168600
61524200
6278720C
63957700
65035600
66021000
66913800
67714000
1800000
1772800
1749100
1718800
1690600
1663400
1635900
1608700
1581200
1553800
1379800
1352300
1325100
1297900
1270400
1114100
1086700
1059200
1032000
1004500
827100
799800
772400
745100
717700
690400
663000
635500
608300
580800
553600
526100
498900
471400
444200
10917CO)
1026300)
957500)
895200)
830800)
765500)
700400 )
635100)
5700CO)
504800 )
1013700)
948600)
883300)
8179CO)
752800)
1110700>
1045500)
980400)
915100)
850000)
1269000 )
12C3700)
1138600)
1073300)
1C08100)
942900 )
877700)
8127CO)
747300)
682200)
6169CO)
551800)
486500)
421400 )
356000)
10917CO)
2118000)
3075500)
3970700)
4801500)
5567000)
6267400)
6902500)
7472500)
7977300)
8991000)
9939600)
10822900)
11640800)
12393600)
13504300)
14549800)
15530200)
16445300)
17295300)
18564300)
19768000)
20906600)
21979900)
22988000)
23930900)
24808600)
25621300)
26368600)
27050800)
27667700)
28219500)
28706000)
29127400)
29483400)
TOTAL 135000
25365CO
182417COO
114703000
67714000
38230600 ( 29483400)
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
22586800
14120000
-------
Table B-1 57
O
K)
PROCESS B, REGULATED POWER CO. ECONOMICS. 500 MW., NEW UNIT, 3.5* S IN COAL. 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 19689000
YEARS
AFTFR
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
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KM
7000
7000
7000
7000
7000
7000
7000
7000
7000
700C
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
15CC
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
15CO
1500
TONS/YEAR
FERTILIZER
230000
230000
230000
230000
230000
230000
230000
230000
230000
230000
164300
1 643 00
164300
164300
164300
115000
115000
115000
11 5000
115000
49300
49300
49300
49300
49300
49300
49300
49300
4S300
49300
49300
4S3CO
49300
49300
49300
TOTAL NH(3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
RCI FOR POK-
ER COMPANY,
I/YEAR
12487800
12370700
12253600
12136500
12019400
11902300
117852CO
11668000
11551000
11433900
9461200
9344100
9226900
9109900
8992700
1355700
7238600
7121500
7004400
6387300
4628200
4511100
4394000
4276900
4159800
4042700
3925600
3808500
3691400
3574300
3457200
3340100
3223000
3105900
2988800
NET
FERTILIZER
SALES
REVENUE,
$/YEAR
10129200
10129200
10129200
10129ZOO
1C129200
10129200
10129200
1C129200
10129200
10129200
7317900
7317900
7317900
7317900
7317900
5173900
5173900
5173900
5173900
5173900
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
2257000
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
2358600
2241500
2124400
2007300
1890200
1773100
1656000
1538800
1421800
1304700
2143300
2026200
1909000
1792000
1674800
2181800
2064700
1947600
1830500
1713400
2371200
2254100
2137000
2019900
1902800
1785700
1668600
1551500
1434400
1317300
1200200
1083100
966000
848900
731800
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
235E60C
4600100
6724500
8731800
10622000
12395100
14051100
15589900
17011700
18316400
20459700
22485900
24394900
26186900
27861700
30043500
32108200
34055800
35886300
37599700
39970900
42225000
44362000
46381900
48284700
50070400
51739000
53290500
54724900
56042200
57242400
58325500
59291500
60140400
60872200
ALTERNATIVE ANNUAL SAV- CUMULATIVE
OPERATING INGS (LOSS) SAVINGS
COST FOR WET USING NH(3I (LOSS) USING
-LIMESTONE SCRUBBING- NH(3) SCRUB-
PROCESS IN- FERTILIZER BING-FERTI LI-
CLUDING REG- INSTEAD OF ZER INSTEAD
ULATED ROI WET-LIME- OF WET-LIME-
FOR POWER STONE STONE
COMPANY, SCRUBBING, SCRUBBING,
S/YEAR i *
2150200 ( 2084CO) 208400)
2119600 ( 121900) 330300)
2089200 ( 35200) 365500)
2058700 514CO 314100)
2028100 137900 176200)
1997500 224400 48200
1967100 311100 359300
1936600 397800 757100
1906000 484200 1241300
1875600 570900 1812200
1640100
1610000
1579400
1549000
1518400
1311600
1281200
1250600
1220100
1189700
952200
921600
891100
860700
830100
799500
769200
738400
708100
677400
647100
616500
585900
555600
525000
503200) 1309000
4162CO) 892800
329600) 563200
243000) 320200
156400) 163800
870200) (
783500)
697000)
610400)
5237CO)
1419000)
1332500)
1245900)
1159200)
1072700)
986200)
899400)
813100)
7263CO)
639900 )
5531CO)
466600)
380100)
293300)
206800)
706400)
1489900)
2186900)
2797300)
3321000)
4740000)
6072500)
7318400)
8477600)
9550300)
105365CO)
11435900)
12249000)
12975300)
13615200)
14168300)
14634900)
15015000)
15308300)
15515100)
TOTAL 135000
44310CO
258478200
197606000
60872200
45357100 ( 15515KO)
PRESENT WORTH IF DISCOUNTED AT 10% TO INITIAL YEAR
18404200
16864800
-------
Table B-158
PROCESS B, REGULATED POKER co. ECONOMICS, soo MW., EXISTING UNIT, 3.5% s IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENTS $ 20191000
YEARS
AFTER
POWER
UNIT
START
AMNUAL
OPERA-
TION
KW-HR/
KM
TONS/YEAR
PERT IL I ZER
TOTAL NH(3l
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
I/YEAR
ALTERNATIVE ANNUAL SAV- CUMULATIVE
NET
FERTILIZER
SALES
REVENUE,
$/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
*
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
*/YEAR
INGS (LOSS)
USING NH(3)
SCRUBS ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
S
SAVINGS
(LOSS) USING
NH(3> SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
f
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
31
32
33
34
35
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
235800
235300
235300
235800
235300
235800
235800
168203
168200
168200
168200
168200
117900
117900
117900
117900
117900
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
50500
13001800
12870600
1 2 73 93 00
12608100
12476800
12345600
12204300
10056700
9925400
9794200
9662900
9531700
7830600
7699300
7568100
7436800
7305600
4964500
4833300
4702000
4570800
4439500
4308300
4177000
4045800
3914500
3783300
3652000
3520800
3389500
3258300
3127200
10375200
10375200
10375200
10375200
10375200
10375200
10375200
7486600
7486600
7486600
7486600
7486600
5300800
5300800
5300800
5300800
5300800
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2310400
2626600
2495400
2364100
2232900
2101600
1970400
1829100
2570100
2438800
2307600
2176300
2045100
2529800
2398500
2267300
2136000
2004800
2654100
2522900
2391600
2260400
2129100
1997900
1866600
1735400
1604100
1472900
1341600
1210400
1079103
947900
816800
2626600
5122000
7486100
9719000
11820600
13791000
15620100
18190200
20629000
22936600
25112900
27158000
29687800
32086300
34353600
36489600
38494400
41148500
43671400
46063000
48323400
50452500
52450400
54317000
56052400
57656500
59129400
60471000
61681400
62760500
63708400
64525200
2261500
2226100
2191000
2155600
2120500
2085100
2050000
1804000
1768900
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1061200
1025900
990700
955400
920200
884900
849700
814300
779200
743800
708700
673300
638200
502800
567700
( 365100)
1 269300)
173100)
{ 77300)
18900
114700
220900
766100)
669900 )
574100)
478000)
382100)
1082200)
986200)
890200)
794200)
698200)
1592900)
1497000)
1400900)
1305000)
1208900)
1113000)
1016900)
921100)
824900)
729100)
632900 )
537100)
440900)
345100)
249100)
365100)
634400)
807500)
884800)
865900)
751200)
530300)
1296400)
1966300)
2540400)
3018400)
3400500)
4482700)
5468900)
6359100;
7153300)
7851500)
9444400)
10941400)
12342300)
13647300)
14856200)
15969200)
16986100)
17907200)
18732100)
19461200)
20094100)
20631200)
21072100)
21417200)
21666300)
TOTAL 114000
3838600
235744600
171219400
64525200
42858900 ( 21666300)
8
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
21364600
16933200
-------
Table B-159
PROCESS B, REGULATED POWER CO. ECONOMICS* 500 MW.t NEW UNIT, 5.0* S IN COAt. 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: * 23525000
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
31
32
33
34
35
TOTAL
PRESENT
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
150C
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
135000
WORTH IF
TONS/YEAR
FERTIL IZER
328600
328600
3286CO
328600
32 8600
328600
328600
326600
328600
328600
234700
234700
234700
234700
234700
164300
164300
164300
164300
164300
70400
7C4CO
70400
70400
70400
70400
70400
70400
7C400
70400
70400
70400
70400
70400
70400
6337000
DISCOUNTED
TOTAL NH(3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
RCI FOR POW-
ER COMPANY,
S/YEAR
15559800
15420000
15280200
15140500
15000700
14860900
14721100
14581400
14441600
14301800
11662000
J1522300
J1382500
11242700
11102900
9C30100
8890300
8750500
8610700
8471000
5621900
5482100
5342300
5202600
5062800
4923000
4783200
4643400
4503700
4363900
4224100
4084300
3944600
3,804800
3665000
NET
FERTILIZER
SALES
REVENUE,
$/YEAR
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
14264500
10329100
1C329100
10329100
10329100
10329100
7317900
7317900
7317900
7317900
7317900
3201800
3201800
3201800
3201800
3201800
3201800
3201800
3Z01800
3201800
3201300
3201800
3201800
3201800
3201800
3201800
319624700 278907000
AT 10? TO INITIAL YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
1295300
1155500
1015700
876000
736200
596400
456600
316900
177100
37300
1332900
1193200
1053400
913600
773800
1712200
1572400
1432600
1292800
1153100
2420100
2280300
2140500
2000800
1861000
1721200
1581400
1441600
1301900
1162100
1022300
882500
742800
603000
463200
40717700
95638CO
CUMULATIVE
NET INCREASE
(DECREASE!
