SUMMARY REPORT
on
A COST-UTILIZATION MODEL FOR SO2-CONTROL
PROCESSES APPLIED TO NEW, LARGE,
POWER-GENERATION FACILITIES
(Contract No. PH 86-68-88)
to
INDUSTRIAL CONTROL UNIT
PROCESS CONTROL ENGINEERING PROGRAM
NATIONAL AIR POLLUTION CONTROL ADMINISTRATION
DEPARTMENT OF HEALTH, EDUCATION AND WELFARE
January 17, 1969
by
A. W. Lemmon, Jr.. B. L Fletcher. R. E. Schuler,
and H. E. Carlton
BATTELLE MEMORIAL INSTITUTE
Columbus Laboratories
505 King Avenue
Columbus. Ohio 43201
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January 17, 1969
Mr. Dario R. Monti, Chief
Industrial Process Development Unit
Process Control Engineering Program
National Air Pollution Control Administration
Department of Health, Education and Welfare
5710 Wooster Pike
Cincinnati, Ohio 45227
Dear Mr. Monti:
Summary Report on
"Cost-Utilization Models for SOj-Control Processes"
Contract No. PH 86-68-88
Enclosed are an original reproducible and twenty-five (25) copies of the Summary
Report on "A Cost-Utilization Model for SC"2 -Control Processes Applied to New, Large,
Power-Gene ration Facilities". This report contains detailed results, conclusions, and
recommendations, and references of all work performed under Contract No.
PH 86-68-88 from December 20, 1967, through January 20, 1969.
The members of the project team at Battelle's Columbus Laboratories are grateful
for your assistance and cooperation in the performance of this contract, Your comments
and suggestions have been helpful, particularly those on the content and format of the
summary report. We, hopefully, have made the necessary modifications in the copies
which have been reproduced and are being transmitted to you herewith.
An aggressive program for use and evaluation of the developed model is suggested.
It includes:
(1) Improving the cost-elements-data bank
(2) Applying the model to specific locations and sizes of generation
facilities.
We would be pleased to submit a proposal to you at your request for the additional effort
which is needed.
-------
Mr. Dario R. Monti 2 January 17, 1969
If you have any questions or comments regarding this report or if you wish to dis-
cuss the possibilities of an ongoing program, please let me know.
Very truly yours,
Alexis W. Lernmon, Jr.
Project Director
AWLrpa
Enc. (25 plus 1 reproducible)
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TABLE OF CONTENTS
SUMMARY .... 1
INTRODUCTION 3
MODEL ORGANIZATION AND PROCEDURE 5
General Description of Model 5
Model Details 7
Forms 14
Analysis Identification and General Power-Plant Data ...... 14
Plant Construction and Start-Up Costs 15
Transmission-Facilities Construction Costs 18
Energy Generated and Energy Available for Distribution 20
Fuel Consumption, Cost, and Sulfur Content 22
Recurring Costs 28
Results of the Analysis 31
Subsystem and Component Costs . 34
COST ELEMENTS FOR FOSSIL-FUEL-BURNING POWER PLANTS 36
Initial Plant Costs 36
Recommended Values 40
Operation and Maintenance 40
Recommended Procedure 41
Transmission Costs 41
Data 42
Discussion 44
Recommended Procedure 45
Fuel Costs and Heating Value 48
Heat Rates 56
Recommended Values 59
Station Capacity Factor 62
Recommended Values 65
Sulfur Dioxide-Control Devices 65
Data 65
Recommended Procedure 68
Sulfur Content of Fuels 68
Data 78
Recommended Values 82
Sulfur Credits 82
Sulfur Composition 83
Sulfuric Acid Markets 83
Regional Value of Sulfur 86
Recommended Values for Recovered Sulfur 87
Carrying Charges Treatment of Financial Costs, Depreciation,
and Taxes 88
Insurance Costs 95
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TABLE OF CONTENTS
(Continued)
Page
NUCLEAR-POWER GENERATION 97
EXAMPLES OF APPLICATION OF COST MODEL 104
Detailed Example 104
Results of Specific-Service-Area Analyses 104
New York City Service Area 112
Baltimore Service Area 114
Central Kentucky Service Area . .114
Southeastern Ohio Service Area 114
Northern Indiana Service Area 118
Salt Lake City Service Area 118
Dallas Service Area 118
Los Angeles Service Area 118
Tampa Service Area 123
Summary of Estimated Costs 123
Sensitivity of Results 126
CONCLUSIONS AND RECOMMENDATIONS . 128
REFERENCES 131
APPENDDC A
BACKGROUND AND DISCUSSION OF MODEL METHODOLOGY AND
LIMITATIONS A-1
APPENDIX B
LISTING OF POWER GENERATION FACILITIES PLANNED AND UNDER
CONSTRUCTION FOR THE TIME PERIOD 1968 THROUGH 1977 . . . . . . B-l
LIST OF TABLES
Table 1. Forms Provided for the Analysis 8
Table 2. Summary of Equations Used in Model and Symbol Definitions .... 11
Table 3. Construction Cost Indexes for Major Cities (September 1968) ... 38
Table 4. Range of Estimated Costs Per Mile for High-Voltage Overhead
Transmission Lines 43
Table 5. Cost of Compensating Reactors 44
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LIST OF TABLES
(Continued)
Page
Table 6. Steam Electric Generating Stations' Average "As-Burned"
Fuel Costs for 1966 49
Table 7. Fuel Costs and Characteristics of Utilities' Generating Stations
Obtained Through Interviews • 50
Table 8. Volume Fuel Costs at the Generating Station for Consolidated
Edison Co. of N. Y., Inc. Before and After Establishment of
Policy to Burn Low-Sulfur Fuel 56
Table 9. Cost of Fuel Oil ($/bbl) for Various Public Service Electric and
Gas Co. Generating Stations and for Different Sulfur Contents
(August 1, 1968) 58
Table 10. Heat Rates for 300 Mw and Larger Electric Generating Units ... 60
Table 11. Average Generating-Station Capacity Factor by U. S. Census
Region - 1966 Estimates 63
Table 12. Historic and Estimated Future United States' Average Capacity
Factor by Energy Source 64
Table 13. Capital and Operating Costs for Sulfur Dioxide Control Devices ... 65
Table 14. Coefficients for Cost-Estimating Relationships 68
Table 15. Shipments and Sulfur Content of Bituminous Coal to Electric
Utilities in 1964, by Final Destination 71
Table 16. Sulfur Content of Number 6 Fuel Oil 78
Table 17. Apparent Consumption of Sulfur in the United States 84
Table 18. Estimated Consumption of Sulfur in the United States by
Acid and Nonacid Applications 84
Table 19. Production of New Sulfuric Acid and Calculated Consumption
of Sulfur in the United States, by Selected Areas 85
Table 20. I960 Average Property Tax Rates (Percent) on all Taxable
Property 89
Table 21. Estimated Levellized Annual Carrying Charges (Percent)
for Various Return Rates and Planning Periods 92
Table 22. Estimated Percent Distribution of U. S. Average Electric
Utility Returns After Taxes but Before Interest 93
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LIST OF TABLES
(Continued)
Page
Table 23. 1966 Effective State Income Tax Rates, Gross Receipts Tax
Rates, and Taxes (Percent) on Generation of Electricity
Converted to an Equivalent Gross-Receipts Basis 94
Table 24. Nuclear-Generation-Cost Estimates Derived From Utility
Interviews 98
Table 25. Nuclear Plants Under Construction or Announced 99
Table 26. Estimated Nuclear Operating, Maintenance and Insurance Costs. . . 102
Table 27. Approximate Generating Costs Excluding Long-Range Escalation . . 102
Table 28. Estimates of Nuclear-Electric-Power-Generation Unit Costs
for a Plant Starting Operation After 1974 - 80 Percent
Assumed Plant Factor 103
Table 29. Costs for Power Generation at a Hypothetical 800-Mw
Generation Plant Serving the New York City Area 113
Table 30. Costs for Power Generation at a Hypothetical 840-Mw
Generation Plant Serving the Baltimore Area 115
Table 31. Costs for Power Generation at a Hypothetical 800-Mw
Generation Plant Serving the Kentucky Area 116
Table 32. Costs for Power Generation at a Hypothetical, 600-Mw
Generation Plant Serving the Ohio Area .. . . .117
Table 33. Costs for Power Generation at a Hypothetical 2082-Mw
Generation Plant Serving the Northern Indiana Area 119
Table 34. Costs for Power Generation at a Hypothetical 800-Mw
Generation Plant Serving the Salt Lake City Area 120
Table 35. Costs for Power Generation at a Hypothetical 800-Mw
Generation Plant Serving the Dallas Area . , 121
Table 36. Costs for Power Generation at a Hypothetical 800-Mw
Generation Plant Serving the Los Angeles Area 122
Table 37. Costs for Power Generation at a Hypothetical §00-Mw
Generation Plant Serving the Tampa Area 124
Table 38. Summary of Estimated Costs of Power Delivered to
Distribution Network 125
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LIST OF FIGURES
Page
Figure 1. Cumulative Nonrecurring and Recurring Costs for Power
Plant With and Without an SO2-Control Process (SCP) 6
Figure 2. Simplified Flow Chart of Model 9
Figure 3. Form A - Analysis Identification and General Power-Plant Data . . 16
Figure 4. Form NR - Plant-Construction and Start-Up Costs 17
Figure 5. Form T - Transmission Facilities Construction Costs 19
Figure 6. Form E - Energy Generated and Energy Available
for Distribution 21
Figure 7. Form FC - Coal Consumption and Cost and Sulfur Content
Summary 24
Figure 8. Form FO - Oil Consumption and Cost and Sulfur Content
Summary 25
Figure 9. Form FG - Gas Consumption and Cost 26
Figure 10. Form R - Recurring Cost Summary . - 29
Figure 11. Form S — Summary of Results of Analysis 32
Figure 12. Total SO2 Released to Atmosphere With and Without
SO2-Control Processes (SCP) 34
Figure 13. Construction Costs for Coal-Fired Electric Generating Units ... 37
Figure 14. Unit Costs of Fossil-Fueled Electric Generating Stations
Corrected for Regional Variation (ENR = 1200) 39
Figure 15. Cost-Estimating Relationship for Operation and
Maintenance Costs 41
Figure 16. Auto-Transformer Costs (Three Winding, OA/FOA/FOA,
15-KV Tertiary HV and LV-Grounded Y) 42
Figure 17. Capital Cost of Transmission JLines 46
Figure 18. Capital Costs for Overhead Transmission Lines 46
Figure 19. Transformer Costs for Transmission Lines (Stepup and
Stepdown From 220 kv) 47
Figure 20. Electrical Losses in Transmission Lines Per Mw hr Delivered
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47
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LIST OF FIGURES
(Continued)
Page
Figure 21. 1966 Average Cost of Coal "As Burned" at Electric Generating
Stations 500 Mwe and Larger in Cents Per Million Btu 51
Figure 22. 1966 Average Cost of Oil "As Burned" at Electric Generating
Stations 500 Mwe and Larger in Cents Per Million Btu 52
Figure 23. 1966 Average Cost of Natural Gas "As Burned" at Electric
Generating Stations 500 Mwe and Larger in Cents Per
Million Btu 53
Figure 24. 1966 Average Heating Value of Coal Burned at Electric .Generating
Stations 500 Mwe and Larger in 1000 Btu's Per Pound 54
Figure 25. Averages of 59 Price Quotations (7/68) for Coal Delivered to
Public Service Electric and Gas Company's Hudson Generating
Station (455 Mwe) Jersey City, N. J., as a Function of
Sulfur Content 57
Figure 26. Capital Costs for Alkalized-Alumina-Type SO2 Control Device. . . 69
Figure 27. Capital Costs for Catalytic-Oxidation-Type SO2 Control Device . . 69
Figure 28. Operating Costs for Alkalized-Alumina Process 70
Figure 29. Operating Costs for Catalytic-Oxidation Process 70
Figure 30. Sulfur Contents of Coal 79
Figure 31. Map of the Coal-Producing Districts of the United States .... 80
Figure 32. Geographical Areas of the National Survey of Burner-Fuel Oils . . 81
Figure 33. Median and Estimated Average U. S. Electric Utility Returns
(After Taxes and Depreciation But Before Interest) as a
Percent of Net Plant Investment 91
Figure 34. Annual Property and Liability Insurance Costs for a Generating
Unit as a Function of Unit Size 96
Figure 35. Trend of Installed Costs of Nuclear Electric Generation
Stations by Size Range 100
Figure 36. Capital Investment Average Site and Labor Conditions -
1974 Operation 101
Figure 37. Nuclear Fuel Cycle Cost Forecasts 101
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LIST OF FIGURES
(Continued)
Page
Figure 38. Form A - Analysis Identification and General Power-Plant Data . . 105
Figure 39. Form S — Summary of Results of Analysis 106
Figure 40. Form NR - Plant-Construction and Start-Up Costs 107
Figure 41. Form E - Energy Generated and Energy Available
for Distribution 108
Figure 42. Form FC - Coal Consumption and Cost and Sulfur Content
Summary 109
Figure 43. Form R — Recurring Cost Summary 110
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A COST-UTILIZATION MODEL
FOR SO2 -CONTROL PROCESSES
APPLIED TO NEW, LARGE,
POWER-GENERATION FACILITIES
by
A. W. Lemmon, Jr., B. L. Fletcher, R. E. Schuler,
and H. E. Carlton
January 17, 1969
SUMMARY
In the search for an effective means for decreasing SO2 emissions resulting from
the use of fossil fuels, a number of control techniques have been proposed and are being
investigated. To permit comparison of the various potential techniques, a standardized
method has been needed. To this end, a cost-utilization model has been developed which
permits the estimation of the incremental cost for control. Specifically, the model has
been formulated to apply to large fossil-fuel-burning electric power stations using SO£-
control processes which result in the recovery of sulfur or sulfuric acid as a by-
product. So that the model will have maximum utility in its present form, provision
has been made for the additional alternatives of: remote siting, nuclear generation, and
substitute fuels having lower sulfur contents.
The model as developed and presented in this report has been formulated as a
group of algebraic expressions. However, emphasis is placed on the use of computa-
tional forms which are provided to assist in organizing input data and performing the
required calculations. These forms are accompanied by data (tabular, graphical, and
in other forms as well) which permit the selection and entry of the appropriate numeri-
cal value in the proper location on a form once a specific SO£ control or other alterna-
tive has been selected. Following the forms in the proper, described sequence results
in the prediction of the cost of electricity (as delivered to the distribution network) which
would be achieved through application of the specified power-generation alternative.
(The costs are not those to the ultimate consumer since other costs — such as those for
distribution, billing, etc. — would have to be included.) Also obtained would be pre-
dicted values for the amount of sulfur removed, for example. The form provided for
the summary of results allows easy comparison of the results obtained for different ap-
proaches to SO2 control for any given service area.
No attempt has been made to include in the present model techniques for determin-
ing the "optimum" process for a specified location and size of generating facility. How-
ever, by the systematic application of the model to numerous alternatives and a set of
locations, the best alternatives will be identified. To illustrate this point, a series of
computations for several locations and alternatives have been performed. Cost of power
delivered to a distribution network varied from a low of 3.67 mills/kwhr for local gen-
eration in an 800-Mw station serving the Dallas area using natural gas as a fuel to a high
of 9.01 mills/kwhr for mine-mouth generation in an 800-Mw station serving the
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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New York City service area. Costs for control (using the alkalized-alumina process)
ranged from a low of 0.26 mills/kwhr for a 2082-Mw station burning 3 percent sulfur
coal to serve the Northern Indiana area to a high of 0. 53 mills/kwhr for an 840-Mw
station burning 3 percent sulfur oil to serve the Baltimore area. For the Northern
Indiana example, the control cost would drop to 0. 18 mills/kwhr if 5 percent sulfur coal
were burned. Costs for control using the Cat-Ox process were also within this range.
Costs for nuclear generation were predicted as 5.28 mills/kwhr for the Northern Indiana
service area and 5.86 mills/kwhr for the Baltimore and New York City service areas.
These were the only nuclear-generation examples computed.
Important indications have been provided by these examples. First, costs for
nuclear generation appear to be competitive with those for fossil-fuel generation, par-
ticularly in high-cost areas for fuel and labor. Second, with currently available
cost information, costs for SC>2 control using processes providing for recovery of sulfur
or sulfuric acid in new, large, power-generation facilities should not be expected to ex-
ceed 0.5 mills/kwhr. Finally, the use of mine-mouth generation without SC>2 control is
not expected to provide a viable alternative because of the high cost of transmission.
It has been concluded that a useful, valid cost-estimating model has been developed
for comparing various alternative methods for controlling SC>2 emissions from large,
new, power-generation stations. However, there are additional needs for a continuing
program to improve the cost data bank and to test further the application of the model to
specific locations and sizes of generation facilities. When these immediate steps have
been accomplished, then a further look should be taken to evaluate the potential benefits
which might accrue from extending the model to include some optimization technique
and/or to computerize it.
BATTEULE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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INTRODUCTION
The problem of atmospheric pollution over the United States is gradually intensify-
ing, and one of the major contributors to this problem is the power -generation industry.
Millions of tons per year of noxious gases are emitted by power plants fired with fossil
fuels. These noxious gases include sulfur dioxide (SO 2) and nitrogen oxides as major
constituents. Recently, intensive interest has been directed at SO 2 as a prime object of
current and future control activities.
Predictions of the growth of the power -gene ration industry and the fossil -fuel -
fired segment have been made. For example, the report of National Academy of
Science's Committee on Pollution(l)* states that "even with the assumption that, by the
year 2000, 50 percent of the U. S. electric generating capacity will be nuclear, it is
projected that fossil -fuel -fired electric generating capacity will double by 1980 and re-
double by the year 2000. As a consequence, emission quantities would also double by
1980 and redouble by 2000. . ." With regard to SO2 emissions it is further stated that,
for the case of severe but realistic controls, SO£ emissions would be expected to in-
crease by 75 percent by 1980 and by an additional 75 percent by 2000. Even with "con-
trol at the maximum level that technology will be able to achieve. . .a 20 percent increase
(in SO2 levels) by 1980 but a 20 percent decrease from that level by 2000. . ." would be
expected.
Thus, the size of the problem is large, and it implies, to some degree, the diffi-
culty of the situation which is faced. For the Federal Government, the National Air
Pollution Control Administration has the assignment of encouraging and supporting the
development of the necessary control technology. In this Federal program, there is a
limit to available funds, manpower, and facilities. As a result, only those processes
that show greatest potential promise for control can be investigated. For greatest effi-
ciency, early decisions as to potential promise should be possible. It is this capability
for early evaluation and decision which needs to be enhanced and to which this program
has been directed.
In planning for the development of SO2 -control processes, two major considera-
tions enter into the decision -making process regarding which processes are likely to be
advantageous:
(1) The additional cost of electricity that results from use of a specific
-control process
(2) The utility of the 803 -control process in terms of its applicability to
specific power plants and the implications this has regarding the
amount of SO£ that will be prevented from entering the atmosphere.
There are other factors that enter into the development -decision process, such as the
evaluation of technical feasibility, but this cost -utilization model is concerned with
evaluation of only those factors listed above. "Benefits" cannot be evaluated at the pres
ent state of our knowledge and, thus, so-called cost-benefit factors cannot be computed.
Arbitrary levels of SO£ concentration in stack gas will form the basis for the compari-
sons to be made.
'References are listed on page 131.
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It should be noted here that the model also contains provision for evaluating the
cost and utility implications of other approaches to SO2 control other than the treatment
of flue gas. The use of low-sulfur coal can be evaluated by suitable adjustment of fuel
costs, and the remote-location approach can be costed by adjustment of transmission,
fuel, and other cost elements that depend upon location. Comparison with costs achieved
by nuclear generation is also possible.
BATTEULE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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MODEL ORGANIZATION AND PROCEDURE
General Description of Model
The model developed in this program is designed to enable the analysis of the in-
cremental cost of approaches to controlling SO2 emissions of large fossil-fuel-burning
electric power plants. The model also contains provision for evaluating the costs of
approaches to SO2 control other than the treatment of flue gas. For example, the use of
low-sulfur coal can be evaluated by suitable adjustment of fuel costs, or a remote-siting
approach can be considered by inclusion of transmission costs and the adjustment of fuel
and other cost elements that depend upon location. The incremental cost is ultimately
expressed in terms of a "mills/kwhr" value above that for power generation without an
SO2 -control approach.
The model is concerned with power-generation costs only, except in the case when
transmission costs are included because remote siting is being considered as an alter-
native approach to SO2 control. The costs developed, then, are not those to the ultimate
consumer, since other costs — such as those for distribution — would have to be
included.
The model is formulated as a group of algebraic expressions. However, emphasis
is placed on use of the forms that are also provided to assist in organizing input data and
performing the required calculations. Use of these forms helps to insure that the re-
quired cost elements are considered, that the proper computations are completed, and
that records are made of the analysis. The form provided for the summary of results
allows easy comparison of the results obtained for different approaches to SO2 control
for the power plant of interest. The input data are obtained from curves showing "cost-
estimating relationships" (CER's) or tables provided in the section on Cost Elements for
Fossil-Fuel-Burning Power Plants.
Costs are regarded as falling in the two broad categories - nonrecurring and re-
curring. Nonrecurring costs are those required for initial equipment installation and
start-up and, if applicable, the cost of additional-equipment installation that may take
place after the plant is in operation; for example, an additional power-generation unit
might be installed after several years of operation of the first unit. Recurring costs
are those costs for fuel, operations, maintenance, and other annual expenses. Deter-
mination of the nonrecurring and the annual recurring costs permits the analyst to gen-
erate plots such as those shown in Figure 1. The nonrecurring cost is shown as an
initial cost at the start of the first year of operation, and the recurring-cost cumulative
total is plotted for each subsequent year of the time period of interest.
Use of the nonrecurring-recurring cost approach avoids the problems associated
with determining the annual charges that arise because of the initial investment. How-
ever, in order to determine an incremental "mills/kwhr" value that reflects both non-
recurring and recurring costs, it is necessary to "annualize" the nonrecurring costs.
This requires consideration of "financial factors" such as the cost of capital, the period
and type of depreciation, and income-related taxes. Provision is made in the model for
including such "financial factors" as an annual cost that is added to other recurring
costs. This sum of the annual costs divided by the sum of net energy available for dis-
tribution for the planning period provides the desired "mills/kwhr" value.
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Ul
o
c
o
o
o
3
e
Initial nonrecurring cost
FIGURE 1. CUMULATIVE NONRECURRING AND RECURRING COSTS
FOR POWER PLANT WITH AND WITHOUT AN SO2-
CONTROL PROCESS (SCP)
The model permits analysis on a yearly basis or on a cumulative total basis for a
specified planning period. In cases where the annual costs do not vary, the analysis of
only the nonrecurring cost and 1 year's recurring cost is required. However, if
changes in "capacity factor"*, power-generation capacity, fuel characteristics, or other
factors are expected to occur after the first year of operation, then annual costs must
be adjusted accordingly. The model makes provision for this by allowing for annual
entries of recurring costs.
The concern of this model is with future costs, and there are many problems
associated with translating past cost experience into a future estimate. To avoid some
of these problems, future cost estimates are made in terms of current dollars. Also,
provision has been made for the adjustment of historic construction cost data to current
dollars, (see p 40.)
This program has not been primarily concerned with generating the detailed in-
stallation, operation, and maintenance costs for SO£ -control equipment and the asso-
ciated by-product plant, although a limited amount of work has been performed in this
area to help guide model-development efforts. The costs for the 50% -control approach
are entered as increments to the nonrecurring and recurring costs of power-plant con-
struction and operation. This is accomplished by one of the following procedures:
(1) The nonrecurring and recurring costs for the SO2 -control equipment
and by-product plant are entered in combination or separately on the
appropriate forms to enable addition to the nonrecurring and recurring
costs of the power plant. If the nonrecurring and recurring costs for
• See p 62 for definition of "capacity factor".
BATTELLE MEMORIAL. INSTITUTE - COLUMBUS LABORATORIES
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the power plant without SO2 control are influenced by the use of SO2-
control devices — for example, if boiler-plant modifications are
required — then these costs are adjusted accordingly. Provision is
also made for allowing credits for the sale of by-product.
(2) If a fuel change is used for SO2 control, the incremental cost is de-
termined by evaluating the recurring fuel costs resulting from changes
in fuel price and consumption, the latter being influenced by possible
changes in heat rate of the power plant and heat content of the fuel.
(3) If remote siting is considered as an option to the use of an SC>2 control
process, then the nonrecurring and recurring costs for power trans-
mission are considered.
Provision is made in the model for determining the total weight of sulfur contained
in the fuel burned. If the analyst knows or assumes an efficiency of SC>2 removal of the
SO2-control process, he can then compute the amount of sulfur removed that would
otherwise be released to the atmosphere as SC>2. Such data, along with the incremental
costs required for the SC>2 -control process, then permit the analyst to calculate the cost
per ton of sulfur prevented from entering the atmosphere as SC>2.
An important consideration in the model is the time period to be examined in the
cost analysis. Ideally, cost data starting with the first significant research expenditure
for the SO2-control process along with all other nonrecurring and recurring costs for
the power plant and the SC>2-control-process facilities — with credits for the sale of by-
products — and continuing throughout the life of the power plant would be considered.
However, this ideal must be tempered with the realization that cost uncertainties in-
crease with the extent of the time horizon. For this reason, the position taken is that
cost projections beyond a ZO-year plant operation period are not meaningful in terms of
evaluating the relative economics of SC>2 -control-process alternatives.
Additional discussion of the background and other considerations that influenced
the structure of the model are found in Appendix A.
Model Details
The details of the model are described below. This description is organized
around a discussion of the equations used for calculations and the forms that have been
developed for the analyst to use in orgai....zing input data, performing the required cal-
culations and summarizing results. Reference is also made to the appropriate section
of the report for obtaining the required input data.
Figure 2, Simplified Flow Chart of Model, provides an overview of the type and
sequence of computations used in the model. The applicable equations and forms used
for each calculation are indicated. Table 1 lists the forms provided for the analyst, and
Table 2 supplies a summary of the equations used and definitions of symbols in the equa-
tions. The figure number for each form used is indicated, and the text accompanying
each figure should be referred to in order to understand what alternative computations
can be made according to the type of available input data. Some of the terms of the
equations shown in Table 2 are set equal to zero according to the requirements of the
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TABLE 1. FORMS PROVIDED FOR THE ANALYSIS
Title
Form A
Form NR
Form T
Form E
Form FC
Form FO
Form FG
Form R
Form S
ANALYSIS IDENTIFICATION AND GENERAL POWER-
PLANT DATA
PLANT CONSTRUCTION AND START-UP COSTS
TRANSMISSION-FACILITIES CONSTRUCTION COSTS
ENERGY GENERATED AND ENERGY AVAILABLE FOR
DISTRIBUTION
COAL CONSUMPTION AND COST AND SULFUR
CONTENT SUMMARY
OIL CONSUMPTION AND COST AND SULFUR
CONTENT SUMMARY
GAS CONSUMPTION AND COST
RECURRING COST SUMMARY
SUMMARY OF RESULTS OF ANALYSIS
particular analysis; for example, Equation (1), which is used to determine the sum of
nonrecurring costs (Tj^jj^), would be used with C (SO2 -control -process equipment costs)
and B (by -product -plant construction costs) set equal to zero in the case where an
-control process is not applied.
In general, the analyst must first establish the nonrecurring and recurring costs
of the power plant without an SO2 -control approach. The cost analysis is then repeated
for the various control options of interest. By "annualiaing" the nonrecurring costs,
adding these to the recurring costs, summing the resultant for the planning period, and
then dividing by the total electrical energy made available for distribution during the
planning period, a "mills/kwhr" value is obtained. This value for the various control
options can be compared to that for the power plant without SO£ control — the difference
in these values is an overall incremental cost for SO2 control.
The data generated also permit the calculation of a dollar per kilowatt value on the
basis of nonrecurring costs and the nameplate generating capacity of the power plant.
Another calculation provided for is that to determine the cost per ton of sulfur removed
that would otherwise enter the atmosphere as
A capability required of this model is to permit the analyst to introduce incre-
mental costs for SO£ -control approaches. This is accomplished by introducing nonre-
curring and recurring costs as entries in the various forms to be discussed. The ana-
lyst has considerable freedom in the amount of detail shown for such incremental costs.
For example, he can enter separate costs for the operations, maintenance, taxes (non-
income), and insurance when entering recurring costs for the SO£ -control equipment
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
c
Prepare analysts
Identification and
general power-plant data
- Form A, Figure 3
Analysis for Type of SO2 Control Approach Indicated
Computation for power
plant without 805
control approach
Compute plant -
construction and
start-up costs
- Equation (1)
- Form NR, Figure 4
SO2 -Control
Process Used
Compute energy
generated for each
year of planning
period and total
- Equation (3)
- Form E, Figure 5
Yes
Revise plant-
construction and
start-up costs
- Equation (1)
- Form NR. Figure 4
No
Compute energy available
for distribution for each year
of planning period and total
- Equation (4)
- Form E, Figure 6
Include SO^ control
equipment and
by-product plant In
nonrecurring costs
- Equation (1)
- Form NR, Figure 4
heat rate
Compute fuel
consumption and cost
- Equation (5)
- Form FC (coal), Figure 7
- Form FO (oil), Figure 8
- Form FG (gas). Figure 9
Compute sulfur
content of fuel
- Equation (6)
- Form FC (coal), Figure 1
- Form FO (oil), Figure 8
^*v altered by .X^
^•process?^
t Yes
Recompute fuel
coniumption and cost
- Equation (5)
- Form FC (coal), Figure 7
- Form FO (oil), Figure 8
- Form FG (gas), Figure 9
+
Recompute sulfur
content of fuel
- Equation (6)
- Form FC (coal), Figure 1
- Form FO (oil), Figure 8
Compute recurring costs for
each year of planning
period and total
- Equation (8) '
- Form R, Figures 10 and 11
ectnc energy >.
cost for SOo control process
Recompute energy available
for distribution for each year
of planning period and total
- Equation (4)
- Form E, Figure 6
Recompute recurring
costs for each year
of planning period and
total, including those for
SO2 control process and
by-product plant
- Equation (8)
- Form R. Figures 10 and 11
Fuel Change
Remote Siting
start-up costs
Equation (1)
Form NR, Figure 4
Compute transmission
facilities -construction
- Equation (2)
- Form T. Figure 6
a
Q.
Revise plant-construction
and start-up costs to Include
transmission facilities
- Equation (1)
- Form NR. Figure 4
Recompute fuel
consumption and cost
- Equation (5)
- Form FC (coal). Figure 7
- Form FO (oil), Figure 8
- Form FG (gas), Figure 9
(gas),
Recompute sulfur
content of fuel
- Equation (6)
- Form FC (coal), Figure 1
- Form FO (oil). Figure 8
Recompute recurring costs
for each year of planning
period and total
• Equation (8)
• Form R. Figures 10 and 11
Compute energy available
for distribution for each year
of planning period and total
- Equation (4)
- Form E, Figure 6
Recompute recurring costs for
each year of planning period
and total
- Equation (8)
- Torm R, Figures 10 and 11
Summarize Results
on Form S
Computes Aw on
nonrecurring cost
basis
Compute mills/kwhr on
basis of total energy
for distribution and sum
of recurring and
annualized nonrecurring
costs
Determine additional
mllls/kwhr (Incremental
cost) for SO2 control
approach
Compute $/ton of sulfur
removed
A-55781
FIGURE 2. SIMPLIFIED FLOW CHART OF MODEL
Note: Referenced equations are shown in Table 2.
-------
11
TABLE 2. SUMMARY OF EQUATIONS USED IN
MODEL AND SYMBOL DEFINITIONS
Equation Symbol Definition
(1) TNR =P + S+ C + B+ T
^NR Total nonrecurring conotruc'don and
start-up coots
P Power-plant construction coot
S Start-up cost
C SOg-control-process equipment coot
B By-product-plant construction coat
T Transmission-facilitieo construction
cost
(2) TT = I + E + MjDj + M2D2
(3) ET> . = 8. 766 x 1(T5 x Y. x
Nonrecurring coot for tranamioaio>a
facilities
Coot of structures and improvements
at the power plant
Coct of station equipment
Number of miles of overhead
transmission lines
Cost per mile for overhead traxio-
mission lines
Number of mileo of underground
transmission lines
Coot per mile for
£raaomic30ion lines
E_, Total energy generatedj h;'J.l:lo:a.j of
kwhr
Y Capacity factor, %
Pj^ Nasmeplate generating capacity; Mw
i Subscript fco indicate i^ ynay
0ATT2LLE MEMORIAL INSTITUTE
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12
TABLE 2. (Continued)
" EBPP, i " ETR,
Equation Symbol Definition
(4)
ENET Energy available for distribution
ET Total energy generated
Epp Energy consumption in power plant
Ee/-p Energy required for SO^-control
equipment
ERpp Energy required for by-product-
plant operation
Erprj Transmission energy losses
i Subscript to indicate i"1 year
I d\ TT - V *r f if IT vTJ v TT ~ *
(3) £ j - J\ X ^>: X £,_ . X rt- X U;
F Annual fuel cost
K Multiplier for adjusting units
C Cost of fuel (coal), $/ton
E»j. Total energy generated, billions
of kwhr
H Heat rate, Btu/kwhr
U Heat content of fuel (coal), Btu/lb
i Subscript to indicate i year
}-2
Wg Weight of sulfur in fuel, tons
Wp Sulfur content, percent by weight
Wp Weight of fuel consumed, tono
i Subscript to indicate i"1 year
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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13
TABLE 2. (Continued)
Equation
Symbol
Definition
(8)
n=l
+ T. + I.) - C.
i in i
•M
D
R
F
O
M
T
I
n
C
i
Fob plant cost per ton of coal, $/ton
Cost of coal at mine, $/ton
Distance from mine to power plant,
miles
Transportation charge, $/ton-mile
Subscript to indicate i year
Total annual recurring cost
Fuel cost
Operations cost
Maintenance cost
Taxes (nonincome)
Insurance cost
Subscript applies as follows:
n = 1, power plant
n = 2, transmission facilities
n = 3, SO2~control-process equipment
n = 4, by-product plant
Income from sale of by-product
Subscript to indicate i"1 year
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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14
and by-product plant; or he can use one cost entry that covers all recurring cost ele-
ments for both the control equipment and by-product plant. This flexibility is consid-
ered desirable in anticipation of the types of analyses expected to be of interest.
It is worthwhile to point out here some of the important possibilities the analyst
should have in mind when performing the analysis:
(1) The application of an SC>2-control process may require modification
of the power-plant design, and the analyst should consider whether
this will have an impact on nonrecurring costs for the power plant.
Fuel changes may also affect these costs.
(2) If the recurring costs for the SO£ -control equipment and by-product-
plant operation do not include the cost of electrical energy used, then
this energy should be subtracted from that available for distribution.
(3) Fuel consumption should be adjusted to allow for any changes in heat
rate resulting from the application of the SO2 -control process.
Figure 2 introduces these considerations by asking questions at the appropriate place in
the analysis.
Forms
The forms provided are designed to assist the analyst in organizing input data and
performing the required calculations. Each line item on these forms reminds the ana-
lyst of what is needed to complete the analysis. The Data Source column provided on
several of the forms shows how or where the entry for a specific line is determined.
Where appropriate, the completed forms also provide a good record of what was consid-
ered or ignored in a particular analysis. As shown in Figure 2, each analysis requires
a Form A, Analysis Identification and General Power Plant Data and a Form S, Sum-
mary of Results of Analysis. The number and type of other forms used is determined by
the number of SC>2 -control options considered.
Provision is made on each form for analysis identification, and the entry of notes
and other information that is expected to assume increasing importance as analytical re-
sults accumulate and the need develops to recall the details of various analyses.
Now consider the details regarding the calculations and the completion of each form.
Analysis Identification and General Power-Plant Data
Form A, Analysis Identification and General Power-Plant Data (Figure 3), is used
to identify the analysis and to provide general data regarding the power plant, indicate
the planning period of interest, and specify what SC>2-control processes are being con-
sidered. The nameplate generating capacity of the power-generation units is shown in
the form, and provision is made for showing when the initial and subsequent power-
generation units will be placed in operation and when construction will start, the latter
time being of interest when the analyst must consider the availability date of a SC>2 -
control process. The capacity factor assumed is also shown on this form, but if it is
desirable to vary this during the planning period, this is shown on Form E(see page 21).
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
15
The type or types of fuel are identified. (If more than one type of fuel is used, the frac-
tion of time each type is used must be indicated.) The permissible SC>2 concentration is
shown along with the percentage of sulfur removed.
