OKDES
CAPITAL REQUIREMENTS AND BUSBAR COSTS
FOR POWER IN THE OHIO RIVER BASIN,
1985 AND 2000
PHASE II
OHIO RIVER DASIN ENERGY STUDY
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October 1980
CAPITAL REQUIREMENTS AND BUSBAR COSTS
FOR POWER IN THE OHIO RIVER BASIN,
1985 AND 2000
by
Richard Newcomb
Bruce Bancroft
West Virginia University
Morgantown, West Virginia 26506
Prepared for
Ohio River Basin Energy Study (ORBES)
Subcontract under Prime Contract EPA R805588
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
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DISCLAIMER
This report has been reviewed by the Project Office of the Ohio
River Basin Energy Study, U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the U.S. Environmental
Protection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
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CONTENTS
Page
Figures ill
Tables iv
Acknowledgment v
1. Introduction 1
2. Conclusions 2
3. The Framework of the Study 4
4. Methods Used to Compute Capital Requirements and
Busbar Costs 14
Appendix 31
References 40
11
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FIGURES
Number Page
1 Capital Cost Component of Busbar Costs 21
2 Capital Cost Component of Busbar Costs (Coal) 22
3 Fuel Cost Component of Busbar Costs (Coal) 24
4 Optimum Tails Composition (Nuclear) 27
5 Yellowcake Component of Busbar Costs (Nuclear) 28
6 Conversion-to-UFg Component of Busbar Costs (Nuclear) .. 28
7 SWU Cost Component of Busbar Costs (Nuclear) 29
8 Fabrication Cost (Nuclear) 29
9 Spent Fuel Shipping and Waste Management Component of
Busbar Costs (Nuclear) 30
111
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EXHIBITS
Number
1.1 Current ('75), Planned ('85) and Conjured ('00)
Utility Capacity Additions and Retirements in
the ORBES Region ,
1.2 ORBES State Solid Fuel Electric Mwe Net Capacities -
Current (1975), Planned (1985) and Conjured
(2000)
1.3 Gross Additions to Plant 1975-85, and 1985-2000 in Mwe
in the ORBES Region by State for Scenarios 2, 2n,
and 7 8
1.4 Standard Plant Equivalent (SPE) Solid Fuel Gross Addi-
tions in Mwe in the Concept Regions by State for
Scenarios 2, 2n and 7 9
1.5 Coal Prices 10
1.6 Various Nuclear Fuel Cycle Study Assumptions 12
2.1 Capital Costs for Coal and Nuclear Plants as a Func-
tion of Various Input Parameters 15
2.2 Capital Requirements by State for the Time Periods
1975-1985 and 1985-2000 for Scenarios 2, 2n, and 7 .. 16
2.3 Busbar Costs in Mills/Kwh (1975 $) by State for 1985
and 2000 18
2.4 Nuclear Fuel Cycle Cost Assumptions (1975 $) 25
2.5 Equilibrium Annual Quantities Required for the Nuclear
Fuel Cycle as a Function of Enrichment Tails Assay .. 26
A. 1 The CONCEPT Package 33
A.2 CONCEPT Variable List 34
A. 3 CONLAM Variable List 36
A. 4 CONTAC Variable List 37
A.5 Major OMCOST Variables 38
IV
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ACKNOWLEDGEMENTS
The authors wish to acknowledge the invaluable research assistance
of J. Fan, B. Han, C. Yang, and G. Shaw of the Mineral Economics Depart-
ment, whose work on the computer implementations was critical to this
report. Two basic programs were supplied by Oak Ridge and Argonne
National Laboratories and considerable use of CONCEPT-V was made through-
out the report. Extensive employment of data and assumptions of other
ORBES authors' reports was also made and these are acknowledged in the
text. Regional coal cost calculations were supplied by Professor Walter
Page. The authors take sole responsibility for any and all errors or
omissions of the report.