COST OF
POWER,
$
1295300
2450800
3466500
4342500
5078700
5675100
6131700
6448600
6625700
6663000
7995900
9189100
10242500
11156100
11929900
13642100
15214500
16647100
17939900
19093000
21513100
23793400
25933900
27934700
29795700
31516900
33098300
34539900
35841800
37003900
38026200
38908700
39651500
40254500
40717700
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
S/YEAR
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1803000
1769500
1512100 (
1478400 (
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
910300
876800
843100
809600
776200
742500
708800
675300
641800
608100
52610600
19662100
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUB8ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
*
1211200
1317500
1423600
1529800
1635900
1742200
1848300
1954600
2060900
2167000
571000
677000
783300
889400
995700
200100)
94000)
12300
118500
224700
1341900)
1235600)
1128600)
1023300)
917000)
810900)
704600)
598500)
492300)
385900)
279800)
173700)
67500)
38800
144900
11892900
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
1211200
2528700
3952300
5482100
7118000
8860200
10708500
12663100
14724000
16891000
17462000
18139000
18922300
19811700
20807400
20607300
20513300
20525600
20644100
20868800
19526900
18291300
17162700
16139400
15222400
14411500
13706900
13108400
12616100
12230200
11950400
11776700
11709200
11748000
11892900
-------
Table B-160
OJ
o
ISl
PROCESS B, REGULATED POWER CO. ECONOMICS, 1000 MM.t NEW UNIT, 3.5% S IN COAL, 26-1,9-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 31000000
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
f.
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
75
76
27
78
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
70CC
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
350C
3500
350C
3500
3500
1500
1500
1500
1500
1.500
15CC
! 500
1500
1500
] 500
1 50C
\500
1500
1500
1500
TONS/YEAR
FERTJLI ZER
•444000
4440 CO
4440-00
444000
444000
444000
444000
444000
444000
444000
318000
318000
31KOOO
318000
318000
222000
222000
2220CO
222300
222000
95200
95200
95200
S5200
95200
95200
95200
95200
S52CO
95200
95200
95200
95200
95200
95200
TCTAL NH<3>
SCR UBB ING-
FERTILIZER
VFG. CCST
INCLUDING
REGULATED
RCI FOR PCW-
ER COMPANY,
$/YEAR
20344500
20160200
19975900
19791600
19607300
19423100
19238800
190545CO
18870200
18685900
15231900
15047600
J 4863300
14679100
1.4494800
117855CC
J1601200
11416900
11232600
11048300
7334400
7150200
6965900
678160C
6597300
6413000
6228700
6044400
58560CO
567580C
5491600
5307300
5123000
4938700
475440C
NET
FERTILIZER
SALES
REVENUE ,
I/YEAR
18994300
18994300
18994300
18994300
18994300
18994300
18994300
18994300
18994300 (
18994300 (
13829800
13829800
13829800
13829800
13829800
S792400
S792400
9792400
9792400
9792400
4304900
4304900
4304900
43C4900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
4304900
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
1350200
1165900
981600
797300
613000
428800
244500
60200
124100)
308400 )
1402100
1217800
1033500
849300
665000
1993100
1808800
1624500
1440200
1255900
3029500
2845300
2661000
2476700
2292400
2108100
1923800
1739500
1551100
1.370900
1186700
1002400
818100
633800
449500
CUMULATIVE
NET INCREAS
(DECREASE)
COST OF
POWER.
$
125020C
2516100
3497700
429500C
4908000
5336800
5581300
5641500
5517400
5209000
6611100
7828900
8862400
9711700
10376700
12369800
14178600
15803100
17243300
1849920C
21528700
24374000
27035000
29511700
31804100
33912200
35836000
37575500
39326600
40497500
41684200
42686600
43504700
443 38500
44588000
ALTERNATIVE
OPERATING
COST FDR WE
-LIMESTONE
PROCESS IN
E CLUOING REG
ULATED ROI
FOR POWER
COMPANY,
$/YEAR
3362400
3317000
3271900
3226500
3181200
3135800
3090700
3045400
3000000
2954900
2565100
2519800
2474500
2429300
2384000
2053500
2008400
1963100
1917700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1179500
1134200
1088800
1043700
998400
953000
907700
662500
ANNUAL SAV-
INGS (LCSS)
T USING NH<3
SCRU8BING-
- FERTILIZER
- INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
2012200
2151100
2290300
24292CO
25682CO
2707000
28462CO
2985200
3124100
32633CO
1163000
1302000
14410CO
1580000
17190CO
6C400
J 99600
3386CO
477500
616500
1533CCC)
1394100)
1255200)
1116000)
977000 )
8381CO)
699100)
560000)
4169CO)
282100)
143CCO)
4000)
134900
273900
413000
C 'ILATIVE
,/INGS
( jiS) USING
.jH(3 ) SCRUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
2012200
4163300
645360C
8882800
11451000
14158000
17004200
39989400
2313.3500
26376800
27539800
28841800
30282800
31862800
33581800
33642200
33841800
34180400
3465790C
35274400
33741400
32347300
31092100
29976100
28999100
28161000
27461900
26901900
264850CO
26202900
26059900
26055900
26190800
26464700
26877700
TOTAL 13EOOO
8568CCO
417215500
372627500
PRFSFNT WORTH IF DISCOUNTED AT 109! TC INITIAL YEAR
44588000
9470500
71465700
26463500
26877700
-------
Ui
8
Table B-161
PROCESS Bt REGULATED POWER CO. ECONOMICS, 1000 MW., EXISTING UNIT, 3.5? S IN COAL, 26-19-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 32904000
YEARS
AFTER
POWER
UNIT
START
1
2
3
it
5
6
7
8
9
10
11
12
13
14
15
16
17
1.8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
ANNUAL
OPERA-
TION
KW-HR/
KW
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
\500
1 500
1500
1500
1500
1500
1500
1500
1500
1.500
1500
1500
1500
1500
1500
TOTAL NH(3
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
RCI FOR POW-
TONS/YEAR ER COMPANY,
FERTILIZER S/YEAR
460000
46000Q
460000
460000
460000
46COOO
460000
328600
328600
328600
328600
328600
230000
230000
230000
230000
230000
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
98500
21830400
21616600
21402800
21189000
20975100
20761300
20547500
16827800
16613900
164001.00
16186300
15972500
13050600
12836800
12623000
12409200
12195300
8196400
7982600
7768800
7555000
7341100
7127300
6913500
6699700
6485800
6272000
6058200
5844400
5630500
5416700
5202900
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
19642000
19642000
19642000
19642000
19642000
19642000
19642000
14264500
14264500
14264500
14264500
14264500
10129200
10129200
10129200
10129200
10129200
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
4448300
NET ANNUAL
INCREASE
( DECREASE)
COST 3F
POWER,
$
2188400
1974600
1760800
1547000
1333100
1119300
905500
2563300
2349400
2135600
192X800
1 708000
2921400
2707600
2493800
2230000
2066100
3748100
3534300
3320500
3106700
2892800
2679000
2465200
2251400
2037500
1823700
1609900
1396100
1182200
968400
754600
ALTERNATIVE ANNUAL SAV- CUMULATIVE
OPERATING INGS (LOSS) SAVINGS