Other entries are for bookkeeping purposes, such as a list of the various forms
used in the particular analysis.
Plant Construction and Start-Up Costs
The total nonrecurring construction and start-up costs (Tjg^) are determined from
the equation
P + S + C + B + T, (1)
wherein the following definitions apply:
Symbol Definition
P Power-plant construction cost
S Start-up cost
C SO2-control-process equipment cost
B By-product-plant construction cost
T Transmission-facilities construction cost
Form NR, Plant Construction and Start-Up Costs (Figure 4), provides a format for ac-
cumulating these costs. In addition, the costs for the power-plant subsystems that
determine power-plant construction costs are listed on this form. These subsystems
are defined the same as in the Uniform System of Accounts published by the Federal
Power Commission (see Reference 2, p 43). This is done to facilitate use of data pro-
vided to the Federal Power Commission in this format. Also, data regarding these sub-
system costs may be needed because of cost revisions that result from the need to mod-
ify power-plant subsystems when installing SO£-control-process equipment. However,
in those cases where only the overall power-plant cost is known or of interest, only the
entry for the total cost of the power plant (P) is entered on the line Power Plant Sub-
total shown on Form NR.
C and B or T may be set equal to zero in specific analyses according to the option
being analyzed. A value would be used for T in the case where the remote-siting option
is being considered. Only the subtotal for C + B is shown on Form NR for those cases
where C and B are not costed separately.
Start-up costs (S) have been included in the nonrecurring costs to remind the ana-
lyst of their possible importance in the cases where SO2 -control processes are first
applied to large power plants. However, data regarding start-up costs are not yet
available.
Data regarding plant-construction costs are discussed in the section on Initial
Plant Costs. Transmission-facilities construction costs are discussed in the section on
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
Power Plant Identification:
Location:
Year of Start of Construction:
Generating
Unit No.
16
Service Area:
Nameplate
Capacity,
megawatts
First Year
of Operation
Type of Fuel
Coal
Oil
Gas
Planning Period Considered:
Capacity Factor, %, Average:
SO2 Control Processes Considered:
Fraction of Time
Each Type Used
Through
Permissible SO2 Concentration Used in Analysis:
Sulfur Removal:
_ppm
%
Forms Used For Analysis (list by Form and Analysis Identification No. )
Notes:
*If the capacity factor varies during
planning period, show on Form E.
Analysis Identification:
Date Prepared:
Analyst:
FIGURE 3. FORM A - ANALYSIS IDENTIFICATION AND GENERAL
POWER-PLANT DATA
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
Item
Land and Land Rights
Structures and Improvements
Boiler-Plant Equipment
Engines
Turbogenerator Units
Accessory Electrical Equipment
Miscellaneous Power Plant Equip.
17
FPC
Account
No.
310
311
312
313
314
315
316
(1)
(2)
Cost,
millions of
dollars
Power Plant Subtotal
Transmission-Facilities Construction Cost . •
SO2-Control-Process Equipment
By-Product Plant
SC>2 Control Process and By-Product Plant Subtotal
Start-Up Costs _
Other (Specify) _
TOTAL _
(1) Indicate number of power generating units considered where appropriate.
(2) Check in this column if cost includes consideration of modifications required
for SOg control process.
Notes:
Analysis Identification
Date Prepared
Analyst
FIGURE 4. FORM NR - PLANT-CONSTRUCTION AND START-UP COSTS
BATTEULE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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18
Transmission Costs. SC>2 -control process equipment and by-product-plant construc-
tion costs are discussed in the section on Sulfur Dioxide Control Devices.
Transmission-Facilities Construction Costs
If the remote-siting option is to be considered, then the nonrecurring and recurr-
ing costs for transmission facilities should be included in the analysis. Form T, Trans-
mission Facilities Construction Costs (Figure 5), provides for the analysis of these
costs. Note that two approaches are allowed for in the computation of nonrecurring
transmission-line costs. The first is based on the use of dollars-per-mile data.. The
equation used to compute the nonrecurring cost for transmission facilities (Tj) in this
case is , .
T = I + E + M,D, + M2DZ ' ^
wherein the following definitions apply:
Symbol . Definition
I Cost of structures and improvements at the
power plant [ FPC Account No. 352, Refer-
ence (2), p 54]
E Cost of station equipment [ FPC Account
No. 353, Reference (2), p 54]
M Number of miles of overhead transmission
lines
D Cost per mile for overhead transmission lines
M? Number of miles of underground transmission
lines
D_, Cost per mile for underground transmission
lines
If there are significant differences in the cost of various sections of overhead or under-
ground transmission lines, then additional MxD terms can be included to reflect this
situation. The sum of the M-terms should add up to the total transmission distance.
Because of the nature of data presently available, cost elements I and E are con-
sidered as one cost and are entered on the "Terminal and Other Equipment" line of
Form T. Data for these costs are discussed in the section on Transmission Costs.
If the case should arise where per-mile costs for transmission lines are not avail-
able or considered inadequate, then it may be necessary to evaluate the component costs.
This can be done on the basis of FPC account numbers [ Reference (2), p 54] , and
Form T makes provision for this alternative calculation. The line items shown under
Alternative Transmission Facilities Cost Computation are defined in detail on pp 54-55
of Reference (2). However, the cost-per-mile approach to costing is more convenient,
and the component-costing approach is included only to provide the analyst with an alter-
native if cost-per-mile data are lacking.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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19
Item
Cost,
millions of dollars
Transmission Facilities:
Overhead Line: (miles) x
Overhead Line: (miles) x
($/mile) x 10
($/mile) x 10
-6
Underground Line:
Underground Line:
($/mile) x 10
-6 _
(miles) x
(miles) x ($/mile) x 10'6 =
Total Transmission Line
Terminal and Other Equipment
Total Transmission Facilities
Alternative Transmission Facilities Cost Computation:
Item
Land and Land Rights
Clearing Land and Rights of Way
Structures and Improvements
Station Equipment
Towers and Fixtures
Poles and Fixtures
Overhead Conductors and Devices
Underground Conduit
Underground Conductors and Devices
Roads
FPC
Account
Number
350
351
352
353
354
355
356
357
358
359
Total Transmission Facilities (Alternative)
Notes:
Analysis Identification
Date Prepared
Analyst
FIGURE 5. FORM T - TRANSMISSION FACILITIES CONSTRUCTION COSTS
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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20
The recurring costs for transmission facilities — operations, maintenance, taxes
(nonincome), and insurance are entered in Form R, Recurring Cost Summary. (See
section on Recurring Costs.)
Energy Generated and Energy Available for Distribution
In order to determine the fuel consumed, it is necessary to calculate the total en-
ergy generated. Also, in order to calculate the mills/kwhr cost for energy delivered to
the distribution network, it is necessary to determine the energy available for distribu-
tion as determined by the energy consumption within the power plant, energy require-
ments of the SO2-control equipment and by-product plant, and the energy losses in the
transmission equipment, if remote siting of the power plant is to be considered.
The total energy generated during the i year is calculated by the following
equation:
.= 8.766 x 10~4 x Y. x PN . . (3)
Terms of the equation are defined as follows:
Symbol Definition
E Total energy generated, billions of kwhr
Y Capacity factor*, %
P Nameplate generating capacity, Mw
The 8.766 x 10"""* factor allows for the number of hours in the year and adjusts for the
units used. The values calculated for E-p j are entered on the appropriate fuel-
consumption summaries (Form FC, FO, or FG — see following section) to enable com-
putation of total fuel consumption. The energy calculations are made by use of Form E,
Energy Generated and Energy Available for Distribution (Figure 6).
The calculation of energy available for distribution is based on the following rela-
tionship for the i1-*1 year:
ENET,i = ET,i ~ EPP, i ~ ESCP, i ~ EBPP, i ~ ETR, i ' (4)
The terms of this equation are defined as follows:
'Capacity factor is defined here as 100 times the ratio of energy generated per year to the product of nameplate generating
capacity times the number of hours in the year (8766 hx/yr).
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Year »•
Line
No. Item Units Entry Source*
1
2
3
Nameplate Capacity
Capacity Factor
Energy Generated
Megawatts
Percent
Billion kwhr
Form A
Form A
B.766 x I(T5 x (U x U)
4
5
6
7
Power for SO^ Control
Equipment
Power for By-Product
Plant
Total
Energy Required
Megawatts
Megawatts
Megawatts
Billion kwhr
Input
Input
(4) *
-------
22
Symbol Definition
E Energy available for distribution
IN £4 1
E Total energy generated
E Energy consumption in power plant
Energy required for SO -control equipment
i
E Energy required for by -product -plant
operation
E _ Transmission -energy losses
TR
Provision is made for calculation of energy available on an annual basis in order
to accommodate the installation of additional generating capacity or a change in capacity
factor after the first year of operation. However, it is expected that many cases will be
analyzed by use of an average value throughout the planning period. The calculation of
energy on the basis of the above equation implies that the electrical -energy require-
ments for SC>2 -control and by -product -plant operation have been taken into account, so
the cost of this energy should not be added to the recurring costs assigned to the SO2 -
control process and by-product plant. However, the analyst has the option of including
the electrical-energy charges in the recurring operations costs for the SO2 -control
process and by -product -plant operation, but the Eg^p ^ and Egpp ^ terms should be
omitted from the evaluation of PjsfET i "* ^is case.
The heat rate (Btu/kwhr) data used to calculate fuel consumption and costs is
based on net generation. This means that the fuel costs for internal power consumption
within '.he plant are allowed for, so, further consideration is not given to energy con-
sumption within the plant when heat -rate data of this type are used. Form E contains a
line Other Losses that can be used to subtract out energy consumed within the power
plant, if such data become available. However, if this is done, care should be taken to
adjust the heat rate accordingly.
Fuel Consumption, Cost, and Sulfur Content
It has been reported that fuel costs accounted for 78 percent of annual production
expenses in 1966 [ Reference (3)] ; hence, this is a major recurring expense item. Also,
the use of low-sulfur fuels is a possible alternative to installation of an SO2 -control
process, but this usually implies higher fuel expenses, so the comparative costs require
evaluation.
Annual fuel costs for the i year (F^) are found by use of the following expression;
F. = K x C. x E^ . x H. x U."1 , (5)
i i T,i i i '
where K is a constant representing the multiplier required to adjust the units used for
the other factors in the equation. The other factors are defined as follows:
SATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
23
Symbol Definition (for Coal)
C Cost of fuel, $/ton-
E Total energy generated, billions of kwhr
H Heat rate, Btu/kwhr
U Heat content of fuel, Btu/lb
If oil is burned, U^ is expressed as Btu/gal; for gas, Uj is expressed as Btu/cu ft. Note
that the forms provided for calculation of fuel costs also make provision for the use of
fuel costs stated in terms of I/million Btu. If more than one fuel is used at a plant,
then separate calculations for each fuel •would be made on the basis of percent of total
energy generated by each fuel.
Form FC, Coal Consumption and Cost and Sulfur Content Summary (Figure 7), is
provided for the calculation of coal costs on an annual basis. (Forms FO, Figure 8, and
FG, Figure 9, are for oil and gas, respectively.) By suitable input-data adjustments,
it is possible to determine the effects on recurring fuel costs of changes in capacity
factor, incorporation of additional generating units after the first year of operation, and
changes in the cost and heat content of the fuel as a function of time. However, in many
cases, it is expected that it will be adequate to use an average value that applies through-
out the planning period considered. The form used for calculating fuel consumption and
cost is also a convenient place to calculate the amount of sulfur contained in the fuel.
Provision is made for this calculation on Forms FC and FO. (The sulfur content of gas
is usually considered to be negligible. ) The weight of the sulfur in the fuel consumed
during the i*h year is obtained from the relationship:
'W- . = W_ . x W_ . x 10~2 . (6)
S,i P,i F,i
The terms used are defined as follows:
Symbol Definition
W Weight of sulfur in fuel, tons
5
W Sulfur content, weight percent
W Weight of fuel consumed, tons
If sulfur weight is to be given in long tons, the weight obtained by this expression is
divided by 1.12.
The Energy Generated entry on Forms FC, FO, and FG is obtained from Form E.
The calculation of fuel consumption, cost, and sulfur content then proceeds by perform-
ing the arithmetic operations indicated on the form to complete each successive line.
In the case of coal, the cost should be that for "as burned" as distinguished from
"fob plant". This distinction is made because the fob plant cost of coal is the mine
price plus freight charges, while the as-burned cost includes the cost of handling to
place the coal in the boiler room bunkers; also, the as-burned cost includes a debit or
credit for ash disposal. However, the as-burned prices shown are also influenced by
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
Year
i i i i r
BATTELLE MEMORIAL INSTITUTE -
o
OLUMBUS L
.ABORATORIES
Line
No.
1
2
3
4
5
6
Item Units Entry Source*
Energy Generated
Heat Rate
Total Btu Required
Btu/Lb of Coal
Btu/Ton of Coal
Coal Consumed
109 kwhr
103 Btu/kwfar
1012 Btu
103 Btu/lb
10^ Btu/ton
10^ tons
Form C. Line (3)
Input
<1)«(Z)
Input
2.0 x (4)
(3) * (5)
Coal Consumption
Total
X
"X"
3>
-------
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Year — «•
Line
No. Item Units Entry Source*
1
2
3
4
5
b
Energy Generated
Heat Rate
Total Btu Required
Btu/Gdl Oil
Gal Oil Consumed
Barrels Oil Consumed
109 kwhr
I03 Btu/kwhr
1012 Btu
103 Btu/gal
ID6 gal
10A bbl
Form E, Line (5)
Input
(1) x (2)
Input
1(1) I- (4)] x 103
(5) * 42.0
7
8
"As-Burned" Cost
Total Cost
1 I million Btu
Million $
Input
(3) x (7) x 10-Z
9
10
"As-Burned" Cost
Total Cost
$/bbl
Million $
Input
(6) x (9)
t in i
Oil Consumption
/ million Btu
Oil Cost
t/barrcl
II
12
1 5
14
Sulfur Content
Btu/Lb Oil
Weij|ht of Oil Consumed
Total Sulfur
• Numt
Weight %
103 Btu/lb
10^ long tons
103 long tons
Input
Input
[ ()) t (12)| x 0 4464
' (11) x (1 J) x 10
Notes:
Sulfur Content
|
Total
X
^x"
X
x
^x^
Analyst a Identifica
Date Prepared
Analyst
^x^
^xj
tion
rv
FIGURE 8. FORM FO - OIL CONSUMPTION AND COST AND SULFUR CONTENT SUMMARY
-------
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Year —
-.ine
No Item Units Entry Source*
1
2
3
4
5
Energy Generated
Heat Rate
Total Btu Required
Btu/cu ft
Cu Ft Gas Consumed
109 kwhr
10* Btu/kwhr
1012 Btu
Btu/cu ft
109 cu ft
Form E. Line (3)
Input
(1) x U)
Input
[U> t (4)] x 103
\
If cost in i 1 million Btu
6
7
"As-Burned" Cost
Total Cost
i 1 million Btu
Million $
Input
(3) x (6) x \0~i
1
Gas Consumption
Gas Cost
1
Total
X
X
x
If cost in i 1 thousand cu ft
6
9
"As-Burned" Cost
Total Cost
i 1 10J cu ft
Million $
Input
(5) x (8) x 10-2-
* Numbers in parentheses refer to line number of form.
Notes:
FIGURE 9. FORM FG - GAS CONSUMPTION AND COST
.x
Analysis Identification
Date Prepared
Analyst
-------
27
the method of pricing according to whether the coal is used directly or from stockpiles,
and this might result in reported as -burned costs being lower than fob plant costs [ see
Reference (4)] . As -burned cost data should be used wherever possible, but if not avail-
able, fob plant costs can be used. The analyst should note such cases on Forms FC,
FO, or FG.
If the cost of coal at the mine mouth is known, then transportation charges must
be added to obtain the fob plant cost. The following expression is used to compute the
cost per ton of coal for the i^h year;
A similar equation would be used to calculate oil costs. The terms of the above equa-
tion are defined as follows:
Symbol _ Definition
Fob plant cost per ton o
Cost of coal at mine, $/ton
T Fob plant cost per ton of coal, $/ton
F
^ ,
M
D Distance from mine to power plant, miles
T Transportation charge, $/ton-mile*
The value of Tp when adjusted to become an as -burned cost would then become the
value for C in Equation (5).
The importance of fuel costs makes it desirable to carefully consider the impact
an SO2 -control process will have in terms of the amount of fuel that •will be consumed
to produce the same amount of energy. An SO2 -control process can conceivably affect
the heat rate or lead to greater electrical energy consumption within the plant. When
these cases are identified, suitable allowance should be made in fuel consumption by
altering the heat rate; or, in the case of increased electrical energy consumption, the
amount of power delivered to the transmission point should be decreased, the result
being an increase in the cost of energy for distribution. The electrical -energy require-
ments for the SC>2 -control -process equipment and the by-product plant are allowed for
in the calculation of net energy available for distribution (page 20).
Data regarding fuel costs are given in the section on Fuel Costs and Heating
Value .
Fuel Changes. If more than one fuel is burned, then it is necessary to complete
more than one form for fuel consumption, cost, and sulfur-content determination. The
most direct way to accomplish this is to apportion the capacity-factor entry on Form E
according to the percent of time that each different fuel is burned. The appropriate
number of Forms FC, FO, or FG are then completed to determine the apportioned fuel
cost and sulfur content. Each of these separate results for costs would then be com-
bined to give the total annual fuel costs entered on Form R. The separate sulfur con-
tents must then be combined to obtain the total sulfur, but no special form is provided
*These charges are sometimes expressed in mills/ton-mile.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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28
for this — an appropriate note on the fuel-consumption forms used should call attention
to the need for this calculation and its location on an attachment provided by the analyst.
Recurring Costs
Aside from annual fuel costs, the other recurring costs of interest are the opera-
tions and maintenance costs for the power plant and associated SC>2-control-process
equipment, the transmission facilities, and the by-product plant. In addition, the annual
taxes (nonincome) and insurance should be included in these costs. Also, annual credits
should be allowed for the sale of by-product.
The expression used to assess total recurring costs (T^ ^) for the i"1 year is
T = F. + ) (O, + M. + T. + I.) - C. .
R, i i LJ i i ' i in *
(8)
' i 11 in i
n=l
The terms of this equation are defined as follows:
Symbol Definition
F Fuel cost
O Operations cost
M Maintenance cost
T Taxes (nonincome)
I Insurance cost
n Subscript applies as follows:
n = 1, power plant
n = 2, transmission facilities
n = 3, SC>2 -control-process equipment
n = 4, by-product plant
C Income from sale by by-product
Form R, Recurring Cost Summary (Figure 10) is provided for organizing input
data and performing the required cost calculations.
Fuel costs are entered from Form F, Fuel Consumption, Cost and Sulfur Content
Summary. The other entries are obtained from the data discussed in the report section
on cost elements.
The analyst has a number of options in the use of the form. Several of these are
as follows:
(1) If annual costs are not varied throughout the planning period, then an
entry is required only for the first year of operations and the total
which is obtained by multiplying by the number of years in the planning
period.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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Annual Recur ring Cost, millions of dollars
Line
No.
Entry Source*
Total
I Fuel
Form FC. FO. or FG
nn
Power Plant
i
'
4
5
6
Ope rations
Maintenance **
Annual Taxes (nonmcome)
Subtotal
Input
Input
Input
Input
(2) + (3) * (4) + (5)
7
8
g
10
11
Operations**
Maintenance**
Annual Insurance
Subtotal
12
Net - SO^ Control, etc.
Input
Input
Input
Input
(7) + (8) * (9) t {10)
(27) - from p. 2, Form R
Transmission Facilities
Net - SO ^Control-Process Equipment, By-Product Plant and Income
Net - Annual Rrcur ring Costs
(I) t (6) t (1 II
::on
-"Numbers in parentheses refer to line number of form.
;If operations and maintenant e not coated separately, enter »m "Operations", lines (2) and (7).
Notes:
Analysis Identification^
Date Prepared
Analyst
FIGURE 10. FORM R (p. 1 of 2) - RECURRING COST SUMMARY
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BATTELLE MEMORIAL INSTITUTE - COLUMSU!
> LABORATORIES
Line
No. Item Entry Sourre
14
15
16
17
18
Opp rations**
Maintenance.**
Subtotal
19
it
21
22
«
Operations**
Maintenance**
A
Subtotal
Input
Input
Input
Input
(141 * (IS) » (IS) » (IT)
Input
Input
Input
Input
»U<»*m)« of 21 - ftECUMJMG COST SUMMARY
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31
(2) If the recurring costs for the SC>2-control-process equipment and by-
product plant are not being analyzed separately, then entries are made
in the process-equipment section only.
(3) If desired, the components of the SC>2-control process and/or by-
product-plant recurring costs can be ignored and only the total
entered, this being done when the analyst's interest is only the deter-
mination of the effects of incremental increases in costs.
(4) Form R allows for a 20-year planning period, but the period of interest
can be varied according to the requirements of the analysis.
Some of the reasons for allowing for possible annual variations in recurring costs
have been discussed previously. In addition, note that in the calculation of annual in-
come from by-product sales, it is possible to vary the sales price realized if the analyst
wants to evaluate the implications of, say, future price decreases.
Results of the Analysis
With the data generated by the completion of the previously discussed forms, it is
possible to obtain the results of the analysis. Form S, Summary of Results of Analysis
(Figure 11), is used for this purpose. This form provides for the entry of results for^
the power plant without SC>2 control and for the SC>2 -control options considered. The
appropriate options are noted by the analyst at the top of the unlabelled columns (see
Form S). Depending upon the specific problem under consideration, the analyst would
be interested in determining the nonrecurring and recurring costs for the power plant
for one or more of the following cases:
(1) Without SO2-control measures
(2) With various SC>2 -control-process equipment and by-product plants
(3) Using low-sulfur fuels
(4) Remotely sited.
Analysis of the first case would be performed in all analyses, since this provides the
basis for cost comparisons. The evaluation of more than one type of SO2-control-
process equipment and by-product plant may be of interest.
Provision is made on Form S for the calculation of the cost per unit nameplate
power-generating capacity in terms of dollars per kilowatt. The entries on Form S are
direct in meaning, and the terms used are as defined in the previous discussion of the
forms referenced in the column, Data Source. Note that each line entry on Form S has
the source of data indicated according to the form on which it is located. The Data
Source column also shows the required arithmetic operations. The percentage value
that is used to obtain the entry on Line 5 of Form S is discussed in the following section.
Form S also provides for the tabulation of data regarding sulfur removal. Al-
though this model is not concerned with determining the efficiencies and the resultant
BATTELLE MEMORIAL INSTITUTE -COLUMBUS LABORATORIES
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Line
No . Item
1
2
3
4
5
6
7
8
9
10
11
12
Total Nonrecurring Cost
Nameplate Generating Capacity
Units
Million $
Megawatts
Entry
Source*
Form MR
Form A
Dollar s /Kw
$/Kw
(l)/(2)]x!03
Total Recurring Costs**
Million $
Form R
Total Annualized
Nonrecurring Costa**
Million $
(!)*<%)* 0.2
Total Cost
Million $
(4) + (5)
Total Energy for Distribution
109 kwhr
Form E
Cost/Energy
Mills /kwhr
(6) +(7)
Incremental Cost
for SO2 Control
Mills /kwhr
(8)***
Total Sulfur Content of Fuel
10^ long tons
Forms
FC or FO
Total Sulfur Removed
10-* long tons
Process
Analysis
Net Cost/ Ton of Sulfur Removed
$/long ton
See
Instructions
•Numbers in parentheses refer to line Dumber of form.
"Show percent of nonrecurring cost used for initialization .
•"Subtract line (8) value in "Without SO2 Control" column from appropriate column.
Notes:
Without
SO2
Control
*—SO2 -Control Options Considered
Analysis Identification
Date Prepared
Analys t '
FIGURE 11. FORM S - SUMMARY OF RESULTS OF ANALYSIS
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33
amount of sulfur removed by various SC»2 -control processes, the analyst would presum-
ably generate such data on the basis of the characteristics of the control process under
consideration and the amount of sulfur in the fuel. After determining the amount of sul-
fur removed during the planning period and the cost differences between the plant with
and without SOz control, the incremental cost for sulfur removal could be determined in
terms of mills/kwhr. These values for the different SC"2-control approaches of interest
are obtained by subtracting the costs shown on Line 8 of Form S for the power plant
without SO£ control from the corresponding values for the SC>2-control options consid-
ered, and the result is entered on Line 9.
The incremental cost per ton of sulfur removed is also of interest. This value is
obtained by taking the total of the recurring and annualized nonrecurring costs (Line 6,
Form S) for the SC>2 -control option case of interest and subtracting the same total for
the power plant without SC"2 control. The cost differences obtained are divided by the
total sulfur removed by the process. The result is then entered on Line 12 of Form S.
Note that the above discussion has been in terms of the totals for the entire plan-
ning period. However, if there is no significant annual variation in any of the values of
interest, the analyst has the option of working with the values for the first year only.
This approach will provide the same values for mills/kwhr and $/ton of sulfur.
Annualized Nonrecurring Costs. In order to obtain a value of mills/kwhr that re-
flects both nonrecurring and recurring costs, it is necessary to "annualize" the non-
recurring cost for the planning period. By doing this, it is possible to obtain a mills/
kwhr value that provides a single number for the analyst to consider. However, the
analyst should not forget the importance of the separate nonrecurring cost, since this
provides important information regarding the initial investment required.
The annualization of nonrecurring costs is based upon application of a percentage
value that includes consideration of financial costs, depreciation, and income-related
taxes. These costs are discussed in the section on Carrying Charges — Treatment of
Financial Costs, Depreciation, and Taxes. Table 21 in that section provides a tabula-
tion of annual carrying charges that would be used to annualize the nonrecurring costs.
For example, if the "rate of return" is assumed to be 7 percent and the depreciation
period is 20 years, then the U.S. average value used would be 13.46 percent.
Graphic Presentation of Results. Aside from the tabulation of results found in
Form S, graphic presentations are of interest. Plots of cumulative costs such as those
shown in Figure 1 can be generated from the nonrecurring and recurring cost data. In
addition, on the basis of the total sulfur content of the fuel and the efficiency of the SC>2-
control process, it would be possible to generate curves showing the cumulative total of
SO2 released to the atmosphere with and without SO^-control processes. Figure 12
shows such a plot for the case where two different SO2 -control processes are operated
at the same efficiency. If the costs shown in Figure 1 apply, then Process A would be
more attractive than Process B from a cost standpoint.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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34
t/1
TJ
0)
0>
CC
CO
o <»>
o f
I i
O
Year
FIGURE 12.
TOTAL SO2 RELEASED TO ATMOSPHERE WITH AND WITHOUT
SO2-CONTROL PROCESSES (SCP)
Subsystem and Component Costs
The cost elements previously discussed have been primarily concerned with ag-
gregate costs at the systems level. Exceptions have been made on Form NR, Plant
Construction and Start-Up Costs, and Form T, Transmission Facilities Construction
Costs, and this has been done only because of the convenience.of showing alternative
subsystem cost computations on the same form. To the extent possible the analyst
should work with system-level costs in order to avoid the time-consuming effort to do
detailed costing; however, cases may arise where it is in order to examine subsystem
or component costs. For example, the incorporation of the SO2 -control process may
require modifications of power-plant equipment. If these are extensive, then the im-
pact on subsystem or component costs for the power plant may require evaluation.
The subsystems of the power plant are listed on the previously mentioned Form
NR. Components of these subsystems are listed in the FPC publication, Uniform Sys-
tem of Accounts Prescribed for Public Utilities and Licenses. (2) For example, on
page 45 of Reference (2), the components of the boiler-plant subsystem are listed as
follows:
(1) Ash-handling equipment
(2) Boiler feed system
(3) Boiler-plant cranes and hoists
(4) Boilers and equipment
(5) Breeching and accessories
(6) Coal-handling and -storage equipment
(7) Draft equipment
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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35
(8) Gas-burning equipment
(9) Instruments and devices
(10) Lighting systems
(11) Oil-burning equipment
(1Z) Pulverized fuel equipment
(13) Stacks
(14) Station piping
(15) Stoker or equivalent feeding equipment
(16) Ventilating equipment
(17) Water purification equipment
(18) Water-supply systems
(19) Wood fuel equipment.
Reference (2) also provides a description of what is included in the above-listed
equipment.
It is also possible to develop operations and maintenance expenses on the basis of
more detailed component costs. For the electric plant, Reference (2) breaks down these
costs as follows:
FPC
Account
Operation No.
Operation supervision and engineering 500
Steam expenses 502
Steam from other sources 503
Steam transferred (credit) 504
Electric expenses 505
Miscellaneous steam power expenses 506
Rents 507
Maintenance
Supervision and engineering 510
Structures 511
Boiler plant 512
Electric plant 513
Miscellaneous steam plant 514
A more detailed description of these cost elements is found in Reference (2), and de-
tailed data regarding these costs are found in the annual FPC publication, Steam-
Electric Plant Construction Cost and Annual Production Expenses.(3)
Note that fuel costs (FPC Account No. 501) has been omitted from the above list
since this important expense is treated separately.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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36
COST ELEMENTS FOR
FOSSIL-FUEL-BURNING POWER PLANTS
The data for the calculation of costs are partially in the literature and partially un-
available, and quality varies from very accurate accountant reports to educated guesses.
For the electrical system there is a large body of previous cost data which has been used
for preparing cost-estimating relationships. For the sulfur control devices, only a few
speculative estimates of costs are available. These estimates were then developed into
cost-estimating relationships by the use of Lang factors and exponential functions.
The cost data for the electrical generating plants are published annually by the
Federal Power Commission (FPC) in sufficient detail for the purpose of evaluating possi-
ble utility-rate impacts through the model and for obtaining cost-estimating relationships
for estimating costs of new plants and fuel, operating, and maintenance expenses. The
Bureau of Mines publishes extensive data on fuels. The FPC has published data on
transmission-line costs. The cost data for the sulfur-control devices are the least accu-
rate because no operating experience is available. Katell's estimates have generally
been used for purposes related to the use of the model.
Cost-estimating relationships have been developed to represent the capital cost,
the annualized costs, and the operating costs. In this report, capital costs are called
nonrecurring costs and operating costs, recurring costs.
Initial Plant Costs
The initial plant cost includes the costs associated with the construction of a-gen-
erating plant up to the time it is generating power. Since this model will be used with
unfinished plants or proposed plants, a method is needed for estimating the initial cost.
The cost of the plant depends upon the geographical location of the plant and upon the fuel
to be burned. Coal-fired plants are more expensive than oil- or gas-fired plants because
of the coal-handling equipment needed. Coal-fired plants can be converted to oil or gas
firing with minimal additional cost, and the cost of a change from oil to gas or vice versa
is also minimal. The initial cost of the plant is the major part of the capital investment
and therefore the accuracy of this estimate will have a significant but lesser percentage
effect on the accuracy of the final costs. Interest charges and amortization of the plant
cost usually account for about 50 percent of the overall cost of electricity at the generat-
ing station.
The construction costs of steam-electric plants is published annually by the Federal
Power Commission (FPC). ^ ' Unfortunately, the costs are presented for all units in a
station rather than for the individual units. Although the cost of an individual unit could
be determined by comparing the station cost of the year previous to startup of a new unit
with the cost of current year, for the present purpose it appears adequate to consider
only the costs of new stations. The costs of large, new, coal-fired generating stations
which started operation between I960 and 1965 are plotted in Figure 13. Cost data before
I960 cannot be related to these costs because of changes in technology and inflation.
It has been suggested that oil- and gas-fired units are only 80 percent of the cost of
a coal-fired unit of the same capacity. (5) Regional cost variation can partially be
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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37
200
O
TJ
—
"5
180
3 160
o>
Q.
140
(5)
Dillard and Baldwin
200
400 600
Unit Capacity, Mw
800
1000
A-55782
FIGURE 13. CONSTRUCTION COSTS FOR COAL-FIRED ELECTRIC
GENERATING UNITS
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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38
determined from the construction-cost index^°) which is published quarterly and presents
relative construction costs in major cities. Table 3 is a listing of recent cost indexes.
TABLE 3. CONSTRUCTION COST INDEXES
FOR MAJOR CITIES
(SEPTEMBER 1968)(6)
City
Index
Atlanta
Baltimore
B i r min gham
Boston
Chicago
Cincinnati
Cleveland
Dallas
Denver
Detroit
Kansas City
Los Angeles
Minneapolis
New Orleans
New York
Philadelphia
Pittsburgh
St. Louis
San Francisco
Seattle
Montreal
Toronto
U. S. Average
919
974
901
1171
1331
1245
1460
893
1054
1389
1115
1272
1199
931
1575
1106
1169
1339
1413
1255
1047
1031
1186
Costs regionally corrected to a cost index of 1200 and the cost of oil- and gas-fired
units increased by 25 percent (1/0.8) are plotted in Figure 14. The scatter in these costs
is only somewhat less than the scatter in costs shown in Figure 13.
With a few exceptions, the construction costs of units larger than 300 Mw fall within
25 percent of the line shown in Figure 14. Since bid prices often vary by this amount,
the correlation is probably as good as might be expected. The Eddystone plant, plotted
at a cost of $240/kw, was a plant of a radical new design where an exceptionally low heat
rate was obtained at the expense of high capital cost. Other variations are caused par-
tially by some tradeoff in heat rate against capital costs and by some randomness.
The regional correction appears to be quite good. However, the costs are for
metropolitan areas, and the costs for nonurban areas are not available. The cities listed
in the cost index are scattered, and often it is difficult to decide which cost index to use.
It is suggested that the cost index for the nearest city be used.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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39
220
JC
CL
O
•o
O
O
(A
180
140
120
too
coo
200
400 600
Unit Capacity, Mw
800
1000
A-55783
FIGURE 14. UNIT COSTS OF FOSSIL-FUELED ELECTRIC GENERATING
STATIONS CORRECTED FOR REGIONAL VARIATION
(ENR = 1200)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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40
The difference in cost between gas- or oil-fired plants and a. coal-fired plant is
based on the additional cost of coal-handling equipment. The difference in costs is ap-
parent when plant costs are examined. Oil-fired plants are sometimes considered to
cost a few percent more than gas-fired plants, probably because of the storage facilities
required for oil. This difference in cost is minimal, however, and should be ignored in
using these values in the model.
Recommended Values
It is recommended that the cost of a plant be estimated using the Engineering Cost
Index of the nearest city in conjunction with the curve shown in Figure 14, i.e., multiply
the appropriate value read from the curve by the ratio of the cost index (value from
Table 3, or a more current value) to 1200, the normalizing value. If the unit will not
need coal-handling facilities, because oil or gas will be the fuel, this predicted cost
should be modified by multiplying it by 0. 8.
Operation and Maintenance
The operation and maintenance expenses are usually separated from the fuel cost,
and this procedure is followed in the model. Operation and maintenance expenses amount
to about 10 percent of the cost of electricity at the generating station; hence, sensitivity
of results to these values is less than that to fuel costs and capital costs which represent
a higher percentage of total generation cost.
Operation and maintenance costs are published annually by the Federal Power
Commission^) for most large power plants. These costs are plotted against the initial
cost of the generating station in Figure 15.
Operation and maintenance costs for a station normally are expressed in mills/
kwhr. A good correlation is observed in Figure 15, where operation and maintenance
costs for new plants are plotted as a function of the initial cost of the plant. Changes in
operation and maintenance costs are seen to be associated fairly well with changes in the
$/kw first cost of the unit. This is a result of two relationships. A given generating unit
which is double the size of another will not require twice the operating and maintenance
personnel. The larger unit will have the same number of boilers, turbines, and gener-
ators as the smaller one and is likely to have a similar number of burners, pumps, and
controls. Only the size of each will be larger. Thus, while more labor will be involved
in repairing a larger pump, it should not be double. The second relationship is that as
gene rating-unit sizes double, their first costs usually do not. Therefore, it would be
expected that the operating and maintenance expenses for a unit expressed in mills/kwhr
would decrease as a unit's installed cost in $/kw decreased, because it is probable that
a larger unit is being investigated.
Operational costs are primarily labor costs, and regional variations in labor rates
are reflected in the capital costs. Therefore, regional-cost corrections are inherent in
the estimating method. The cost estimates are below the national average of 0.75 mill/
kwhr since the newer plants need less maintenance because of advanced technology and
operational costs are reduced because of large-scale operation.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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Operation and Maintenance Expense, mills per kwhr
Oooopppoor
O — Nw*uia»-40
90 100 ISO
Construction Cost, dollars per kw
200
FIGURE 15. COST-ESTIMATING RELATIONSHIP FOR OPERATION
AND MAINTENANCE COSTS
Recommended Procedure
It is recommended that the operation and maintenance cost be estimated from the
correlating line on Figure 15.