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SECTION 1
INTRODUCTION
This report provides estimates of capital-output ratios and typical
operating costs for the comparison of alternative patterns of electric
utility expansion in the Ohio River Basin (ORB) over the next twenty-five
years. The assumptions of growth in the region of interest are those
defined by the Ohio River Basin Energy Study (ORBES). All of Kentucky
and portions of Illinois, Indiana, Ohio, Pennsylvania and West Virginia
comprise the basin area. The objective of our research is to estimate
capital requirements and representative busbar utility prices for power
plants described and projected in other ORBES studies for selected
counties in each of the states. Industry's estimates of capacity are
accepted through 1985 from their plans in progress. Capacities through
the year 2000 are conjured by the other ORBES studies. The assumptions
concerning the representative sites, types of plant, scale and costs of
delivered fuel are given by the ORBES project, along with the demand
conditions. Three scenarios are discussed over the future periods ending
in 1985 and 2000: (i) "scenario 2," a moderate growth inside ORB
assuming no export or nuclear expansion, (ii) "scenario 2n," an expanded
export case, the added facilities being fueled by nuclear energy, and (iii)
"scenario 7," a high growth coal forecast based on a Nuclear Energy Regula-
tory Commission (NERC) projection.
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SECTION 2
CONCLUSIONS
ORBES assumes ten year construction times for nuclear plants scaled
at 1,000 megawatts (MW) scale and five year times for coal plants scaled
at 650 MW. Under these assumptions, the incremental power from coal is
cheaper by one third than new nuclear power. In 1985 (measured in 1975
constant dollars), capital and fixed costs are 41.5 mills per kwh for
coal compared to 65.7 mills per kilowatt hour (kwh) for nuclear. In
current 1980 dollars, the busbar price for electricity is 7.5 cents per
kwh for coal and 10.2 cents per kwh for nuclear. If coal plants are
built to the same scale, the coal price falls further to half that of
nuclear. If the longer construction time assumed for nuclear is dropped,
the cost of coal and nuclear are approximately equal. It is on this last,
ceteris paribus,* basis that the following results of this research are
summarized as follows.
(1) The total ORBES capital requirements are large. In 1975 constant
dollars the cumulative gross increments to capacity planned in the region
through 1985 require a $39 billion investment over five to ten years.
This investment total is about 25 percent of current (1975) annual levels
of gross product estimated for the region. By the year 2000, the increment
required reaches $97 billion in the lowest growth case (scenario No. 2,
nuclear foreclosure), $118 billion in the mixed case, (scenario No. 2n,
domestic coal and nuclear exports) and $126 billion in the high coal case
(scenario, No. 7}).
(2) The capital requirement differences among states by the year 2000
generated for the scenarios are also large for some states. The nuclear
export scenario adds $20 billion, most of it in two states, Ohio and Penn-
sylvania. The high coal case adds $30 billion in coal facilities affecting
largely Kentucky, Ohio and West Virginia. The capacities and locations
are the same in 1985 for all scenarios.
*Ceteris paribus, or "all things being equal" is a convenient assumption
because it implies the closest comparison, but, of course, with two such
different technologies, all things never are equal in reality. We
describe in detail below how the significant component of cost, capital
and fixed charge rates, is affected by ORBES assumptions yielding the
ultimate advantages to coal. These advantages would be increased if tax
subsidies are calculated following Chapman's ORBES study. Here, costs
reflect only the busbar price to the utility user and not the social cost
of power.
2
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(3) As one might expect, the component of cost that dominates the
price of electricity at the busbar is comprised of capital costs and other
special fixed charges. Under public utility accounting conventions, a
variety of special charges are added to annual capital costs per kwh.
The capital cost is, of course, higher for nuclear plants than for coal.
Significant economies of scale are characteristic of both technologies,
but nuclear fuel costs are lower. When the advantages of larger scale
are combined with lower nuclear fuel costs and the construction times are
assumed equal, coal and nuclear costs are close. ORBES assumptions
realistically double the time for nuclear plant construction following
current experience. When this is assumed, despite higher fuel costs for
coal and lower scales, utilities find coal significantly cheaper. If
construction times are equalized, nuclear is clearly cheaper nowhere in
the region in 1985. However, by the year 2000, nuclear is cheaper by a
small fraction in the major coal field states. In contrast, by 2000,
coal is cheaper only in Illinois. No cost differences are very large.
C4) Were construction times to be equalized, in a typical case such
as at the busbar in Ohio in 1985, coal fixed costs of 35.4 mills per kwh
out of a total cost for coal of 50.4 mills would compare closely with
nuclear fixed costs of 41.5 mills out of a total 50.3 mills. In current
1980 dollars, total busbar cost approaches 7.0 cents per kwh in 2000.
The difference between coal and nuclear costs at the most in 2000 would
be less than a cent. These results contrast with other studies, which
have generally shown about a 20 percent advantage for nuclear facilities.