COST F3* WET USING NH(3) (LOSS) USING
-LIMESTONE SCRUBBING- NH(3> SCRUB-
CUMULATIVE PROCESS IN- FERTILIZER BING-FERTILI-
NET INCREASE CLUDING REG- INSTEAD OF ZER INSTEAD
(DECREASE) ULATED ROI WET-LIME- OF WET-LIME-
COST OF FOR POWER STONE STONE
POWER, COMPANY, SCRUBBING, SCRUBBING,
$ S/YEAR $ *
2188400
4163000
5923800
7470800
8803900
9923200
10828700
13392000
15741400
17877000
19798800
2! 5 06600
24428200
27135800
29629600
31909600
33975700
37723800
41258100
44576600
47685300
50578100
53257100
55722300
57973700
60011200
61834900
63444800
64840900
66023100
66991500
67746100
3587300 1398900
3533800 1559200
3480600 1719300
3*27200 1880200
3373900 2040800
3319900 2200600
3267200 2361700
2857000 293700
2803800 454400
2750300 614700
2696900 775100
2643600 935600
2294300
2241100
2137600
2134400
2080900
1685300
1632000
1578600
1525300
1471900
1418600
1365200
1311900
1258500
1205000
1151800
1098300
1045100
991600
938400
627100)
466500)
306200)
145600)
14800
2062800)
1902300)
1741900 )
1581400)
1420900)
1260400 )
1100000)
939500)
779000 )
618700)
458100)
297800)
137100)
23200
133800
1398900
2958100
4677900
6558100
8598900
10799500
13161200
13454900
13909300
14524000
15299100
16234700
15607600
15141100
14334900
14689300
14704100
12641300
10739000
8997100
7415700
5994800
4734400
3634400
2694900
1915900
1297200
839100
541300
404200
427400
611200
TOTAL 114000
7490500
393933100
326187000
67746100
68357300
611200
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
19161400
26919700
-------
Table B-162
PROCESS C. REGULATED POWER CO. ECONOMICSi 200 MW., EXISTING UNIT, 3.5$ S IN COALt 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: t 9589500
YFARS
AFTER
POWFR
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/
KW
TCfvS/YEAR
FERT1LIZER
TOTAL NH<3>
SCRUBS IMG-
FERTI LI ZER
MFG. COST
INCLUDING
REGULATED
RCI FOR POW-
ER CONPANY,
t/YFAR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
t/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUBBING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
CUMULATIVE
S AV IN GS
(LOSS) USING
NH(3) SCRUB-
BIN G-FERTIL I-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBI NG,
$
5
6
7
8
9
10
1J
12
! 3
14
15
16
17
18
19
70
71
22
73
74
75
76
77
28
29
30
31
32
33
34
35
7000
7000
50CO
5000
5000
500G
5000
3500
3500
3500
35CO
3500
15CC
1500
1500
1 500
1 500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
567CO
56700
40500
40500
40500
40500
40500
2S400
28400
28400
28400
28400
12200
12200
12200
12200
12200
12200
12200
12200
12200
12200
12200
12200
12200
12200
122CO
5219900
5146000
4410700
4336900
4263000
4189200
4115400
3 51. 93 CO
34455CO
3377600
3297800
3224000
2385800
23)2000
2238200
2164300
2090500
Z0166CO
1S42800
1875800
17951 00
1721300
1647400
1573600
1499700
1425900
1352000
1987300
1987300
1428400
1428400
1428400
1428400
1428400
1007300
1007300
1007300
1007300
1007300
437000
437000
437000
437000
437000
437000
437000
437000
437000
437000
437JOOO
437000
437000
437000
437000
3232600
3158700
2982300
2908500
2834600
2760800
2687000
2512000
2438200
2370300
2290500
2216700
1948800
1875000
1801200
1727300
1653500
1579600
1505800
1438800
1358100
1284300
1210400
1136600
1062700
988900
915000
3232600
6391300
9373600
12282100
1 5116700
17877500
20564500
23076500
25514700
27885000
30175500
32392200
34341000
36216000
38017200
39744500
41398000
42977600
44483400
45922200
4728030C
48564600
49775000
50911600
51974300
52963200
53878200
1087900
1067700
947100
927000
906800
836600
866400
762900
742800
722600
702400
682200
553000
532800
512600
492400
472300
452100
431900
411700
391600
371400
351200
331000
310900
290700
270500
2144700 )
2091000)
2035200)
1981500)
1927800)
18742CO)
1820600)
1 7491CO)
1695400)
1647700)
1588100)
1534500)
13958CC)
1342200)
1288600)
1234900)
1181200)
1127500)
107390C)
1027100)
9665CO)
912900)
859200)
8056CO)
751800)
698200)
644500)
2144700)
4235700)
6270900)
8252400)
10180200)
12054400)
13875000)
15624100)
17319500)
18967200 )
20555300)
22089800)
23485600)
24827800)
26116400 )
27351300)
28532500)
29660000)
30733900)
31761000)
32727500)
33640400)
34499600)
35305200)
36057000)
36755200)
37399700)
TOTAL
79000
640900
76586300
22708100
53878200
16478500 ( 37399700)
PRESENT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
22882000
7219400
-------
Table B-163
U)
o
oo
PRDCFSS Ct PECULATED POWER co. ECONOMICS, ECC M*. , NEW UNIT, 2.0* s IN CCAL, 19-14-0 FERTILIZER PRCOUCTIQN
FIXED INVESTMENT: $ 13057300
YFARS
AFTFR
PCWFR
UN! T
START
ANNUAL
TICN
KW-HR/
Kfc
TCC-S/YFAR
FERTILIZER
TOTAL NH(3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGUL4TEC
RCI FOR POW-
ER COMPANY,
i/YEAR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
ME T ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATI VE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
t/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUBfllNG-
FERTIL IZER
INSTEAD OF
WET-LI ME-
STCNE
SCRUBBING,
t
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SC RUB-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
1
?
3
4
5
6
7
ft
9
10
1 1
12
13
14
15
1 6
17
1.8
19
?0
21
22
?3
24
?5
?6
27
?fi
29
30
31
3?
33
34
35
7000
7000
7 COO
7000
7000
7 ore
7000
7000
70CO
7000
5000
50CO
5000
SOOC
5000
3500
350C
3500
3500
350C
1 500
1500
1500
1500
1 5 CO
1500
\ 500
I 500
1500
T 5CO
1500
1.500
I 500
1500
1500
766CO
7660C
76i00
7t&00
76600
76600
76600
76600
764CO
76600
54700
547CO
54700
54700
547CO
38300
36300
38300
36300
36JOO
16400
16400
16400
16400
16400
16400
16400
164CO
16400
16400
1 64CO
16400
16400
16400
16400
6B337CO
67561 00
6678600
6601000
6523400
64^5800
63683CO
6290700
62131CO
63.35500
5120900
5C4?300
4965700
4388100
48106CO
4073200
3995600
391 8COC
38
-------
Table B-164
PROCFS? C. REGULATfcO POw ER CD. ECONOMICS, 500 MW.t NEW UNIT, 3.5* S IN COALt 19-14 "* FERTILIZER PRODUCTION
FIXED INVESTMENT:" $ 16356800
YFARS
AFTER
POV.ER
UNIT
START
ANNUAL
QPFRA-
TIGN
KW-HK/
KW
TCNS/YEAR
FERTIL IZER
TOTAL NH(3)
SCRUBBING-
FERTILI ZER
MFG. COST
INCLUDING
REGULATED
SCI FOR POW-
CR COMPANY,
S/YEAR
NET
FERTILIZER
SALES
REVENUE,
t/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATI VE
NET INCREASE
(DECREASE)
COST OF
PCWER,
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
$/YEAR
ANNUAL SAV-
INGS (LOiS)
USING NH<3>
SCRUBS ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STCNE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SC RUB-
BIN G-FERT ILI-
ZER INSTEAD
OF WET-LIME-
STCNE
SCRUB 81 NG,
$
J
?
3
4
5
6
7
8
9
TO
11
1 2
13
14
15
16
1 7
1 S
19
70
71
72
23
74
25
76
77
28
29
30
31
3?