Transmission Costs
The transmission line is used to transport the power from the generating station to
the distribution area. In the context used in the model, the transmission plant denotes
the difference in equipment required by alternatives between the generating station and
the distribution area. If, under two alternatives, the generating station is within the dis-
tribution area for both, it is assumed that no differences in transmission plant need be
considered. Transmission plants may be ac or dc, and they may be overhead or under-
ground. They are characterized by high capital costs and low operating costs, and their
voltage is usually at least double that of the distribution system. Generally, the economic
size of the transmission line is one-third to one-forth the maximum technical capability
of the line. Therefore, a line will take rather severe overloads under emergency condi-
tions. Frequently, roughly parallel lines are installed to increase system reliability.
Direct-current transmission is in the experimental stage and apparently will be preferred
only for transmitting very large blocks of power long distances, for use with underground
systems or for transmitting energy through large bodies of water. Alternating-current
lines are normally used. Underground transmission lines are used only in urban areas
and are 10 to 15 times as expensive as overhead lines. Because of the higher voltages,
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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42
electromagnetic field characteristics, and generally greater length of transmission lines,
both underground and overhead'facilities require reactors to compensate for the reactive
impedance of the line and to prevent the energy from being dissipated before it reaches
its destination. . - - ......
Data
Table 4 presents the costs of overhead lines of various voltages. However, note
that the power rating in the table is the technical rating and not the economic rating.
Figure 16 presents the cost of transformers for increasing the voltage from 220 kv to a
higher transmission voltage. Table 5 presents the costs of compensating reactors for
the transmission lines. All of these values have been taken from a Federal Power Com-
mission report. (''
2400
700/230 kv
3 - I <£ banks
500/230 kv
3-lcfc banks
345/230 kv
I -3cf> banks
400
200 300 4OO 500 600 700 800 900
Bank Output, Mva (Top Rating)
1000
FIGURE 16. AUTO-TRANS FORMER COSTS (THREE WINDING,
OA/FOA/FOA, 15-KV TERTIARY HV AND
LV-GROUNDED Y)
Note: Transformer costs include foundations, steel, fire protection, arresters, labor, con-
tingencies, other direct construction costs, engineering and general overheads (21
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43
TABLE 4. RANGE OF ESTIMATED COSTS PER MILE FOR HIGH-VOLTAGE OVERHEAD TRANSMISSION LINES*7)
(Exclusive of Compensation, Conversion, Terminal, *nd Transformation Cost)
Nominal Reported Reported Range of Labor Reported
ACSR Summer No. of Range of Cost/Mile. $1000 Range of
Oper. Cond. Thermal Circuits & Material Tower Right-of-
Volt., Size, Rating**), Structure Cost/Mile(c), Erection and Way Cost*^.
kv MCM Mva Material*1*) $1000 Foundations**1) Stringing*6) $1000/Mile
Total Cost/Mile, $1000
Adjusted
Reported Range Average
700
138
230
345
500
700
1-477
1-795
1-795
1-795
1-477
1-795
1-795
1-795
1-954
1-1431
1-1431
2-795
2-795
2-1590
2-1780
4-954
75
105
105
210
150
210
210
420
385
490
980
1050
1050
3160
2470
4700
' Alternating-Current Lines
1-W 6.5-23.0 0-24.0
1-W 9.4-23.5 0-26.0
1-S 13.2-28.0 3.0-38.0
2-S 22.7-36.0 5.0-48.0
1-W 8.9-25.0 0-26.0
1-W 11.3-26.0 0-26.0
1-S 14.4-30.0 3.6-42.0
2-S 25.6-42.0 5.3-51.0
1-W 11.8-29.0 0-20.0
1-S 20.5-45.0 4.0-53.0
2-S 31.0-60.0 5.7-64.0
1-W 25.0-36.5 0-20.0
1-S 24.5-56.0 4.2-38.0
2-S 45.0-106.0 5.7-93.0
1-S 36.3-72.0 4.4-72.0 26.6-120.0
1-S 78.0-93.6 5.6-84.0 41.8-168.0
Direct-Current Lines
5.9-24.0
. 7.7-30.0
9.6-36.0
16.9-60.6
7.3-20.0
8.4-36.0
11.4-42.0
16.9-66.0
9.3-43.0
12.1-58.0
17.1-90.0
14.4-54.0
15.6-57.0
26.0-159.0
0-38.0
0-38.0
7.1-3810
7.1-38.0
7.5-46.0
7.5-46.0
7.5-46.0
7.5-46.0
7.7-52.0
7.9-52.0
7.7-52.0
11.6-57.0
8.0-57.0
7.9-57.0
9.3-64.0
15.9-76.0
19.8-86.0
23.4-100.0
34.9-122.0
51.3-170.0
35.2-94.1
32.2-111.0
36.9-136.0
54.5-184.0
33.5-124.0
44.3-173.0
61.6-237.0
63.9-147.0
52.5-171.0
85.1-393.0
76.5-306.0
164.5-387.0
50.8
50.9
66.2
87.8
65.4
60.7
73.0
97.0
75.2
94.1
128.4
91.8
101.7
183.5
155.1
199.4
±200
±400
±600
2-1590
2-1590
2-1590
600
1200
2160
1-S
1-S
1-S
31.6-43.
26.6-48.
43.2-62.
0
0
6
5.7-26.0
3.9-30.0
5.9-34.0
21.
19.
27.
0-54.0
6-57.0
7-60.0
10.4-33.8
11.8-40.5
13.0-47.5
71.9-151.0
58.2-160.0
94.0-176.0
94.8
95.7
129.0
Note: Engineering and overhead costs are included in the various items. Limits of ranges on individual items do not exactly
equal the sum of the corresponding limits because of variations in breakdowns because of reporting companies.
(a) Based on 85 C conductor and 40 C ambient air temperature plus solar heating, 2. 0 fps wind velocity, and 0.5 emmissivity
coefficient. Terminal equipment based on 1500-ampere valve ratings for ±200 and ±400 kilovolts, and 1800 amperes for
±600 kilovolts.
(b) 1 = one circuit on single-circuit tower, 2 = two circuits on double-circuit tower, W = wood pole, S = steel tower.
(c) Includes structure, insulators, conductors, fittings, and all other materials including foundation material, sales tax, and
storage or handling charges. Does not include transformer cost.
(d) Includes all foundation installation, surveying, grounding and any necessary construction roads.
(e) Includes all costs of assembling the material into a complete line.
(f) Includes property and clearing costs for 60 percent of right of way. R/W widths 69 kv-ac-75 ft.; 138 kv-ac-100 ft.;
230 kv-ac and ±200 kv-dc-125 ft.; 345 kv-ac and ±400 kv-dc-150 ft.; 500 kv-ac and ±600 kv-dc-175 ft.; 700 kv-ac-225 ft.
The maintenance cost was suggested as 1 percent of the capital cost in the report
on Underground Power Transmission. (7) The electrical losses were estimated by calcu-
lating I^R loss from estimated line sizes, assuming a power factor of one. Corona
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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44
losses are negligible at transmission voltages below 500 kv, and at 500 kv they are im-
portant only at times of precipitation when they may be as high as 100 kw/mile. .Corona
losses have been discussed by Anderson et al. (10)
TABLE 5. COST OF COMPENSATING
REACTORS
Reactance,
MVAR
50
100
200
300
220-345 kv,
$/KVAR
6
4
3
2.5
500 kv,
$/KVAR
9
6
4
3
Discussion
From the three-to-one variation in cost for a line presented in Table 4, it can be
seen that an accurate estimate of transmission-line costs cannot be obtained without de-
tails of the line. For the cost model it is suggested that an average cost be used where
specific data are not available. The data plotted in Figure 17 indicate the wide variability
in capital cost. It is also suggested that the line be designed for operation at about 30
percent of its thermal rating. This is roughly in line with TVA voltage recommendations
for the various power capabilities. Also, calculations using the costs presented later
indicate that this is approximately the economic loading. These calculations also indi-
cated that the 30 percent figure was not critical.
The transformer costs will be inherent in the system for voltages up to about
220 kv because the main distribution system will probably operate at that voltage. There-
fore, these costs should be included in distribution costs, which are not part of this
study. Transformer cost for stepup and stepdown over that voltage should be added to
the transmission costs. Shunt impedances for compensation have not been considered.
They will not be needed for transmission distances less than 200 miles.
To assume reliable operations, it is suggested that the same number of transmis-
sion lines be used as the generating plant has generators. Usually a generator is sized
so that its shutdown will not affect system reliability, and the transmission line should
be sized on the same basis. Underground lines are very expensive and will probably be
used only in the distribution system. The costs are from 10 to 15 times the cost of an
overhead line. If underground lines are needed, it is suggested that the minimum figure
of 10 times the cost of overhead lines be used.
The figure of 1 percent for maintenance cost in the FPC report''' appears reason-
able, and it is suggested that this number be used. This includes the maintenance of ac-
cess roads, weed control, and occasional storm losses. The I^R losses can be calcu-
lated easily after the wire size is estimated. The wire sizes in Table 4 were used for
estimating this loss. However, the I R loss varies with the loading of the line. If the
loading schedule is not known, it is suggested that the line be considered as operating at
design load or completely disconnected from the station and load. Corona losses will
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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45
depend upon the weather conditions. For the curvei presented later, it is assumed that
the corona losses will average 20 kw/mile for a 500-kv line and be negligible at lower
voltages. Except at light loadings, this is not an important cost. A loss of 20 kw/mile
assumes that precipitation, dew, frost, fog, or other corona-causing weather conditions
will occur 20 percent of the time.
Recommended Procedure
The following steps constitute the recommended procedure for determining the
costs associated with power transmission from generation locations outside the distribu-
tion network:
(1) Determine the capital cost of the transmission line from Figure 18
(2) Determine the capital cost (if any) of transformerr from Figure 19
(3) Sum to determine capital cost
(4) Multiply the capital cost by 0.01 to determine annual maintenance cost
(5) Determine the electrical losses from Figure 20 and subtract this loss
from the net power generated by the generating plant.
BATTELLE MEMORIAL. INSTITUTE - COLUMBUS LABORATORIES
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46
500
400
o
•o
•o
c
o
3 200
VI
3
.1 100
Q.
8
\
a Maximum
o Average
x Minimum
KX>0 2000 3000 4000
Thermal Capability, Mw
5000
FIGURE 17. CAPITAL COST OF TRANSMISSION LINES
1000
900
800
2>
f 700
*
fc 600
f 500
8 400
o
'5. 300
o
o
200
100
\
200 400 600
Design Load, Mw
600
1000
FIGURE 18. CAPITAL COSTS FOR OVERHEAD TRANSMISSION LINES
BATTCLLC MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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47
J
.g
1
tf
o
o
k_
0>
**- 1
S '
S
Q
/'
x
0 200 400 600 800 1000
Rating, Mw
FIGURE 19. TRANSFORMER COSTS FOR TRANSMISSION LINES
(STEPUP AND STEPDOWN FROM 220 kv)
Operating load, percent
of design load
200 400 600 800 1000
Design Load, Mw A.55784
FIGURE 20. ELECTRICAL LOSSES IN TRANSMISSION LINES PER Mw-hr DELIVERED
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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48
Fuel Costs and Heating Value
Data on fuel costs are usually available only in some aggregated form as shown
in Table 6. While this table is useful in identifying general regional trends, it over-
states the cost of alternatives available to utilities currently planning a new, large
facility. Average delivered coal prices are particularly misleading because they do not
adequately reflect the volume economies available to a large purchaser who is located
near the mine mouth, purchases from captive mines, or uses unit-train hauling. These
differences are indicated by comparing data from Table 6 with those in Table 7 which
shows typical fuel costs for utilities contacted during this program. As an example,
while the average delivered coal price to all utilities in the East South Central Census
Region in 1966 was 19. 3^/million Btu, the delivered cost to three of TVA's larger sta-
tions in the same area ranged from 13. 7^/million Btu (in a mine-mouth location) to
17. 9^/million Btu.
It would also be desirable to distinguish fuel costs at the source and the transpor-
tation component from the delivered price. An attempt was made to identify these com-
ponents during utility interviews, and where adequate data were available, the cost of
coal at the source was estimated (Table 7). The deviation in coal costs at the mine is
seen to be much smaller for the three TVA stations mentioned before than it was for the
delivered cost of fuel. It has been found that for a given mode of transportation and dis-
tance, the costs per ton mile are fairly uniform. These transportation costs can be
applied to a particular evaluation considering alternative plant types and sites where fuel
source and source costs are known. However, to develop a mass of data on estimated
fuel cost at the mine would require, as an example, the listing of a large number of
facilities and their as-burned fuel costs, determining the fuel-source location, and sub-
tracting an estimated transportation charge from this.
At present, a reasonable data base may be developed by assuming that each utility
performs a rigorous analysis of alternatives in selecting a plant site, and that their
choice represents the optimum costs available to them at the time, including both coal
costs as mined and transportation charges. Therefore, as-burned fuel costs have been
tabulated from the FPC's publication Steam Electric Plant Construction Cost and Annual
Production Expenses^) for all generating stations 500 Mw(e) and larger. Volume trans-
portation methods are usually employed and should be reflected in the fuel costs for
these larger stations. These data have been plotted on United States maps and coal costs
are presented in Figure 21, oil costs in Figure 22, and gas costs in Figure 23. Thus,
in any evaluation of a general nature which does not require the isolation of the fuel
transportation component, the delivered costs of alternative fuels may be estimated by
referring to these three maps.
The heating value of coal is seen to vary considerably among different regions.
Heating-value data were tabulated from the FPC's steam plant report' ) and are pre-
sented in Figure 24. The heat contents of oil and natural gas are more consistent and
their average values are also shown in Figure 24.
Unfortunately, the heating values for oil are shown in terms of Btu's/gal, while
to compute the sulfur content of oil used as fuel, a value in terms of Btu's/lb is needed.
Values of typical heating values per pound for residual fuel oils are given by the
American Petroleum Institute(^) as follows:
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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49
TABLE 6. STEAM ELECTRIC GENERATING STATIONS'
AVERAGE "AS-BURNED" FUEL COSTS FOR
1966(4)
Region
New England
Middle Atlantic
E. N. Central
W. N. Central
South Atlantic
E. S. Central
W. S. Central
Mountain
Pacific
U. S. Average
Coal
33.6
26.5
24.4
26.4
25.6
19.3
--
20.4
--
29.7
Costs, cents/million Btu
Oil
32.9
31.8
--
--
33.6
--
--
25.4
31.5
32.4
Gas
33.8
34.4
25.9
24.2
31.8
22.7
19.8
26.7
31.5
25.0
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 7. FUEL, COSTS AND CHARACTERISTICS OF UTILITIES' GENERATING STATIONS
OBTAINED THROUGH INTERVIEWS
0
H
PI
r
T
PI
X
PI
O
5
r
2
(A
H
C
-•
PI
1
O
O
r
c
X
D
C
Vt
r
a
o
5
H
0
5
m
M
Net
Plant Size,
(Utility) Mine
o
Pittsburgh* 7> ( P. G. &E) 735
Joliet (Com. Ed.) 1,862
Waukegan (Com. Ed. ) 1, 093
(So. Cal. Ed.)
(P.S. of Okla.)
(Pac. P. &L. )
(P.S. of Colo.)
Bull Run (TVA)
Gallatin (TVA) 1,255
Paradise (TVA) 1,908
(Bost. Ed. )
(Cons. Ed. )
(P.S. of N. J.)
Plant Location
Calif.
Joliet, 111.
Waukegan, 111.
Los Angeles, Calif.
Tulsa, Okla.
Centralia, Wash.
Denver, Colo.
Gallatin, Term.
Drakesboro, Ky.
Boston
New York City
Fuel
Oil
Gas
Coal
Coal
Coal
Oil
Oil
Gas
Coal
Coal
Coal
Gas
Coal
Coal
Coal
Oil
Oil
Oil
Coal
Coal
Coal
Oil
Fuel Cost Transp. Cost,
FOB Mine, ^/million Btu
^/million Btu (Dist. , miles)
15.94(E) 6. 12(300)*a)
19.6KE) 7.46(200)
14. 85 (E) 8.65(180)
11.43 4. 77(298)
13.23 4.67(119)
13.7 0
— ,
See Figure 25
See Table 9
Delivered
Fuel Cost,
^/million Btu
32.8
31.2
36-40(E)
22.06
27.07
38.0
30.0
19.0
20. 5(E)
16.0
23.5
22. s(b)
16.2
17.9
13.7
25.0
37.0-38.0
32.0-33.0*°)
38.0
29.0
Sulfur
Content,
percent
1. 1 to 1.5
0. 5 or less
1.7
0.7
0.65
2.3
4. 1
4.3
2.8
1. 0 or less
2.5
1. 0 or less
2.0
(E) Estimated.
(a) Unit train.
(b) Interruptible gas.
(c) For comparison only: all fuel burned under 1 percent sulfur.
-------
5
H
>
i
o
S
8
o
FIGURE 21. 1966 AVERAGE COST OF COAL "AS BURNED" AT ELECTRIC GENERATING STATIONS 500 Mwe AND
LARGER IN CENTS PER MILLION Btu<3)
Note: Circled numbers were obtained through interview.
-------
H
H
m
r
r
m
m
o
5
(A
ID
I
O
o
r
z
o
O
5
m
en
FIGURE 22. 1966 AVERAGE COST OF OIL "AS BURNED" AT ELECTRIC GENERATING STATIONS 500 Mwe AND
LARGER IN CENTS PER MILLION Btu<3>
Note: Circled numbers were obtained through interview.
-------
H
H
m
r
r
ID
Z
n
o
-t
c
H
m
i
o
o
c
i
a
M
H
O
B
m
(A
\
FIGURE 23. 1966 AVERAGE COST OF NATURAL GAS "AS BURNED" AT ELECTRIC GENERATING STATIONS
500 Mwe AND LARGER IN CENTS PER MILLION BTU
Note: Circled numbers were obtained through interview.
-------
\
>
m
i
o
FIGURE 24. 1966 AVEEIAGE HEATING VALUE OF COAL BURNED AT ELECTRIC GENERATING STATIONS 500 Mwe
AND LARGER IN 1000 BTU'S PER POUND
Note: Data for oil and gas were averaged but not plotted.
-------
55
Gravity, deg API Btu/Lb
Residual Fuel Oils at 60 F _ Liquid
California 16.5 18,319
Kentucky 15.2 18,651
California 7.6 17,970
Another approach is to use the chart given by Perry* to convert the values shown on
Figure 24 (for oil) to Btu's/lb. This results in the following:
Oil Heating Value
Btu/Gal Btu/Lb
West Coast 152,821 18,860
Rest of the Country 149,437 19,080
It is further observed that the API typical values are not consistent with the Perry chart,
which indicates that actual values for each case of interest would be desirable. (Note
that a constant value of 18, 700 Btu/lb has been used in the examples shown in a later
section of this report. )
One method of reducing sulfur oxide emissions, which is always available to utili-
ties, is to burn a fuel with a lower sulfur content. For many locations, however, this
alternative imposes substantial cost consequences. As an example, most of the United
States' reserves of low sulfur coal are located west of the Mississippi River'**', whereas
a majority of the country's electrical generation facilities are located near more densely
populated urban centers east of the Mississippi. For most of the eastern plants, the
transportation cost for moving low- sulfur coal from western mines would be prohibitive.
Some reserves of low-sulfur coal are located in the eastern coal fields. Unfortu-
nately, the use of coal with more than 1 percent sulfur content has long imposed an un-
desirable cost consequence on the steel industry. Because a majority of steel plants are
still located east of the Mississippi River, the steel industry has taken prior claim on a
major portion of the eastern reserves of low- sulfur coal through long-term contracts.
Most plains states and west-coast utilities seem able to obtain low-sulfur coal with little
cost penalty.
East-coast utilities also face higher transportation charges for low-sulfur oil.
Most oil that is competitively priced for utility use on the east coast is shipped from
South America. However, Venezuelan oil, as an example, is typically high in sulfur
content. The lowest cost low sulfur oil in many cases is shipped from Africa, and this re
suits in a higher delivered cost. On the west coast, oil with 2 percent sulfur or less is
available at competitive prices from domestic sources.
An example of these cost consequences is offered by the experience of Consolidated
Edison, the electric utility serving New York City, which recently reduced the allowable
sulfur content of their fuel purchases from 2. 5 percent to 1 percent or less. Changes in
volume fuel costs as a result of the new sulfur specifications are summarized in Table 8.
•This can be achieved not only by using natural fuels which are low in sulfur but also by modifying the fuel. For example,
currently there are efforts by the National Air Pollution Control Administration to develop and demonstrate improved
conventional coal-cleaning practices for reducing sulfur contents.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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56
TABLE 8. VOLUME FUEL COSTS AT THE GENERATING STATION
FOR CONSOLIDATED EDISON CO. OF N. Y. , INC.
BEFORE AND AFTER ESTABLISHMENT OF POLICY
TO BURN LOW-SULFUR FUEL
Costs,
^/million Btu
Sulfur Content, percent
Fuel
Oil - "Delivered"
Coal - "Delivered"
Trans p. component
Estimated price
fob mine
2.5
32-33
29
10
19
1. 0
37-38
35
-------
57
II
10
8
5
fc
ex
(A
(A
3 4
Delivered price
FOB mine price
Transportation cost
Q8 1.0
FIGURE 25.
1.2 1.4 1.6 1.8 2.0 2.2
Coal Sulfur Content, percent
2.4 2.6
2.8 3.0
A-55785
AVERAGES OF 59 PRICE QUOTATIONS (7/68) FOR COAL
DELIVERED TO PUBLIC SERVICE ELECTRIC AND GAS
COMPANY'S HUDSON GENERATING STATION (455 Mwe),
JERSEY CITY, N. J. , AS A FUNCTION OF
SULFUR CONTENT
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 9. COST OF FUEL OIL ($/BBL) FOR VARIOUS PUBLIC SERVICE ELECTRIC AND GAS CO.
GENERATING STATIONS AND FOR DIFFERENT SULFUR CONTENTS (August 1, 1968)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Essex
Marion
(Hudson) Kearny Sewaren Linden
Bunker C - 2. 5% Sulfur
Pipe 1.99 (4-67)
Barge 2.09(10-67) 2.06(4-67)
Lo-Sulfur - 1.0% Sulfur
Pipe Z. 25
Barge 2.30 2.30
Hi-Vis - 2.0% Sulfur
Pipe 1.91(4-68)
Hi-Vis^ Low-Sulfur 1.0% Sulfur
Pipe 2.25
Bunker C - 2.0% Sulfur
Pipe 2.05(10-67)
Lo-Sulfur- 1.0% Sulfur
Pipe 2.35
Hi- Vis - 2. 3% Sulfur
Pipe 1.76(4-68)
Lo-Sulfur - 1.0% Sulfur
Barge
Hi- Vis - 1.6% Sulfur
Barge
Lo-Sulfur - 1.0% Sulfur
Barge
Burlington
2.30
1.92 (4-68)
2. 50 (2.40)
(a) ( ) - Price at date of discontinuance.
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59
Table 10 presents the heat rates for generating units over 300 Mw and for stations
where the average size of unit is over 300 Mw. This table is slightly biased toward the
better heat rates because poor unit heat rates are not available for individual units.
However, it does not appear that many poor heat rates were missed.
The heat rates in Table 10 were obtained from the 1965 and 1966 editions of
Steam-Electric Plant Construction Cost and Annual Production Expenses, published by
the FPC. (3)
The heat rate of an individual plant tends to increase with time because of an
increased number of stops and starts and because of poorer operating conditions. There
fore the very good heat rates for the newer plants probably will not be maintained. The
Eddystone plant has a heat rate about 400 Btu/kwhr less than its contemporaries. How-
ever, the Eddystone plant was twice as expensive as other plants of similar size.
The heat rate also depends upon the type of fuel. When calculating the heating
value of the fuel it is assumed that the water in the fuel, and the water formed by the
combustion of hydrogen, will be condensed, a condition obviously not obtained in a
boiler. About 4 percent of the heating value of coal, 7 percent of the heating value of
oil, or 10 percent of the heating value of gas is not available because of the water vapor
in the flue gas. The heat rates when burning oil and gas therefore are consistently less
than the heat rates when burning coal.
Twenty-one units of all sizes had heat rates under 9000 Btu/kwhr. These are all
fairly new plants and their heat rates are expected to become poorer as they become
older. The best heat rate obtained with any plant is 8,667, only 4 percent less than
9, 000 Btu/kwhr. With the present high money rates, and with nuclear plants taking
over in high-fuel-cost areas, it appears that the capital costs rather than fuel costs
will be reduced in the near future. Therefore, a rapid decrease in the heat rates of
new plants is not expected. A 9, 000 Btu/kwhr rate for new coal facilities is thus re-
commended. Gas and oil plants will probably be of similar design, and correcting for
the lower net heating value of the fuel, the rates will be 9, 350 and 9, 700 Btu/kwhr for
oil and gas.
The heat rate probably can be estimated more closely than any other cost factor
in the model. The differences in heat rates between the best and poorest coal plants
are about 10 percent. The differences in size, age, and other factors appear small
compared with expected variations in other parts of the model. However, it is recom-
mended that a different heat rate be used for the different fuels because of well-
established differences. These differences may be important if incremental costs
between fuels are compared, even though the total cost change maybe insignificant.
Recommended Values
It is recommended that the heat rate for coal-fired plants be estimated at 9, 000
Btu/kwhr, oil-fired plants at 9350 Btu/kwhr, and gas-fired plants at 9, 700 Btu/kwhr.
BATTELUE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 10.
60
HEAT RATES FOR 300 Mw AND LARGER ELECTRIC
GENERATING UNITSO)
Plant or Unit
Brunner Island
Eddy stone No. 1
Eddystone No. 2
Chalk Point
Hudson
Breed
Sporn No. 5
River Rouge
Roxboro
Marshall
McDonough
Colbert "B"
Paradise No. 1
Paradise No. 2
Widow's Creek "B1'
Coffeen
South Oak Creek
Joliet
Will County
Tanners Creek No. 4
St. Clair No. 6
St. Clair No. 5
Marshall
Gallatin
B ranch
Mt. Storm
New Boston
Cape Kennedy
Port Everglades
Port Everglades No. 3
Sewaren
Ritchie
Robinson
Handley No. 3
Little Gypsy
Stryker Creek No. 2
Webster No. 3
Sabine
Heat Rate,
Btu/kwhr
Coal Fired
9508
8735
8795
8762
9339
8957
9049
9450
9224
8691
9252
9520
9010
8900
9350
9930
9144
10,014
9616
8764
9010
9060
8712
9190
9692
9452
Oil Fired
9034
9461
9816
9482
Gas Fired
9902
9694
9610
9815
9794
9726
9891
Rating -Units,
Mw
\
768-2
354-1
354-1
727-2
454-1
450-1
496-1
933-3
410-1
700-2
600-2
550-1
704-1
704-1
1125-2
330-1
860-3
1862-8
1268-4
580-1
353-1
358-1
354-1
1255-4
300-1
1140-2
359-1
369-1
1254-3
402-1
359-1
404-1
405
668-2
527-1
389-1
952-3
Start- Up
Date
1961
I960
1960
1964
1964
I960
1960
1956
1966
1965
1963
1965
1963
1963
1961
1965
1959
1917
1955
1964
1961
1961
1965
1956
1965
1965
1965
1965
1960
1964
1961
1966
1963
1961
1965
1965
1962
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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61
TABLE 10. (Continued)
Plant or Unit
Mostly Coal
Arthur Kill
Mercer .
Astoria . .
Waukegan No. 8
Waukegan No. 7
State Line No. 4
Mostly Oil
Ravenswood
Riviera
Mostly Gas :
Alamitos
Allen
Etiwanda No. 3
Etiwanda No. 4
Bergen No. 1
Bergen No. 2
El Segundo No. 3
El Segundo No. 4
Pittsburg No. 6
Pittsburg
Contra Costa No. 7
Contra Costa No. 6
Morro Bay No. 4
Morro Bay No. 3
Heat Rate,
Btu/kwhr
Mixed Fuels
9389
9266
10, 171
9114
9185
9236
9916
9694
9530
9470
9692
9682
9353
9331
9239
9265
9420
9798
9377
9504
9506
9552
Rating -Units,
Mw
376-1
652-1
1550-5
389-1
355-1'.
326-1
1828-3
310-1
1982-6
990-3
333-1
333-1
325-1
325-1
342-1
342 -1
326-1
1277-6
359-1
359-1
359-1
359-1
Start- Up
Date
1959
I960
1953
1962
1958
1962
1963
1963
1956
1958
1963
1963
1959
I960
1964
1965
1961
1954
1964
1964
1963
1962
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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62
Station Capacity Factor
If cost comparisons are to be made between generating facilities on the basis of
some cost per kwhr, then the selection of the appropriate plant capacity factor is crucial
since it determines by how many units the capital costs and carrying charges are to be
divided. Capacity factor is defined as follows:
_ •«.,._ Kwhr generated in a given time period
apaci y ac or - Name plate kw rating X hours in the time period
The usual operating procedure for a utility on any given day is to increase the
portion of the load being carried by those generating facilities with the lowest incremen-
tal fuel cost first. As these efficient units are loaded to capacity, less efficient units
with higher unit fuel costs are started next. The reverse procedure is followed as sys-
tem load declines. Because the newer power plants are usually the most efficient, and
therefore have the lowest incremental fuel costs, these are the units that are started
first and shut down last. They are the generating units with the highest capacity factor.
One limit on any unit's capacity factor is its expected outage rate. Thus, the typical
history of a generating unit is that its capacity factor may be modest (50 to 70 percent)
in the first year or two of operation until the many operating and equipment difficulties
have been resolved. Over the next 5 years, it will probably remain among the most
efficient plants in the system, and its capacity factor should range between 70 and 85
percent unless unusual maintenance is required. More efficient plants should be avail-
able and operating in the remainder of a ZO-year period, and the capacity factor should
gradually decline to within the 40 to 60 percent range. Finally, in the later stages of its
useful life, the unit will be relegated more and more to peaking duty, and its capacity
factor will further decline to the 20 to 40 percent range. Unless the unit is unusually
efficient for its time, the average capacity factor for a unit over its life should not differ
substantially from the average system capacity factor.
Table 11 lists the average capacity factor for each United States' census region and
the United States' average. There are only minor deviations from the nation's average in
individual census regions with the exception that the capacity factors are higher in indus-
trialized urban regions and are lower in the rural areas. Individual-utility average ca-
pacity factors deviate more widely. As an example, Ohio Power Company, located in
the East North Central Region has a capacity factor approaching 70 percent. Nevertheless,
for fossil-fuel-fired steam plants, the average data in Table 11 should provide satisfactory
accuracy for use in the model.
Adequate operating experience has not been acquired for nuclear facilities to make
their historic capacity factors meaningful. Many utilities are estimating 75 to 85 percent
capacity factors for nuclear facilities when making the investment decision. This figure
which is higher than system average, is justified on the basis that although the anticipated
average cost of electricity generated by a nuclear station will be close to that of a fossil-
fired unit, the incremental fuel cost is much lower. As discussed in the section on
Nuclear Generation, carrying charges comprise a significant portion of the cost of nuclear
generation. Thus, the utilities reason that the first nuclear facility they install will have
a capacity factor higher than system average. However, as more and more nuclear plants
are added to any one system, their individual capacity factors must drop and approach the
system averages. This tendency is estimated in Table 12 which is a projection of United
BATTELLE .MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 11. AVERAGE GENERA TING-STATION CAPACITY FACTOR BY
U. S. CENSUS REGION - 1966 ESTIMATES
Census Region
Conventional
Steam Plants
Identification of
States in Census
Regions
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
51.9
55.4
58.0
49.9
55.5
55.2
49.2
47.1
Pacific
U. S. Average
52.6
53.4
Maine
New Hampshire
Vermont
Massachusetts
Rhode Island
Connecticut
New York
New Jersey
Pennsylvania
Ohio
Indiana
Illinois
Michigan
Wisconsin
Minnesota
Iowa
Missouri
North Dakota
South Dakota
Nebraska
Kansas
Delaware
Maryland
District of Columbia
Virginia
West Virginia
North Carolina
South Carolina
Georgia
Florida
Kentucky
Tennessee
Alabama
Mississippi
Arkansas
Louisiana
Oklahoma
Texas
Montana
Idaho
Wyoming
Colorado
New Mexico
Arizona
Utah
Nevada
Washington
Oregon
California
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TABLE 12. HISTORIC AND ESTIMATED FUTURE UNITED STATES'
AVERAGE CAPACITY FACTOR BY ENERGY SOURCEU5)
Year End Capacity,
thousands Mw
Coal
Gas
Oil
Hydro
Nuclear
Total
Energy Generated,
billions Kwhr
Coal
Gas
Oil
Hydro
Nuclear
Total
Average Annual Capacity
Factor, %
Fossil (Coal, Gas, Oil)
Hydro
Nuclear
Weighted Average
1955
60
22
8
25
0
115
302
95
37
113
0_
547
58.3
53.8
--
56.7
1965
125
47
17
45
1
235
571
222
65
193
4
1,055
53.5
51.3
42.3
53.6
1975
214
83
27
63
68
455
865
380
95
250
430
2,020
49.3
46. 1
80.0
52.3
1985
323
125
36
89
277
850
1, 155
500
110
320
1,615
3,700
42.
42.
70.
51.
9
0
0
3
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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States' average capacity factor* for various forma of generation. It shows estimated
average capacity factors for nuclear facilities of 80 percent in 1975 but of only 70 per-
cent by 1985. Finally, it must be noted that as the installation of more and more nuclear
facilities with capacity factors, higher than the system average are projected for the
future, the capacity factors of the remaining fossil-fired stations must fall below the
system averages.
Recommended Values
It is recommended that the average station capacity factors of Table 11 be used
whenever better, more specific information is not available.
Sulfur Dioxide-Control Devices
The cost of a sulfur-control device to the electric consumer depends upon the
direct cost of the device and upon the extra cost incurred from losses in transmission
because of the more expensive power. However, the latter cost is small and conse-
quently the major cost to the consumer is for the operation of the sulfur-control device.
Therefore, the assignment of an arbitrary cost to the sulfur-control device is almost
identical to the assignment of an arbitrary incremental cost to the consumer.
How the data available at one operating condition were extrapolated to other
operating conditions is described below. The Katell studies for 800 Mw plants using
the alkalized-alumina and the catalytic-oxidation processes have been used for the cost
base.
Data
The data Used for. developing costs of sulfur -control devices are those presented
by Katell. (*6) Katell1 o cost data, summarized in Table 13, are specifically for BOO-
TABLE 13. CAPITAL AND OPERATING COSTS FOR SULFUR
DIOXIDE CONTROL DEVICES* 16)
Operating
(90% Operating Load)
$/Ton
Capital Requirement^) Mills/ of Mills/
Process Dollars $/Kw $/Yr Kwhr Coal 104 Btu
Alkalized
alumina
Catalytic
oxidation
8,510,000
16,999,000
10.64
21.25
3,402,000
3,881,000
0.537
0.613
1.54
1.75
60.0
68.4
(a) Includes plant cost, interest during construction, and working capital.
(b) Includes raw materials, utilities, labor, maintenance, overhead, and capital charges of l¥h of total
investment but excludes by-product credit.
•ATTELLB MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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Mw(e) plants burning coal with a 3 percent sulfur content and operating at a 90 percent
load factor. Recently Katell^?) has modified one component of the annual cost, the
payroll overhead, by increasing it to 25 percent of payroll.
Other data are being developed for the National Air Pollution Control Administra-
tion by other contractors but are not yet available. Chilton^) has presented many
methods of extrapolating costs from one level of operation to another. Basically the 0.6
power rule, with modifications, is recommended.
Other cost data have been presented by Johswich^^J^ Katell and
Bienstock, Field, Katell, and Plants <2°), Field, Brunn, Haynes, and Benson(21), and
Kiyoura'22', and in an article in Sulphur(23). The data of Katell^) were U8ed because
they were the most detailed.
When using the model, costs for many plant sizes and operating conditions are
necessary. Therefore the assumptions below were Used to extrapolate Katell1 s data
other plant sizes and operating conditions.
(1) Capital costs are an 0. 6 power function of size.
(2) Catalyst and absorbent costs are proportional to size.
(3) The size of the absorbing section of the sulfur control device is
proportional to the negative logarithm of the fraction of sulfur
not removed from the stack gas.