Major differences are discussed in the text.
(5) Because construction times are unequal, the advantage goes to coal
despite the smaller assumed scales. The ORBES acceptance of a longer
construction time for nuclear raises its fixed cost 58 percent from 41.5
mills to 65.7 mills per kwh in 1985. The bottom-line busbar cost then
becomes 10.2 cents per kwh for the larger scale nuclear plants versus 7.5
cents in current 1980 dollars for the smaller scale coal plants.
Section three gives the framework for this study and section four
the computations of capital costs and comparative prices.
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SECTION 3
TOE FRAMEWORK OF THE STUDY
The comparison of busbar costs for coal-fired or nuclear power
facilties variously located in the region defined as the Ohio River
Basin (ORB) is accomplished by the analysis of unit costs in process
evaluation models simulating (i) power plant construction and (ii) power
plant operations. The cost of nuclear fuel or coal supplied to these
plants at different sites is added to these capital and operating costs
to arrive at estimated prices for electricity at the busbar. Total
capital costs are also estimated. Thus, this study forms an important
link in the larger ORBES assessment of clean energy alternative supply
patterns, benefits and costs for given demands in 1985 and 2000.
The evaluation, while quite detailed for a cost engineering exercise,
is relatively simple in terms of accounting and economics. The estimates
are developed in six stages, three of them provided by this study and
three by correlative studies. First, estimates of conventional mining
and preparation costs are taken from the Blome study. Second, estimates
of average delivered costs for coal blended to achieve uniform Btu values
and sulfur content (1.2% by weight on average) to centroids of each state
are accepted from the Page Report (Exhibit 1.5). This forms the basis
for average costs for coal in each ORB state for 1985 and 2000. Third,
the nuclear fuel cycle is analyzed in this study to arrive at nuclear
fuel costs. Fourth, site-specific construction costs are evaluated in
the Oak Ridge model CONCEPT V (cf. Appendix). This model distinguishes
the differential capital costs of various coal and nuclear power plant
constructions, containing dozens of technical or site related parameters
and thousands of variable plant costs. The areas for which historical
factor prices and other site-related costs are stored in CONCEPT include
those typical of the Chicago, Cincinnati and Pittsburgh regions. These
are assigned to ORBES counties in Illinois, Indiana-Kentucky, and Ohio-
Pennsylvania-West Virginia respectively. Independent runs are made on
pressurized water reactors (PWR) and moderate sulfur coal-fired boilers
equipped with scrubbers (CS) to generate capital-output ratios. Incre-
mental units sited in the ORB by the Larson and Fowler Studies are then
employed to compute current base year (1975), planned (1985) and conjured
(2000) capacities and additions net of retirements in the ORB by solid
fuel type. These are considered for both greenfield (stand-alone) plants
and plants added to existing or planned capacities. We have shown these
by state for three scenarios designated by ORBES, coal (2), NERC (7) and
Nuclear Export (2n) in Exhibit 1.1. These are reduced in Exhibit 1.2 to
estimates of solid fuel electric net capacities by state for each of the
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Exhibit 1.1 CURRENT ('75), PLANNED ('85), AND CONJURED COO) UTILITY CAPACITY ADDITIONS AND RETIREMENTS IN THE ORBES REGION IN MWe BY SOLID FUEL TYPE,
GREENFIELD (GF) AND ADDED TO EXISTING OR PLANNED (ATE) BY ST.ATE FOR COAL (2), NERC (7), AND NUCLEAR EXPORT (2n) SCENARIOS
Scenario Fuel
#2 Coal
Conventional
A-. Base Capacity
Period1
Addition
Subtotal
Retirements
B21 Net Capacity
Period2
Addition
Subtotal
Retirements
C21 Net Capacity
#7 NERC Coal
Added Period2
C71 Net Capacity
#2 Nuclear
A2") Base Capacity
Period1
Addition
Subtotal
Retirements
B22 Net Capacity
»2n Period2
Addition
Subtotal
Retirements
C22 Net Capacity
#7 NERC-NUC