33
"*4
35
7000
7000
7000
7000
7000
7000
7000
700C
7000
7000
500 C
5000
5or c
5000
5000
350C
3500
3500
350C
35CO
1500
1500
1500
1500
1500
1500
1 50C
1.500
1500
1 500
1500
T 500
1500
1500
1 5CC
134000
134000
134000
134000
134000
134COO
134000
134000
134000
134000
95700
95700
95700
9^700
95700
67000
67000
67000
67 COO
67000
28700
2P7CO
28700
£8700
2b700
^8703
28700
28700
28700
28700
28700
28700
28700
2 87 00
28700
92B7CCC
91.89900
9C92700
8995600
8998500
880140C
8704200
3607000
85100CC
841Z800
7C26000
6928SCC
6831700
67345CO
6637400
5532700
543?5CC
5338400
5241300
5144100
3599000
3501900
3404700
3307600
3210500
3113300
3016200
2939000
2821900
27248CO
2627600
2530400
2433700
2336200
22391.00
4596200
4596200
4596200
4596200
4596200
4596200
4596200
4596200
4596200
4596200
3314100
3314100
3314100
3314100
3314100
2340300
234C300
234C300
2340300
234C300
1017700
J 017700
1017700
1017700
1017700
1017700
1017700
1017700
1017700
1017700
1C17700
1017700
1C17700
1017700
1017700
4690800
4593700
4496500
4399400
4302300
4205200
4108000
4010800
3913800
3816600
3711900
3614700
3517600
3420400
3323300
3192400
3095200
2998\00
2901000
2803800
2581300
2434200
2387000
2289900
2192800
2095600
1998500
1901300
1804200
1707100
1609900
1512700
1416000
1318500
1221400
4690800
928450C
13781000
183 80400
22482700
26687900
30795900
34806700
38720500
4253710C
46249000
49863700
53381300
56601700
601 25000
6331740C
66412600
69410700
72311700
75115500
77696800
80181000
82568000
84857900
87050700
89146300
91144800
93046) 00
94B5030C
96557400
98167300
99680000
1,01096000
102414500
103635900
2150200
2119600
2089200
2058700
2028100
1997500
1967100
1936600
1906000
1875600
1640100
1610000
1579400
1549000
1518400
1311600
1281200
1250600
1220100
1189700
952200
921600
891100
860700
830100
799500
769200
738400
708100
677400
647100
616500
585900
55560C
525000 <
( 2540600)
t 2474100)
2407300)
2340700 )
2274200)
2207700)
2140900)
2074200)
2007800 >
I 941 000 )
2071800)
2004700)
19382CO)
1871400)
1804900)
1880800)
1814000 )
1747500)
1680900)
1614100 )
1629100)
1562600)
1495900 )
1429200)
1362700)
1296100
1229300)
1162900)
1096100)
1029700)
962800 )
8962CO)
830100)
! 762900 >
69640C)
2540600)
5014700)
7422000)
9762700 )
12036900)
J4244600)
16385500)
18459700)
20467500)
22408500 )
24480300)
26485000)
28423200)
30294600)
32099500)
33980300)
35794300)
37541800)
39222700)
40836800)
42465900)
44028500)
45524400)
46953600)
48316300)
49612400)
50841700)
52004600)
53100700)
54130400)
55093200)
55989400)
56819500)
57582400)
58278800)
TOTAL 135000
25&4000
193135400
89499500
103635900
45357100 ( 58278800)
PRFSBMT WORTH IF DISCOUNTED AT 10* TO INITIAL YEAR
36843600
16864800
-------
Table B-165
PROCESS c. REGULATED POWER co. ECONOMICS, soc MW. , EXISTING UNIT, 3.5* s IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 17329600
YFARS
AFTFR
PDWFR
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/
KM
TONS/YEAR
TOTAL NH<3)
SCRUBBING-
FERTILIZER
MFG. COST
INCLUDING
REGULATED
ROI FOR POW-
ER COMPANY,
FERTILIZER S/YEAR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASEl
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
$/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NM(3)
SCRUBBING-
FERTIL IZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3) SCRUB-
BIN G-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
3
4
5
6
7
P
9
10
11
12
13
14
15
16
17
18
19
?0
2?
23
?4
75
26
27
28
?9
30
31
32
33
34
35
7000
7000
7000
7000
7000
7000
7000
5000
50CO
5000
5000
500C
3500
3500
3500
3500
3500
1500
1500
1500
150C
1500
1. 500
1500
1500
1500
1500
150C
1500
1500
1500
1500
137000
137000
137000
137000
137000
137000
137000
97JOO
97900
97900
97900
97900
66500
68500
6P500
6B500
68500
29400
29400
294CO
2S4CO
29400
29400
29400
29400
2S4CO
29400
29400
29400
29400
29400
29400
9955800
98433CC
9730700
9618200
5505700
9393200
9280600
7784300
7671800
7559200
7446700
7334200
6140200
6027600
5915100
5302600
5690000
4025400
3912900
3800400
368760C
3575300
3462 800
3350200
3237700
3125200
3012700
2900100
2787600
2675100
2562600
245000C
4695000
4695000
4695000
4695000
4695000
4695000
4695000
3388300
3388300
2388300
3388300
3388300
2391300
2391300
2391300
2391300
2391300
1042200
1042200
1042200
1042200
1C42200
1042200
1C42200
1042200
1042200
1042200
1042200
1C42200
1C42200
1042200
1C42200
5260800
5148300
5035700
4923200
4810700
4698200
4585600
4396000
4283500
4170900
4058400
3945900
3748900
3636300
3523800
3411300
3298700
2983200
2870700
2758200
2645600
2533100
2420600
2308000
2195500
2083000
3 970500
1857900
1745400
1632900
1520400
1407800
5260800
10409100
15444800
20368000
25178700
29876900
34462500
38658500
43142000
47312900
51371300
55317200
59066100
62702400
66226200
69637500
72936200
75919400
78790100
81548300
84193900
86727000
89147600
91455600
93651100
957341.00
97704600
99562500
101307900
102940800
104461200
105869000
2261500
2226100
2191000
2155600
,2120500
2085100
2050000
1804000
1768900
1733500
1698300
1663000
1447600
1412300
1377100
1341800
1306600
1061200
1025900
990700
955400
920200
884900
849700
814300
779200
743300
708700
673300
638200
602800
567700
2999300) (
2922200)
2844700)
2767600)
2690200)
2613100)
2535600)
2592000 )
2514600)
2437*00)
2360100 )
2282900)
2301300 )
2224000)
2146700)
2069500)
1992100)
1922000)
1.844800 )
1767500)
1690200)
1612900)
1535700)
1458300)
1381200)
1303800)
? 2267CO)
1 1492CO)
1072100)
994700)
917600)
( 840100)
2999300)
5921500)
8766200)
11533800)
14224000)
16837100)
19372700)
21964700)
24479300)
26916700)
29276800)
31559700)
33861000)
36085000)
38231700)
40301200)
42293300)
44215300)
46060100)
47827600)
49517800)
51130700)
52666400)
5412470C)
55505900)
56809700)
5*0364001
59185600)
60257700)
61252400)
( 62170000)
( 63010100)
TOTAL 114000
2232000
163265000
77396000
105869000
42858900 ( 63010100)
PRFSFNT WORTH IF DISCOUNTED AT 10% TO IMTIAL YEAR
40208100
16933200
-------
Table B-166
PROCESS C, PECULATED PCW5R CO. ECONCPICS, 500 MW., NEW UNIT, 5.0* S IN COAL, 19-14-0 FERTILIZER PROOLCTIQN
FIXED INVESTMENT: $ 19321300
YEARS
AFTFR
PDWRR
UNIT
START
ANNUAL
OPERA-
TION
KVJ-HR/
KW
TONS/YEAR
FFRT ILIZER
TOTAL Nh<3>
SCRUBBI NG-
FERT ILIZER
MFC. COST
INCLUDING
REGULATED
SCI FOR FCh-
ER COMPANY,
t/YEAR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
[DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE!
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTCNE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
$/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUB8ING-
FERTILIZER
INSTEAD OF
WET-LIME-
STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3 ) SCRUB-
8ING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STONE
SCRUBBING,
$
1
2
3
4
5
6
7
8
o
10
11
1 ?
1 3
14
1 5
16
17
la
19
20
?1
22
23
?4
25
26
27
2B
?9
30
31
3?