(4) The size of the desorption and sulfur -processing section of the
device is proportional to the sulfur recovered.
(5) Manpower requirements are constant.
(6) Some operating and maintenance costs are proportional to the
capital cost.
(7) Other operating expenses are proportional to the power generated.
(8) Still other expenses are proportional to the amount of sulfur
recovered.
(9) Payroll overhead is 25 percent.
From these assumptions, the equations below were developed for capital and
operating costs. The procedure followed was to express each of the above nine cost
components as a function of plant size, etc., using the data of Table 13. The co-
efficients of like terms were then aggregated to obtain the capital-cost equation:
Capital Cost -
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C3x[MWx (667S -S02)]°'6
+ C4 x MW
667S\
g^-j
+ C, x MW (667S - SO.) ,
b t-
where
G!» Cj, etc. = aggregated coefficients
MW = plant rating, Mw
S = sulfur content of coal, percent
SC>2 = allowable SO2 emission, ppm.
Similarly, the ope rating -cost equation can be expressed as:
Cost = AI x labor rate
x capital cost
+ A3 x MW x LF '
+ A4x MW x LF x log1Q [ 667S ]
+. MW x LF x (667S - SO2) x (A5 + AS€ x price coal - AsS x price sulfur),
where A\, A2, etc. , AgC and AgS are aggregated coefficients and LF is the load factor.
At present this cost has been calculated as a recurring cost not including financial
factors. However, the financial factors, amortization, insurance, profit, interest, etc.,
could easily be included by adding the appropriate amount to A2. In the procedure devel-
oped and presented in this report, however, an alternative method has been used. The
procedure developed is discussed in another section.
For an individual process, several of the aggregated coefficients have been found
to be zero. Table 14 lists values of the coefficients for two 803- control devices. The
constants for other control devices could be determined from one detailed cost
breakdown.
The method of cost estimating is as accurate as the present cost estimates. Within
one process, the estimates indicate with reasonable accuracy how costs change with
changes in the various independent variables. When comparing different processes, the
cost data probably are not sufficiently reliable and should not be used to determine the
lowest cost alternative. As more accurate cost data become available, the coefficients
in the equations can easily be reevaluated.
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TABLE 14. COEFFICIENTS FOR COST-ESTIMATING
RELATIONSHIPS
Process
Coefficient
Ci
C2
C3
C4
C5
C6
AI
A2
A3
A4
A5
A5C
A5S
Alkalized Alumina
0
66, 700
890
0
0
0.24
59, 000
0.062
0
1,370
0
0. 120
0. 046
Catalytic Oxidation
293
0
0
0
0.87
0
59,000
0.062
0
398
0.07
0
0.046
The pattern of costs for the alkalized-alumina and catalytic-oxidation processes
are different. The catalytic-oxidation process should be more advantageous than the
alkalized-alumina for the largest plants operating at the highest load factors, with the
maximum sulfur removal, and with the highest-sulfur coals.
Recommended Procedure
If data are available for the specific operating conditions, it is recommended that
these data be used. If they are not available, it is recommended that cost be determined
from Figues 26 through 29, which are graphical solutions for the equations discussed
above but do not include a sulfur credit. If the operating conditions are such that the
costs cannot be read from the figures, then the equations should be used with the aggre-
gated coefficients given in Table 14.
Sulfur Content of Fuels
With the advent of SO2~ pollution controls, a premium is being placed on low-
sulfur fuels, and high-sulfur fuels may sell at a discount. At present, sulfur-control
regulation is just starting to affect the prices, and the final price structure can only be
estimated. Presumably, low-sulfur coal eventually will sell at a premium equivalent
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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too
100 300 1000 3000
Unit Size, Mw
10,000
FIGURE 26. CAPITAL COSTS FOR ALKALIZED-ALUMINA-TYPE
SO2 CONTROL DEVICE
100
-Cost independent
I of sulfur in cool
in
O
O
•o
_o
i
O
u
O
300 1000
Plant Size ,Mw
3000
10,000
A-537B6
FIGURE 27. CAPITAL COSTS FOR CATALYTIC-OXIDATION-TYPE
SO2 CONTROL DEVICE
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IU
01 5
o
E^
3 .
S. °-5
o
< 0.2
O.I
1C
I 3% sulfur in cool
- 0.02% S02 in stock
•"'
Lood
foe tor
- 50% '
- 30% "
— "
l
/
//?
^
1 Mill
/
//£
y
f
'
\ 1 1 1 II
O 300 1000 3000 10,000
Unit Size, Mw
FIGURE 28. OPERATING COSTS FOR ALKALIZED-ALUMINA PROCESS
10
«. S
0.5
0.2
0.1
3% sulfur in cool
90% S0e removal
30%
I l l l 11
I Mill
100 300 1000
Plont Size.Mw
3000 IO.OOO
A-65787
FIGURE 29. OPERATING COSTS FOR CATALYTIC-OXIDATION PROCESS
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TABLE 15. SHIPMENTS AND SULFUR CONTENT OF BITUMINOUS COAL
TO ELECTRIC UTILITIES IN 1964, BY FINAL DESTINATION^24)
Final Destination and Bituminous Coal,
Sulfur Content,
percent
District of Origin thousand short tons Range Average
New England
Massachusetts from district- -
1
2
3 and 6
7
8
Subtotal
Connecticut from district- -
1
3 and 6
7
8
Subtotal
Maine, New Hampshire, Vermont,
Rhode Island from district- -
2
3 and 6
8
Subtotal
Total New England States
States
562
149
713
35
1,967
3,426
2,461
1,329
24
171
3,985
8
389
392
789
8,200
1.0-3.6
1.2-2.8
0.7-3.6
0.5-0.7
0.6-2.0
0.5-3.6
1.0-3. 1
0.7-3.6
0.7
0.9
0.7-3.6
1.5
1.0-3.6
0.8-1.0
0.8-3.6
0.5-3.6
1. 5
1.8
2. 1
0.7
0.8
1.2
1.7
2.7
0.7
0.9
2.0
1.5
2.6
1.0
1.8
1.6
Middle Atlantic States
New York from district- -
1
Z
3 and 6
4
8
Subtotal
New Jersey from district--
1
Z
3 and 6
7
8
Subtotal
3,979
481
7, 130
194
1,096
12,880
1,702
246
3,723
27
31
5,729
1.0-3.6
1. 1-2.8
0.7-3.6
2.6
0.5-3. 1
0.5-3.6
1.0-3. 1
1. 1-2.0
0.7-3.6
0.7
0.6-1.7
0.6-3.6
1.9
1.6
2.1
2.6
0.9
1.9
1.6
1.5
2.4
0.7
0.8
2. 1
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TABLE 15. (Continued)
Final Destination and Bituminous Coal,
District of Origin thousand short tons
Pennsylvania from district -
1
2
3 and 6
4
Middle Atlantic States
(Continued)
_
8,830
6,096
4,904
4
Subtotal 19, 836
Total Middle Atlantic States 38, 445
Ohio from district --
1
2
3 and 6
4
7
8
9
Indiana from district- -
8
9
10
11
Illinois from district--
7
8
9
10
11
East North Central States
729
1,065
2,421
15,604
1
2,099
1,850
Subtotal 23,769
543
5,915
1,787
8, 774
Subtotal 17,019
1
34
2,852
19,706
402
Subtotal 22,995
Sulfur Content,
percent
Range
1.0-3.6
1. 1-4. 1
0.7-3.6
2. 0-3. 6
0.7-4. 1
0. 5-4. 1
2.2-3. 1
1. 1-4. 1
0.7-3.8
1.6-5.0
0.7
0. 5-1.7
2.7-4.0
0. 5-5.0
0.6-1.3
2. 0-4.0
1.2-4. 1
1. 1-5.3
0.6-5.3
0.7
0. 5-2.9
2. 0-4.0
1. 1-4. 1
1. 1-4. 5
0. 5-4.5
Average
1. 7
1.8
2.4
2. 2
1.9
1.9
2.7
2.4
2.7
3.7
0. 7
0. 8
3. 1
3.2
0.9
2.9
3. 1
3.3
3. 1
0.7
1. 0
2.8
2.8
2.9
2.8
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TABLE 15. (Continued)
Final Destination and Bituminous Coal,
District of Origin thousand short tons
Michigan from district- -
1
2
3 and 6
4
7
8
9
10
Wisconsin from district--
Z
3 and 6
4
7
8
9
10
11
East North Central States
(Continued)
310
2
549
6,320
20
6,532
756
201
Subtotal 14, 690
53
336
266
19
382
1,917
3,594
96
Subtotal 6, 663
Total North Central States 85, 136
Minnesota from district- -
2
3 and 6
4
7
8
9
10
15
21
Iowa from district- -
10
11
12
15
West North Central States
1
193
350
15
209
90
2,344
65
582
Subtotal 3, 849
1,397
1
747
174
Subtotal 2,319
Sulfur Content,
percent
Range
1.2-2.8
2.8
0.7-3.6
1. 6-4. 5
0.7
0. 5-2.9
2.0-4.0
1.6-3.7
0. 5-4.5
1. 1-2.2
1.2-3.6
2.2-3. 1
0.7
0.6-1.3
2.0-4.0
1. 1-4. 1
1. 1-4. 5
0.6-4.5
0. 5-5.3
1.8
3.5-3.6
1.6-3. 1
0.7
0.7-0.8
2.0-2.9
1. 1-4. 1
3.0
0.7-1.0
0.7-4. 1
1. 1-4. 1
3.9
4.2-5.7
3.0-6.0
1. 1-6.0
Average
2.0
2.8
2.8
3.2
0.7
0.9
2.9
2.7
2. 1
1. 5
2.3
2.9
0.7
0.8
2.8
2.4
3.0
2.4
2.8
1.8
3.6
3.0
0.7
0.8
2.6
2.9
3.0
0.8
2.5
3.0
3.9
4.7
5. 1
3.7
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TABLE 15. (Continued)
Final Destination and Bituminous Coal,
District of Origin thousand short tons
Missouri from district--
9
10
15
West North Central States
(Continued)
10
2,651
2,757
Subtotal 5,418
Sulfur Content,
percent
Range
2.7-4.0
1. 1-4. 1
3.0-6.0
1. 1-6.0
Average
3. 1
2.9
4.0
3. 5
North and South Dakota from
district--
10
19
21
Nebraska and Kansas from
district 15
Total West North
1
188
1, 115
Subtotal 1, 304
925
Central States 13,815
South Atlantic States
1.2-4. 1
0.6-1.0
0.7-1.0
0.6-4. 1
3.0-6.0
0.6-6.0
3. 1
0.9
0.8
0.8
3. 7
3.0
Delaware and Maryland from
district- -
1
2
3 and 6
8
District of Columbia from
1
3 and 6
Virginia from district--
7
8
3,611
428
1,572
165
Subtotal 5, 776
district- -
343
7
24
Subtotal 374
503
7,321
Subtotal 7, 824
1.0-3. 1
1. 5
0.7-3.5
0. 5-1. 1
0. 5-3. 5
1.0-2.5
2.2
0.5-0.7
0. 5-2.5
0. 5-1. 1
0. 5-3. 1
0. 5-3. 1
1.8
1.5
2.0
0.9
1.8
1. 5
2.2
0.7
1. 5
0. 7
1.0
1.0
West Virginia from district--
3 and 6
4
8
3,699
919
3,009
Subtotal 7, 627
0.7-3.8
2. 1-5.0
0. 6-2. 1
0.6-5.0
3.2
3.3
1.4
2.5
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TABLE 15. (Continued)
Final Destination and Bituminous Coal,
Sulfur Content,
percent
District of Origin thousand short tons Range
Average
South Atlantic States
(Continued)
North Carolina from district- -
7
8
Subtotal
South Carolina from district- -
7
8
Subtotal
Georgia and Florida from district- -
8
9
13
Subtotal
Total South Atlantic States
305
8, 182
8,487
46
2,555
2,601
3,723
1,734
575
6,032
38,721
0.5-0.9
0.5-3. 1
0.5-3. 1
0.7
0. 5-3. 1
0.5-3. 1
0.5-3. 1
2.0-4.0
0.7-1.6
0.5-4.0
0. 5-5.0
0.7
0.9
0.9
0.7
1.0
1.0
1.6
3.0
0.9
1.9
1. 5
East South Central States
Kentucky from district- -
8
9
10
Subtotal
Tennessee from district- -
7
8
9
10
13
Subtotal
Alabama and Mississippi from
district- -
9
10
13
Subtotal
Total East South Central States
889
7,246
3,046
11, 181
20
5,729
4,662
184
475
11,070
5,013
69
6,918
IZ^OOt)
34,251
0.5-2.6
2.0-4.0
1. 1-4. 1
0.5-4. 1
0.7
0. 5-4.3
2.0-4.0
2.5
- 1.6
0.5-4.3
2.0-4.0
2.5
0.7-1.7
0.7-4.0
0.5-4.3
1.2
3.0
2. 1
2.6
0.7
1.8
3. 1
2. 5
1.6
2.4
2.9
2.5
1. 1
1.9
2.2
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TABLE 15. (Continued)
Final Destination and Bituminous Coal,
District of Origin thousand short tons
West South Central
Arkansas, Louisiana, Oklahoma,
Texas from district 15
States
18
Sulfur Content,
percent
Range
4.0
Average
4.0
Mountain States
Colorado from district- -
16
17 1,
19 __
Subtotal 1,
Utah from district 20
Montana and Idaho from
districts 22 and 23
Wyoming from district 19 1,
New Mexico from district 18 2,
Arizona and Nevada from district- -
18
20
Subtotal
Total Mountain States 6,
535
113
284
932
410
294
762
116
426
30
456
970
0.3-0.7
0. 5-0.9
0.7
0.3-0.9
0.6-0.8
0.6
0.6-1.0
1.0
1.0
0. 6-0.7
0.6-1.0
0.3-1.0
0. 5
0.7
0.7
0.6
0.7
0.6
0.9
1.0
1.0
0.7
1.0
0.8
Pacific States
Alaska from districts 22 and 23
354
0.7
0.7
Other Destinations
Canada from district- -
1
2
3 and 6 1,
8
9
Subtotal 3,
259
888
887
121
20
175
1.6-2.0
1.5
1.2-3.5
0.6-1.2
2.7-4.0
0.6-4.0
1.7
1. 5
2.3
0.8
3. 1
2.0
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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77
TABLE 15. (Continued)
Sulfur Content,
Final Destination and Bituminous Coal, percent
District of Origin thousand short tons Range Average
Other Destinations
(Continued)
Destinations that are not
revealable from district--
1
2
3 and 6
8
9
10
11
13
15
20
Subtotal
Total Other Destinations
Grand Total
4
7
27
100
48
9
75
3
11
23
307
3,482
229,392
1.8
1.8
2.4
1. 1
2.9
2.7
3.3
1. 1
3.9
0.7
0.7-3.9
0.6-4.0
0.5-6.0
1.8
1.8
2.4
1. 1
2.9
2.7
3.3
1. 1
3.9
0.7
2. 1
2. 1
2.3
BATTELLE MEMORIAL. INSTITUTE - COLUMBUS LABORATORIES
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78
to the cost of removing sulfur dioxide from the flue gas by the least expensive method.
At present, low-sulfur oil in New York sells for 37^/MM Btu, while high-sulfur oil
sells for 28^/MM Btu. In general, premiums are not charged for low-sulfur coal, ex-
cept that often the low-sulfur coal mine is farther from the electric plant than is the
mine for high-sulfur coal and there is a transportation price differential.
Data
Figure 30^4) shows that in 1964, electric utilities consumed less low-sulfur coal
and more medium-sulfur coal than the national averages. Table 15 pinpoints coal ship-
ments to utilities in the year 1964 from specific coal-producing regions. (24) Not only
is the tonnage shipped from each producing region to electric utilities presented, but
also the range and average sulfur content of those shipments. Figure 31 (25) js a map
which identifies the various coal-producing regions. As indicated in Table 15, the
weighted average of sulfur content for coal burned by electric utilities is 2.3 percent.
This is for cleaned coal; for coal not cleaned as is used by some utilities, the sulfur
content would be 0.3 to 0.5 percent higher.
Figure 32 shows the oil-using regions and Table 16 shows typical sulfur contents
(minimum, average, and maximum) of oils used in these various regions. "6) Trend
data indicate that the national arithmetic average sulfur content of 129 samples of fuel
oil burned by electric utilities was relatively constant around 1.6 percent in the 5-year
period I960 through 1965.
TABLE 16. SULFUR CONTENT OF NUMBER 6 FUEL OIL
(26)
Geographic Distribution Rocky Mountain
of Burner Fuel Olls(a); Eastern Region Southern Region Central Region Region Western Region
Districts Within Region: A. B. C D E, F, G H. I. J, K L, M. N. O. P
Additional Districts^: D.E.F. G.J A, B, C. E, F. G. J A.B.C.D.H.I.J.K.L E.F.G. H.l.K E.F, G.H.I. K
Number of Fuels: 40 15 34 17 23
Test Min Avg Max Min Avg Max Mln Avg Max Min Avg Max Min Avg Max
Sulfur Content, percent 0.47 1.43 2.8 0.48 1.65 3.15 0.38 1.58 4.0 0.45 1.81 4.0 0.87 1.56 4.0
(a) Regions and districts are shown on map (Figure 32).
(b) Some of the fuels are sold in districts of more than one region.
Discussion
The option of burning low-sulfur coal is available only to a few utilities and not to
the industry at large because insufficient low-sulfur coal is available. Only about 40
percent of the bituminous coal mined has a sulfur content of less than 1 percent and most
of that is used in the manufacture of steel.
A comparison of the coal reserves with the coal production listed by DeCarlo,
et al. (24) indicates that the sulfur content of coal will increase as the low-sulfur reserves
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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79
Medium-sulfur cools
(I.I to 3.0 percent)
138,222,000 tons
High-sulfur cools
(over 3.0 percent)
48,547,000 tons
Low-sulfur cools
(l.O percent or less)
42,623,000 tons
Shipments of Bituminous Coals to Electric Utility Plants, by Sulfur Content,
in 1964 (Includes Subbituminous Coals and Lignite)
Low-sulfur coals
(1.0 percent or less)
202,565,561 tons
High-sulfur coals
(over 3.0 percent)
133,153,827 tons
Medium-sulfur coals
3.0 percent)
462,815 tons
b. Production of Coals of All Ranks, by Sulfur Content, in 1964
FIGURE 30. SULFUR CONTENTS OF COAL<24)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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FIGURE 31. MAP OF THE COAL-PRODUCING DISTRICTS OF THE UNITED STATES
District Number and Name
1.
2.
3.
4.
5.
6.
7.
8.
Eastern Pennsylvania
Western Pennsylvania
Northern West Virginia
Ohio
Michigan
Panhandle
Southern numbered 1
Southern numbered 2
9.
10.
11.
12.
13.
14.
15.
16.
West Kentucky
Illinois
Indiana
Iowa
Southeastern
Arkansas-Oklahoma
Southwestern
Northern Colorado
17.
18.
19.
20.
21.
22.
23.
Southern Colorado
New Mexico
Wyoming
Utah
North -South Dakota
Montana
Washington
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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00
FIGURE 32. GEOGRAPHICAL AREAS OF THE NATIONAL SURVEY OF BURNER-FUEL OILS(2<>)
-------
are depleted. The steel industry, the second largest user of coal, would be more seri-
ously affected by an increase in the sulfur content of coal than the electric utilities and
therefore should be willing to pay a higher premium for low-sulfur coal. Thus, the
option of reducing sulfur emmission by the substitution of low-sulfur coal, o.r the equiv-
alent by deep cleaning or conversion to gas or liquid fuelj for high-sulfur coal will be
available only in special cases.
The simplest way to treat the additional cost of low-sulfur coal is to compare the
distances from the mines to the generating station and assume that all of the cost dif-
ferences is due to additional transportation costs. Current data do not permit deter-
mining the price differential between coals of different sulfur contents.
Recommended Values
It is recognized that the best information for use in the model for evaluating
specific situations might be obtained directly from the electric utility or coal supplier.
In a comparison being made between a high-sulfur coal and a low-sulfur coal, quotations
for both fuels, if possible on a delivered basis, would be most desirable. However, in
most evaluations and, in particular if a hypothetical plant is being considered, the sulfur
content of the coal should be taken from Table 15 for the region of use and origination.
The only present basis for comparing the prices of low- and high-sulfur oil is the
experience in New York of Consolidated Edision. Therefore, the cost of a low-sulfur
oil should be estimated as being 20 percent higher than the applicable high-sulfur-oil
cost.
Sulfur Credits
The prospect that substantial quantities of sulfur could be recovered from the stack
gases of electric generating facilities poses the problem of determining a probable value
for the sulfur. In the context of this program, the value figure needed corresponds to
the so-called "net back" that the producer of sulfur realizes from sales at his producing
location.
The value of sulfur to the consumer depends on his use of it and the relationship
that this bears to the commercial forms of sulfur available to him. The consumer of
sulfur who is making sulfuric acid can utilize a wide variety of forms - brimstone
(elemental sulfur), pyrites, sulfur dioxide from smelter gas, hydrogen sulfide, certain
petroleum sludge acids, etc. Conversely, the consumer of sulfur who is making matches
or compounding rubber products has to have brimstone in solid form with specific physi-
cal properties and purity requirements. In effect, the markets for sulfur in the United
States require the producers to supply a multitude of forms and quality levels, each
tailored for its intended end use.
The principal forms in which sulfur is consumed include (1) crude brimstone, either
dark or bright, (2) processed sulfur or refined sulfur, and (3) sulfur dioxide derived from
roasting of pyrites or nonferrous sulfides. Crude brimstone contains a minimum of 99.5
percent sulfur, and when contaminated with carbon from Frasch-mined deposits, it is
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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83
known as "dark" crude brimstone, entirely suitable for making sulfuric acid but not
acceptable for many other uses. A minor quantity of Frasch-mined brimstone and vir-
tually all the recovered sulfur produced from some natural gas or petroleum refinery
off-gas streams is bright crude brimstone, suitable for conversion to processed sulfur
or for many nonacid uses. Processed sulfur contains from 93 to 99.9 percent of sulfur,
has the characteristic yellow coloration, and is treated to make it suitable for a specific
nonacid use, such as rubber compounding, pesticide formulation, or match manufacture.
Sulfur dioxide, a gas at ambient temperatures and pressures, is used predominantly for
making sulfuric acid in a plant adjacent to the sources of the sulfur dioxide.
Sulfur Consumption
In 1966, the latest year for which "official" data are available, apparent consump-
tion in the United States amounted to about 9.2 million long tons'^') Of sulfur equivalent
in all forms. This was supplied from domestic production of brimstone, pyrites, and
sulfur dioxide in smelter gases and imports of brimstone and pyrites, as shown in
Table 17.
These are the only so-called "official" data known to exist with respect to the con-
sumption of all forms of sulfur in the United States. It will be noted that the emphasis
for these data is the source of the sulfur and not the use to which it is put or the inter-
mediate products by which this supply is converted to end uses.
"Unofficial" estimates prepared by representatives of the major U. S. Frasch sul-
fur producers(28) indicate that 82 to 87 percent of the sulfur consumed in the United
States is used to make sulfuric acid. The balance of 13 to 18 percent is consumed in a
large number of end uses and industries, among which the pulp and paper, industrial
chemicals, rubber, and pesticides industries are relatively important. Table 18 presents
Gittinger's estimates. (28)
Sulfuric Acid Markets
Neither of the sources of da.ta.^> ^°' attempt to detail the geographic distribution
of sulfur consumption in the United States. However, data on the production of sulfuric
acid is collected and reported by the U. S. Bureau of the Census on a regional basis;
from this sulfur consumption can be approximated by applying an appropriate conversion
factor. In prior studies, Battelle has developed such a conversion factor that agrees
rather well with the "unofficial" estimates for consumption of sulfur in sulfuric acid. To
produce 1 short ton of sulfuric acid (100 percent basis) requires approximately 0. 3 long
tons of brimstone in a modern catalytic acid plant. Although a number of less efficient
chamber acid plants are still in use, the application of the 0. 3 factor to total new acid
produced is an adequate first approximation of regional sulfur consumption for sulfuric
acid. Table 19 presents Bureau of the Census data for production of new sulfuric acid
in selected geographic areas. To avoid revelation of specific plant data, the distribution
by area differs from the usual presentation of the nine standard Census regions.
It will be noted that the several sets of data do not result in a statistically compat-
ible series of numbers for any given year. This results from differences in orientation
of the various reporting agencies and their inclusion or exclusion of certain data, for
example, the spent acid burned in a number of acid plants located beside petroleum
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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84
TABLE 17. APPARENT CONSUMPTION OF SULFUR IN THE UNITED
STATES*27)
(Thousands of Long Tons of Sulfur Equivalent)
Brimstone^' \,
U. S. Frasch crude*a)
U. S. recovered
Mexican Frasch crude
•Canadian recovered
Subtotal
Pyrites.
U. S. production
Canadian imports
Subtotal
Smelter -Gas Acid
Other Production*^*)
Total*0)
1960
3343'.:
775
6'0.7
134
4859
416
146
562
345
95
5862
1961
3259
831
649
183
4922
399
135
534
332
106
5893
1962
3320
907
746
295
5268
379
145
524
355
98
6244
1963
3438
929
863
488
5718
344
93
437
336
116
6607
1964
3847
988
891
571
6297
354
120
474
366
124
7260
1965
4286
1167
831
656
6940
354
160
514
388
139
7980
1966
5314
1256
799
715
8084
356
160
516
424
134
9158
(a) Apparent sales less exports of crude and refined sulfur.
(b) Includes H2S and SC>2 from certain refineries and smelters.
(c) Detail may not add to total because of independent rounding.
TABLE 18. ESTIMATED CONSUMPTION OF SULFUR
IN THE UNITED STATES BY ACID AND
NONACID APPLICATION*28)
(Thousands of Long Tons of Sulfur Equivalent)
Acid Use
Nonacid Use
Total
I960
4950
1050
6000
1961
4950
1050
6000
1962
5250
1050
6300
1963
5750
1100
6850
1964
6300
1150
7450
1965
6935
1190
8125
1966
7975
1225
9200
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 19. PRODUCTION OF NEW SULFURIC ACID AND CALCULATED CONSUMPTION OF SULFUR IN THE UNITED STATES,
BY SELECTED AREAS(29>
H
m
r
r
m
m
§
TO
r
z
M
H
C
m
i
o
Q
r
c
x
m
c
M
r
o
o
a
H
O
5
n
M
I960
New England
Middle Atlantic
Pennsylvania
North Central
Illinois
Iowa
Michigan
Ohio
Wisconsin
South
Delaware and Maryland
Florida
Texas
West
California
Idaho
U. S. Total
H2SO4
(100%),
Mst
193
2,436
755
3,623
1,356
82
324
742
(a)
8,546
1,119
2,272
1,593
2.288
1.009
(1)
17. 085
Sulfur
(All Forms),
Mlt
58
731
227
1.087
407
25
97
223
2,564
336
682
478
686
303
5.126
1961
H2S04
(100%),
Mst
179
2,423
770
3,629
1,399
75
308
684
(a)
8.731
1.078
2,518
1.585
2,096
924
(1)
17. 058
Sulfur
(All Forms).
Mlt
54
727
231
1,089
420
23
92
205
2,619
323
755
476
629
277
5.117
1962
H2SO4
(100%).
Mst
184
2.482
797
3.819
1,464
82
332
662
(a)
9,975
1,114
3,087
1,886
2,323
1.057
(1)
18.782
Sulfur
(All Forms),
Mlt
55
745
239
1. 146
439
25
100
199
2.993
334
926
566
697
317
5.635
1963
H2SO4
(100%).
Mst
184
2.626
877
4,052
1.562
90
356
659
(a)
10. 833
1.017
3,822
1,926
2,342
1,049
(1)
20, 038
Sulfur
(All Forms).
Mlt
55
788
263
1.216
469
27
107
198
3.250
305
1. 147
578
703
315
6.011
1964
H2SO4
(100%).
Mst
193
2.768
941
4.317
1.697
92
347
675
(a)
12, 117
1.043
4.406
2,274
2.566
1,163
(1)
21,959
Sulfur
(All Forms),
Mlt
58
830
282
1,295
509
28
104
203
3,635
313
1,322
682
770
349
6. 588 .
1965
H2S04
(100%).
Mst
207
2.709
972
4.355
1,704
82.
323
704
(a)
13. 675
1.035
5,558
2.502
2.867
1.398
(1)
23, 813
Sulfur
(All Forms),
Mlt
62
813
292
1,307
511
25
97
211
4,103
311
1,667
751
860
419
7,144
1966
H2S04
(100%).
Mst
205
2,721
966
4,475
1.763
99
342
689
38
16, 749
1.049
7,444
2,968
3.357
1.423
737
27.506
Sulfur
(All Forms),
Mlt
62
816
290
1.343
529
30
103
207
11
5.025
315
2,233
890
1,007
427
221
8,252
(a) Included with "other" (not reported here) to avoid disclosure of individual plant data.
-------
86
refineries. This spent acid is included in the Census data but is not recorded elsewhere
as a source of sulfur except as a rather gross estimate prepared by "unofficial" sources.
As shown in Table 19, the Middle Atlantic and North Central areas - containing a
large share of the industrial production of the country - has had a rather modest growth
from I960 to 1966. The major increase has occurred in the Southern area - especially
Florida and Tesas - under the impetus of rapidly expanding markets for phosphatic
fertilizers.
For the near-term future - say 1975 - the industrialized northeast is expected to
continue the growth pattern of the past few years. On the other hand, the rapid growth
of phosphatic fertilizers will be moderated by capacity in excess of demand until the
latter part of the period.
Regional Value of Sulfur
Traditionally, Frasch brimstone produced in the Gulf Coast area has been the
price leader for sulfur both within the United States and worldwide. Since 1965, the
quoted price for brimstone fob Gulf ports has risen from $26. 50/long ton for dark crude
to the current level of $41.50. To a large extent, the fertilizer buildup in the United
States has accounted for a demand in excess of productive capacity for sulfur. Between
1963 and 1967, the production deficit was supplied from producers' stocks, but the pro-
longed shortfall permitted producers to raise prices without fear of substitution.
Production increases effected in 1966 and 1967, coupled with 2 years of less-than-
expected growth in phosphatic fertilizers - also 1966 and 1967 - combined to reestablish
the supply-demand balance late in 1967, and the preliminary indication is that some
addition will be made to producers' stocks during 1968. Assuming that the producers -
worldwide - will be able to meet near-term demands, it is anticipated that the fob Gulf
ports quoted price for brimstone will fall to the $30 to $35 range by about 1970 and re-
main in that range through 1975.
On the basis of the current quoted price - $41. 50 fob Gulf ports - brimstone has
an approximate value of $48.50 in the New York - New Jersey area, and $50 to $52 in
the Chicago or Pittsburgh areas on the basis of ship or barge transportation in molten
form. These are the approximate values for sulfur with which sulfur recovered from
power plant stacks would compete. By 1970, the comparable values are expected to be
$37 to $42 in New York - New Jersey, and $40 to $43 in Chicago and Pittsburgh, assum-
ing that the bulk of the demand will be supplied by shipments from the Gulf Coast. When
more than one-third of the local (within a 100-mile radius) demand is available from
local sources at prices equivalent to or less than the prevailing Gulf ports price, the
local market price will be depressed. Further, if the local area becomes an export
center - i.e., produces more than the local demand - the adjacent areas also will ex-
perience price depression toward the prevaling Gulf ports price, under the assumption
that the local production is in the form of brimstone with quality equivalent to crude
Frasch brimstone.
A study of local demand centers in the northeastern part of the United States appears
to be necessary to properly assess the impact of any given sulfur-recovery installation
from generating-facilities' stack gases.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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87
Recommended Values for Recovered Sulfur
The electric utility recovering sulfur from stack gases will be faced with the
problem of disposing of that sulfur and concurrently with the problem of setting a price
for it. As indicated in the preceding section, the site of recovery and the sulfur supply/
demand relationship in that area will influence the "net back" that the utility could ex-
pect. But the costs for selling that sulfur represent expenses that must be deducted
from the "net back" to determine the value the utility can credit to the producing
installation.
Two principal routes are open to the utility recovering sulfur with respect to dis-
posing of it. Firstly, the utility may decide to handle the marketing of the sulfur on its
own and become a competitor for any markets available. Secondly, the utility may elect
to arrange for the marketing of the sulfur through an established organization, thus avoid-
ing an entry into the chemical business. The choice between these two alternatives will
depend on a number of factors, including the important consideration of the quantity of
sulfur involved and the status of the sulfur market in the area.
For preliminary planning purposes, either alternative mentioned above will in-
volve expenses over and above the cost of actually producing the sulfur. These expenses
should be deducted from the sales price received in order to determine the credit to the
producing facility. When the utility becomes the marketing agent, it can be anticipated
that about 20 percent of the sales price will be allocated to selling expenses, general
administrative overhead, and profit. Thus, at a sales price of $37/long ton, the credit
to the producing facility would be $29. 60. If the utility can arrange for sales to be
handled by an outside organization, the sales commission might be negotiated to be about
10 percent of the sales price, which would yield a credit to the producing facility of
$33. 30 on a sales price of $37/long ton.
Between these two alternatives, the latter appears to be the more attractive choice
to maximize the value credited to the producing facility. However, it can be anticipated
that the established sulfur-marketing organizations might resist such an arrangement,
forcing the utility to undertake an independent marketing effort. In the initial operation
of the model it is recommended that the assumption be made that the utility will have to
handle the marketing of the sulfur and will incur the associated expenses, leaving 80
percent of the sales price as the credit to the producing facility.
Further, the assumption should be made that the effective sales price for sulfur
in the period from 1970 to 1975 will be about $30/long ton fob U. S. Gulf ports. This
will mean an effective sales price of $37/long ton in the New York area, and $40/long
ton in the Chicago or Pittsburgh areas under current supply conditions.
If the recovery process results in the production of sulfuric acid instead of brim-
stone, the calculation of its value becomes more complex. With sulfur selling for about
$48/long ton in New York currently, the quoted price for 100 percent sulfuric acid is
$34. 65/short ton fob works. One short ton of this acid will contain 0. 3 long tons of sul-
fur having a value of $14.40, the balance being attributable to conversion costs, sales
and administrative overhead expenses, and profit. For simplicity, call this figure $20/
short ton. Then, with sulfur selling at $37/long ton, the resulting sulfuric acid should
sell for $31. 10/short ton in the 100 percent grade. This figure would then be reduced
by 20 percent to arrive at a credit of $24. 90/short ton of acid to the producing facility.
BATTELUE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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88
In the event that the recovery process yields a lower strength and contaminated
acid, it would be necessary in most locations to process it to a clean 100 percent acid
to assure markets for it. On the basis of estimates of concentration and filtration costs,
Battelle calculates that a 70 percent acid would have to sell for $5 to $6/short ton less
than the going market price for 100 percent acid in order to be marketable. Again assum-
ing the $37/long ton sulfur price, the sales price for the 70 percent acid would be $25. 10
to $26. 10/short ton fob works, with a probable deduction of 20 percent from this as the
value credited to the producing facility, say $20. 10 to $20.90,
By means of these relationships, values for recovered products can be calculated
for any sulfur price between $30 and $45/long fob Gulf ports. Below $30 and above $45,
recalculation of the appropriate prices for 100 percent and 70 percent sulfuric acids
would be necessary.
Carrying Charges Treatment of
Financial Costs, Depreciation, and Taxes
Although carrying charges quoted by individual utilities are seen to vary consider-
ably because of the items included, at some point in their investment decision each com-
pany must consider similar factors. As an example, some companies choose to include
a component for "general supervision and maintenance" in their carrying charges. In
Battelle's model, all such costs are considered under regular recurring costs (as are
property taxes and insurance). Thus, the only elements remaining for separate inclusion
as carrying charges are financial costs, depreciation, and gross-receipts and income-
based taxes. Because utility returns are predictable, most taxes can be expressed as a
percentage of this return, and it is common utility practice to include taxes in their
carrying charges.
The effective property-tax rates that are included under recurring costs are de-
rived from Netzer's study/^O) and represent the average of the effective rates applied
to all taxable property in a state in I960. These state averages were in turn combined
to derive averages for each FPC District (Table 20). Actual taxes on individual power
plants within a single FPC district will vary widely from these averages depending upon
location, because the administration of property taxes is highly fragmented. The fact
that I960 statistics are being used should not introduce too much bias in estimating cur-
rent tax levels as applied to power-generating stations since many of these are located
outside of metropolitan areas. Rural areas traditionally have lower property tax rates
than metropolitan regions.