Added Period2
C71 Net Capacity
Date
'75
'85
'00
'75
'85
'00
ILLINOIS
TOTAL GF ATE
10,512
4,399 1,034 3,365
14,911
- 511
14,400
9,723 8,450 1,273
24,123
-3,631
20,492 9,484 4,638
3,250 3,250
23,742 12,734 4,638
1,865
4,056 2,028 2,028
5,921
5,921
1,000 1,000
6,921
- 209
6,712 2,028 3,028
-1,000 -1,000
5,712 2,028 2,028
INDIANA
TOTAL GF ATE
10,114
8,951 2,705 6,246
19,065
- 534
18,531
12,700 11,700 1,000
31,237
-5,272
25,959 14,405 7,246
4,550 4,550
30,509 18,955 7,246
-0-
2,260 1,130 1,130
2,260
2,260
1,000 1,000
3,260
3,260 1,130 2,130
-1,000 -1,000
2,260 1,130 1,130
KENTUCKY
TOTAL GF ATE
10,948
8,880 2,955 5,925
19,828
- 837
18,991
12,550 10,400 2,150
31,541
-4,962
26,579 13,579 8,975
7,800 7,800
34,379 21,155 8,975
OHIO
TOTAL GF ATE
17,034
3,927
20,961
-1,439
19,522
13,000
32,522
-5,160
27,362
7,800
35,162
-0-
810 810
810
810
10,810 10,810
11,620
11,620 810 10,810
-10,000 -10,000
1,620 810 810
PENNSYLVANIA
TOTAL GF ATE
9,691
6,134 1,547 4,587
15,825
- 336
15,489
9,100 9,100
24,589
-2,552
22,037 10,647 4,587
1,300 1,300
23,337 11,947 4,587
-0-
1,830 925 915
1,830
1,830
8,000 8,000
9,830
9,830 8,925 925
-8,000 -8,000
1,830 925 925
WEST VIRGINIA
TOTAL GF ATE
11,966
2,552 1,926 626
14,518
- 582
13,936
9,100 9,100
23,036
-3,670
19,366 11,026 626
7,150 7,150
26,516 18,176 626
Sources: Tables 1 and 3, Electric Generating Unit Inventory, 1976 - 1986, Steven O. Larsen, Energy Resources Center, Univ. of Illinois at Chicago Circle, Nov. 1978,
and Supplementary Reports by Gary Fowler, June 20, 1979 {1, In) and November 26, 1979 (7).
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Exhibit 1.2 ORBES STATE SOLID FUEL ELECTRIC MWe NET CAPACITIES - CURRENT (1975), PLANNED (1985) AND CONJURED (2000)
Scenario
#2
#2n
#7
State
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
1975
Coal Nuclear Other Total
(#2) 10,512 1,865 1,582 13,959
10,114 -0- 1,037 11,151
10,948 -0- 1,054 12,002
17,034 -0- 2,067 19,101
9,691 -0- 473 10,164
11,966 -0- 608 12,574
70,265 1,865 6,821 78,951
1985
Coal Nuclear Other Total
(#2) 14,400 5,921 4,640 24,961
18.531 2,260 1,158 21,949
18,991 -0- 1,186 20,177
19,522 810 1,882 22,214
15,489 1,830 1,260 18,579
13,936 -0- 1,098 15,034
100,869 10,821 11,224 122,914
Coal
(#2) 20,492
25,959
26,579
27,362
22,037
19,366
141,795
(#2n) 20,492
25,959
26,579
27,362
22,037
19,366
141,795
(t7) 23,742
30,509
34,379
35,162
23,337
26,516
173,645
Nuclear
5,922
2,260
-0-
810
1,830
-0-
10,822
6,712
3,260
-0-
11,620
9,830
-0-
31,422
5,712
2,260
-0-
1,620
1,830
-0-
11,422
2000
Other
1,600
1,000
1,000
2,000
500
600
6,700
1,600
1,000
1,000
2,000
500
600
6,700
1,600
1,000
1,000
2,000
500
600
6,700
Total
28,014
29,219
27,579
30,172
24,367
19,966
159,317
28,804
30,219
27,579
40,982
32,367
19,966
179,917
31,054
33,769
35,379
38,782
25,667
27,116
191,767
Sources: Exhibit 1
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three years for coal, nuclear and other facilities. This permits the
calculation of gross additions to capacity from 1975-85 and 1985-00 by
state for each scenario (Exhibit 1.3). We have expressed these in terms
of "standard plant equivalents" for application to CONCEPT V runs
(Exhibit 1.4). The gross additions for coal are 35,100 MW or 54 plants
of 650 MW distributed as shown: seven plants to IL, fourteen each to
IN and KY, six to OH, nine to PA and four to WV. In addition, nine
nuclear power plants of 1,000 MW capacity are distributed to account for
the total 44,100 MW obtaining for ORB in all scenarios by 1985. The dis-
tributions for the Coal C66,300 MW), NERC (99,150 MW) and Nuclear Export
(87,300 NW) scenarios by state for the year 2000 are also shown, again
in terms of "standard equivalent plants." Fifth, an evaluation of nonfuel
operating and maintenance costs is performed, making use of the model
OMCOST (Cf. Appendix). Factor markets for OMCOST variables are assumed
to be approximately the same in each of the states. The sixth and last
step is left to be performed in the final ORBES report in which the busbar
costs generated in this study are input. This will assess the full and
more complex social costs and benefits incurred under the various scenarios.