33
34
35
7000
7000
7000
7000
7COO
7000
70CC
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
350C
3500
3500
^ 500
1500
1 500
1500
1500
1500
1500
1500
150C
15CO
1500
1500
1500
150C
1500
191400
193.400
191400
191400
191400
191400
191400
191400
193400
19? 4CO
136700
136700
136700
136700
136700
95700
95700
95700
95700
95700
41000
41000
41000
41000
41000
41000
41000
41JOO
41000
4iOOO
41000
41000
41000
41000
41000
H569200
11454500
) 1339600
H??4800
j j.noooo
10995200
10880400
1C765500
10650700
1C535900
8723100
8608300
8493500
8378600
8263800
6328300
6713400
65986 CO
6483800
636S900
4371900
4257100
4142300
40?7500
3912700
3797900
368300C
3568200
34534CC
333P60C
3223800
3X09000
2994200
2879300
27645CO
6482700
6482700
6482700
6482700
6482700
6482700
6482700
6482700
6482700
6482700
4684700
4684700
4684700
4684700
4684700
3314100
3314TOO
3314100
33143 00
3314100
1446100
1446500
1446X00
1446100
1446100
1446100
1446100
1446100
1446' 00
1446X00
1446100
1446100
3446X00
? 446100
1446100
5086500
4971800
4856900
4742100
4627300
4512=00
4397700
4282800
4168000
4053200
4038400
3923600
3808800
3693900
3579100
3514100
3399300
3284500
3169700
3054800
2925800
2811000
2696200
2531400
2466600
2351800
2236900
2X22100
2007300
J892500
1777700
1662900
15481 00
1433200
1318400
508650G
10C58300
14915200
1965730C
24284600
28797100
331 94800
37477600
4164560C
4569880C
49737200
5366C800
57^69600
611 63500
64742600
68256700
7J65600C
74940500
7B110200
833 65000
84090800
P6901800
895980CO
923 79400
94646000
96997800
99234700
101 35680C
103364100
10525660C
.107C3430C
108697200
110245300
111678500
112996900
2506500
2473000
2439300
2405800
2372100
2338600
2304900
2271500
2238000
2204300
1903900
1870200
1836700
1803000
1769500
1512100
1478400
1444900
1411300
1377800
1078200
1044700
1011900
977500
944000
910300
876800
843100
8G9600
776200
742500
708800
675300
6411800
608100
2580000)
2498800)
2417600)
2336300)
2255200)
2173900)
2092800)
2011300 )
1930000 )
1848900)
2134500 )
2053400)
19721CO)
1890900 )
18096CO)
2002000 )
1920900)
18396CC)
( 1758400)
1677000)
1847600)
1766300 )
X6843CO)
16C3900)
1522600)
1441500)
1360100 )
1279000)
11977CO)
1116300 )
1035200)
9541CO)
872800)
7914CO)
710300)
2580000)
5078800)
7496400)
9832700)
12087900)
14261800)
16354600)
18365900)
20295900)
22144800)
24279300)
26332700)
28304800)
30195700)
32005300)
34007300)
35928200)
37767800)
395262CO)
41203200 )
4305080C)
44817100)
46501400)
48105300)
49627900 )
51069400)
52429500)
53708500)
54906200)
56022500)
57057700)
58011800)
58884600)
59676000)
60386300)
TOTAL 1350CC
36910CO
2395C94CO
126512500
112996900
52610600 ( 603863CC)
PRESENT WORTH IF DISCOUNTED AT 10* TC INITIAL YEAR
39847900
19662100
-------
Table B-1 67
to
PROCESS C. REGULATED PGwtR CO. ECCNCMICS, 5000
.i NEW UNIT, 3.5% S IN COAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: $ 24639300
YEARS
AFTFR
POWFR
UNIT
START
ANNUAL
OPERA-
TION
KW-HR/
KW
TONS/YEAR
PERTILIZFP
TCTAL NHOI
SCRUBBING-
FFRTILIZcR
•*FG. CGST
IKCLUDI NG
REGULAT ED
RCI FOR POW-
ER CDMPANY,
S/YFAR
NET
FERTILIZER
SALES
REVENUE,
I/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNAT IVE
OPESATI NG
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
S/YEAR
ANNUAL SAV-
INGS (LOSS)
USING NH(3)
SCRUBBING-
FF.RTILIZER
INSTEAD OF
WET-LIfE-
STONE
SCRUBBING,
$
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3> SCRU9-
BING-FERTILI-
ZER INSTEAD
OF WET-LIME-
STCNE
SCRUBBING,
t
1
2
3
4
5
6
7
a
9
10
11
12
13
14
15
If.
17
18
19
70
21
72
23
?4
?.5
26
27
28
29
30
31
32
33
34
35
7000
7 ore
7000
70CC
7000
7000
7000
70CC
7000
7000
5000
5000
500U
5000
50CC
35PO
3500
3500
?500
3500
150C
1500
'. 500
1500
1500
1 500
1500
1500
1 ^00
1 500
15CO
J.500
1 500
1SCC
150C
259500
25S5CO
259>CO
259500
259500
259500
259500
25S5CO
259500
259500
165*00
135*00
185*00
185-fOO
12S300
12 98 CO
129300
129dOO
5560C
556CO
55600 '
55600
55oOO
55600
55600
55600
55600
55600
55600
5E6CO
55oOO
55600
5i6CO
1 5145900
1 4599600
148534CC
14707200
14561 OCO
1441.4800
!4?68500
!4',22?OC
1 3976! 00
? 33300CO
11404500
11258300
11112100
10965900
10319600
890?3CO
8757100
8610900
84647CO
8318400
5658800
55! 26CO
5366400
5220] 00
•5073900
4927700
478140C
*635200
4*89000
434280C
4196600
40504CC
3904100
3757900
361170C
8677700
6677700
8677700
R677700
8677700
6677700
P677700
£677700
8677700
8677700
6286900
6236900
6286900
6286900
6286900
4456000
4456000
4456000
4456QOO
4456000
1949300
1949300
1949300
1949300
1949300
) 949300
1949300
1949300
1949300
J 949300
1949300
1949300
1949300
v 1949300
3 549300
6468200
632X900
6175700
6029500
5893300
5737100
5590800
544^600
5293400
5152300
511.7600
4971400
4.825200
4679000
4532700
4447300
4301100
4154900
4008700
3862400
3709500
3563300
3417100
3270800
3124600
2978400
2832100
2635900
2539700
2393500
22*7300
2101100
1954800
1808600
1662400
6468200
12790X00
3.8965800
24*95300
30878600
36615700
42206500
47651300
52949500
58101800
63219400
68) 90800
73016000
776 95 000
82227700
86675000
90976100
95131000
993 39700
10300210C
106711600
110274900
11369200C
116962800
120C87400
123C65800
125897900
128583800
131123500
133517000
13576430C
1.37865400
13982020C
14162880C
14?291200
3362400
3317000 (
3271900
3226500
3181200
31 ^5800
3090700
3045*00
3000000
2954900
25651.00
2519800
2474500
2429300
2384000
2053500
20C8400
1963100
191,7700
1872400
1496500
1451200
1405800
1360700
1315400
1270000
1224700
1)79500
1134200
1088300
1043 700
998400
953000
907700
862500
3105800)
30C49CO)
2903800)
28C3000)
2702100)
2601300)
25001 CO)
2399200)
2298400 )
21974CO)
2552500)
2451600)
2350700)
2249700)
2148700)
2393800)
2292700)
2191800)
2091000 )
1990000)
2213CCO)
2112100 )
2011300)
15101CO)
1809200)
17C84CO)
1607*00 )
1506400)
14C5500)
1304700 )
1203600)
31C2700)
1001800 )
9C0900)
799900)
3105800)
61 107CO)
9014500)
11817500)
14519600)
17120900 )
19621000)
22020200)
24318600)
265160CO)
29068500)
31520100)
33870800)
36120500)
38269200)
40663COO)
42955700)
4514750C)
47238500)
49228500)
5144150C)
53553600
55564900)
57475000)
59284200 )
60992600)
62600000)
64106400)
65511900)
66816600)
68020200)
69122900)
70124700)
71025600)
( 71825500)
TOTAL 135CPC
5005000
313022200
169731000
143291200
71465700 ( 71825500)
PRESENT WORTH IF OISCCLNTED AT 10? TC INITIAL YEAR
50606500
26463500
-------
Table B-168
PROCFSS C, REGULATED POWER CO. ECONOMICS, 1CCC MW., EXISTING UNIT, 3.5% S IN CGAL, 19-14-0 FERTILIZER PRODUCTION
FIXED INVESTMENT: t 26646400
YFARS
AFTFR
PDHER
UNIT
START
ANNUAL
OP/ELA-
TION
KW-HR/
KM
TONS/YEAR
FERTILIZER
TOTAL NH(3)
SCRUBBING-
FERTI LIZEK
MFG. COST
INCLUDING
REGULATED
BCI FOR POW-
ER COMPANY,
J/YEiR
NET
FERTILIZER
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE)
COST OF
POWER,
$
CUMULATIVE
NET INCREASE
(DECREASE)
COST OF
POWER,
$
ALTERNATIVE
OPERATING
COST FOR WET
-LIMESTONE
PROCESS IN-
CLUDING REG-
ULATED ROI
FOR POWER
COMPANY,
t/YEAR
ANNUAL SAV-
INGS (LCSS)
USING NHI3)
SCRUBBING-
FERTILIZER
INSTEAD OF
WET-LIME-
STCNE
SCRLaSING,
CUMULATIVE
SAVINGS
(LOSS) USING
NH(3> SCRUB-
BING- FERTILI-
ZER INSTEAD
OF HET-LIME-
STCNE
SCRUBBING,
$
1
2
3
4
5
6
7
R
9
10
11
12
13
14
15
16
17
18
19
20
21
22
73
24
25
76
77
78
79
30
31
3?