The financial components of the carrying charges are subject to less regional
variation for two reasons: (1) electric utility return is regulated by individual states
whose regulatory philosophies are fairly similar and (2) utilities compete in a national
market for capital. Since the deviation in financial risk between various utilities is
relatively small, so is their interest cost for debt securities at any given time.
Considerable discussion surrounds the selection of appropriate "cost of capital"
or "target return" rates to be used in evaluating investment alternatives. One point
frequently raised is that these costs should represent conditions anticipated during the
life of the project and not historic costs. Fortunately, for purpose of this study, the
utility return on investment (the combined return on bonds and the equity of all classes
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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89
TABLE 20. I960 AVERAGE PROPERTY TAX RATES (PERCENT) ON ALL
TAXABLE PROPERTY(30)
FPC District
Maine
Vermont
New Hampshire
Massachusetts
Rhode Island
Connecticut
New York
New Jersey
Pennsylvania
Maryland
Delaware
Average
FPC District
West Virginia
Ohio
Michigan
Indiana
\f Avt til ?* 1^*r
tvencucKy
Average
FPC District
Virginia
North Carolina
South Carolina
Tennessee
Georgia
Alabama
Florida
Average
I
2.
2.
1.
2.
1.
1.
2.
2.
1.
1.
0.
•MM
1.
II
0.
1.
1.
1.
.
1.
Ill
0.
0.
0.
1.
0.
0.
1.
^•H
0.
4
1
9
4
9
6
1
3
3
5
7
8
9
4
8
2
"
2
9
8
8
0
9
5
1
9
FPC District
Wisconsin
Illinois
Minnesota
Iowa
Missouri
Average
FPC District
Kansas
Arkansas
Mississippi
Louisiana
Oklahoma
New Mexico
Average
FPC District
North Dakota
South Dakota
Nebraska
Wyoming
Colorado
Average
IV
1.
1.
1.
1.
1.
1.
V
1.
0.
0.
0.
0.
i
X .
0.
VI
1.
1.
1.
1.
1.
1.
9
5
9
2
1
5
4
6
7
8
9
o
V
9
3
4
4
0
4
3
FPC District VII
Montana
Idaho
Utah
Washington
Oregon
Average
FPC District VIII
California
Nevada
Arizona
Average
United States Average
1. 1
1.0
1. 1
0.9
1.6
1.2
1.4
0.9
1.0
1. 1
1.4
BATTELLE MEMORIAL. INSTITUTE - COLUMBUS LABORATORIES
-------
90
of stock) is regulated by the individual states. Not only are these procedures somewhat
similar among states, but, in many cases, legal proceedings are required to alter the
allowable return. The latter procedure tends to make changes in rates and utility re-
turns far less volatile than swings in the financial markets.
The Federal Power Commission provides a tabulation of rates of return for all
electric utilities, calculated on a consistent basis, in its annual statistical summary.^ D
It must be emphasized that this "rate of return" is different in a financial sense than the
one usually considered because it includes the return on debt as well as equity compo-
nents. Figure shows the median United States return from 1961 through 1966. In
1966, 75.9 percent of all U. S. electric utilities earned returns of between 6.00 percent
and 8.99 percent; thus, the disperison around the 7.44 percent median is fairly small.
Although this rate of return has been steadily rising for the past 5 years, the rate of
increase appears to be leveling off.
The computational procedure outlined in the FPC summary(3D was applied to the
composite income statement and balance sheet of all United States electric utilities for
1966 which are summarized in the same publication. These calculations produced an
average return of 7.03 percent. The fact that the average return is 0.945 times the
median indicates a skewed distribution of returns, and we have assumed the distribution
to retain the same shape every year. Thus, in any year, the average return should
approximate 0.945 times the median return published by the FPC. This estimation is
applied to historical data in Figure 33.
Sample calculations are summarized in Table 21. These are based upon both the
current average 7.0 percent return figure and a 7. 5 percent return in order to reflect
anticipated future conditions. The average interest rate paid by all electric utilities on
their debt is included in this return and can be calculated from the summarized financial
statements in the FPC statistical summary. This rate was 3.67 percent in 1966. Should
the utilities continue to pay 6 percent or more for new long-term-debt securities, this
average interest cost should rise substantially. The 7.5 percent return figure assumes
an average interest cost approaching 5 percent; however, the earnings rate on equity is
assumed to have remained the same in this calculation. In the long run, the equity re-
turn rate would also rise in order to maintain a spread representative of the different
risks inherent between these two types of securities. For purposes of reviewing the
appropriateness of the return component of the carrying charges calculated in this re-
port, however, one need only check the trend of median utility returns published in
future FPC statistical summaries, apply the appropriate average to median ratio
(0.945), and consider current trends in the financial markets.
Because interest expenses are deductible from State and Federal income taxes it
is necessary to know how the total return is divided between return on debt and equity.
Actually, the FPC calculated return includes a third relatively small factor, tax credits.
The distribution for a 7.0 percent return is estimated from the composite financial state-
ments in the FPC statistical summary(31) and is shown in Table 22. The estimated dis-
tribution for a 7. 5 percent return (assuming the added 0.5 percent is entirely attributable
to higher interest costs) is also indicated.
Other assumptions made in generating the carrying charges were the use of sinking
fund depreciation for making the investment decision and double-declining balance depre-
ciation for tax purposes. The sinking-fund discount rate was assumed to be the same as
the cost of money. A United States' utility average debt-equity ratio in 1966 of 0. 5226 to
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
91
r.D
7.5
7.4
73
72
§ 7I
&
£ 7°
3
®
CC 6.9
6.8
6.7
6.6
r
f
/
J
j
~\-\
/
s
f
/
/l
y
/
/
\
A
/
1
I
/
f
1
x^
<
./
Estir
i
y
u
. ^
| W
t
noted
^
iX
i
S. median
V
X
U.S. a\
y
/erage
1961 1962 1963 1964 1965 1966 1967
Year
FIGURE 33. MEDIAN AND ESTIMATED AVERAGE U. S. ELECTRIC UTILITY
RETURNS (AFTER TAXES AND DEPRECIATION BUT BEFORE
INTEREST) AS A PERCENT OF NET PLANT INVESTMENT^1)
BATTELLE MEMORIAL. INSTITUTE - COLUMBUS LABORATORIES
-------
U.S. Avg
TABLE 21. ESTIMATED LEVELLIZED ANNUAL CARRYING CHARGES (PERCENT)
FOR VARIOUS RETURN RATES AND PLANNING PERIODS
CD
H
m
r
n
ac
n
0
*
>
r
z
^
FPC
Dist.
I
U
III
IV
V
VI
VII
VIII
7%
Return and
Depr.
9.44
n
n
n
n
n
n
n
Return - 20
Fed. Inc.
Tax
3.33
"
it
it
n
ii
it
n
Years
State Inc.
Tax
0.33
0.07
0.25
0. 13
0. 14
0. 10
0.25
0.22
7-1/2 % Return - 20 Years
Rev.
Taxes
0.89
0.20
0.93
0.26
0.23
0.00
0.60
0.03
Total
13.99
13.04
13.95
13. 16
13. 14
12.87
13.62
13.02
Return and
Depr.
9.81
n
ii
"
n
n
n
ii
Fed. Inc. State Inc.
Tax . Tax
3.12 0.31
" 0.06
0.23
" 0. 12
" 0. 13
" 0.09
11 0.24
" 0.21
Rev.
Taxes
0.88
0. 19
0.91
0.26
0.22
0.00
0.59
0.03
Total
14. 12
13.18
14.07
13.31
13.28
13.02
13.76
13. 17
9.44
3.33
0.20
0.49 13.46 9.81
3.12
0. 19
0.48
13.60
m
i
o
o
r
c
X
c '
r
o
a
H
U
a
m
-------
93
TABLE 22. ESTIMATED PERCENT DISTRIBUTION OF U. S.
AVERAGE ELECTRIC UTILITY RETURNS AFTER
TAXES BUT BEFORE INTEREST
Interest
Equity
Tax Credits
1966 Averages
7.0 Percent Return
27.8%
69.5%
2.7%
Estimated for
7.5 Percent Return^)
33.2%
64.3%
2.5%
(a) Assumes that all of increased return is attributed to increased interest rates,
0.4774, calculated from the FPC statistical summary, was used. Furthermore,
interest costs on long-term debt were based upon the 1966, 3. 67 percent utility average.
Federal income tax calculations included the 10 percent surcharge, and a 52. 8 percent
effective rate was employed.
State income tax rates and gross receipts rates vary widely; indeed, some states
have no form of corporate income tax or special revenue taxes on utilities. Effective
rates for the year 1966 were obtained from The State Tax Handbook 32) and are tabulated
in Table 23. These rates, in turn, were averaged for the group of states in each FPC
district, and the average rate for each district is also shown in Table 23. In certain
states, Federal Income Tax is deductible from the state tax. In these cases, the pub-
lished state rate has been reduced by a factor representing the deduction, so that the
percentage shown is the effective rate on net income before income taxes. In other
states a tax is imposed on each kwhr of electricity generated. On the basis of United
States' averages, this generation tax has been converted to a fraction of gross receipts
and is included in the gross receipts tax rate in Table 23.
Carrying charges computed on the basis of these assumptions and stated as a
constant annual percentage of the original investment cost are summarized in Table 21.
These carrying charges have been calculated both for a 7.0 and 7. 5 percent return and
consider a 20- and 30 -year planning period. Data derived from the FPC statistical
summary and all other historic cost data would currently reflect carrying charges at
7.0 percent and 30 years. Utility rates are normally based upon historical costs; thus,
this combination of return and equipment life might represent the impact of an invest-
ment decision on the cost of electricity as generated.
For the purposes of planning, however, the utility may wish to minimize the risks
attributable to uncertainty and would evaluate the investment over a shorter, 20 -year
period. Furthermore, it might apply an anticipated return rather than historic figure.
Thus, for the purpose of simulating a utility investment decision, carrying charges based
upon a 20 -year life and 7.5 percent return might be more realistic.
For a given rate of return and planning period, it has been assumed that these two
factors will not vary among the eight FPC Districts. Thus, although state income taxes
and gross revenue taxes do vary from one location to another, these are all deductions
before net income. Net income is assumed constant; therefore, the Federal Income Tax
charge will not show a regional variation.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
TABLE 23. 1966 EFFECTIVE STATE INCOME TAX RATES, GROSS RECEIPTS, TAX RATES,
AND TAXES (PERCENT) ON GENERATION OF ELECTRICITY CONVERTED TO AN
EQUIVALENT GROSS-RECEIPTS BASIS*32)
FPC
District I
FPC
S. Inc. Gr. Recpts.
BATTEU
r
PI
m
o
JU
r
z
M
H
H
C
H
W
O
c
o
c
(A
r
OB
O
O
3
fn
M
Maine
Vermont
New Hampshire
Massachusetts
Rhode Island
Connecticut
New York
New Jersey
Pennsylvania
Maryland
Delaware
Average
FPC
West Virginia
Ohio
Michigan
Indiana
Kentucky
Average
5.
9.
6.
6.
5.
5.
3.
6.
5.
5
5.
0
0
8
0
3
5
3
0
0
o
2
,>.
-
2.5
4.0
2.5
14.6
1.4
2.0
0 1
2.7
District II
—
_ _
2,
3.
1.
0
3(b)
1
—
3 0
0.2
^
0.6
Virginia
North Carolina
South Carolina
Tennessee
Georgia
Alabama
Florida
Average
FPC
Wisconsin
Illinois
Minnesota
Missouri
Average
FPC
Kansas
Arkansas
Mississippi
Louisiana
Oklahoma
Texas
New Mexico
Average
District III
FPC District VI
S. Inc. Gr. Recpts.
5.
6.
5.
4.
5.
2.
3.
0
0
0
0
0
4(b)
9
3.5
6.0
3.4(a)
3.5
-
2.9(a)
0.3
2.8
District IV
3.
4.
0.
2.
3(b)
4(b)
9(b)
1
4. 1
-
_
0.8
District V
2.
5.
3.
1.
1-
1.
2.
0
0
9!b>
9
4(b)
2
0.4
2.0
2.0
0. 5
0.7
North Dakota
South Dakota
Nebraska
Wyoming
Colorado
Average
FPC
Montana
, M oho
Utah
Washington
Oregon
Average
FPC
California
Nevada
Arizona
Average
United States
Average
S. Inc. Gr. Recpts.
2.8
-
5.0
1.6
District VII
5. 3
6 0
2.8
6.0
4. 0
District VIII
5.5
2.0
3_._l
3. 5
3.2
—
-
0.2
0.0
1.3
3 l*a)
0,3
3.8
0.3
1.8
__
0.2
0. 1
1.5
(a) Includes tax on generation.
(b) Published rate modified to reflect deductibility of Federal Income Tax.
-------
95
The relative sensitivity of these carrying charges is illustrated by the four cases
in Table 21. For a given evaluation period, there is little variation in the overall carry-
ing charge as a result of changing costs of money, if the change is primarily in the inter-
est cost on debt. In the long run, one would expect the return on equity to rise also and
this would ultimately result in substantially increased carrying charges since all the tax
components would then also increase. Although not shown, one could anticipate a high
degree of sensitivity to a change in income tax rate if a given return after taxes is to be
maintained. Finally, the anticipated sensitivity to changes in depreciation or planning
period is shown by comparing the examples for 20 to 30 years for a given rate of return.
It should be pointed out that in the cost model and in the treatment of annual carry-
ing charges, the investment, operating costs, etc., of the 803-control process have been
considered in the same light as any other component of the power station. Under current
laws and regulations, there appears to be some question as to the validity of this
approach. It is not appropriate to argue this point here. But, if some other method of
treatment proves to be necessary, only minor modifications of the model structure will
be needed.
Insurance Costs
Insurance costs for generating facilities consist primarily of two components,
property and liability insurance. The cost is divided nearly equally between these two
types and the total cost varies in proportion to the size and value of a facility. The cost,
therefore, may be stated as a percentage of plant first cost, and this percentage will be
nearly uniform for all sizes of conventional steam plants.
An early impediment to commercial development of nuclear power was the question
of unlimited liability in the event of an accident. Although the probability of such a
catastrophe is minute, without some actuarial experience, insurance companies were
unwilling to provide insurance, and without some legal limitation on their liability, po-
tential users were unwilling to risk developmental investment. The Price-Anderson
Act of 1957 provided this statutory limitation, and it further authorized the AEC to
indemnify parties held liable for damages incurred as a result of a nuclear incident.
AEC coverage is extended only for amounts in excess of $74 million and up to the statu-
tory limit. This, in effect, limits the amount of privately placed liability-insurance
coverage required for a given nuclear facility to $74 million and tends to lower the cost
of insurance coverage, stated as a percent of first cost, as the size of nuclear plants
increases. Nevertheless, insurance costs are considerably higher on a nuclear plant
than on a comparable sized fossil-fuel-fired installation because of the greater potential
liability and the larger investment required per Mw(e) of capacity.
Annual insurance costs expressed as a percentage of unit first cost were computed
from a number of sources and plotted in Figure 34. These sources include data acquired
from field interviews, the National Power Survey, *-*3) an(j an analysis done by S. M.
Stoller Associates, a nuclear consultant, for an A. D. Little report on the "Future
Market for Utility Coal in New England". (34) Trend lines have been estimated and are
suitable for use in the model; however, it would be desirable to develop a larger data
base, in particular, to more accurately estimate nuclear insurance costs.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
96
c
8
o
a>
u
c
o
3
C
C
<
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0,3
0.2
O.I
_ r
A
Cc
Jucle
\
3r pi
"^
nventional
ants
o
\
stea
^
m pic
• A -
^X
ints
— • -
^x
— —
^~l~*++
•— • —
\
— — .
c
^
1
— -_
>
"^x
>
j
• — .
t
•x.
M^
0 100 200 300 400 500 600 700 800 900 1000 1100 1200
Unit Size , Mwe
FIGURE 34. ANNUAL PROPERTY AND LIABILITY INSURANCE COSTS FOR
A GENERATING UNIT AS A FUNCTION OF UNIT SIZE<33.34)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
97
NUCLEAR-POWER GENERATION
Nearly half of all the new electrical-generation capacity planned between now and
1974 will use a nuclear energy source. Although a variety of subjective considerations
(such as possible future pollution-control regulations) may have had an impact upon these
decisions, the primary determinant was undoubtedly anticipated economic gain. Although
some question is still raised about future supplies of fissionable material, the overriding
cost component in any nuclear-power-plant evaluation is the capital cost of the facility.
On an annual basis, carrying charges are typically one-half of the total cost of nuclear
power generation.
Unfortunately, these investment costs have fluctuated widely and have trended
sharply upward in the recent past. Since there is a long lead time (at least 6 years)
between announced construction and the in-service date of a nuclear plant, these higher
costs will be reflected in stations coming on line after 1974.
For the purpose of this study, nuclear generation may be considered as an alterna-
tive to controlling the SO2 emissions from a fossil-fuel-fired station. Therefore, pri-
mary interest is in the anticipated costs of nuclear plants being planned at any given point
in time. With the nuclear cost picture being so volatile, historic cost data are not very
useful for this purpose. Furthermore, only a small number of nuclear stations are cur-
rently in operation, and historic nuclear cost data are not available in abundance. Cost
data for nuclear facilities are tabulated in the FPC's publication Steam-Electric Plant
Construction Cost and Annual Production Expenses(^); however, the facilities included
to date are smaller than 300 Mw, and it will be several years before enough larger
nuclear plants are in operation to make this a useful data source.
TABLE 24. NUCLEAR-GENERATION-COST ESTIMATES DERIVED FROM
UTILITY INTERVIEWS
Unit Name
Utility
Scheduled in Service
Size, Mw(e) net
First Cost, $/kw
Est. Plant Factor,
percent
Fuel Cost, mills/kwhr
O. & M. , millAwhr
Insurance, mill/kwhr
Substation O. & M.
millAwhr
Ft. St. Vrain(a>
P. S. of Colo.
1972
350
154
83.5
1.63
0.46
0.18
.02
San Orofre
S. Calif. Ed.
1968
430
202
Diablo Canyon
No. 2
Pac. G. & E.
1972
1060
149
80.0
1.89
. 09
.06
.01
Pilgrim
No. 1
Bost. Ed.
1971
625
192
91.0
0.40
Browns Ferry
Nos. 1 and 2
TVA
1970
1063(b>
117
85.0
1.26^c^
0.19
.04
.01
Indian
No. 2
Cons.
1969
873
100
1.62
Point
No. 3
Ed.
1971
965
160
1.76
Subtotal,
mills/kwhr 2.29
Utility Fixed Charges,
mills/kwhr 2.43
Total, mills/kwhr
4.77
2.05
2.55
4.60
1.50
0.89(c)
2.39(c)
(a) High-temperature gas-cooled reactor (some costs subsidized).
(b) Personnel may be shared with Unit No. 1.
(c) TVA's low carrying charges make these components seem disproportionately small.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
98
Table 24 is a listing of costs made available by utilities visited in the course of
this study. The data are useful as indications of relative costs; however, the data base
is too small to allow meaningful aggregation. Table 25 is a tabulation of nuclear plants
for which construction plans have been announced. The estimated first costs in terms
of $/kw have been grouped by unit size and by year of planned installation. This is shown
in Figure 35. Not only does the installed cost/kw rise sharply as unit size decreases,
but a sharp annual upward cost trend is evident for all sizes. Figure 36 shows estimates
of installed costs by unit size for all types of steam-gene rating facilities, including
nuclear, for the year 1974.
The estimation of nuclear fuel costs requires a financial model of its own since the
fuel is purchased (or leased) a year or more before the plant goes into operation. It is
then treated, used, repositioned in the core, processed with credits accruing to recov-
ered plutonium, and then reused. A typical cycle as just described may last from 3 to
5 years. Thus, the largest portion of these costs are carrying charges. How this invest-
ment is distributed over the energy generated is dependent upon plant capacity factor,
cost of money, taxes, and other items. Because analysis of the costs associated with
nuclear-fuel management is a science in itself, fuel costs as estimated by utilities should
be used for making the necessary predictions. This assumes that the installations'
operating patterns and financial costs are similar enough so that serious error is not
introduced by this aggregation. Figure 37 is a 1965 estimate of the trend in nuclear fuel
costs; however, recent experience suggests that this trend is not dropping as rapidly as
indicated.
Estimates of operating and maintenance expenses for different sizes of nuclear
plants for both 1970 and 1975 are shown in Table 26. Table 27 shows the estimated total
cost of generation in mills/kwhr for three nuclear plants that are approaching the opera-
ting stage. These costs are broken down into carrying charges, fuel costs, and other.
The costs on Brown's Ferry have been adjusted from TVA's to a private utility's finan-
cial costs. The data in Figure 37 and Table 26 seem to fit into the framework of the
data in Table 27.
The data were combined to generate a sample calculation which might be repre-
sentative of a nuclear facility being planned now for 1974 operation. These calculations
are summarized in Table 28, and the prospects for nuclear generation are, on the whole,
not so encouraging in the future as in the past. This picture is largely created by the
sharply increasing first cost of these facilities, and for purposes of comparison, the
same costs have been generated for typical installed costs of 1 year earlier. This
results in overall generation costs in mills/kwhr that are 5 to 10 percent lower for facili-
ties starting in 1973 than for those starting in 1974. Since many of the first costs quoted
for plants scheduled for operation between 1970 and 1973 are as much as 30 percent less
than the general 1974 cost levels, the rush to nuclear power in this period is
unde r standable.
Thus, in expanding the data base of nuclear-generation costs in the immediate
future, cost estimates of those facilities currently being planned should be relied upon.
A report on nuclear-power-plant activity is published annually in Electrical World(35)
and is a source for data of this type.
The staff of Electrical World is also maintaining a tabulation of all planned gener-
ating facilities. Appendix B shows the fossil-fuel and hydroelectric portions to
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
99
TABLE 25. NUCLEAR PLANTS UNDER CONSTRUCTION OR ANNOUNCED<35>
Owner (epereter)
tanrlia PUM ratliit Header
date MoXaliaat H*m
tleeJfawr
1X9
Jaraay Central PAL
Oalrytand Pwr Co-op
Niagara Mohawk Pwr
Commonwealth Edison
Consolidated Edison
Northeast Utilities
Rochester GAE
in*
Commonwealth Ediaon
Comm. Ediaon. Iowa-Ill.
Tenn. Valley Authority
Florida PAL
Wisconsin-Michigan Powar
Carolina PAL
Northern States Power
Contumeri Powar
un
Duke Power
Comm. Edison, lowa-ln.
Consolidated Cdlson
Tenn. Valley Authority
Florida PAL
Wisconsin-Michigan Power
Philadelphia Elect, et al>
Vermont Yankee Nudaar
Omaha Public Powar Dial.
Virginia CAP
Boston Edlton
Metropolitan Edlion
Niagara Mohawk Powar
an
Duke Power
Commonwealth Cdlton
Pacific CtE
Contumers Public Pwr. Dlst.
Meine Yenkee Atomic Pwr
Public Service CAC. et el-
Arkansas PAL
Wisconsin PS. et el '•
Tenn. Velley Authority
Public Service of Colo.
Northern Slates Power
Virginia CAP
Florida Powar
Indiana A Mlchlgen |ACP|
Ul>
Duke Power
Commonwealth Cdison
Consolidated Cdlson
Sacramento MUD
Lot Angelas. DWP
Iowa Electric LAP
Baltimore GAE
Georgia Power
Long Itland Lighting
New York State EAG
Public Service CAG. et el-
Carolina PAL
Phaadelphle Clec. el alt
Jaraay Central PAL
Duguasne Light, et at-
Indiana A Michigan |AEP|
Northeast Utilities
Toledo Edlton. CEI
Baltimore GAE
PacINc OAE
Carolina Power A Lt
Northern States Power
Virginia EAP
So Cal Ed. San Diego
Contumera Power
Portland GE
1975
Lot Angeles, DWP
Philadelphia Elect
Contumen Power
1*77
Philadelphia Elect.
Net (eked aled
Consolidated Ediaon
Northarn Indiana PS
Caroline PAL
Ouqueane light (AEC)
Commonwealth Edlton
Yankee Atomic Elect
Consolidated Edlion
AEC (Rurel Coop Power)
Saxton Nudaar Corp"
Detroit Edison
Pldflc GAE
Conaumera Power
ACC [Puerto Rico WRA|
Washington Public Pwr
Northern States Power
Philadelphia Elect
Conn. Yankee Atomic
So Cal Ed, San Diego
Oyster Creek 1
Lacrosse BWR
Nina Mile Point 1
Oreaden 2
Indian Point 2
Millstone 1
R. E. Glnna 1
Dresden 1
Quad-Cltiea 1
Browna Ferry 1
Turkey Point 1
Point Beach 1
Roblnaon I
Monllcello 1
Palltadat
Ocone* 1
Quad-Otlea 2
Indian Pdnt 1
Browns Ferry 2
Turkey Point 4
Point Beech 2
Peech Bottom 2
Varmont Yankee
Ft Calhoun 1
Surry 1
Pilgrim 1
Three Mile Itland 1
Cation 1
Oconee 2
Ztoo l
Diablo 1
Cooper 1
Maine Yankee
Salem 1
RutsetlvUle 1
Kewenee 1
Browns Ferry 3
Fort St. Vreln
Prairie Island 1
Surry 2
Crystal River 1
Cook 1
Oconea 3
2ion 2
Undecided
Rancho Seco 1
Melibu
Duane Arnold
Celverts Cliffs 1
Edwin 1. Hatch 1
Shoreham 1
Ball Station 1
Salem 2
Brunswick 1
Peech Bottom 3
Oyster Creek 2
Beaver Velley 1
Cook 2
M«lstone2
Undecided
Calverta Cliffs 2
Diablo 2
Brunswick 2
Prairie Island 2
North Anna 1
Botaa Island 1
Midland 1
Trojan
Boise Island 2
Undedded
Midland 2
Undedded
Undedded
Batty 12
Undedded
Shipping port
Dresden 1
Yenkee Nudaar
Indian Point 1
Elk River
Sexton
Enrico Fernlc
Humboll Bay 3
Big Rock Point
Bonua
Hantord
Pethflnder
Peach Bottom 1
Haddam Neck
San Onofra
40-U
19(1"
40-(9
IX*
20-61
2oU
1970
1*70
40-70
2O-70
20-70
20-70
2O-70
20-70
20-71
1971
2O-71
4O-71
20-M
20-71
2O-7I
10-71
20-71
1O-71
20-71
4O-71
20-72
1*72
20-72
2O-72
20-72
10-72
40-72
2Q-72
40-72
IO-72
20-72
10-72
20-72
2O-72
20-73
2O-73
20-73
20-73
4O-73
1O-73
1*71
20-73
20-73
10-73
20-73
2O-73
2Q-73
20-71
20-73
20-74
40-74
10-74
3O-74
2Q-74
2O-74
1O-74
30-74
20-74
40-74 •
20-75
2Q-75
1975
2O-77
19(7
KM
Ml
19(2
19(2
1X2
Ml".
M3
Ml
M4
19M
M7
10-(*
1O-W
515 (MO)
50
500 K20|
715 |(0t|
(71
(52.1
420
715 (90*)
715(909)
1.075 11,121)
(99.5
454(4*7)
472 (545)
700(931)
941|(((|
7»|(0t|
9(5
1,075 (1.129)
(99.5
454(4*7)
1.0(5
S14|540|
457
7*0(9121
(25|(54|
(10 (940)
750
941|HI|
1.050 (1,1001
1.0(0
779
910 1*55)
1.050 (1.091)
(50
527
1.075 11,129)
130
530(550]
tw!*»5,''
1.054 (1,093)
941|M(|
1.050 11.1001
1.115
(00
4(2
550
(00 (MS)
(00
523 (551)
(10
1.050(1.091)
(20
1.0(5
(10|*20)
900
1.029)1.097)
(29.2
900
(00|((5|
1.0(0
(20
530(550)
7*0(912)
• 900
•WO •
• 1,000
• 990' •
1.0(5
• (00 •
1.0(5
1.115
515*
920
150
200
179
270
20.9
4J
60,9|150)
(9
75
17.1"
(00(9(0)"
59.5
eg
4(7(5(71
4M
1,600 (L.920)
1(5
1.53(11.77(1
2.255 (2,5271
2,759
2.011
1.100
2.255(2.527)
2.255 (2.927]
3.293 (1.440)
2.202
1.3M (1.519)
2.094
1.4(9 |1.S/4|
2.200(24401
2.4(9 12.5(41
2.255 (2.9271
1,025
1.2*1 (1.440)
2.202
1.3*6 11.519)
3.2*5
1.513 I1.K5I
1,420
2.441 12.54(|
L912 ILtNl
2.452 P.5B)
2.191
2.4(9 p.5(4|
1.250 (1.3(11
3.250
2.391
2.560 (2.650)
1,250(1.3*11
2.5(1
1.650
3.293 (3,440)
(42
1.650 IU2U
2.441(2,54(1
2.452 (2.9(01
1,25011.1*1)
2.4U (2,5*4)
3,250 |».3»1|
1.2*1
2.452
1.471
1.591
2.450 (2.700)
2.416
1.5*1 11,665|
2.43(
3.250(3.3*11
2.4K
1,295
2.452 (2.7721
2.440
3.250(1.3911
2.5(0
Undedded
2.450 (2.700)
3,250
2.4K
l.(50 (1.7211
2.44112.54(1
NA
2.440"
NA
3.300
3,2*5
2.440"
3.2*5
3.2*3
_^__
2.4X
505
700
(00
(15
S9J
21.5 (351
240
240
50"
4.000
1(0
115
1.471 11425)
1.147
QE
A-C
OC
QE
Waat.
OE
Watt,
OE
QE
OE
Waal.
Wett.
Waat.
QE
Comb.
BAW
QE
Welt
QE
Weat.
Weat.
OE
OE
Comb.
Watt.
QE
SAW
OE
BAW
Waat.
Waat.
QE
Comb.
Weat.
BAW
Weat.
GE
GGA
I Weat.
Weat.
BAW
Weat.
BAW
Weat.
OE
BAW
Weat.
QE
Comb.
GE
GE
GE
Waat.
OE
QE
BAW
Weat
Weat.
Comb.
Undadded
Comb. Engr-
Undedded
OE
Wett.
Weat.
Undadded
Undaddad
Undedded
Undedded
OE
Undedded
QE
GE'
OC'
QE
Weat
QE
Waat
SAW
A-C
Waat
Comb.
UE
OE
Comb.
Kalaer
AC
OOA
Weal.
Weat
OE
A-C
OE
QE
Wait
QE
Wait
OE
OC
QE
Weat.
Waat
Weat.
QE
Weat
OE
QE
Weat.
OC
Walt
waat
QE
OE
OE
Wett
OC
OE
QE
OE
Weat.
Weal.
Weal.
Weil.
Weil.
Weat.
Wett.
OC
OE
Watt
Wait.
Wett
OE
OC
Weat.
ACI
Wait
Undaddad
QE
OE
OC
OE
OC
wast.
OC
OC
Weat.
Waat.
B-B
Undeddad
Undaddad
weat.
Undedded
OE
West.
Wett.
Cng. Elect.
Undedded
Und added
Eng. Elect.
QE
Undedded
QE
ACI'
-
OE
Waat
OC
Waat
Elton
Waat
A-C
QE
QE
GE
AC
weat
weat
Wait
Buma A Ro*
SAL
•Owner
SAL
UEAC
Elwaco
Qlbert
SAL
SAL
Owner
Bechtel
Bechtal
Ebaaco
Bechtel
Bachtal
Owner
SAL
UEAC
Owner
Bechtel
Bechtal
Bechtal
Cbaaeo
Glbba A HID
SAW
Bechtel
Gilbert
Owner /SAW
Owner
SAL
Owner
Burnt A Roa
SAW
Owner
Bechtel
Pioneer
Owner
SAL
Pioneer
SAW
Gilbert
Owner
Owner
SAL
Owner
Bechtel
Owner
Comm. Ataoc.
Bechtel
Owner/Bechtel
SAW
UEAC
Owner
UEAC
Bechtel
Burna A Roe
SAW
Owner
Undedded
Undaddad
Bechtet
Owner
UEAC
Pioneer
SAW
Undedded
Bechtel
— —
Owner
Undaddad
Bechtal
Undedded
Owner
— «««
Undedded
Owner"
Bechtal
SAW
Owner
A-C
Waat
APDA/Comm.
Bechtal
Bechtal
^^^_
Burna A Roe"
npnear
Bechtel
SAW
Bedrtal
Burna A Ro*
Melon Coral.
SAW
UEAC
UEAC
Cbaaeo
Bechtel
UEAC
UEAC
Owner
Becfttel
Bachtal
Ebaaco
Bechtel
Bechtel
Owner
UEAC
UEAC
Owner
Bechtal
Bachtal
Bechtal
Ebaaco
Owner
SAW
Bechtal
UEAC
SAW
Owner
Owner
Owner
Burna A Roa
SAW
UEAC
Bechtel
ptjnear
Owner
Ebeteo
Owner
SAW
Owner
Owner
Owner
Owner
Undeddad
Undecided
Owner
Undedded
Bachtal
Owner
SAW '
UEAC
UEAC
UEAC
Bechtel
Burna A Roe
SAW
Owner
Undedded
Undedded
Bechtel
Owner
UEAC
Owner
SAW
Undedded
Bechtel
Owner
Undedded
Bechtel
Undedded
Undaddad
— ^^
Undadded
Burna A Roa"
Beehtal
SAW
Owner
Maion Const
^__
UEAC
Bechtal
Becntel
^^__
Burnt A Roe"
AC
Becntel
SAW
Baohtal
NA
20033490
mots,***
(04*94091
NA
0.1*9401
7440*4(1
7M(*4>»>
m,fl*B,**it
U14M4B9
MJOO.OO*
75.0*0.0*9
3M4**40C<
•V*5*B4VO'
9B.BBB.fJBO'
NA
1219004001
111.500,000
(2400.000
142400.0001
115.000400
714*0.0*0
127410,0091
Not* 17
129400.000
NA
n, 500.000'
125.000.0(01
191411.000
UO. 000.000
111400.000
110,000,0001
140.00J.OOO
(34*0400
1494(04*0
(2.0004*0
93J00400I
12741*400*
1144X40*
13tV*9*4*Bi
1914*04(0
1M49*.***'
NA
142.5M.5N
•2.500.0*9
100.0*04*0
121. MOM
150.000400
NA
115400.0001
110,000,0001
127,200.000
142.500.000>
NA
150.000,000
1S04004*0>
NA
111.000.000
107.150.000
150,470,000
116.000.000
9M09.000
190.000.0001
NA
U). 500,000'
169.000,000
204,900.000
— ^—
131,50I.OI»i
NA
NA
^— _
NA
71.W.OOJ1
K400400"
t»0/kw
NA
U.50UM
(.500.0(0
7U00400
24JOO.OOO
2*. 190,000
1JJ06.009I
X4004B9I
2ij»»4B*
(2aV/lnv
(*4»»40(
A
:.l
Jt
.1
.1
-•
.1
.tl
.11
1
S
S
()—rating! In bracket! are anticipated future upralln«t for stretch, rellcenslng. valves «
A-C—AMIS Chalmers
AC)—Associated electric Industries. Great Britain
APOA—Atomic Power Development Associates
B-B—Brown Boveri. Switrerland
BAW—Babcock A WIKoi
Comb.—Combustion Engineering
Comm.—Commonwealth Associates
GAl—Ollbert Atsoclates Inc.
GE—General Electric
COA—Gulf General Atomic
Qlbbs A Hill—Qlbba. Hill. Durham and Rlehardaon
NA—not avallawa
Pioneer—Plonear tervlce A Engr.
SAL—Sargent A Lundy
SAW—Stone A Webatar En*r.