33
34
35
7000
7000
700C
7000
7000
700C
7000
500C
5000
5000
5000
5000
35CC
3500
3500
3500
35CC
1500
1500
1500
1500
1500
1500
15CC
15CO
1 500
1500
1500
1500
1500
1500
1500
268000
268000
268000
268000
268000
266CCO
268000
191400
191400
191400
1914CO
191400
134000
134000
134000
134000
134000
57400
574CO
574CO
57400
574CO
57400
57400
574CO
57400
574CO
574CO
57400
514CO
574GO
57400
1614270C
15969700
157966CO
15623600
15450500
1E2775CC
15104400
125507CO
I23776CC
12204500
120315CO
118584CC
9834900
9661 800
9488700
9315700
9142600
6340400
6167300
5994300
5323,200
5648200
5475100
5302000
512900C
4956000
4732900
460980C
4436800
4263700
409C7CC
3917600
8951200
8951200
8951200
8951200
8951200
8951200
8951200
6482700
6482700
6482700
6482700
6482700
4596200
4596200
4596200
4596200
4596200
2011300
2011300
2C11300
2011300
2011300
2C11300
2011300
2C11300
2C11300
2011300
2C11300
2011300
2011300
2C11300
2011300
7171 500
7018500
6845400
6672400
6499300
6326300
6153200
6068000
5894900
57Z1800
5548800
5375700
5238700
5065600
4892500
4719500
4546400
4329100
4156000
393 3000
3809900
3636900
3463800
3290700
3117700
2944700
2771600
2598500
24255CO
2252400
2079400
1906300
71 91500
14210000
21055400
27727800
34227100
40553400
46706600
52774600
58669500
64391300
69940100
75315800
80554500
85t20100
90512600
95232100
99778500
104107600
108263600
112246600
116C5650C
119693400
1231 57200
126447900
129565600
132510300
135281900
137880400
140305900
142558300
144637700
1465440CO
3587300
3533800
3480600
3427200
3373900
3319900
3267200
2857000
2803800
2750300
2696900
2643600
2294300
2241100
2187600
2134400
2080900
1685300
1632000
1578600
1525300
1471900
1418600
1365200
1311900
1258500
1205000
1151800
1098300
1045100
991600
938400
( 3604200)
3484700)
3364800)
3245200)
3125400)
30064CC)
2886000)
32110CO)
3091100)
2971500)
28519CC)
2732100)
29444CC)
28245CO)
2704900 >
2585100)
24655CO)
2643800)
2524COO)
2404400 )
2284600)
2165000)
2045200)
19255CO)
18C58CO)
1686200)
15666CO)
1446700 )
1327200)
1207300)
1087800)
967900)
3604200*
7088900)
10453700)
13698900)
16824300)
198307CO)
22716700)
25927700)
29018800)
31990300)
348422CO)
37574300)
4 05 187 CO)
43343200)
46048100)
48633200)
51098700)
53742500)
56266500)
58670900)
60955500)
63120500)
65165700)
67091200)
68897000)
70583200)
72149800)
735$65flO>
74923700)
76131000)
77218800)
78186700)
TOTAL 114000
4364000
2947664CO
148222400
1465440CO
68357300 ( 78186700)
U)
t—»
U)
PRESENT WORTh IF DISCOUNTED AT 10SE TO INITIAL YEAR
55036300
26919700
-------
INDIVIDUAL SCRUBBER BYPASS
PULVERIZED COAL
PSUM MATERIAL BALANCE fff-4-4
SLUICING PUMP TO POND
TANK
Figure C-1. Flowsheet—Process A
-------
DESCRIPTION
RATE. LBS./HR
scfM
PM
PARTICULATES, LBS./HR.
CMPEKATURE. -r
PECIFIC GRAVITY
ISCOSITY. CPS
NOBSOLVED SOLIDS, X
STREAM HO
DESCRIPTION
RATE. LBS./HR
Km
• PM
PARTICIPATES, LBS./HR
TEMPERATURE, * '
SPECIFIC GRAVITY
VISCOSITY, CPS
UMMS30LVCD SOLIDS, %
FH
STREAM NO.
DESCRIPTION
MTE. LM./HR.
SCFM
•Ml
PARTICULATO. LSJ/HR
TEMPiRATunt. •*
SPECIFIC BHAVITY
VISCOSITY, CPS
UNOSWLVEO SOUOS. »
>N
STREAM NO.
DESCRIPTION
RATE, LBS./HR.
tc.ru
0PM
PARTICULATES, LB3./HR.
TEMPERATURE, 'F
SPECIFIC BRAVITY
VISCOSITY. CPS
UNMSSOLVCD SOLIDS, *
PH
COAL
TO
575 M
AMBIENT
21
ASH SLURRY
TO
POND
69 6 M
-
130
LOT
12
41
AIR TO
•OX NTTfflC
ACID UMT
tMM
• I.SM
-
to
SI
WATER
TO
SCRUBBER
1,039
-
t.O*
sg
:OMBUSTION
AIR TO
AIR HEATER
4,777 M
ItO
22
DRAIN
T04TH
PLATE TANK
I70M
-
941
COMBUSTION
AIR TO
BOILER
4.30SM
943 M
BIO
23
RECYCLE
TO
4TB PLATE
194 M
-
30S
42
AMMONIA TO
SOX MTRK
ACID UMT
13. 9 M
4.S40
-
62
OAS
TO
VENT
4,«S6
1,639
•
120
43
WATER TO
90XHTRIC
ACID UMT
B.4SIM
-
IIM
• S
S3
LIOUOR
TO
SURGE TANK
I.2BT
-
2.T2
120
O.S3
4
GAS
TO
ECONOMIZER
4.B37M
33.TM
»0
24
OVERFLOW
TO 3RD
PLATE TANK
IB.2U
-
3S.4
1.00
as
S
GAS
TO
AIR HEATER
4,«S7M
33. 7 M
709
29
!«..
PLATE TANK
IBIM
.
30S
4
GAS
TO
COOLER
I.2SIM
B.43B
110
2«
RECYCLE
TO
S"» PLATE
IBIM
.
30*
GAS
TO
SCRUBBER
1.291 M
•,455
172
27
OVERFLOW
TO 2ND
PL ATE TANK
I6.9N
-
3I.B
1.04
0.7
44
NITRIC ACID
TO
EXTRACTOR
77.SM
-
IK
LSI
S4
SOLUTION
TO
EVAPORATOR
242M
-
403
ISO
1.2
49
EXTRACTOR
41. 3M
-
.
•S
STEAM TO
EVAPORATION
SYSTEM
ITSM
-
.
41
ANTI-FOAM
ABENTTO
EXTRACTOR
IB. 9
-
BB
WATER TO
DISSOLVMS
TANK
It.BM
-
39
B9
47
GAS
TO
SCRUBBER
I.BB9
310
-
IBB
B7
STEAM TO
DISSOUflNB
TANK
2.BII
-
-
IAS
TO
REHEATER
I.3I2M
39
119
2B
DRAM
TO 2"0
PLATE TANK
192 M
.
309
GAS
TO
STACK
I.3I2M
2B9M
39
2BO
2B
RECYCLE
TO
2"° PLATE
192 M
-
309
WARM WATER
TO GAS
COOLER
339{«
BBS
143
30
SOLUTION
TO
SURGE TANK
72. 8 M
-
Ill
120
1.24
9.9
0.3
HOT WATER
TOGAS
REHEATER
339M
729
2BO
31
AMMONIA
TO
NEUTRALIZER
2.927
1,089
-
WATER
TO SETTLING
TANK
79. Z>»
199
89
32
WATER
NEUTRALIZER
22. BN
.
49.9
89
4B
• WATER
TO
SCRUBBER
373
-
0.78
BB
BB
SOLUTION
TO
SURGE TANK
44.BM
-
71.4
IOO
1.29
49
GAS
TO
VENT
1,919
' 244
.
120
BB
CONDITIONER
TO
DRUM
1,738
-
-
SO
LIOUOR
PO°ND
709
-
1.13
120
TO
PRODUCT
TO
STORAGE
SB. SM
-
-
91
PRODUCT
TO
PRECIPITATOn
117 M
.
149
IBB
71
92
SLURRY
TO
FILTER
2 ISM
,
345
190
72
MAKE-UP
WATER TO
SCRUBBER
16 M
32
B9
33
SOLUTION
TO
OXIDIZER
49.2 M
.
82.8
IBS
1 l>
I.B
0.2
S3
WATER
FILTER
90.9M
-
101
89
73
AMMONIA
TO
SCRUBBER
2,224
14
AIR
TO
COMPRESSOR
28.9 M
8.380
• S
94
CAKE TO
SLUICING
TANK
74.7 M
-
-
74
AMMONIA
GAS COOLER
29 I
39
WATER
TO
INTERCOOLER
I98M
.
312
89
SB
WATER TO
"rilST
241 M
-
492
69
79
AMMONIA TO
2ND RECYCLE
PUMP
1,684
36
GAS
SCRUBBER
28. 7 M
6,067
-
96
SLURRY
TO
POND
319 M
.
998
20
7B
3RD RECYCLE
PUMP
342
37
SOLUTION
TO
PUMP
6I3M
-
1,009
IS9
1,22
I.B
97
FILTRATE
TO
SURGE TANK
199 M
.
329
77
4 TH RECYCLE
PUMP
169
38
WATER TO
SOLUTION
COOLER
1,096 M
-
2.116
69
9B
SOLUTION
TO
NEUTRALIZE*
241 M
.
409
100
78
TO SETTLING
TANK
374 M
741
1.01
2.S
39
RECYCLE
SOLUTION TO
OXIDIZER
562 M
-
922
135
1.23
2,2
39
AMMOMA
TO
NEUTRALIZER
9,653
2,103
,
79
20
TO
1ST PLATE
3S4M
40
SOLUTION
PRECIPITATOR
102 M
-
166
139
1.23
2.2
0.2
BO
T¥
SCRUBBER
4,983
1,719
.
190
80
NOTES:
I. CALCULATIONS BASED ON:
•. 3.9X SULFUR IN COAL (DRY BASIS)
b. 12% ASH COAL (AS FIRED BASIS)
e. 92 X OF SULFUR IN COAL EVOLVES AS SO]
d 79 X OF ASH IN COAL EVOLVES AS FLY ASH
>. MISCELLANEOUS INFORMATION FROM SCRUBBER MANUFACTURER
I 99.9« REMOVAL OF PARTICULATE9 TO SCRUBBERS
«. 90 X SO, REMOVAL
2. PARTICULATES SHOULD BE ADDED TO GAS TO 9ET TOTAL STREAM RATE
3. STREAM NUMBERS 6-29 ARE ONE OF FOUR SIMILAR STREAMS
4. STREAM NUMBERS 33-39 ARE ONE OF TWO SIMILAR STREAMS
CO
SYMBOL IN TABLE
M THOUSAND
REFCRCHCE DRAW/US:
PKOCfSS FLOW OIASKAH.
Figure C-2. Material Balance—Process A
-------
OJ
I—'
Ov
INDIVIDUAL SCRt**f*
HJLVtIHZCD COAL
MATERIAL BALANCE ._ r6i-A-ll
GYPSUM
SLURRY
SLUICING PUMP TO POND
Figure C-3. Flowsheet—Process B
-------
STREAM NO
DESCRIPTION
BPM
PARTICULARS, LBS./HR.
TEMPERATURE, *F
PECIFIC GRAVITY
VISCOSITY, CPS
MISSOLVED SOUDB, %
H
STREAM HO.
DESCRIPTION
ATE, LB9-/MR.
CFM
IPM
PARTKULATD. LBS/HR.
TEMPERATURE. 'F
SPECIFIC 8RAVITY
VIBCOSITX CM
uNMSsaycD SOLIDS.*
pH
STREAM NO.
OEKRBrnoN
ICFBJ
am
numcuutm, LBS./HR.
TEMPeRATURC. 'f
sptcvic BMwirr
VWCOBITV, CP8
MOnSOLVED SOUOS.%
IM
STREAM NO.
OESCRIPTW*
•ATE, LBB./HR.
SCFM
•PM,
PARTICULATES. LBS./HR
TEMPERATURE, *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNBBSOLVED SOLIDS,*
pN
1
COAL
TO
AMBIENT
COMBUSTION
AIR TO
110
COMBUSTION
AIR TO
• 10
GAS
TO
99.TU
00
GAS
TO
^WM"
33. TM
TOS
GAS
TO
274M
«.<53
910
T
GAS
TO
8.499
172
tl
RECYCLE
TO
1ST PLATE
984 M
.
7(8
41
RECYCLE
TO
SOLUTION
:
19.8
tt
ASH SLURRY
TO
POND
SS.SM
.
130
LOT
IS
41
SOLUTION
TO
-
112
114
I.O
1.8
o.s
is
DRAIN
TO STH
PLATE TANK
ISBM
.
999
41
AIR TO
•0* NITRIC
ACIDUNtT
4IH
-
IS
14
RECYCLE
TO
STH PLATE
IS4M
_
909
44
AMMONIA TO
«OH NITRIC
ACIO UNIT
1 8.TT8
9.M9
.
• 1
AMMgNU
NEUTRALIZE!
5,204
!,»»
-
SI
GAS
TO
SCRUBBER
1,009
2,1 12
-
190
tl
WATER
TO
SCRUBBER
148
i.sa
ss
•4
DAI
TO
VENT
9.T8I
2,099
-
110
IS
OVERFLOW
T04TH
PLATE TANK
18. 1U
.
90.4
1.00
0.8
4*
WATER TO
80* NITRE
ACIO UNIT
1 9.890M !
7,280
89
••
LIOUOR
TO
8UR8E TANK
1,188
-
tM
120
O.M
18
DRAM
TO 4TH
PLATE TANK
I84U
-
301
41
NITRIC ACID
TO
EXTRACTOR
:
78.9
1.99
(8
SOLUTION
TO
EVAPORATOR
ISIM
-
901
ISO
LZ
17
RECYCLE
TO
4TM PLATE
I84M
-
908
47
ROCK
TO
EXTRACTOR
-
-
87
STEAM TO
EVAPORATE)*
SYSTEM
I18M
-
•
GAS
TO
2B
119
11
OVERFLOW
TOSRO
PLATE TANK
IB.SM
-
l»5
lot
O.8
4*
ANTI-FOAM
AGENT TO
EXTRACTOR
I 18.2
88
WATER TO
DI9SOLVNG
TANK
I4.BM
-
18.9
89
8
GAS
TO
282M
89
290
IB
' DRAIU
TO 9«0
PLATE TANK
iTW
-
90S
4B
OAS
TO
SCRUBBER
1 '•*"
909
-
189
88
SrEAMTO
SSOLVMG
TANK
1,128
-
10
KARM WATER
TO GAS
99BM
149
90
-RECYCLE
TO
9MO PLATE
I79M
-
90B
90
WATER
TO
SCRUBBER
O.TS
SB
70
SOLUTION
TO
SURGE TANK
S9.8M
-
S4. 1
IOO
1.29
HOT WATER
TO GAS
33»M
280
11
OVERFLOW
TO 2ND
PLATE TANK
I8.ZM
.
27.*
1.18
1.7
WATER
TO SETTLING
TANK
7«.2M
89
91
DRAIN
TO 2«0
PLATE TANK
I99M
.
90S
«
MAKE-UP
WATER TO
ISM
69
99
RECYCLE
TO
2*
-------
00
SOLUTION
COOLER
BULK
STORAGE
BUILDING
REFERENCE DRAWING:
MATERIAL BALANCE AfO-A-4
Figure C-5. Flowsheet-Process C
-------
DESCRIPTION
)PM
NU*TlCOl,ftTES,LW./HR.