UEAC—United Cn*lneara A ConatracUra
Weet.—Weeanahouea ctactrtc
Natee la tabutatlen:
1 Half of total cost for two units
1 Excludes $15 million for research A development
' Eicludet Indirect costs
• Jointly owned by Duqunne Light. Ohio Edison.
and Pann. Pwr
* Optional
< Plant delayed
< Includes BO Uw(e) obtained from Metropolitan
Water District turbine
• Jointly owned by Public Service ttO. PMIa Beet
Atlantic City Elac. and Oelmarva PAL
» Jointly owned by Wleconeln Pf, Wlaconaln PAL.
and Madison QAE
" Includes reaervolr, dam and tlta development far
ultimate 4.000 Mw
" Now under startup tests (1/2*/**) report
reaching 40 Mw(O
» Data It for two unit turbine plant onry—
ACC awns reactor
>• Stockholders: Jenay Central PAL, New Jaraay
PAL. Metro Edison, end Pinllic
•* CrUlcaltty data
M Want graea output
" Date submitted ta ACC: Total location costs
(4T5.100.000; other coats (23400400; Interest
(11400400
• Data from CW June 14, 1M9
• For turWne plant only (SAW/Waat designed
reactor plant Drava waa conatnjctor)
" Includes capadty for steam aupplM ofl-alte
n Excludaa land coats
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
100
A-55788
FIGURE 35. TREND OF INSTALLED COSTS OF NUCLEAR ELECTRIC GENERATION
STATIONS BY SIZE RANGED5)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
220
200
180
8. 160
. 140
91
>
C
120
100
80
400
101
Nuclear
Bxcluding fuel)
600 800
Maximum Net Capability, Mw
1000
FIGURE 36. CAPITAL INVESTMENT AVERAGE SITE AND LABOR CONDITIONS
1974 OPERATION^15)
First Unit - New Site
ALT. A-increasing U,0scost
ALT. B-r k>w plutonium
V0lue Late 1962
0.8
1968 1972 1976 I960 1984 1968 1992 1996 20OO
A-557M
Year of Operation
FIGURE 37. NUCLEAR FUEL CYCLE COST FORECASTS^36)
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
102
supplement the information for nuclear facilities shown in Table 25. It is expected that
this information will be updated regularly. On the other hand, as soon as some opera-
tional experience is gained on the larger nuclear stations, fuel costs and operation and
maintenance expenses should be less volatile, and they will be available annually in the
FPC's report on steam-electric generation facilities^-*) in the FPC accounting format.
TABLE 26. ESTIMATED NUCLEAR OPERATING, MAINTENANCE
AND INSURANCE COSTS^37)
(Mills/Kwhr)
Year of Startup
Electrical Power Output, net Mw
O&M
Insurance
Total
450
0.40
0.21
0.61
1970
650
0.31
0.47
1000
0.25
0. 13
0.38
450
0.30
O.J5
0.45
1975
650
0.24
O.J2
0.36
1000
0. 19
0. 10
0. 29
TABLE 27. APPROXIMATE GENERATING COSTS EXCLUDING
LONG-RANGE ESCALATION^)
(Mills/Kwhr)
Plant Fuel Other Total
1962-3 Cost Outlook Based on -
Oyster Creek (Nuclear) 2.0 1.8 0.6 4.4
Comparable Coal Plant 1.9 1.9 0.6 4.4
1966 Cost Outlook Based on -
Brown's Ferry (Nuclear) 2.1 1.6 0.4 4.1
Comparable Coal Plant 2.0 2.0 0. 5 4. 5
1967 Cost Outlook Based on -
Diablo Canyon (Nuclear)
Comparable Coal Plant
2.6
2.3
1.7
2.1
0.4
0.5
4.7
4.9
Note: All figures adjusted to comparable basis.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
103
TABLE 28. ESTIMATES OF NUCLEAR ELECTRIC-POWER-GENERATION UNIT
COSTS FOR A PLANT STARTING OPERATION AFTER 1974 -
80 PERCENT ASSUMED PLANT FACTOR
(U. S. Average Figures)
Plant Size, Mw(e) net 400 600 800 1000
Installed Cost, $/kw . 212 193 178 166
Carrying Charges at 10. 74% (30 Years/at 7%), mills/kwhr 3.26 2.96 2.73 2.55
Property Taxes at 1.4%, mills/kwhr 0.43 0.39 0.36 0.34
Fuel, mills/kwhr 1.70 1.70 1.70 1.70
O. & M. , mills/kwhr 0.35 0.31 0.28 0.22
Insurance, mills/kwhr 0. 18 0. 16 0. 14 0. 11
Total, mills/kwhr 5.92 5.52 5.21 4.92
Comparison with 1973 First-Cost Levels:
Installed Cost, $/kw
Carrying Charges and Property Taxes, mills/kwhr
Total, mills/kwhr 5.70 5.33 4.96 4.32
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
104
EXAMPLES OF APPLICATION OF COST MODEL
This section contains a group of figures and a group of tables illustrating the use
of the cost model and its associated data bank. The figures contain the model forms
used and the solution for the selected situation. The tables summarize the results which
have been computed for a number of situations believed to be of interest and are illus-
trative of the variety of situations that may be explored with the model.
Detailed Example
The example (Figures 38 through 43) for the Cook Plant, St. Joseph, Michigan,
illustrates the use of the model forms for the power plant without SO£ control and with
the alkalized-alumina process installed.
This example illustrates some of the simplifications that can be resorted to in a
"first-cut" analysis. For example, although the generating units are started 1 year
apart, the analyst assumed that this was not of great significance since a 20-year period
was being examined. Also, although the load factor was assumed to be decreasing from
an initial 80 percent to 40 percent by the end of the planning period, it was decided that
the average.(60 percent) would be used to obtain the required totals for the planning
period, since year-to-year variations were not considered of importance in this particu-
lar analysis. If this simplification could not be used, then all columns in the lines used
would have been filled.
Form S, Summary of Results of Analysis (Figure 39), that follows shows that in
this case, the incremental cost for SO2-control using the alkalized-alumina process is
0. 37 mill/kwhr after allowing for credits for sulfur produced. Also, this incremental
cost is equivalent to $41. 60 for each long ton of sulfur not allowed to enter the atmosphere
as SO2- Note that in this particular case the net energy available for distribution was
taken as equal to that generated. This approach was used because the SO2~control pro-
cess and by-product-plant recurring costs already included a charge for electrical-
energy requirements; also, the heat rate used was for the net output of the power plant,
so energy consumption in the power plant was not considered. Since the nonrecurring
and recurring costs for the SO2-control equipment and by-product plant were combined
in the type of estimate made, they are not shown separately in Form NR, Plant Con-
struction and Start-Up Costs, and Form R, Recurring Cost Summary.
Results of Specific-Service-Area Analyses
The model has been used to analyze a number of situations for service areas which
are believed of considerable interest and illustrative of the results which can be obtained
through application of the model. The results presented here are suggested as providing
insight concerning the ultimate problem being faced. This ultimate problem is one of
planning research and development programs so that greatest efficacy can be achieved
at the earliest time in the control of SO2 emissions.
As in the previous two detailed examples, the data used for computation have been
obtained from the sections of this report covering the recommended data on cost
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
105
Power Plant Identification: Cook
Location: St. Joseph, Mich.
Year of Start of Construction:
Generating
Unit No.
Nameplate
Capacity,
megawatts
1041
1041
Service Area: Northern Indiana
First Year
of Operation
1972*
1973=1
Type of Fuel
Coal
Oil
Gas
Planning Period Considered:
Capacity Factor, %, Average:
1973
60
Fraction of Time
Each Type Used
1,0
Through
SO2 Control Processes Considered: Alkalized Alumina
1992
Permissible SO2 Concentration Used in Analysis: 200 ppm
Sulfur Removal: 90 %
Forms Used For Analysis (list by Form and Analysis Identification No.
NR E FC R S
Notes: * Both units assumed to start operation in 1973 for purposes of analysis.
*If the capacity factor varies during
planning period, show on Form E.
Analysis Identification: BCL-1A
Date Prepared: 10/15/68
Analyst: HEC/RES/AWL/BLF
FIGURE 38. FORM A - ANALYSIS IDENTIFICATION AND GENERAL
POWER-PLANT DATA
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
Line
No. Item
1
2
3
4
5
6
7
8
9
10
11
12
Total Nonrecurring Cost
Units
Million $
Entry
Source*
Form NR
Nameplate Generating Capacity
Megawatts
Form A
Dollars/Kw
$/Kw
[(l)/(2)]xl03
Total Recurring Costs**
Million $
Form R
Total Annualized
Nonrecurring Costs**
Million $
(I)x(%)x0.2
Total Cost
Million $
(4) + (5)
Total Energy for Distribution
109 kwhr
Form E
Cost/Energy
Mills/kwhr
(6) T- (7)
Incremental Cost
for SO£ Control
Mills /kwhr
(8)***
Total Sulfur Content of Fuel
10^ long tons
Forms
FC or FO
Total Sulfur Removed
; 0^ long tons
Process
Analysis
Net Cost/Ton of Sulfur Removed
$/long ton
See
Instructions
•Numbers in parentheses refer to line number of form.
"Show percent of nonrecurring cost used for annuallzalion ID. 46 .
"•Subtract line (8) value in "Witlimii SO.> Control" column from appropriate column.
Notes:
Without
SO2 Alkalized
Control Alumina
270 290
-Control Options Considerec
2082
130
2082
139
679.0 708.0
726.8 780.7
1405.8 1488.7
219.6 219.6
6.40
6.77
0.37
2210
2210
1989
41.60
Analysis Identification BCL- 1A
Date Prepared 10/18/68
Analyst HEC/AWL/BLF
FIGURE 39. FORM S - SUMMARY OF RESULTS OF ANALYSIS
-------
Item
Land and Land Rights
Structures and Improvements
Boiler-Plant Equipment
Engines
Turbogenerator Units
Accessory Electrical Equipment
Miscellaneous Power Plant Equip.
107
FPC
Account
No.
310
311
312
313
314
315
316
(1)
(2)
Cost,
millions of
dollars
Power Plant Subtotal
270
20
Transmission-Facilities Construction Cost
SO2-Control-Process Equipment
By-Product Plant
SC>2 Control Process and By-Product Plant Subtotal
Start-Up Costs
Other (Specify)
TOTAL 290
(1) Indicate number of power generating units considered where appropriate.
(2) Check in this column if cost includes consideration of modifications required
for SO2 control process.
Notes:
Analysis Identification BCL-1A
Date Prepared 10/15/68
Analyst HEC/RES/AWL/BLF
FIGURE 40. FORM NR - PLANT-CONSTRUCTION AND START-UP COSTS
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
1973 74 75 76 77 78 79 80 81 82 8) 84 85 86 87
89 90 91
Line
No.
Item
Units
Entry Source*
Energy Generated
Total
1
2
3
Nameplate Capacity
Capacity Factor
Energy Generated
Megawatts
Percent
Billion kwhr
Form A
Form A
8.766 x 10'5 x (1) x (2)
2082
80
14.64
(Us<
(Us<
avei
avei
age
ige
/alue
ralue
of 61
for
>lanning p
iriod
of 10.98 for planning per
1 1 1 1
1
iod)
40
7. 32
219.6
Energy for SO2 Control Equipment and By-Product
MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
4
5
6
7
8
9
10
11
Power for SO^ Control
Equipment
Power for By-Product
Plant
Total
Energy Required
Megawatts
Megawatts
Megawatts
Billion kwhr
Power Loss
Energy Loss
Megawatts
Billion kwhr
Megawatts
Billion kwhr
Input
Input
(4) +(5)
8.766 x 10-5 „ (6) x (2)
Input
8.766 x 10-5 x (8) x (2)
Input
8.766 x 1CT5 x (10) x (2)
(See
Note
i)
12
Energy Available
Billion kwhr
(3) - (7) - (9) - (11)
I4.64J
(Use average *
. J J
Transmission Energy Loss
Other (specify)
Energy Available for Distribution
/alue of 10.98 f
I 1
'
ar plannina per
* Numbers in parentheses refer to line number on form.
Notes: Energy required for SO> control equipment and by-product plant not calculated - costed in
analysis of SO > control costs.
iod)
O
oo
7. 32
219.6
Analysts Identification BCL-1A
Date Prepared 10/15/68
Analyst HEC/RES/ AWL/BLF
FIGURE 41. FORM E - ENERGY GENERATED AND ENERGY AVAILABLE FOR DISTRIBUTION
-------
Ye»r
— » | 1973J -"4 [ 75 | 76 | 77 | 78 [ 79 [ 80 [ 81 [ 91 | 83 | 84 [ 85 | 86 [ 87 | 88 | 89 | 90 | 91 | 92
BATTELLE MEMORIAL INSTI TUTE - COLUMBUS LABORATORIES
Line
No. Item Units Entry Source*
1
2
1
4
5
6
Energy Generated
Heat Rate
Total Btu Required
Btu/Lb of Coal
Btu/Ton of Coal
Coal Consumed
I09 kwhr
105 Btu/kwhr
1012 Btu
lO1 Btu/lb
10* Btu /ton
10° tons
Form E, Line ( 3)
Input
(1) xU)
Input
2.0 x (4)
(3) * (5)
14.64
9.0
132
12.0
24.0
5.50
(Use average value of 10.98 for planninj
(Use average value
(Use average value
L 1 B 1
of 99 for planni
Coal Consumption
1
period)
1
of 4. 125 for pi an nine
1 ii e
If cost in C1 /million Btu
7
8
"As-Burned" Cost
Total Cost
i 1 million Btu
Million $
Input
(3) x (7) x lO"2
24.0
31. 6i
riod)
peripd)
1
1
(Use average value of 23.76 for planninj
If cost in $/ton
9
10
"As-Burned" Cost
Total Cost
$/Ton
Million $
Input
(6)x(9)
11
12
Sulfur Content
Total Sulfur
Weight %
10* long tons
Input
(6) x (11) x 8.93
3.C
147.3
(Use average value of 110.5 for planninj
Coal Cost
pe riod)
Total
7.32
66
2.75
219.6
X
1980
^xT
pxQ
82. 5
15.84
X
475.2
Sulfur Content
peripd)
* Numbers in parentheses refer to line number of form.
Notes: Totals based on 60 percent average capacity factor. The entries for 1973 show values
corresponding to an 80 percent capacity factor; those for 1992, a 40 percent capacity factor.
^xC
'
73.7
X
2210
Analysis Identification BCL-1A
Date Prepared
10/15/68
Analyst HEC/AWL/BLF
FIGURE 42. FORM FC - COAL CONSUMPTION AND COST AND SULFUR CONTENT SUMMARY
-------
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Year — •-
Line
No. Item Entry Source*
1
Fuel
Form FC, FO. or FG
1973
74 | 75 76
77 78 79 80
81
82
83
84
85
86
87
88 | 89
90
91
-rn
Annual Recurring Cost, millions of dollars
Fuel Total
31.68
(Use average va
ue of 23.76 for planning period)
2
3
4
5
6
Operations**
Maintenance **
Annual Taxes (nonincome)
Annual Insurance
Subtotal
Input
Input
Input
Input
(2) + (3) + (4) + (5)
6.60
4.86
0.38
11.84
(Use average value of 4. 95 for planning period)
(Use average value of 10. 19 for planning pe rio
d)
7
8
9
10
M
Operations**
Maintenance**
Annual Taxes (nonincome)
Annual Insurance
Subtotal
Input
Input
Input
Input
(7) + (8)* (9)+ (10)
12
Net - SO ^ Control, etc.
j(27) - from p. 2, Form R
1.30
Power Plant
15.84
475.2
Transmission Facilities
3.30
8.54
99.0
97.2
7.4
203.*
Net - SO^'Control-Process Equipment. By-Product Plant and Income
(Use average value of 1,445 for planning period)
1)
Net
(1) + (6) t (11) + (12)
44.82
perio'd)
Net - Annual Recurring Costa
•Numbers in parentheses refer to line number of form.
**If operations and maintenance not cos ted separately, enter on "Operation*", Lines (2) and (7).
Notes: Line (4) value based on 1.8 percent of nonrecurring cost. Line (5) value based on
1.67
29.7
26. Oil 708.0
Analysis Identification BCL-1A
Date Prepared 10/)6/68
Analrst HEC/A1ffL/BLF
FIGURE 43. FORM R (p. 1 of 2) - RECURRING COST SUMMARY
-------
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
Line
No.
14
15
16
17
18
Year •*•
Item Entry Source
Operations**
Maintenance**
Annual Taxes (nonincome)
Annual Insurance
Subtotal
19
20
21
22
23
Operations**
Annual Taxes (nonincome)
Annual Insurance
Subtotal
Input
Input
Input
Input
(14) + (15) + (16) + (17)
Input
Input
Input
. Input
(19) * (20) f (21) > (22)
1973
74
75
76
77
78
79
80 61
82
83
84
85
86
87
88
89
90
91
92
Annual Recurring Cost, millions of dollars
5.15
0.36
0.03
5.54
(Us
; aver
age v;
lue o
4.27
for f
tanning peri
SO^-Control- Process Equipment***
od)
(Use average value of 4. 665 for planning period)
24
25
26
Production. 1000 long tons
Sales Price $/long ton
Income, million $
Input
Input
(24) x (25) x 10"3
27
Net - SO2 Control, etc.
(18) * (23) - (26)
132.6
32.0
4.24
(Us
: aver
age v>
due o
(Use average value o
III
99.45 tor p
-
1
lanning peri
1
1
By-product Plant
Income From By- Product Sales
ad)
3. 18 for planning period)
1.30
.(Use average value of 1. 485 for planning period)
Net
* Number* in parentheses refer Co line number of form.
•• If operations and maintenance not coated separately, enter on "Operation!". Lines (2) and (7).
*•• If SO2-control-process equipment and by-product plant not costed separately, enter on Lines ( 14) through (18).
Notts:
1
3.4
1.79
•»
66.3
2.12
1.67
85.5
7.2
0.6
93.3
1989
X
63.6
29.7
Analysis Identification BCL-IA
Date Prepared
10/16/68
Analyst HEC/AWL/BLF
FIGURE 43 (CONTINUED). FORM R (p. 2 of 2) - RECURRING COST SUMMARY
-------
112
elements. Details of the computations are not included here since they correspond to
those of the previous complete examples. Results are shown in a format similar to
Form S (Figure 11) but into which additional information on the elements of cost, both
nonrecurring and recurring, have been inserted.
Examples have been included both for actual planned facilities and for hypothetical
installations. Some of the examples correspond to facilities under construction or being
planned by utilities visited during the course of this program. Thus, a qualitative com-
parison can be made between the results obtained by the utilities in their planning stud-
ies and those presented here. For simplicity in developing these examples, the analysis
has been performed for a period of only 1 year rather than the normal period of 20 or
30 years. In other words, it has been assumed that the operations do not vary over the
period of interest.
Annualized nonrecurring costs have been computed on the basis of a 20-year pe-
riod using a 7 percent interest rate for money. Thus, the multiplying factor would be
13.99 percent, including income taxes, etc.
New York City Service Area
For the New York City service area, an analysis has been performed on the basis
of a hypothetical new installation having a generating capacity of 800 megawatts. The
practice in this area is to locate the generation station within the service area primarily
because rights-of-way for overhead transmission lines to lead from remote generation
facilities are not available.
Three cost examples have been computed. These are shown in Table 29. Column
1 shows a conventional oil-fired installation, while Column 2 indicates the effect of ad-
ding an alkalized-alumina control device to remove 90 percent of the SC>2 being emitted.
A remote-location alternative is shown in Column 3. The transmission-line costs have
been computed for a total length of 340 miles, with the last 40 miles being underground
as would be required because rights-of-way for overhead lines are not available.
Comparison of the costs for energy delivered to the local distribution network of
New York City indicates that the penalty for SO2 control by the alkalized-alumina pro-
cess is about 0.40 mill. In other words, the value of the sulfur recovered is not suffi-
cient to compensate for the cost incurred in recovery. This is further illustrated by the
value of $51/long ton shown in Table 29 as the cost for removing a long ton of sulfur.
This is after credit for the predicted net sales value of $29. 60/long ton which might be
realized in the 1970 to 1975 time period in the New York area has been taken.
As indicated by Column 3 of Table 29, the cost of electrical power remotely gen-
erated and transmitted to the New York service area would not be competitive with lo-
cally generated power. The primary reason for this is the excessive cost for the under-
ground transmission needed over the last 40 miles of the 340 miles total distance. The
underground portion of this transmission line has been estimated to cost $61 million,
representing 30 percent of the estimated total investment for the project. Without this
requirement for underground transmission, however, a competitive cost might be
achieved for remote generation.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
113
TABLE 29. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800 -Mw GENERATION PLANT
SERVING THE NEW YORK CITY AREA
Number of Generating Units: 1
Plant Factor: 70 percent
New York Location
Fuel: Coal (3 percent sulfur, 12,000 Btu/lb)
Fuel Cost: 31^/million Btu
Remote Pennsylvania Location
Fuel: Coal (2 percent sulfur, 12,800 Btu/lb)
Fuel Cost: 19^/million Btu
Line
No.
1
2
3
4
5
6
1
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 -Control Plant O&M
Real Estate Taxes & Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost/Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Net Cost /Long Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million $
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
109 kwhr
MillsAwhr
Mills/kwhr
10^ long tons
103 long tons
$/ton
Conventional
Coal
127
--
--
127
800
159
2.75
--
--
2.90
13.70
--
19.35
17.80
37.15
4.91
7.57
--
43.0
--
--
Coal With
Alkalized -
Alumina
Control
127
--
8.5
135.5
800
169
2.75
--
1.90
3. 10
13.70
1.23
20.22
18.90
39.12
4.91
7.97
0.40
43.0
38.7
51
Remote
Pennsylvania
Location
With Coal
93
109
--
200
800
250
1.96
1.09
--
3.00
8.40
--
14.45
28.00
42.45
4.71
9.01
--
30.0
--
--
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
114
Another alternative would be nuclear generation, and this has been indicated as
the way future needs in the New York service area will be met. Although such a case
has not been computed, the cost for electricity would probably be only slightly more
than the 5. 88 mills/kwhr (say 6. 5 mills/kwhr) estimated for nuclear generation in the
Baltimore area (see Table 30). Thus, nuclear generation seems to be already more than
competitive with other postulated alternatives, including local generation without low-
sulfur fuels or without SO2~control processes.
Baltimore Service Area
A fairly complete set of alternatives has been computed for the Baltimore service
area. These are shown in Table 30. Generation using coal as the fuel is shown in the
first seven columns, while that using oil is shown in the next three. The last column
shows the predicted costs for nuclear generation.
Included in this set of examples is a computation of expected costs for the two
SC>2-control processes for which data have been assembled: alkalized alumina and cata-
lytic oxidation. Alternative costs for the catalytic-oxidation control process as shown
by a recent Monsanto brochure'''' have also been estimated (see Column 5).
Application of the various control processes to coal- and oil-fired operation re-
sulted in estimated incremental costs of from 0. 39 to 0. 57 mill/kwhr. The use of low-
sulfur oil as a fuel is predicted to increase costs by 0.66 mill/kwhr over that for oil of
normal sulfur (3 percent) content.
Remote generation at a mine-mouth station near Conemaugh with two 200-mile
transmission lines being used to transport power to the Baltimore transmission system
does not appear to be competitive either with or without SO? control. Nuclear genera-
tion (shown in Column 11), however, does appear to be competitive, as does the low-
sulfur-oil alternative, with the alternatives employing any one of the several control al-
ternatives. Broadly speaking, the use of oil as a fuel appears to be slightly less costly
than the use of coal at this particular location.
Central Kentucky Service Area
Table 31 shows cost estimates for a mine-mouth generation facility in the west-
central Kentucky region. This represents the situation for a new unit which might be
postulated for the mine-mouth Paradise Station on the Green River near Drakesboro.
Burning coal containing 3 percent sulfur and costing 13i£/million Btu, the base cost of
electrical power is predicted as 4.47 mills/kwhr. The incremental cost for SO2 control
using the alkalized-alumina process would be 0.31 mill/kwhr.
Southeastern Ohio Service Area
Two examples are shown in Table 32 for electric power generation in the south-
eastern Ohio coal fields. For a 600-Mw generating station having two 300-Mw units and
operating at an 80 percent load factor, the base cost would be 5. 10 mills/kwhr. Sulfur
control through the use of the alkalized-alumina process has been estimated to add 0.44
mill/kwhr to the generation cost.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
TABLE 30. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 840-Mw GENERATION PLANT SERVING THE BALTIMORE AREA
Number of Generating Units: 2 (except 1 for nuclear)
o
fTELLE MEMOE
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W
— 1
c
H
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g
o
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r
c
2
O
C
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QJ
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3
>
O
flant factor: BU percent
Baltimore Location
Fuel: Coal (3 percent sulfur, 12, 500 Btu/lb)
Oil (3 percent sulfur 18, 700 Btu/lb)
Low-sulfur oil ( 1 percent sulfur, 18, 700 Btu/lb)
Fuel Cost: Coal, 29d/million Btu
Oil, 31
-------
116
TABLE 31. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800-Mw GENERATION PLANT
SERVING THE KENTUCKY AREA
Number of Generating Units: 1
Plant Factor: TO percent
Fuel: Coal (3 percent sulfur. 11,100 Btu/lb)
Fuel Cost: 13^/million Btu
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars /Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SC>2 Control Plant O&M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost /Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost/Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million $
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
109 kwhr
MillsAwhr
MUls/kwhr
10^ long tons
ID"* long tons
$ /long ton
Coal With
Conventional Alkalized-Alumina
Coal Control
100 100
..
8.5
100 108.5
800 800
125 136
2.16 , 2.16
--
1.90
1.00 1.08
5.14 5.74
1.54
8.90 9.34
13.04 14.15
21.94 23.49
4.91 4.91
4.47 4.78
0.31
53.7 53.7
48.3
32
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
117
TABLE 32. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 600-Mw
GENERATION PLANT SERVING THE OHIO AREA
Number of Generating Units: 2
Plant Factor: 80 percent
Fuel: Coal (3 percent sulfur, 10,400 Btu/lb)
Fuel Cost: 16^/million Btu
Line
No.
1
2
3
4
5
6
1
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars /Kilowatt
Electric Plant O& M
Transmission Plant Maintenance
SO2 Control Plant O& M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost/Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost/Ton of Sulfur Removed
Coal With
Conventional Alkalized-Alumina
Units Coal Control
Million $
Million $
Million $
Million $
Mw
$/kw
Million $
Million$
Million $
Million $
Million $
Million $
Million $
Million $
Million $
109 kwhr
Mills/kwhr
Mills /kwhr
10^ long tons
10^ long tons
$ /long ton
90 90
--
9.2
90 99
600 600
150 165
2.23 2.23
—
1.90
1.43 1.58
6.05 6.05
1.37
9.71 10.39
11.75 12.92
21.46 23.31
4.21 4.21
5.10 5.54
0.44
48.7 48.7
43.8
42
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
118
Northern Indiana Service Area
Northern Indiana was selected as an example because this represents an area
where future service will be provided by a nuclear facility currently under construction,
i.e., at St. Joseph, Michigan. Table 33 summarizes the results of the cases considered.
As will be observed, nuclear generation is competitive with power generated lo-
cally burning a 3 percent sulfur coal without a sulfur control device. Estimated costs
are 5.28 and 5.29 mills/kwhr, respectively. There is no significance to the variation
in the third significant figure shown; it is carried only for convenience.
Generation at a remote location (central Indiana at mine mouth) with transmission
by twin lines, each 180 miles in length, to the service area would result in a power cost
of 5.81 mills/kwhr. Obviously, this alternative is not competitive even though this is
the one currently in use, with power being transmitted into this service area from both
central Indiana and southeastern Ohio.
An interesting result of these alternatives that have been evaluated is that the net
incremental cost for control using the alkalized-alumina process is less for a 5 percent
sulfur coal than for a 3 percent sulfur coal. Thus, there appears to be merit for at-
tempting to produce as much sulfur as possible once the facility is available. The com-
parison was made using an assumed constant value for sulfur and on the basis that the
stack-effluent concentration of SO2 was the same in both cases.
Salt Lake City Service Area
Table 34 shows an example of the estimated cost for a mine-mouth plant serving
the Salt Lake City area. The example is for a 40-mile transmission distance using a
single circuit line, from the Castle Gate location east and north of Salt Lake City where
coal deposits are known to be. The estimated cost of power, 4.89 mills/kwhr, is one
of the lower values found even though fuel cost is not particularly low and transmission
over a 40-mile distance is required.
Dallas Service Area
The example shown in Table 35 for the Dallas service area indicates the low gen-
erated cost, 3.67 mills/kwhr, that can be achieved through the use of natural gas as a
fuel. In this area close to natural gas supplies, the fuel cost is low. Also, a generating
station using natural gas as a fuel has the lowest initial as well as maintenance and other
costs. Thus, this example probably represents near to the lowest power cost achievable
in the United States for a fossil fuel plant.
Los Angeles Service Area
Shown in Table 36 are cost-computation examples for four alternatives for serving
the Los Angeles service area. An oil-fired facility using oil with 3 percent sulfur con-
tent is estimated to result in the lowest cost for generated power. Somewhat higher in
cost (by 0.41 mill/kwhr) is a facility using alkalized-alumina control. Use of low-sulfur
oil as a fuel would result in an incremental increase almost double (0. 74 vs 0.41 mill/
kwhr) that for alkalized-alumina control.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
TABLE 33. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 2082-Mw GENERATION PLANT SERVING THE NORTHERN INDIANA AREA
Number of Generating Units: 2
Plant Factor: 80 percent
BATTELLE MEMOR
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o
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Northern Indiana Location
Fuel: Coal (3 percent sulfur, 11,000 Btu/lb)
Low-sulfur coal (1 percent sulfur. 11,000 Btu/lb)
High -sulfur coal (5 percent sulfur. 11,000 Btu/lb)
Fuel Cost: Coal, 24^/million Btu
Low-sulfur coal, 28^/million Btu.
High -sulfur coal, 24^/million Btu
Remote Central Indiana Location
Fuel: Coal (3 percent sulfur, 11,000 Btu/lb)
Fuel Cost: 20^/million Btu
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 Control Plant O& M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H.2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost/Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost/Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million $
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
109 kwhi
Mills/kwhr
Mills/kwhr
Idft long tons
103 long tons
$/long ton
Conven -
tional
Coal
271
--
--
271
2082
130
6.61
--
--
3.79
31.60
--
42.00
35.30
77.30
14.61
5.29
--
160
--
-.-
Low-
Coal With
Sulfur Alkalized-Alumina
Coal
271 .
--
—
271
2082
130
6.61
—
--
3.79
36.80
—
47.20
35.30
82.50
14.61
5.65
0.36
53
--
—
Control
271
—
20
291
2082
140
6.61
--
5.40
4.06
31.60
4.61
43.06
38.00
81.06
14.61
5.55
0.26
160
144
26
High -Sulfur
Coal With
Alkalized-Alumina.
Control
271
--
24
295
2082
141
6.61
--
6.90
4.13
31.60
7.68
41.56
38.40
79.86
14.61
5.47
0.16
266
240
11
Remote Central
Indiana Location
With Coal
271
73
--
344
2082
165
6.61
0.67
--
4.81
26.30
—
38.39
44.80
83.19
- 14. 32
5.81
--
160
—
--
Remote Central
Indiana Location
With Coal.
Alkalized -Alumina
Control
271
73
20
364
2082
174
6.61
0.67
5.40
5.09
26.30
4.61
39.46
47.50
86.96
14.32
6.07
0.26
160
144
19
Nuclear
340
—
--
340
2082
163
3.66
—
—
5.77
23.40
--
32.83
44.30
77.13
14.61
5.28
--
—
--
--
-------
120
TABLE 34. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800-Mw
GENERATION PLANT SERVING THE SALT LAKE CITY AREA
Number of Generating Units: 1
Plant Factor: 80 percent
Remote Castle Gate Location
Fuel: Coal (1 percent sulfur. 12.100 Btu/lb)
Fuel Cost: 23^/million Btu
Line
No.
1
2
3
4
5
6
1
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 Control Plant O& M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost /Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost/Ton of Sulfur Removed
Units
Million $
Million §
Million $
Million $
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
109 kwhr
MUls/kwhr
Mills/kwhr
10^ long tons
10-3 long tons
$ /long ton
Coal
84.0
8.9
—
92.9
800
116
2.07
0.09
--
1.21
11.60
--
14.91
12.30
21.27
5.58
4.89
--
11.8
—
--
BATTELL.E MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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TABLE 35. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800-Mw
GENERATION PLANT SERVING THE DALLAS AREA
Number of Generating Units.- 1
Plant Factor: 80 percent
Dallas Location
Fuel: Gas (1000 Btu/cu ft, no sulfur)
Fuel Cost: 20 tf/mill ion Btu
Line
No.
1
2
3
4
5
6
1
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 Control Plant O&M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost /Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost /Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million S
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Millions
109 kwhr
Mills/kwhr
Mills/kwhr
10^ long tons
103 long tons
$/long ton
Gas
56.0
--
--
5T.6
800
12
1.40
--
--
0.69
10.90
--
12.99
•7.59
20.58
5.61
3.61
--
0
--
--
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TABLE 36. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800-Mw GENERATION PLANT
SERVING THE LOS ANGELES AREA
Number of Generating Units.- 1
Plant Factor: 80 percent
Los Angeles Location
Fuel: OU (3 percent sulfur, 18.700 BtuAb)
Low-sulfur oil (1 percent sulfur, 18, TOO Btu/lb)
Fuel Cost: Oil, 30^/million Btu
Low-sulfur oil, 38 ^/million Btu
Remote New Mexico Location
Fuel: Coal (1 percent sulfur, 9,000 Btu/lb)
Fuel Cost: 14(2/million Btu
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Item
Electric Plant
Transmission Line
SO2 -Control Device
Total Nonrecurring Cost
Nameplate Generating Capacity
Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 Control Plant O&M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
Total Recurring Costs
Total Annualized Nonrecurring Costs
Total Cost
Total Energy for Distribution
Cost /Energy
Incremental Cost for SO2 Control
Total Sulfur Content of Fuel
Total Sulfur Removed
Cost/Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million $
Mw
$/kw
Millions
Mill ion $
Million $
Million $
Millions
Million $
Million $
Millions
Million $
109 kwhr
Mills /kwhr
Mills/kwhr
10** long tons
10^ long tons
$ /long ton
Conventional
Oil
82
--
—
82
800
102
2.02
--
--
1.28
15.74
'
19.04
10.68
29.72
5.61
5.30
--
37.4
--
--
Low -Sulfur
Oil
82
--
--
82
800
102
2.02
--
--
1.28
19.92
--
23.22
10.68
33.90
5.61
6.04
0.74
12.5
--
--
Oil With
Alkalized -
Alumina
Control
82
--
8.5
90.5
800
113
2.02
--
2.10
1.44
15.74
1.08
20.22
11.79
32.01
5.61
5.71
0.41
37.4
33.7
67
Remote
New Mexico
Generation
With Coal
84
109
—
193
800
238
2.07
1.09
--
2.32
7.08
--
12.56
24.70
37.26
5.14
7.25
—
25.1
--
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The other alternative explored was remote generation at mine mouth in the Four
Corners area plus transmission over a distance of 700 miles to the service area. This
alternative is not competitive, costing almost 2 mills/kwhr more than the base case us-
ing high-sulfur oil without control. However, enlargement of this power-generation
station is under way in this location with the fourth unit, having a 755-Mw capacity,
scheduled for completion in 1969 and the fifth in 1970. The only obvious factor that can-
not be evaluated for this alternative is the interaction which undoubtedly exists between
the transmission facilities for power from this location and those serving Glen Canyon
and Hoover Dams.
Tampa Service Area
The Tampa area, examples for which are shown in Table 37, would normally gen-
erate power using oil containing about 3 percent sulfur as a fuel. This base case is
shown in Column 1. Columns 2 and 3 indicate that low-sulfur oil and alkalized-alumina-
control alternatives would be more costly by about the same increment, 0.47 and 0.43
mill/kwhr, respectively, than the base case. Generation using coal as a fuel appears
to be cheaper than that using oil. An interesting alternative, apparently worth consider-
ing for this area, would be the use of coal as a fuel with the alkalized-alumina process
being used for control. This alternative would have an incremental cost only 0. 15 mill/
kwhr higher than that of generation using 3 percent sulfur oil as a fuel.
Summary of Estimated Costs
Table 38 is a summary of the estimated costs of power delivered to the distribution
network. Although not comparable in an absolute sense because of differences in
generating-unit sizes, load factors, etc., some interesting observations are possible.
Costs for power delivered to the distribution network are about 5 mills/kwhr in
most parts of the United States. However, there are some significant deviations. For
example, for locations in and near the natural-gas fields where natural gas is used as
the fuel, estimated costs are somewhat lower. The cost in Dallas, which was one of the
examples computed, was estimated to be 3.67 mills/kwhr. There appear to be two rea-
sons for this. First, the fuel cost (at 20i£/million Btu), although not the lowest, is in
the lower part of the range. Second, the capital cost of the generating plant is low, both
because a boiler using natural gas as a fuel has a lower cost and because Dallas is in a
low-construction-cost region.