TEMPERA! 0«. *F
SPECIFIC GRAVITY
VISCOSITY, C*S
•H
DESCRIPTION
SCFM
PAlTTICULATES, L5S / HR.
TEMPERATURE. • ir
SPECIFIC ORAVITY
VISCOSITY, CPS
OESCMPTION
RATE. LBS./HR.
SCFM
GPM
PARTlCULATES, LBl/HR.
TEMPERATURE, 'F
SPECIFIC OHAVITY
VISCOSITY, CPS
UNOISSOLVED SOLOS, %
»H
STREAM NO.
DESCRIPTION
RATE,L8S./HR
SCFM
GPU
PARTICIPATES, LBS./HR,
TEMPERATURE. *F
SPECIFIC GRAVITY
VISCOSITY, CPS
UNOISSOLVED SOLIDS, %
»M
DESCRIPTION
SCFM
OP*
PARfWULATES, LBS./HR
TEMPERATURE, *F
SPCCIFIC ORAVITY
VISCOSITY. CPS
JMMUOLVEO SOLIDS, %
»H
C«5L
375M
AMBIENT
RECYCLE
»•» PLATE
SOLUTION
TO
RECYCLE
C.ZBOM
.
tOM
131
T«
•w
SCRUBBER
550
-
l.t
is
AIM
A
lieu
Bl
120
COMBUSTION
MR TO
VTTH
,
110
OVERFLOW
fOtW
PLATE TANK
-
1.04
0.7
.oumoK
2W EFFECT
«,504M
.
I0.4M
IM
.
COMBUSTION
AIR TO
4JOSM
MM*
610
rS-K,
PLATE TANK
VAPOR TO
CONDENSING
SYSTEM
29.4M
I0.4M
-
151
TT
•AS
TO
VENT
l.4tt
411
.
110
WOT
NCUTRALUD
— : —
W.O
120
us
TB
LIQUOR
r^D
•Bl
-
t.SO
ItO
fSD
SCREENS
— :
.
ISO
•»
4.6S7M
— 2*™ —
33.7M
BSO
«C«Li
2ND PLATE
INH4),S04
SLURRY TO
CENTRIFIME
ZZ4M
.
S3T
131
7»
SLURRY
FILTER
IIOM
-
t<3
1*5
OVERSIZE
CMlfuJ
:
_
— 515 —
•*.««
33.7M
709
SOLUTION
0 SETTLMO
TANK
ItO
1.24
B.«
M
UOUOR
TO
RECYCLE
I7SH
tBB
IM
tf
1,28111
1,438
310
sm,
TO FILTER
:
1.Z5
""*•"•
CONVEYOR.
43.2M
130
•0
WATER
TO
FILTER
4O.4M
.
M.*
B3
co&ra.
— : —
_
•1
EXTRACTOR-
•REOP1TATOR
40.4M
.
•at
T1
— : —
IBS
«
I.EBIU
1,455
(72
FILTRATE
n^Srm
-
t.«4
HOT AIR TO
DECOMPOSER
• PRI. W N. B
usu
I40M
1,000
B2
"SB"
BI.OH
.
FEEDO
«
i.aitM
35
1 IS
WATER
TO
FILTER
— its —
es
HOT AIR
TO
DECOMPOSER
X70M
BSL9M
LOOO
B3
tMM
TANK
IOSM
-
tM
•B
.c4L
M.9M
SB
%'
1^I2M
SB
250
ASH SLURRY
TO
POND
-
LJ —
LOT
°#
PRI. WH.B.
«4OM
I4ZM
-
745
MUM WATER
TO OAS
33HI
143
SOLUTION
NEUTRALIZE*
-
— HI —
U4
5.8
•AS
natk.
•40M
I4ZM
.
3M
B4
«£»
FOND
II5M
.
23S
1.13
to
CY&M
It.BM
4M
(•5
•9
FILTRATE
SUM?***
77.5M
-
IZ5
MB
LM
*Tr5
CYCLONE
IBM
73B
its
HOT WATER
R^EATER
33B
2BO
WATER
NEUTRAUEER
-
•S
OAS
TO
SEC. W.H.BL
MOM
I4XM
»4
M
w.™
5UROETAHK
I2M
24
•5
T
CONVEYOR
I
WATER
TO SETTLING
79.2 M
155
55
1 SOLUTION
TO
0XIDIZER
(•3
IJO
i.e
BAi
TO
SCRUHER
I4OM
i42M
.
140
B7
SOLUTION
TO
SCRUBBER
S.BSO
.
14.2
l.t)
RECYCLE TO
AMMONIATO)
ORANULATOR
I '
.
IBO
WATER TO
I4.4M
25. S
•5
AIR
TO
COMPRESSOR
«,2*0
B5
WATER
TO
SCRUMEM
2SJM
32 4
•5
••
ft-SE*
KUTRALIZEI
7.IBO
11.4
IZO
I.Z5
MR
TO
SCRUBBER
MAM
.
•IS
AMMONIA
TO
'••"
•«
WATER
TO
NTERCOOLEft
ss
flAS
TO
VENT
•42M
I42M
120
»
rar
NEUTRALIZE!
i,«aa
•IT
-
SOLUTION
TO
SCRUBBER
25.2
1,21
AMMONIA
GASCOOLEfl
29
OAS
TO
SCRUBBER
s,oe7
-«"
PUMP
Z4.3M
52.3
120
SO
HAS
TO
SCRUBBER
28.3*1
•,••5
230
AIR
TO
FAN
CI.7M
-
13
I2O
AMMONIA TO
2ND RECYCLE
L*64
4!
SOLUTION
TO
PUMP
IBS
1.5
-r
NEUTRALIZER
IS.3M
39,0
tl
HAS
TO
FAN
3T.OM
It.lM
IZO
•wss
reUTBALJZEF
I
24.9
120
1.23
NH4OH TO
3«D RECYCLE
2,012
433
WATER TO
SOLUTION
COOLER
55
STEAM
TO PltE-
NEUTRALIZER
3UM
EI.OM
MS
•2
SLURRY TO
AMMONIATOR-
•RAHULATOR
B5.5M
(22
230
ESSS!S
-------
-^u**^,
" ,«s*53£
UNIT SIZES
BULK SHIPPING BUILDING - 6Q'M SO'
£xrHACTOfi f/M/r- //0'r/Jf
NITftfC AClQ UNIT - I3O''M ZOO'
CONTROL BUILDING (AMMONIA) -*o'*6O'
HMi STOHAGS TANK - 73'Dim. x 7J'-£htfti
HNQt 3TQP.AG£ rANHS -37' Q.+. * JO'*;f/i
SifftGf TANKS -JQ'Q.-t. x /S'tKf*
OXIDIZ.ER - /O'Di*. x4O'fityft
CONDtTlON£H -5/tOJ - /•!'Os*. M SO *;?*
CONQ/riONER UNLOADING DOCK - /t'r/f
GYP3UM PONO - t/OO'x tfSO'
PACKASfO AQtLtfi UHITS -/f -4- * JO'-jf"
L EGFNft
PIPS. LINES FOP,:
I. Liquid Amman!?
2. Cfndrnsttr ftefttrn
J. Scrukifr issuer
+. #m~ Wfffr
J. Fire A Service HSgtfr
6. Pt**t Air
~6yPSUM JLt/AAY t-tNf
Figure C-7. Plot Plan
-------
(.0
to
SURGE TANK
(DUST SCRUBBING)
CIRCULATION PUMPS (4)
(DUST SCRUBBING)
RECIRCULATION PUMPS (3)
(REHEATING SYSTEM)
SYM. ABT t 5OO MW UNIT
SURGE TANKS (3)
(AMMONIA SCRUBBING)
TRANSFER PUMPS
+• H 4
CIRCULATION PUMPS (6)
(AMMONIA SCRUBBING)
FLUE GAS DUCT
GAS REHEATER
OXIDIZE*
r' DIA.X it'men
TRANSFER
PUMPS
CIRCULATION
TRANSFER
PUMPS
NEUTRALIZER
6'DIA. X t'HIGH
SURGE TANK
SO'DIA.X tS'HICH
SOLUTION COOLER
36'O.D. SHELL WITH
2O' TUBES
AIR COMPRESSOR
Figure C-8. Plan View
-------
ti
HOT£: SURGE TANKS, PUMPS 8
OXIOIZER SYSTCU OMITTED
ra> CLtiurr rscc PLAN:
Figure C-9. Elevation View
------- |