The cost of power delivered to the generation network in New York City can be
contrasted with this; here the cost is the highest of those estimated. Obvious reasons
are the high cost of fuel and the high cost of construction.
Several interesting general trends can be observed by study of this summary table.
Nuclear generation appears to be competitive in all areas except possibly in those regions
where fossil fuel is available locally and can be obtained without incurring high labor and
transportation costs. Dallas and Kentucky are prime examples here.
Remote generation does not appear to be a viable alternative. The transmission
costs for any significant distance are so large that other alternatives appear to have les-
ser cost. For example, rail hauling of coal, particularly in unit trains, over distances
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TABLE 37. COSTS FOR POWER GENERATION AT A HYPOTHETICAL 800-Mw
GENERATION PLANT SERVING THE TAMPA AREA
Number of Generating Units: 1
Plant Factor: 80 percent
Tampa Location
Fuel: Oil (3 percent sulfur, 18,700 Btu/lb)
Low-sulfur oil (1 percent sulfur, 18,700 Btu/lb)
Coal (3 percent sulfur, 11,400 Btu/lb)
Fuel Cost: Oil, 33^/million Btu
Low-sulfur oil, 38^/million Btu
Coal, 27tf/million Btu
Line
No. Item
Electric Plant
Transmission Line
SOg -Control Device
1 Total Nonrecurring Cost
2 Nameplate Generating Capacity
3 Dollars/Kilowatt
Electric Plant O&M
Transmission Plant Maintenance
SO2 Control Plant O&M
Real Estate Taxes and Insurance
Fuel Cost
Sulfur (or H2SO4) Credit
4 Total Recurring Costs
5 Total Annualized Nonrecurring Costs
6 Total Cost
1 Total Energy for Distribution
8 Cost/Energy
9 Incremental Cost for SO2 Control
10 Total Sulfur Content of Fuel
11 Total Sulfur Removed
12 Cost/Ton of Sulfur Removed
Units
Million $
Million $
Million $
Million $
Mw
$/kw
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Million $
Millions
109 kwhr
Mills/kwhr
Mills/kwhr
103 long tons
103 long tons
SAong ton
Conven-
tional
Oil
59
--
--
59
800
74
1.40
--
--
0.77
17.30
--
19.47
8.23
27.70
5.61
4.93
37.4
--
--
Low -Sulfur
Oil
59
--
--
59
800
74
1.40
--
--
0.77
19.92
--
22.09
8.23
30.32
5.61
5.40
0.47
12.5
--
--
Oil With
Alkalized -
Alumina
Control
59
--
8.5
67.5
800
84
1.40
--
2.10
0.88
17.30
1.00
20.68
9.40
30.08
5.61
5.36
0.43
37.4
33.7
71
Conven-
tional
Coal
74
--
--
74
800
92
1.74
--
--
0.96
13.62
--
16.32
10.32
26.64
5.61
4.75
59.3
--
--
Coal With
Alkalized -
Alumina
Control
74
--
8.5
82.5
800
103
1.74
--
2.10
1.07
13.62
1.57
16.96
11.50
28.46
5.61
5.08
0.33
59.3
53.2
34
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TABLE 38. SUMMARY OF ESTIMATED COSTS OF POWER
DELIVERED TO DISTRIBUTION NETWORK
Service Area
New York City
Baltimore
Kentucky
Ohio
Northern
Indiana
Salt Lake City
Dallas
Los Angeles
Tampa
Fuel
Coal (3% S)
Coal (2% S)
Coal (3% S)
Oil (3% S)
Oil (1% S)
Coal (3% S)
Coal (3% S)
Coal (5% S)
Coal (3% S)
Coal (1% S)
Coal (1% S)
Natural gas
Oil (3% S)
Oil (1% S)
Coal (1% S)
Oil (3% S)
Oil (1% S)
Coal (3% S)
Conven-
tional
7.57
5.45
5. 16
5.82
4.47
5.10
5. 29
5.65
3.67
5.30
6.04
4.93
5.40
4.75
Estimated Costs, mills /kwhr
Alkalized- Catalytic-
Remote Alumina Oxidation
Location Control Control Nuclear
7.97 (5.86)(c)
9.01
6.70 5.92 5.84 5.86
(7. 19)(a) (5.88)05)
5.69
4.78
5.54
5.47
5.81 5.55 5.28
(6.07)(a)
4.89
5.71
7.25
5.36
5.08
(a) Alkalized-alumina control.
(b) Monsanto costs.
(c) Obtained from Baltimore example.
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of 200 miles or more (if there is already a rail line in existence) appears to be cheaper.
The estimates for Baltimore and Northern Indiana show this. The New York City esti-
mates for remote generation are more costly yet because of the necessity for under-
ground transmission lines for part of the distance from any remote generation station.
Using currently available estimates of SO2~control-process costs as previously
discussed, Table 38 indicates that incremental costs for control approximate 0. 5 mill/
kwhr, essentially independent of the two processes costed. There are variations in this
value, of course, which depend on the size of the installation, degree of removal, sulfur
market values, etc. , but the 0. 5 mill/kwhr value might serve as a convenient rule of
thumb.
One other feature of interest is the result, previously mentioned, that use of a
higher sulfur fuel in conjunction with a control process would result in a slightly lower
net cost for power. (See the values tabulated for the Northern Indiana service area,
Table 33. ) This suggests that if a SC>2-control process with recovery of a by-product is
to be applied, use of a fuel with the largest content of sulfur available should be explored.
Modification of this viewpoint, of course, would probably be necessary if the monetary
value of sulfur or sulfuric acid becomes less.
Sensitivity of Results
Another reason for performing the computations summarized in Table 38 was to
explore the sensitivity of power costs to a variation in each of the several cost compo-
nents when combined according to the cost-model structure, A surprising result was
the large influence of transmission distance in increasing the cost of power delivered to
the distribution network. The results indicate that rail and/or barge hauling of coal and
ocean and/or barge shipment of oil is much more advantageous even for distances as
short as 180 miles. This conclusion is somewhat in opposition to current practices as
exemplified by the Northern Indiana and Los Angeles service-area examples. Further
exploration of transmission costs as contrasted to fuel transportation costs thus appears
to be warranted.
Although better, more refined data would be desirable on the control-process costs,
this cost component does not appear to be a large factor in the overall power cost.
However, the value assigned to the sulfur or sulfuric acid does have a large percentage
effect on the control cost and, thus, emphasis in future efforts should be placed here.
The time variation of these values may also prove to have importance.
The variation of fuel, as burned, costs with time may also prove to be a signifi-
cant factor. Since fuel cost represents 25 to 50 percent of the total cost per unit of
power, the variation of the fuel cost as a function of time may have a strong influence.
A situation where this might be expected is the example for the Dallas service area,
where the fuel is natural gas. Here, a doubling of the price of natural gas, not incon-
ceivable over a 20-year period, would increase the cost of power by 50 percent, from
30 67 to 5. 51 mills/kwhr.
Finally, the results obtained are believed sensitive to plant factor although no ex-
ploration of the significance of this has been performed. This was primarily because
no logic in the manner in which electric utilities perform their planning to account for
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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this factor could be detected. For the most part, the utilities make comparisons of in-
teresting alternatives at constant high plant factors of 80 to 90 percent, even though
their system load factor may approximate 50 to 60 percent. The influence of such tac-
tics on decisions reached needs to be explored, particularly when control-process needs
begin to influence system operation.
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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CONCLUSIONS AND RECOMMENDATIONS
Development of a cost model to be used in evaluating the promise of SO2~control
processes has been achieved. Although the model is not as sophisticated as others de-
veloped in the past for other areas, such as aerospace, a planned balance between sophis-
tication and utility was desired. Thus, ease of application and a fair degree of simplicity
leading to short times for computation also exist.
The cost model which has been described in this report is applicable during each
solution to only one of almost an infinite number of real or assumed situations. Thus, in
its present form, costs for various locations, sizes, alternatives, etc., must be com-
puted individually and compared before any conclusions can be reached. In other words,
optimization techniques have not been built into the model.
In using the model, a few limitations should be recognized. The model will be valid
only to the degree that the input data are accurate. Although a sensitivity analysis was
performed in terms of the computation of numerous examples and alternatives, further
effort is undoubtedly needed to permit discerning the areas where more accurate repre-
sentations of cost are desirable because of the high sensitivity of results to certain cost
representations. As with all cost-model studies, the cost data for utilizing the developed
methodology are historically based. Therefore, periodic refinement and updating need to
be performed. Finally, time and effort limitations will be recognized. Analysis for sev-
eral alternatives for a given service area will take a significant time period, perhaps
several days. Thus, in the present stage of development of the model, judicious selection
of the locations and alternatives needs to be made.
To be used for planning purposes for SO2~control-process development, solutions
for a large number of planned facilities will undoubtedly be needed before a reasonable
assurance as to the "best" programs can be discerned. The following activities are pro-
jected as leading to improvements in confidence in the use and utility of the results of the
present model.
(1) Development and Maintenance of a Data Bank
The present program provides some data regarding power»plant costs
and future construction plans. However, in order to keep the cost data
current and to accumulate enough data from which more reliable cost-
estimating relationships can be derived, a continuing effort is required.
Also, such data should be gathered and placed in a form suitable for use
in the model. The maintenance of such data should be an ongoing effort.
The level of effort required would depend upon the extent of use of the
model.
(2) Early Model Testing, Utilization, and Modifications
Beyond the efforts of the present program, it is deemed necessary to test
the usefulness of the model in a variety of planning problems. Especially
important will be the evaluation of data problems and the amount of effort
required to perform the analyses. These initial analyses are expected
to lead also to identification of needs for model modifications. These
activities require management efforts to see that the user is in a position
BATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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to report difficulties and to be satisfied that appropriate corrective
measures are being taken; otherwise, the model will fall into disfavor
and eventually not be used. To avoid this it is essential that an aggres-
sive program of encouraging use and evaluation of the model be followed.
Also, difficulties should be resolved rapidly so that the model is a viable
tool of the planner. This will require more than casual efforts, and ap-
propriate in-house or outside-contractor arrangements should be made
to insure a proper conduct of this phase.
(3) Computerization
After the efforts described in (1) and (2) are under way and it appears
that any difficulties have been resolved, it will then be appropriate to
consider the desirability of computerizing the model. . This step should
be undertaken in light of
(a) Frequency of use of the model
(b) Manual efforts required for routine and repetitive data manipulation
(c) Availability of appropriate data processing personnel and equipment,
in-house or on a contractual basis
(d) Anticipated requirements for further model modification.
(4) Extensions of the Model
Aside from minor modifications of the model, the use of the model in the
context of R&D planning activities is expected to lead to considerations of
extension of the type or scope of what is analyzed. For example, the in-
clusion of more detailed analysis of the impact of developing alternative
SC^-control processes might be treated as a resource (R&D funds) allo-
cation problem amenable to solution by techniques such as "linear pro-
gramming". Another possibility is the inclusion of a more sophisticated
technique for the analysis of uncertainties regarding costs and utilization.
Incorporation of more complex techniques, such as Monte Carlo, will
probably require use of the digital computer because of more extensive
requirements for calculation.
The specific next steps to be taken in a continuing program for improving the util-
ity of the model and understanding the system which it represents are believed to be
three. First, a more intensive study needs to be made of the sulfur (and sulfuric acid)
market, particularly the effects which might result from alternative sources of sulfur
(and sulfuric acid) coming into existence. This area is particularly important because of
the sensitivity of net costs for sulfur removal and recovery to the market and "net back"
price for sulfur and sulfuric acid. A simplified, gross approach was taken to establish.
approximate values for use in the current cost model. Now, a more sophisticated ap-
proach is needed in which other independent variables will be considered.
Second, an improved and enlarged data base would be desirable so that improve-
ments could be made in the correlations (cost-estimating relationships) being used in com-
puting the costs of alternatives for accomplishing SOg control,
QAYTELLE MEMORIAL, INSTITUTE - COLUMBUS LABORATORIES
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Third and finally, the computation of many more cases is needed. These cases,
and their alternatives, would logically be based on the utilities plans for new power-
generation facilities over the next few years, as shown in Table 25 and Appendix B. Only
through comparing the costs of various alternatives as they might exist in the different
geographical areas would an understanding of the potential benefits and applications to be
derived from each of the several SO2~control processes be attained.
When these next steps have been accomplished, a further look into the benefits be-
ing derived should be made to assess the potential for further benefits through, for ex-
ample, extensions of the model and/or computerization.
^ MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
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(3) Steam-Electric Plant Construction Cost and Annual Production Expenses,
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133 and 134
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(37) Future Market for Utility Coal in New England, report to Office of Coal Research,
U.S. Department of the Interior, by Arthur D. Little, Inc., Cambridge,
Massachusetts (November, 1966).
(38) Behnke, W. B., "A Look at Nuclear-Fossil-Fuel Economics", paper presented at
Third Energy Transportation Conference (November 20, 1967).
(39) "The Catalytic-Oxidation (Cat-Ox) System for Removing SO2 from Flue Gas", a
brochure of Monsanto Company, Air Pollution Control Enterprise, St. Louis,
Missouri (circa 1968).
(40) Cost-Effectiveness Analysis: New Approaches in Decision Making, Goldman, T. A.
(Ed.), Frederick A. Praeger Publishers, New York (1968):
(a) Hatry, H. P., "The Use of Cost Estimates", pp 44-68.
(b) McCullough, U. D. , "Estimating Systems Costs", pp 69-90.
(41) Launch Vehicle Component Cost Study, Technical Report, Vol II, LMSC-895429,
Lockheed Missile and Space Company (June 30, 1965). (Available from NASA to
U.S,, Government agencies and U.S. Government contractors only.)
(42) Fisher, G. H., "Derivation of Estimating Relationships. An Illustrative Example",
The Rand Corporation (November, 1962).
(43) "Engineering Economics", Commonwealth Edison Company, Chicago, Illinois (1963).
(44) Dienemann, P0 F0, "Estimating Cost Uncertainty Using Monte Carlo Techniques",
RM-4854-PR, The Rand Corporation (January, 1966).
(45) Private communication, Edwin R. Conklin (of Electrical World), July 29, 1968.
BATTEk(=E MEMQR5AL. INSTITUTE - COLUMBUS LABORATORIES
-------
APPENDIX A
BACKGROUND AND DISCUSSION OF
MODEL METHODOLOGY AND LIMITATIONS
OAYTOU.E MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
A-l
APPENDIX A
BACKGROUND AND DISCUSSION OF
MODEL METHODOLOGY AND LIMITATIONS
Background
The analysis of future costs for the application of various technical approaches to a
problem is an essential part of the long-range planning problem. This type of analysis is
of special interest to those concerned with the selection between competing research and
development programs. The competition for available research and development funds
has intensified the need for analyses directed toward early isolation of those programs
with the most attractive technical potential and economic advantage. This program has
been directed toward providing the long-range planner with a tool for evaluating the im-
pact on the costs of electric power of various approaches to the control of SO2 emissions
from fossil-fuel-burning electric power plants. The intent is to provide a means for in-
troducing the costs of SO2 control as an additional increment of cost for electric power
generation.
The approach taken has been influenced by the prior experience of groups con-
fronted with some of the most difficult cost-analysis problems in the context of long-
range planning, namely, those who identified the problems and developed the methodology
for the analysis of the cost-effectiveness of future military and aerospace systems. Al-
though this experience has influenced the approach taken to developing this model, it has
been necessary to avoid a full-scale adoption of techniques developed by these groups be-
cause of the relatively small amount of effort that is considered presently appropriate
for the class of problems under consideration.
Typical of the efforts in the military and aerospace field are those described in
Rand reports generated in the post-World War II period. For example, Cost-
Effectiveness Analysis: New Approaches in Decision-Making, (40)* contains several ar-
ticles with a number of references to reports of the Rand Corporation and other organiza-
tions that deal with cost models and cost-effectiveness analyses. The article entitled
"Estimating Systems Costs'1'^ °' points out several findings based on experience with
military and aerospace cost-prediction problems. This article notes the importance of
dealing with comparative costs rather than absolute accuracy of costs; in other words,
the costs developed are regarded more as indices that indicate cost differences and their
extent. These types of costs are distinguished from those used for, say, budgeting pur-
poses. A major reason for taking this approach is the uncertainties of future costs.
Related to this argument is the "current dollars" approach, which means that possible
future inflationary effects are ignored since such effects should not normally affect the
ratio of costs of competing systems.
Coot-estimating relationships (CER's) play an important role in cost models. They
are used to determine costs on the basis of some physical or performance characteristic;
for example, in Figure 14, initial power-plant construction costs are shown as a function
of generating capacity. CER's are used in place of detailed cost estimates, such as
might be generated for bidding purposes, in order to minimize the effort required to
^References are listed on page 131.
SATTELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
A-2
generate a preliminary cost estimate,, Their exact nature depends upon the types of data
available and approach taken to convert the data to a CER. Statistical techniques, such
as multiple correlation, are frequently used to generate CER's, but the technique applied
depends upon the nature of the available data and the level of effort that is appropriate for
the required analysis. References (41) and (42) provide a discussion of the development
of CER's for use in aerospace cost models. As the data base regarding power plant and
SC>2-control equipment is expanded, it will be worthwhile to consider modifications of,
or the use of more, CER's.
/•-'
Another aspect of the background for model development is the type of financial
analysis performed by electric utilities prior to making investment decisions. Reference
(43) presents an example of the approach used in this type of analysis. This type of anal-
ysis places heavy emphasis on the analysis of tax implications, return on investment,
discounted present worth, and other "financial factors". Although these factors are of
importance to the utility charged with making proper investment decisions, they have not
been given so elaborate a treatment as found in Reference (43), for example. This ap-
proach has been taken for two major reasons:
(1) The long-range planning efforts of interest are concerned with the com-
parison of alternatives to SO2 control, and it is anticipated that the
"financial factor" applied as a percentage of initial investment costs will
be the same; hence, the application of these financial factors would not
alter relative cost standing of the alternatives being considered. How-
ever, if significant differences can be anticipated in, say, taxes or de-
preciation charges, then the analyst must give more careful consideration
to the financial-factor aspects of the problem.
(2) The complexity of the analysis is considerably reduced by taking a simpli-
fied approach to the treatment of financial factors0 At this time it is felt
that many of the needs for cost analyses can be met by the determination
of nonrecurring, recurring, and annualized nonrecurring costs. Until a
firm need is established on the basis of future problems that will be con-
sidered by the analyst, the simplified approach to financial factors ~ which
amounts to the selection of a percentage to be applied to nonrecurring
costs ~ is recommended.
Hardware costs are usually influenced by the rate and amount of production,, A
"learning curve" is frequently applied to determine the future costs of production items.
Reference (41), for example, discusses techniques for incorporating "learning curve"
effects into the cost analysis. This concept has not been explicitly included in the model,
however, because of the nature of the initial data base and other considerations: for ex-
ample, the application of learning curves requires information as to both initial produc-
tion costs for equipment and the anticipated number of equipment items to be produced.
Rate of production is also of interest since this influences the indirect costs applied in
determining production costs. The types of data me.de available for power-plant and
transmission-facility costs would be expected to already reflect any learning-curve ef-
fects. However, it is speculated at this time that the types of data that might become
available regarding SC>2 equipment may not include such effects, unless the equipment is
already in production,, In this case, if the analyst hypothecates the broad application of
the type of SC^-control equipment under consideration, he may find it worthwhile to con-
sider the possible influence of learning-curves effects. But, because of the minimum
concern of this program with SC^-control equipment costs, this aspect of the analyois is
not treated further in this report.
BATTELLSZ MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
A-3
A continual problem with cost models is the reconciliation of the time required for
preparation of input data, the analysis, the interpretation of results, and the amount of
time and expense feasible and desirable in long-range planning efforts. The develop-
ment effort for this model has been influenced by these considerations; however, deci-
sions as to the feasibility of pursuing costs to various levels of detail can best be made
only after some model-use experience has been acquired and after decisions have been
made regarding the feasible amount of effort and expense that can be incurred in the
various planning exercises undertaken by the NAPCA. Comprehensive cost studies can
easily require several man-years of effort, and this is usually infeasible in terms of
the cost of the analysis versus the size of the budget to be committed for developments.
Also, the justification for a large cost-estimating team is based on the need to analyze
a continuous flow of problems. The adjustment of the costing approach to the amount of
manpower that would be available for cost studies is another important consideration.
Presumably the allowable costs for evaluations would be a function of the magnitude of
research and development funds being allocated and the complexity of the problems be-
ing analyzed. This model has been developed with these considerations in mind.
Uncertainty and Sensitivity Considerations
If a cost figure has been obtained, the planner's next problem is to understand its
uncertainty aspects. Without this insight, there is the possibility of selecting a process
whose costs may actually be higher than another because the uncertainties were not an-
alyzed. This makes it important for the analyst to examine the difference in results
when reasonable variations in the cost values are allowed. The recommended approach
is for the analyst to repeat the analysis using estimates of the highest or lowest possible
values for the cost elements to which the results are most senoitive. For example, fuel
costs may be about 80 percent of the total of annual fuel, operations, and maintenance
costs. This would indicate that the results are more sensitive to a change of fuel costs
in comparison with, say, a minor modification of maintenance requirements. If the re-
oults of an analysis for comparing, say, a change in fuel with incorporation of an SOj-
control process indicated that a 10 percent change in fuel costs reversed the relative
costs, then the analyst would recognize the need for a more detailed analysis and im-
proved data - or the introduction of considerations outoide the scope of the cost-model
analysis - before deciding which approach is superior.
When the SC>2-control process changes the heat rate of the plant, this is reflected
directly in fuel costs. Also, the control process may require modifications of the power
plant. When this occurs, the analyst must consider how this affects the recurring and
nonrecurring costs as obtained for the power plant without SO2 control,, This requires
examination of costs in more detail, and the analyst needs some insight as to the rela-
tive importance of the various subsystem and component costs. Analysis of a subsystem
cost breakdown for TVA steam-production plants indicates that the nonrecurring costs
for each cost element represent the following approximate percentages of total plant
coot:
E3ATTGLLE MEMORIAL INSTITUTE <= COLUMBUS LABORATORSES
-------
A-4
FPC
Subsystem Account No, Percent
Land and land rights 310 <1
Structures and improvements 311 19
Boiler-plant equipment 31Z 45
Turbogenerators 314 28
Accessory electric equipment 315 6
Other power-plant equipment 316 1
The column "FPC Account No. " gives the account numbers as used in Reference (2),
which describes in detail the components included in each account number.
The above percentages indicate the importance of boiler-plant equipment in over-
all costsj so emphasis should be placed on understanding the influence of the SC^-
control process on this cost element. Note the small significance of land in total costs;
however, the analyst would want to review the relative importance of this cost in those
cases where the plant is located in a metropolitan area.
The recommended approach to sensitivity considerations is for the analyst to per-
form a preliminary estimate of all cost elements in the model, and to then base his ef-
forts in cost refinement and "high-low" estimating upon the relative significance of each
cost element in the initial effort. High-low estimates are derived from consideration
of what might be reasonable for the worst and best possible areas. These types of esti-
mates will be improved as experience is developed and the data base is improved.
A more complex model could be developed that would introduce statistical concepts
into the cost estimates,, Such a model development could eventually lead to the incorpo-
ration of Monte Carlo techniques that introduce random considerations into the analysis;
that is, explicit recognition is given to the improbability that all costs will be high, low,
or at the median at the same time [ see Reference (44)], However, such models intro-
duce requirements for many more calculations than the present model. Such a develop-
ment is left for the future - the investment required must be carefully considered in
terms of needs for analysis and other considerationsc
In summary, the background of other efforts in developing cost models provides a
basis for considering the modeling problem at hand. These past developments have in-
fluenced the approach taken. The following factors also have had strong influence on the
approach taken:
(1) The amount of effort appropriate for the types of analyses of interest
(2) The availability of cost data and the effort required to collect and/or
generate new data
(3) The uncertainties associated with future coot estimates
(4) Ths desirability - especially from an effort-requirement standpoint -
of using "sophisticated" techniques.
QATYBILUE MEMORIAL INSTSTUTE - COLUKBU3 LABORATORIES
-------
APPENDIX B
LISTING OF POWER GENERATION FACILITIES
PLANNED AND UNDER CONSTRUCTION FOR
THE TIME PERIOD 1968 THROUGH 1977
QATTSLt_G MEMORIAL, INSTITUTE - COLUMBUS LASORAT6RIES
-------
B-l
APPENDIX B
LISTING OF POWER GENERATION FACILITIES
PLANNED AND UNDER CONSTRUCTION FOR
THE TIME PERIOD 1968 THROUGH 1977
(As of March 15, 1968, with additions to July 8, 1968)
Compiled by Electrical World<45)
Unit I - Fossil-fueled steam units, 1968 through 1976 - total 108,987 Mw (pages B-2
through B-14)
Unit II - Hydro power units, 1968 through 1975 - total 11,981 Mw (pages B-15 through
B-23)
Unit III - Peaking power units, 1968 through 1971 - total 5,525 Mw (pages B-24 through
B-32)
QATYELLE MEMORIAL INSTITUTE - COLUMBUS LABORATORIES
-------
Unit ff I
7aooiJ.~fueia«5 stGsst psraoi- uniea cchedcled for aervice in _lg68 (Sheet lof 2)
Kerch 15, 1968
m
>
H
H
m
r
r
m
2
m
2
O
z
en
H
H
C
H
m
o
o
r
c
2
(0
c
(A
CD
O
3)
>
-I
O
2
m
to
8
!, Utility
I Keystone
NEGEA
PSE&G
No. Ind. PS
PS Ind0
Car, P&L
Fla. P&L
Comma Ediaon
No. States Pr.
Union Elec.
Monon. Pr.
Mont. Pr.
Pac. G&E
, Perm. P&L
PS of N.Hamp.
United 111
(Cinci. G&E
1 Georgia Pra
;Mis8. Pr.
| Cent.Ill.LtoCo.
!
: Houston L&P
Omaha PPD
Long Is. Ltg.
Detroit Ed,
Detroit Ed.
Ohio Edison
Ohio Pr.
Toledo Edison
Ames, la.
Cent. P&L
Gulf Stetes
LCRA
San Antonio
Unit
Key s tons 2
Canal 1
Hudson 2
Bailly 8
Wabash R. 6
Roxboro 2
C. Kennedy 2
Kincaid 2
A. ICing 1
Sioux 2
Ft. Martin 2
Billings 2
Moae Ldg. 7
Brunner Is. 3
Merrimack 2
Bridgpt Har. 3
Beckjord 6
H. Branch 3
Watson U
Edwards 2
Parish U
No. Omaha 5
Northport 2
HarborBeach 1
St. Clair 7
Satnmis 6
Muskingum R. 5
Bayshore U
Ames 7
Victoria 6
«?mow Glen 3
S.Gideon 2
Braunig 2
Location
iandwichjMass.
I.Kennedy, Fla.
3ayport,Minn.
killings ,Mon.
arborBjMich.
t.GabrialjLa.
Hw
900
560
620
386
365
650
Un
617
590
525
5UO
180
735
750
333
Uoo
1»3U
i*90
250
267
565
216
390
uii
527
600
615
213
35
258
580
lUi
2U5
Fuel
Coal
Oil
Coal
Coal
Coal
Coal
Oil, gas
Coal
Coal
Coal
Coal
Coal
Gas, oil
Coal
Coal
Coal
Coal
Coal
Coal
Gas
Coal
Oil
Coal
Coal
Coal
Coal
Coal
Gas
Gas
Gas
Gas
Boiler fran
C-E
B6ttl
F-W
B&W
C-E
C-E
F-W
B&W
B&W
B&W
C-E
B&W
B&W
C-E
C-E
B&W
Hiley
F-W
C-E
Hiley
B&W
B&W
B&W
B&W
C-E
B&W
F-W
C-E
T-G fron
W
w
W
GE
W
QE
OK
W
W
GE
W
GE
W
GE
W
GE
GE
GE
GE
GE
GE
ASEA
W
W
GE
W
W
H
W
Consultant
Gilbert Assoc.
Stone&tfebster
PSt&G
Sargent&Lundy
Sargent&Lundy
Ebasco
Bechtel
Sargent&Lundy
Pioneer Serv.
United Engrs.
Burns & Roe
flechtel
PG&E
Ebasco
Jackson&Morel '<
Ebasco
Sargent&Lundy
Southern Serv.
Southern Serv.
Comm. Assoc.
Ebasco
Gibbs&Hin
Ebasco
Bechtel
Bechtel
Comm. Assoc*
AEP Serv. Corp.
Gibbs&Hill
Gibbo&Hlll
Sargent&Lundy
StonefeJebster
Gibba&Hill
Brown & Root
Constructor
Ebasco managir
Stone&rfebotcr
United Engre.
Bechtel
Owner
United Engrs.
Sand.&Porter
man'g.
Bechtel
Ebasco
United Engrs,
Bechtel
Stone&rfebster
-------
power units scheduled! fo? service in
( Shsafc 2 of 2)
March 15, 1968
Utility
SATS
WesteFaraerCoop
PS of Colo.
Sierzra Pac. Pr.
1 Con Edison
j PEPCo
; Dover, 0.
Springfield, 111.
Wiec. EP
! TESCo
bolo. Springs, Colo
Utah P&L
[Nevada Pr.
Holland, Mich.
Jasper, Ind.
Monroe, La.
WooreheadjMinn.
(Imperial Dist.
Pac. G&E
Minden, La.
Brazos R. Coop
;Pac. P&L
jla. Southern U.
JJorvalk, 0.
Ala. Elec. Coop.
Jamestown, 1TY
Marsh fi eld, Wise.
Garland, Tex.
Houston If.-?
Louisiana P&L
Opelousas, La.
Huston, La.
Municipal
Unit
Michole 3
Moreland 2
Cherokee k
Pt, Churchill 1
Arthur Kill 3
Benning 15 \
Lakeside
Valley 1 1
Graham 2
Drake 6
Naughton 2
Gardner 2
De Young 5
Municipal 12
Moorehead 5
El Centre k
Geysers lj
Municipal 2
Miller 1
Green R, Wyo,
Burlington 1
Jackson 1
Carlson 6
Wildwood 5
Garland 1
Robinson 3
Little Gypsy 3
No. 3 1
Location
Reno, Nov.
ashing ton, X
ilwaukee,Wisc
emmerer,Wyo.
illmar,Minn.
Total
Mw
200
135
350
110
515
275
22
80
mo
375
76
220
119
29
13
75
28
75
27
15
81
15
203
18
75
25
20
66
565
560
26
27
20
19,085 »
Fuel
Oas
Gas/oil
Coal
Gas/oil
Coal
on
Coal
Gas
Coal
Coal
Qeotherm
Coal
Dae/oil
1*
Boiler from
C-E
Riley
C-E
B&W
C-E
C-E
B&W
Riley
C-E
F-rf
Riley
C-E
C-E
F-W
T-G from
OE
H
OE
GE
GE
GE
GE
GE
GE
GE
GE
Consultant
LD&P
Stearns Roger
Stone&rfebster
Con Edison
Bechtel
Stone&Webater
Ebasco
Bechtel
StearnsRoger
Black & Veatcb
Ebasco
Ebasco
Constructor
>tone&rfebster
Bechtel
Stone&tfebster
Bechtel
-I
H
m
r
r
tn
2
tn
2
o
H
C
^
m
i
o
o
r
c
2
0)
c
(A
0)
o
3)
>
H
O
2
m
en
-------
Fossil-fueled sEesm power units scheduled for service in 1969 ( Sleet 1 of 2)
Kerch 15, 1968
Utility
Jest Psnn lftp«
Jhike Pr.
VEPCo
KCP&L
Cent. P&L
$o. Car. PSA
K. Eng. Pr.
Penelec
E. Ky. REG
Ind. P&L
Kentucky Pr.
Louisville G&E
Ala. Pr.
Fla. Pr.
Fla. P&L
Georgia Pr.
Gulf States
Missouri PS
Okla. G&E
W. Texas Utll.
"luscatine, la.
So.Cal.Fdison
0 & Rock.Util.
Big Rivers Coop
Hoosier Coop
S9.Car.PS Auth.
Oairyland Coop.
N'atchi oches,La.
Wise. P&L
Ark. P&L
A.SSOC. Coop
Texas P&L
West. Pr. & 0
Wise. EP
Unit
Hatf ield Fy 1
Marshall 3
Chesterfield 6
Hawthorne 5
Hill h
Jefferies 3
Breyton Pt. 3
Homer City 1
Cooper 2
Petersburg 2
Big Sandy 2
Cane Run 6
Barry U
Crystal R. 2
Ft. Myers 2
H. Branch U
Nelson U I
Sibley 3
Horseshoe 8
Rio Pecoa 6
Muscatine 8
U Corners U
Lovett 5
Coleman 1
Petersburg 1
Jefferiee U
Genoa 3/1
Edgewater U
Lk. Catherine U
T. Hill 2
Tradinghouse 1
Ft. Dodge U
Location
Ihester, Va.
•oraerset, Mass
lomer pity, Pa
Indianapolis
x>uisTille,Ky.
"t. Myers, Fla
estlake, La.
armington,NM
ompkins,NY
Valley 2 tfilwaukee,Wi9c
Kw
5UO
671
669
U9U
258
160
630
6kO
218
U50
800
275
360
510
Ull
500
580
Uoo
U35
95
81
755
196
160
117
160
325
20
339
530
290
565
150
UiO
Fuel
Coal
Coal
Coal
Coal
Gas/oil
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil, gaa
Coal
Gas/oil
Coal
Gas
Gas/oil
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Gas/oil
Oas/oil
Gas
Gas/oil
Coal .
Boiler from
B&W
C-E
C-E
C-E
B&W
Riley
B&W
F-W
B&W
C-E
F-W
C-E
C-E
C-fc
F-W
B&W
B&W
B&W
C-E
B&H
B&W
F-W
Riley
Hiley
C-E
B&W
C-E
B&W
B&W
B&W
Riley
T-C from
W
GE
QE
GE
W
W
W
GE
GE
GE
GE
GE
GE
GE
GE
W
W
GE
GE
W
GE
W
GE
GE
W
W
GE
Consultant
United Engrs.
Duke Pr.
Stone&Webster
Ebasco
Sargent&Lundy
BurnB&Roe
Stone&tfebster
Gilbert Assoc.
Stanley
Stone&viebs ter
AhP Serv. Corp,
Pioneer Serv.
Southern Serv.
Black & Veatch
Bechtel
Georgia Power
Stone&rfebster
Gilbert Assoc.
Brown & Root
Bechtel
Bechtel
Bechtel
Parsons
LD&P
Burns&Roe
Burns&Roe
Sargent&Luady
Ebasco
Brown & Root
Black & Veatch
Stone&Webstex
Constructor
United Eng£s.
Stone&WebBter
Stone&Webster
Bechtel monag1
Owner
Bechtel
Stone&Webeter
Gilbert manag1
Bechtel
Bechtel
Jurns&Roe
hirns&Roe
Stone&Weboter
W
-------
Focsii-fueled sEeas: power units scheduled for service in 1969 ( Sheet 2 of 3)
March 15, 1968
Revised July 8, 1968
Utility
:>o.Misa, EPA
illack Hills P&L
TVA
florgan C., La.
So.Miae. EPA
>o. Miss. EPA
)watonna,Minn.
' lochester,Minn.
El Paso Elec.
Opelousas, La.
Municipal
Unit
Moselle 1
Wyodak 5
Paradise 3
Moselle 2 1
Moselle 3 l
No. 6
Silver Lk
No. 10
Location
loselle,Miss.
loselle, Miss.
loselle, Miss.
ineland, NJ
Total
Mw
59
22
,130
20
59
59
20
56
108
26
25
Jk,508 M
Fuel
Coal
Boiler from
B&tf
Rile>
C-E
T-C from
OE
Consultant
Stearns Roger
TVA
rt.Ooudeau & A.
Constructor
Stearns Roger
CD
H
m
r
r
m
2
O
z
H
C
H
U\
I
O
O
r
c
2
CO
c
CD
O
TO
O
5
m
in
-------
Fossil-fueled steam power units scheduled for service In 1970 ( Sheet 1 of 3)
March 15, 1968
Revised July 8, 1968
Utility
'a. P&L
'enelec
Delmarva P&L
Cleveland El
So.Cal. Edison
illeg. Pr. Sys.
;ol. & S.O.
)uquesne Lt.
Tamoa Elec.
111". Pr.
Jnion Elec.
Sarland, Tex.
PS of Okla.
San Antonio
SWEPr
PEPCo
Appalachian Pr.
Lansing, Mich.
PS of Ind.
So.Ind. G&E
Duke Pr.
Georgia Pr.
Gull' Pr.
So. Car. E&G
Cent. P&L
Dallas P&L
Empire D. E.
Gulf States
Houston LAP
^pringfld, Mo.
Texas P&L
PP.WKA
•"•o.Oal. Edison
Big Rivers Coop
Unit
Conemaugh 1
Homer City 2
Indian R. 3
Avon 9
U Corners 5
Hatfields Fy 2
Stuart 1
Cheswick 1
Big Bond 1
Baldwin 1
Labadie 1
Garland 2
Northeast 2
Braunig 3
Wilkes 2
Morgantown 1
Mitchell 1
Eckert 6
Cayuga 1
Warrick U
Marshall U
Hammond U
Crist 6
Wateree 1
La Palma 6
Lk. Hubbard 1
Asbury 1
Conroe 1
Cedar Rayou 1
James R. 5
Valley 3
Mojave 1
Coleman 21
Location
lomer C., Pa.
'armington,NM
ipringdale, Pa
,abadie, Mo*
Garland, Tex.
4organtown,Md
4oundsville,WV
Ilarke C.,Nev.
Mw
900
6UO
16?
618
755
5Uo
580
570
U3U
626
600
100
1*50
390
352
556
* 800
7U
531
315
671
505
323
375
167
375
200
250
750
112
375
Uio
755
160
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Gas/on
Coal
Gas/oil
Gas
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Gas
Gas/oil
Coal
Gas/oil
Gas/oil
Coal
Gas/oil
Oil
Coal
Coal.
Boiler from
C-E
F-W
B&W
B&W
B&W
B&W
B &W
C-E
Riley
B&W
C-E
B&W
C-E
B&W
C-fc
F-W
C-E
B&W
C-E
F-W
F-W
Riley
B&W
B&W
B&W
B&W
B&W
Riley
F-W
C-E
C-E
F-W
T-G from
GE
W
W
GE
W
GE
GE
W
W
w
GE
GE
GE
W
W
W
GE
GE
W
GE
GE
GE
^
W }
w /
w
w
GE
OE
Consultant
Gilbert Assoc.
Gilbert Ansoc.
United Engrs.
CEI & Sarg.&L.
Bechtel
United bngrs.
Ebasco
Stone&Webster
Stone&Webster
Sargent&Lundy
Bechtel
Black & Veatch
Gibbs&Hill
Sargent&Lundy
Bechtel
AEP Serv. Corp
Sargent&Lundy
Ebasco
Duke Pr.
Southern Serv.
Southern Serv.
Gilbert Assoc.
Sargent&Lundy
Kbasco
Black & Veatch
Brown & Root
Ebasco
Burna&rtcDonnel
Bechtel
Parsons
Constructor
Ebasco manag'g
Bechtel raanag1
United Engrs.
Bechtel
United Engrs.
Stone&Webster
Bechtel
Bechtel
Bechtel
CD
>
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H
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r
m
2
m
2
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i
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C
CO
o
TO
>
H
O
3
m
-------
Fossil-fueled steam power units scheduled for service In
(Sheet 3 of 3)
March 15, 1968
Revised July 8, 1968
Utility
Detroit Kd.
Hoosier £. Coop
Mlnnkota Coop.
Austin, Tex.
No. Ind. PS
Lafayette, La.
Louisiana P&L
Wheatland Coop.
Municipal
Black Hills P&L
Unit
Monroe 1
Petersburg 2
Center 1
Decker Cr. 1
Mitchell 11
Bonln
9 mile U
No. 8
French 2
Location
Westwego, La.
Garden C., Kai
Columbia, Ho.
Total
Mw
790
117
237
320
115
100
750
90
UO
33
18,018 1
Fuel
Coal
Coal
Coal
Gas/oil
Coal
Oaa/oil
tw
Boiler from
B&tf
Riley
B&W
C-E
B&W
C-E
C-E
T-G from
GE
OE
GE
W
GE
Consultant
Detroit Edison
LD&P
Sanderson & P
Brown & Root
Sargent&Lundy
Ebaeco
Constructor
CO
I
-o
-------
Fossil-fueled steam power units scheduled for service in 1971 ( Sheet 1 of 2)
March 15, 1968
Revised July 8, 1968
tD
>
^
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m
r
r
m
2
m
2
O
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m
Utility
Pa. P&L
Houma, La.
Detroit Ed.
Union Elec.
PEPCo
Appalach. Pr.
Jacksonville, Fla
Georgia Pr.
Cent. La. E.
Cent. P&L
Gulf States
Kansas P&L
Okla. G&E
So. Cal. Edison
Ohio Edison
Savannah E&P
Kansas City
'Pac. P&L
!Utah P&L
Col.AS.O.E.
Kentucky Util.
SWPS
•5o.Cal.Edi son
Houston L&P
Gulf States
Texas Util.
Mios. P&L
Perm. P&L
Tallahassee
Tampa E.
Ark. E. Coop.
Unit
Conemaugh 2
Municipal 9
Monroe 2
Labadie 2
Morgantown 2
Mitchell 2
Northslde 2
Etowah 1
Teche 3
Plant 2
Conroe 2
Lawrence $
jieminola 1
Mojave 2
Sammis 7
Pt.Wentworth U
Quindaro 3/2
'en trail a 1
Naughton 3
Stuart 2
J.W. Brown 3
C.Jones 1
Ormand Beach 1
CedarBayou 2
Willow Glen U
Big Brown 1
v/ilson 2
Montour 1
Big Bend 2
KcClellan 1
Location
Labadie, Mo*
Morgan to wn,Md
MoundsviUe,!^
Centersvllle
Clarice C., NOT
Pt.Wentworth,(
Centralia,Waal
Kemerer, Wyo,
nr. Ventura,
Calif,
St.Oabriel.La,
JJo.Ruskln,Fla
Mw
900
lii
790
600
558
a800
268
712
361
2UO
250
Uio
550
755
600
a!26
mi*
700
330
580
Uh5
235
755
750
580
575
750
750
66
U3U
125
Fuel
Coal
Coal
Coal
Coal
Coal
Oil/gas
Coal
Gas/oil
Gas/oil
Gas/oil
Coal
Gas
Coal
Coal
Gas/oil
Coal
Coal
Coal
Coal
Coal
Gas
Coal
Gas/oil
Coal
Coal
Boiler from
C-K
Riley
B&W
C-E
C-E
F-*
B&W
B&rf
B&W
B&W
C-fc
C-E
B&W
C-£
C-B
C-E
B&W
C-E
C-E
F-tf
B&W
Combustion
B&W
C-E
F-tf
Riley
Riley
T-G from
GE
W
W
GE
GE
GE
GE
W
GE
W
QE
tf
GE
M
OS
W
GE
GE
GE
W
Consultant
Gilbert Assoc.
United Engrs.
Bechtel
Bechtel
AEP Serv. Corp
Reynolds Smith
Southern Serv.
Sargent&Lundy
Brown & Root
Black & Veatcb
Bechtel
Stone&Webater
Bechtel
Ebasco
Sargent&Lundy
Bechtel
Stone&Webster
Ebasco
Stone&Webater
LO&P
Constructor
ijbasoo nan'g
Bechtel
Bechtel
Austin Bldg
Co.
Bechtel
Stone&Webater
Bechtel itum'g
Bechtel
Stone&Webater
Stone&Webeter
oo
-------
Fossil-fueled steam power units scheduled for service In 1971 ( Sheet 2 of 2)
March 15, 1968
Revised July 8, 1968
Utility
Ala. Pr.
Texas E S Co.
Sierra Pac.
Kansas P&L
Conn. L&P
So.Ind.G4E
Indianapolis P&L
Gainesville, Fla.
Lakeland, Fla.
•IcPherson, Kan.
PRWRA
W. Texas Utll.
PO&E
Appalachian Pr.
Brovnsrille , Tex .
New Mex.ELec.Ser
Unit
Barry 5
Eagle Mtn 3
Ft.Churchill 2
Lawrence 5
Montville
Newberg 1
Petersburg 3
Municipal
Municipal
Municipal
Plant 2
Paint Crk U
Geysers 5
Amos 1
Municipal
Location
Bucks, Ala.
Total
Mw
700
375
no
U30
Uoo
300
ii50
66
100
50
U10
107
53
800
60
Uoo
19,96U V
Fuel
Coal
Gas
Oil
Oeotherra
Coal
r
Boiler from
C-E
F-W
BAW
C-E
C-E
B&W
Riley
C-B
T-G from
W
W
OS
OE
Toshiba
Consultant
Oibbs & Hill
Stone&tfebeter
Black & Veatch
Stone&aebster
ASP Serr. Corp
Constructor
Zachry
Austin
-------
Fossil-fueled steam power units scheduled for service in 1972 ( Sheet 1 of 1)
March 15, 1968
Revised July 8, 1968
Utility
Cent* P&L
W. Penn Pr.
Interstate Pr.
Gulf States
Col.&S.O.E.
Southern Co.
Southern Co.
So. Cal. Edison
PS of Ind.
TVA
Pac. P&L
Central HI. Pr.
Cleveland E. I.
SWPS
Union Elec,
Northeast Util.
Cent. in. Lt.
Tex. Dtil.
San Antonio
[>.Colo.R.Auth*
Louisville O&E
LAIW&P
Pacific G&B
Gulf States
Pa. P&L
Brazos E. Coop
Denton, Tex.
El Paso Elec.
Fla. P&L
Fremont, Neb.
Lansing, Mich.
PRWRA
Iowa PS
Appalachian Pr.
Unit
Plant 3
Hatfields Py 3
Sabine U
Stuart 3
Qrmand Beach 2
Cayuga 2
Cumberland 1
Johnston U
Coffeen 2
Eastlake
Wllkes 3
Labadle 3
Montville
Edwards 3
Big Brown 2
CalaTeras 1
S. Gideon 3
Kosmos 1
El Segundo
Plttaburg 7
Sabine I*
Strawberry R 1
Newman U
Municipal
Neal 2
Aaoa 2
Location
nr. Ventura,
Calif.
nr • Cumberland
Mw
2UO
5Uo
216
580
580
700
700
755
531
1,275
330
U32
625
3U5
600
Uoo
300
575
390
325
350
U50
750
580
765
125
75
150
730
55
150
U5o
325
Fuel
Gas/oil
Coal
Gas/oil
Coal
Oaa
Coal
Coal
Coal
Coal
Coal
Gas/oil
Coal
Coal
Coal
Lignite
Gas/oil
Gas/oil
Coal
Gas/oil
Oil
bOO Coal-
Boiler from
B&rf
B&tf
F-W
C-E
B&M
C-E
B&rf
OS
Riley
Combustion
C-E
C-E
C-E
C-E
F-W
C-B
T-C from
rf
OE
GE
GE
OE
OS
rf
Brown-Boveri
GE
OB
GB
GE
GE
OB
OE
W
GE
GE
LADV/iP Scattergood U50 Gas/oil
Consultant
United Engrs.
Southern Serv.
Southern Serv.
Bechtel
Sargent&Lundy
TVA
Ebasco
Sargent&Lundy
Black & Veatcl
Pioneer Serv.
LADW&P
Bechtel
ABP Serr.Corp
Constructor
United Engrs.
Bechtel
Owner
7
o
Total 16,614 Mw
-------
Fossil-fueled steam power units scheduled for service in 1973 (aheet 1 of 1)
March 15, 1968
Revised July 8, 1968
Utility
Ind. P&L
So.Car.E4G
Illinois Pr.
Kansas GAE
Union Elec.
NEES
TVA
Col. & S.Ohio
Union Elec.
Allegheny PS
111. Power
Unit. 111.
Colo. Springs
Gulf States
Independenc e ,Mo
KCP&L
Utah P&L
Okla. G&E
Mid South
Kan.0&2 & KCP&L
Unit
Plant 1
Baldwin 2
Evans 3
Labadie U
SalemHarbor U
Cumberland 2
Conesvllle U
Sioux 3
Allegheny 1
Baldwin 2
Bridgeport 3
Municipal
Municipal
Seminole 2
Location
nr. Cumberland
La Cyg*«,K«n.
Total
Mw
U50
600
600
380
600
k$Q
1,275
600
600
650
600
UOO
106
750
90
i»on
ItkO
550
U5o
8UO
10,831 K
Fuel
Oas/oll
Coal
Coal
Coal
Coal
Coal
V
Boiler from
C-E
B&W
Riley
T-C from
QE
GE
Brown-Boveri
14
W
tf
/
Consultant
Gilbert Assoc?
.
TVA
Black & Veatch
Gibbs & Hin
Becbtel
Constructor
Gibbs & Hill
w
I
-------
Fossil-fueled steam power units scheduled for service in 197U (Bheet 1 of 1)
Kerch 15, 1968
Utility
Union Elec.
Allegheny ps
TVA
Springfiflld,Mo.
Basim Elec.
Cent. La. Elec.
Garland, Tex.
KG Municipal
Kentucky Util.
NOPSI
PS New Max.
PS Olcla.
Tampa Elec.
Salt R. Project
Teocae P&L
Unit
Jioux h
Allegheny 2
himberland 2
James R. 6
)lds 2
tonieipal
Narcbo 1
Location
Total
Mw
600
650
1,300
U2
Uoo
kko
150
150
U5o
750
600
600
750
785
7,737 M
Fuel
Coal
Coal
r
Boiler from
BAM
T-C from
tf
Brown- Borer!
OK
Consultant
Oibbe & Hill
TVA
.
Constructor
OibbB & Hill
-
td
i.
-------
Fossil-fueled steam power units scheduled for service in 1975 (sheet 1 Of 1)
March 15, 1968
Utility
Salt R. Project
Pac. P&L
Unit
Navajo 2
Centralia 2
Location
Total
Mw
750
700
i,U5o i
Fuel
Coal
V
Boiler from
C-E
T-C from
OE
W
Consultant
Constructor
-------
Fossil-fueled steam power units scheduled for service In 1976 ("sheet 1 of 1)
March 15, 1968
CO
-1
H
m
r
r
m
2
m
2
O
3
>
r
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H
H
C
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m
o
o
r
Utility
Salt R. Project
c
CD
C
(A
r
CD
O
3
^
H
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3}
m |
w
1
Unit
Navajo 3
Location
Mw
7/50
Fuel
Boiler from
T-G from
GE
Consultant
Constructor
-------
Hydro pover unite scheduled for sorvica in
Unit # II
( Sheet 1 of 2)
fiarch 15, 1968
Utility
Sabina R.Auth.
Sabtne R.Auth.
US Engrs.
Idaho Pr.
Idaho Pr.
OS Engra.
OS Engrs.
US Engra.
US Engra.
US Engrs.
OS Engrs.
Calif. Dept.Water
Calif. Dept.Water
Calif. Dept.Water
Ala. Pr.
Ala. Pr.
Ala. Pr.
Ala. Pr.
DouglasCoPUD 1
OouglasCoPUD
DouglasCoPUD
Tacoma, Wash.
Tacoraa, Wash.
Calif .Dept.Water
Calif. Dept.Water
Calif .Dept.Water
Grand R. Auth.
Grand R. Auth.
Grand R. Auth.
US Engrs.
US Engrs.
US Engrs.
Ala. Pr.
US Engrs.
USER
Unit
Toledo Bend 1
Toledo Bend 2
fillers Fy 1
tallsCanyon 2
HellsCanyon 3
Day 1
Day 2
Day 3
Day U
Day 5
Day 6
OroYille 3
Oroville U
Oroville 5
^ay Daffl 1
Lay Dan 2
'j&y Dam 3
j&y Dam k
WeUs 8
Wells 9
Wells 10
iossyrock 1
Hoseyrock 2
'hermalito 1
Thermalito 2
'hermalito 3
Salina 1
Salina 2
Salina 3
Narrows 3
Coster 1
Foster 2
lolt Dam 1
Priest 1
•'ontenelle
Location
Mw
U2
U2
25
1U2
H|2
155
155
155
155
155
155
PSU7
re 98
PS117
29
29
29
29
88
88
88
16U
16U
« 33
F3 28
28
U3
U3
U3
9
12
12
ho
28
10
Fuel
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
PS Hyds-o
PS Hydro
PS Hydro
PS Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Prime mvr from
Gen . from
Consultant
v
i
X.
•
Constructor
a
-------
Hydro poorer unite scheduled foir service in ^968 (Sheet 2 e£
Kerch 15, 1968
Utility
Douglas PUD
Calif 0Dept<,Water
Calif. Dept. Water
SMUD
SMUD
SMUD
USER
USSR
Unit
rfells 7
>oville 1
Crovllle 2
"anino 2
Vhite Rk 1
rfhite Rk 2
San Luis 1
San Luis 2
Location
Total
Mw
89
11?
98
68
100
100
53
53
3,370 H
Fuel
Hydro
PS Hydro
PS Hydro
Hydro
Hydro
Hydro
PS Hydro
PS
IT
Prime mvr from
Gen. from
^
Consultant
N
\
'
\
j
N
Cons true to;
w
I
-------
Hydro power units scheduled for service In
Sheet 1 of 2.)
15 o
Utility
US EngrBo
US EngrSo
US Engrs<>
US Engrs,
US Engrs.
Calif.Dept, W
US Engrs.
USSR
Penelec
Penelec
Penelec
US Engrs.
US Engrs.
USER
US Engrs.
US EngrB.
US Engrs.
San Francisco
San Francisco
PG&E
I
Unit
Broken BOH 1
Day 7
Day 8
Day 9
Day 10
Oroville 6
Day 11
Morrow Pt. 2
Seneca 1
Seneca 2
Seneca 3
Millers Fy 2
Killers Fy 3
Morrow Pt. 1
L. Monument 1
L. Monument 2
L. Monument 3
N. Moccasin 1
N.Moccason 2
Belden 1
Location
Total
to
50
155
155
155
155
98
155
60
175
175
30
25
25
60
155
155
155
51
51
117
2,157 t
Fuel
Hydro
Hydro
Hydro
Hydro
Hydro
PS Hydro
Hydro
Hydro
PS Hydro
PS Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
V
Prime ravr from
Gen. from
Consultant
Conotruetoz
I
^1
-------
Hydro power uniLs scheduled for service in
( Sheet 1 of 1)
rfarch 15, 1968
CD
>
H
H
m
r
r
m
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2
O
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H
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CD
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JO
>
H
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2
m
in
Utility
US Engrs.
US Engrs.
US Engrs.
US Engrs.
US Engrf.
US Engrs.
TVA
Yuba R. Water
Yuba R. Water
Yuba R. Vater
JCP&L
JCP&L
JCP&L
US Engre.
US Engrs.
US. Engrs.
US Engrs.
US Engrs.
US Engrs.
Duke Pr.
Duke Pr.
i
i
t
Unit
Lit. Goose 1
Lit. Goose 2
Lit. Goose 3
Day 12
Day 13
Day Hi • • .
Tims Ford
Yuba New Col.l
Yuba New Col. 2
YubaNewNarrow
Longwood Val.l
Longwood Val.2
Longwood Val.3
Broken Bow 1
Kerr 1
Kerr 2
Kerr 3
Kerr h
Stockton 1
Keowee 1
Keowee 2
Location
•
Total
• ' • ''•;
Mw
155
155
155
155
155
155
ho
Hj2
11(2.
U7
PS U3
PS U3
PS U3
50
28
28"
28
28.
U5
70
70
1,777 If.
t
Fuel
Hydro
Hydro
Hydro
Hydro . .
Hydro .
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro •
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
K
Pfiiae.mvr from
,
A-C .
A-C
Gen. from
/
Consultant
•«
Constructor
t
b
i <
k
o
-------
15B I960
ro power
ocheduied for
1971 ( Shost 1 @£ 1)
Utility
US Engr30
US EngrSo
US Engrs.
US EngrSo
US Engrs.
US Engrs.
US Engrs.
US Engrs.
?WUD
Turlock Dlsto
Turlock Dist.
Turlock Dist.
Northeast U.
Northeast U.
Northeast U.
Northeast U.
Chelan PUD 1
Chelan PUD
Chelan PUD
Chelan PUD
Unit
Hull 2
Hull ^
Ozark 1
Ozark 2
Ozark 3
Hull 1
DeOray 1
DeGray 2
Loan Lake
New Don P 1
New Don P 2
New Don P 3
Northfield 1
Northfield 2
Northfield 3
Northfield U
Rocky Reach 8
Rocky Reach 9
Rocky Reach 10
Rocky ueach 11
Location
Total
to
33
33
20
20
20
33
PS UO
PS 28
78
50
50
50
250
250
250
250
150
1^0
150
150
2,055 i
Fuel
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
PS Hydro
PS Hydro
PS Hydro
PS Hydro
Hydro
Hydro
Hydro
Hydro
9
P^ime mvr from
Gen. from
Consultant
1
Conoenaeeo?
(33
I
-------
March 15„ 1?68
Hydro power units scheduled for service in
( shaet 1 of 1)
CD
>
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C
en
oo
o
33
O
5
m
Utility
US Enp.rs.
US En^rs,
US Enprs.
'IS Eners.
US hJ!Crs.
US Enpra.
US Birrs.
US Enpjrs.
Unit
W. Point Ga
W. Point, Ga
Ozark U
Ozark ?
Webbers Kallsl
Webbers Falls2
Carters 1
Carters 2
Location
Total
I!w
36
36
20
20
Pf, 20
PS 20
125
125
Fuel .
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Prime mvr from
Gen. from
Consultant
Constructor
CO
I
rv
o
-------
Hydro pouer units scheduled for service in J[52JL_ ^ Pago i ef
15S 1968
Utility
U? Engrso
i
Unit
Webbers Fls 3
Location
tfcj
PS 20
Fuel
Hydro
Prise rnvr from
Gen0 from
Consultant
Conotruceor
.
-------
Hydro power units scheduled for service in _197K (page 3, af 1)
March
1968
Utility
Unit
txjcation
Fuel
Prime ravr from
Gen . f rora
Consultant
Constructor
NKF?
rjuke Pr0
Ouke Pr»
Jocassee 1
Jocassee 2
Mass,,
Total
600
150
15Q
900 Mw
PS Hydro
PS Hydro
PS Hydro
A-C
a
i
tv
rv
-------
ro power unite ocheduled foir service in ...Igj5r (paga 1 of 2.)
March 15,
Utility
Unit
Location
Kw
Fuel
Prime mvr from
Gsn. from
Consultant
Construetoi
Duke Pr.
Duke Pr,
VEPCo
Jocassse 3
Jocassee h
Marble Valley
Total
150
150
l.ooo
PS hydro
PS Hydro
A-C
A-C
1,300
to
I
(V
OJ
-------
Peaklnp power units scheduled for service in
Unit ff III
968 (Sheet lof It)
March 15, 1968
Revised July 8, 1?68
Unit
Ltchell 9B
Ltchell 9C
iburban
wipbell A
arrow A
Dnroe
—
—
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
izzard Pt.
irbor Beach
Lbany
m R UC
in R 5C
>e 5C
>e 6C
1
2
Location
Central Fla.
Mw
GT$x33
GT 17
GT 17
GT 31
GT 21
GT 20
D 1U
D Ik
0 111
D 10
D 10
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
OT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
0 U
D 5
GT 3U
GT 3k
GT 3U
GT 3k
GT 16
GT 16
Fuel
Gas/oil
Prime mvr from
OK
QE
GE
GE
GE
GE
GE
GE
GE
GE .
GE
GE
GE
GE
OE
GE
Gen. from
rforthington
"~
\
»' Consultant
\
\
\
%t
1
\
^.- „
Constructo:
r
••-
;|
•\
,-:/.
\'
%
*|.
'•'$•
-4
•m
'M
i'S
' .^^
'A-.:
'%
tv
•-
-------
Peaking power units scheduled for service in 1968 (Sheet 2 of It)
March 15, 1968
Utility
la-Ill O&E
la-Ill G&E
Ia-111 O&E
Ia-111 G&E
Springfield ,Mo.
Ind.&Mich. E
Ind.Wich. E
Ind.&Mich. E
Con Edison
Con Edison
Con Edlaon
Con Edison
Con Edison
Con Edison
Con Edison
Con Edison
Con Edison
Con Edison
Delmarva P&L
Delmarva P&L
Delmarva P&L
Northeast Util.
Rochester G&F,
Rochester G&E
Consumers Pr«
Consumers Pr.
Consumers Pr.
Detroit Edison
Louisville G&E
Louisville G&E
PS of Ind.
PS of Ind.
PS of Ind.
PS of Ind.
Carolina P&L
Unit
Riverside
Riverside
Riverside
Riverside
Main St. GT1
Indiana 1
Indiana 2
Indiana 3
59th St.
59th St.
Hudson Ave.
Hudson Ave.
Indian Pt.
Kent Ave.
Kent Ave.
7Uth St.
7Uth St.
Waterside
W.Springfld U
Oaylord 5
rfeadock A
Whiting A
St Glair
^ abash Peak.
Wabash Peak.
W abash Peak.
Wabash Peak.
Robinson
Location
Crisfield,Md.
Delaware Citj
Vienna, Md.
Louisville, K>
Mw
OT 16
GT 16
GT 16
GT 16
GT 16
OT 17
GT 17
GT 17
GT 21
GT 21
OT 21
GT 21
GT 25
GT 15
OT 15
OT 21
OT 21
OT 15
D 10
GT 16
OT 16
OT 21
OT 19
OT 19
GT 21
GT 21
GT 21
GT 21
GT 16
GT 16
GT 19
GT 19
GT 19
GT 16
GT 16
Fuel
Prime mvr from
Gen. from
,
Consultant
Constructor
•• .
w
I
tv
-------
Peaking power units scheduled for service In 1966 (Sheet 3 of U)
rtarch 15, 1968
1 Utility
VEPCo
VEPCo
VEPCo
VEPCo
VLPCo
VEPCo
Municipal
Comm. Fdison
Comm. Fdison
Comm. Edison
Coram. Edison
Comm. Edison
Comm. Edison
Co""., Edison
Comm. Edison
Conun. Edison
Com.n. Edison
Co urn. Fdison
Comm. Fdisor.
Corr Fdisor.
Comm. Fdisor.
Comm. Edison
Comrn, Edison
Macon, Ho.
Peru, 111.
SWEP
SWEP
SWEP
SWPS
Def -oitLkjMinn
San D GbZ
Zt-\ D GiE
San ? G-i-E
s«r. D G&E
Col. L S.O.E.
Unit
Poeaum Pt.
Poaaum Pt.
Possum Pt.
Possum Pt.
Possum Pt.
Poaaum Pt.
Yazoo City 5
Crawford 31-1
Crawford 31-2
Crawford 31-3
Crawford 31-U
Crawford 32-1
Crawford 32-2
Crawford 32-3
Crawford 32-U
Crawford 33-1
Crawford 33-2
Crawford 33-3
Crawford 33-U
Fisk 31 1A2
Kisk 32 1*2
Fisk 33 1&2
Fisk 3U 1*2
Macon
Peru 1 GT
Lone Star 2
Lone Star 3
Lone Star li
Guymon 1
Detroit Lk U
San Diego 1
San Diego 2
San Diego 3
San Diego h
Walnut 7
Location
Yasoo C,Miss
Encina
El Cajon Sub.
Division Sub.
Kearney Sub.
Mv
GT 15
GT 15
GT 15
GT 15
GT 15
GT 15
GT 11»
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 17
GT 76
GT 76
GT 76
GT 76
D 5
GT 12
GT 16
GT 16
GT 16
GT 15
GT 11
GT 20
GT 20
GT 20
GT 20
GT 29
Fuel
Gas/oil
Gas/oil
Oil
Gas/oil
Prime mvr from
OB
GK
GE
GE
Cen. from
,
OE
GE
GE
Gt,
Consultant
Sargent&Lundy
Sargent&Lundy
Pioneer Serv.
Pioneer Serv.
Pioneer Serv.
Pioneer Serv.
Constructo
Owner
Owner
Owner
Owner
03
i
-------
Peaking power units scheduled for service In 1968 ( Sheet U_ofJ»)
rtarch 15, 1968
CD
m
r
r
2
m
2
O
z
w
C
H
m
o
r
c
2
m
c
W
O
3)
>
H
O
2
m
CO
Utility
Col. b S.O.E.
Dayton P&L
Dayton P*L
Dayton P&L
LouiBvlUe G&E
Gainesville, Fla.
Galne8ville,Fla.
Lk. Superior Pr
HarrisonviUeMis
Hartford E L
PS of N.H.
PS of N.H.
Grand Is.,Nebr.
No. Ind. PS
Car. PAL
Jacksonville ,Fla
Jacksonville, Fla
C -dar Falls, la
Co. sa» Eiisc..
-ow.. 1-ison
Wisconsin EP
Wisconsin EP
Wisconsin EP
M138. P&L
Thibodaux,La.
PS of Colo.
Tampa ELec.
Tampa El^c,
Unit
Walnut 8
Hutchings
Monument
Sydney
Paddys Run 12
Gainesville 1
Gainesville 2
Flambeau 1
Franklyn 1
Merrimack 3
'White Lk 1
Burdlck 3
BaiUy 10
Roxboro
Waukegan 31 1&2
Waukegan 32 1&2
Lakeside 21
Lakeside 22
Oak Creek 9
Brown 5
Thibodaux 12
Cherokee
Big Bend
Gannon
Location
Waukegan, 111
Waukegan, 111
Total
Mw
GT 29
GT 29
D lit
D lit
OT 29
OT 15
GT 15
GT 20
D U
GT 21
OT 21
GT 21
CT 15
GT 3U
OT 16
GT 15
GT 15
OT 22
GT 76
OT 76
OT 18
OT 18
GT2x20
OT 12
D 6
D 6
OT 18
GT 18
2,86U »
Fuel
Oil
Oil
Oil/gas
r
Prlne mvr from
H.Vogt (waste ht
Worth ington
Morthington
Gen. from
W
'--^
\
Elec. Mach.
Elec. rtach.
Westinghouse
v Consultant
/
Sargent&Lundy
Pioneer Serv.
Pioneer Serv.
Constructor
rforth ington
Worthington
w
I
-------
Peaking power units scheduled for service In 1969 ( Sheet 1 of 3)
March 15, 1968
Revised July 8, 1968
(0
>
H
H
m
r
r
m
m
2
O
m
o
o
r
c
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c
ISI
01
o
H
O
5
m
ill
Utility
Boston Edison
Boston Edison
Boston Edison
Boston Edison
Boston Edison
Boston Edison
Conn. LAP
Conn. L&P
Bait. GAE
Conn. L&P
PS of N.H.
Atlantic City E.
Atlantic City E.
Atlantic City E.
Northeast Util.
Northeast Util.
Northeast Util.
Northeast U*U.
Northeast Util.
S.oCa^. Edison
S. ..^aloEdi:>on
So,C '.<, Edison
Ptnn. P&L
Penn. Ptt
P: n. J'YL.
Penr.. P&L
Perm. P&L
Col. tc S.O.E.
Kansas City, Kan
So. Gal. Edison
So. Mis o. EPA
.'Mj.Kiss. EPA
So .Miss. EPA
Louisville G&S
Phila. Elec.
Unit
No. 1
No. 2
No. 3
No. U
No. 5
No. 6
No. 1
No. 2
Westport
No. 3
Merrim&ck U
Branford 1
Enf ield 1
T'jmnel 3
Doreen 1
Woodland Rd 1
Alamitos 7
Huntington B«5
Etiwanda 3
Fishbach 1
Fishbach 2
W. Shore 1
W. Shore 2
Lock Haven 1
Stuart
Quindaro 3
Stauffer Chem.
Moselle
Moselle
Moselle
Riverside 1
Chester
Location
AtlanticCity
AtlanticCity
AtlanticCity
Mw
OT 17
GT 17
GT 17
GT 17
GT 17
GT 17
OT 21
GT 21
GT 132
GT 21
OT 19
GT 20
OT 20
OT 20
GT 21
OT 21
OT 21
GT 21
GT 21
OT 121
OT 121
OT 121
OT 19
GT 19
GT 19
OT 19
GT 19
D 11
GT 17
GT 12
OT 1U
OT lit
OT Hi
GT 16
GT 20
Fuel
Prlne mvr from
AEI
AEI
AEI
AEI
AEI
AEI
Gen. from
Consultant
Constructor
(33
i
i\j
00
-------
Peaking power units scheduled for service in 1969 ( Sheet 2 of 3)
March 15, 1968
(D
r
r
m
2
m
o
z
(A
-
m
i
t
o
i
c
ra
c
r
V,
03
C
73
m
(jUtillty
Phila. Elec.
Phila. Elec.
Phila. Elec.
Phila. Elec.
Phila. Elec.
Phila. Elec.
Phila. Elec.
PEPCo
PEPCo
PEPCo
PEPCo
PEPCo
PEPCo
PEPCo
PEPCo
PSS?"
PSE',
Jc:;-sonvlile,Fla
i Jackdo.>7llle,Fla
Jacksonville , Flc
Je: .aonville,Fla
Hur. cipal
Iowa PS
North. States
.%'orth. States
North. States
North. States
We?;. Mass.
dt. . Masr.
We ... tfaS3.
Wes « » MP ss.
'.uniclpal
Muni-lpal
Comm. Edison
C -TO. Edison
Unit
Chester
Chester
Delaware
Delaware
Delaware
Delaware .
Southwark
Kearney 10
Kearney 11
•
i
No. 1
No. 2
No. 3
No. U
Silver Lake
Silver Lake
Silver Lake
Silver Lake
Substa. J-l
Substa. J-2
Joliet 31-1
Joliet 31-2
Location
iC*ukauna,Wi8.
Chao.Clty.Ia
Cndepend,Mo.
Independ,Mo.
Mw
OT 20
OT 20
OT 20
OT 20
GT 20
OT 20
OT 20
GT 17
OT 17
OT 17
OT 17
QT 17
OT 17
OT 17
OT 17
OT 11*0
0A' UO
GT 16
GT 16
OT 16
OT 16
OT 17
QT 3U
GT 20
GT 20
GT 20
OT 20
OT 19
OT 19
GT 19
OT 19
GT 15
GT 15
GT 18
GT 18
Fuel
Prime mvr frotn
Gen. from
_
Consultant
V
/
Constructor
-
•
t
N>
sO
-------
Peaking power units scheduled for sctvlce in
Sheet 3 of 3)
March 15, 1968
0)
m
r
r
n\
m
2
O
H
m
i
o
o
r
c
CD
C
01
o
m
to
Utlllt"
Comm. Edison
Comm. Edison
Comm. Edison
Comm. Edison
Conm. Edison
Comm. Edison
Comm. Edison
Comm. Edison
Comm. Edison
Comm. Edison
Unit
Joliet 31-3
Joliet 31-U
Joliet 32-1
Joliet 32-2
Joliet 32-3
Joliet 32-14
Sabrooke 31-1
Sabrooke 31-2
Sabrooke 31-3
Sabrooke 31-U
Location
Total
Mw
GT 18
GT 18
GT 18
GT 18
GT 18
GT 18
GT 18
GT 18
GT 18
GT 18
2,130 M
Fuel
Prime mvr from
Gen. from
Consultant
Constructor
to
I
-------
Peaking power units scheduled for service In 1070 ( Sheet 1 of 1 )
narch 15, 1968
DO
>
H
-I
m
r
r
m
2
m
2
O
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w>
H
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ro
i
n
o
2
CP
C
in
CD
O
3)
o
-T*
m
Utility
Bait. G&E
So. Cal. Edison
Long la. Ltg.
Long Ts. Ltg.
Long Is. Ltg.
Long Is. Ltg.
Long Is. Ltg.
Long Is. Ltg.
Lon* Is, Ltg.
Long Is. Ltg.
Wise. K P
PEPCo
PEPCo
!
!
Unit
Riverside
Mandalay 5
Barrett
Barrett
Barrett
Barrett
Barrett
Barrett
Barrett
Barrett
Point Beach
Morgantovn
Morgan tovn
Location
Total
Hu
OT 132
GT 121
GT 21
GT 21
GT 21
GT 21
GT 21
OT 21
OT 21
OT 21
OT 20
OT 17
GT 1?
U7$ H*
Fuel
Prlne nrvr from
--
Gen. from
i
1
Consultant
—
Constructor
CO
i
-------
Peaking power units scheduled for service in 1971 (Sheet lof
March 15, 1?68
m
H
H
m
r
r
m
2
m
2
O
2
>
r
z
(/)
H
r
-i
m
i
o
o
r
c
ID
C
10
'
>
03
O
3!
>
H
O
2 i
m i
10
Utility
Long le. Ltg.
Unit
Shorehan
Location
Hw
GT 56
Fuel
Prime mvr fron
Gen. from
Consultant
/
Cons true to
' .„
w
1
l/J
t^J
------- |