A number of considerations are worth noting before proceeding in the next
section to the discussion of this study's comparisons of nuclear and coal.
The fuel cost calculations made available by Page in Exhibit 1.5 are
from Blome after modifications performed by Teknekron. They are shown in
Exhibit 1.5 in constant 1975 dollars of coal as if delivered to a centroid
in each state for all utilities. Page calculates these both per ton and
per million Btu, i.e., they represent an average blend of coals of various
grades with varying Btu content and other characteristics. However, they
are estimated to have a constant 1.2 percent sulfur content by weight.
Because the coal prices are not reported as a function of quantities
delivered by coal type (i.e., as inverse supply functions) there is no
way to account for any of the differential rises in real prices of coal
over time due to varying quantities drawn from the individual supply regions.
However estimated, any real price rise must be a function of depletion
net of technological change occurring in the coal fields as mining proceeds
over time. In reality the price in any given future year will be a func-
tion of cumulative as well as period demands, and the delivered price in
each state will be a function of an aggregate quantity supplied from
various individual supply districts. To estimate the least cost quantities
and determine the market clearing prices in simulation of the spatial
supply and demand equilibria which will occur in future years for all coal
types would require the solution of a very large transportation program.
Ideally the objective function to be maximized should be the net payoff to
both the producing and consuming industries represented in a given year
by the sum of the producers' and the consumers' surplus. However, the
prices of the Blome and Teknekron studies are point estimates assuming
determined aggregates and not the result of market cleaning calculations
involving supply and demand. While they are useful as an engineering
approximation, because they assume that the proportional allocations of
coal would be maintained for the periods of Exhibit 1.5 irrespective of
changes in demands or the different sitings of nuclear and coal plants,
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Exhibit 1.3
GROSS ADDITIONS TO PLANT 1975-85, AND 1985-2000 IN MWe IN THE ORBES
REGION BY STATE FOR SCENARIOS 2, 2n AND 7
Scenario
#2
#2n
#7
State
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
1975-1985
Coal Nuclear Total
4,399 4,056 8,455
8,951 2,260 11,211
8,880 -0- 8,880
3,927 810 4,737
6,134 1,830 7,964
2,552 -0- 2,552
34,843 8,956 43,799
Coal
9,723
12,700
12,550
13,000
9,100
9,100
66,173
9,723
12,700
12,550
13,000
9,100
9,100
66,173
12,973
17,250
20,350
20,800
10,400
16,250
98,023
1985-2000
Nuclear
-0-
-0-
-0-
-0-
-0-
-0-
-0-
1,000
1,000
-0-
10,810
8,000
-0-
20,810
-0-
-0-
-0-
810
. D
-0-
810
Total
9,723
12,700
12,550
13,000
9,100
9,100
66,173
10,723
13,700
12,550
23,810
17,100
9,100
86,983
12,973
17,250
20,350
21,860
10,400
16,250
98,833
Source: Exhibit 1
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Exhibit 1.4 STANDARD PLANT EQUIVALENT1 (SPE) SOLID FUEL GROSS ADDITIONS IN MWe IN THE CONCEPT
REGIONS BY STATE FOR SCENARIOS 2, 2n AND 7
Scenario
#2
#2n
#7
State
(CONCEPT Region)
Illinois (5)
Indiana (6)
Kentucky (6)
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
Illinois (5)
Indiana (6)
Kentucky (6 )
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
Illinois (5)
Indiana (6)
Kentucky (6)
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
1975-1985
Coal Nuclear
No. SPE Mwe No. SPE Mwe
7 4,550 4 4,000
14 9,100 2 2,000
14 9,100 0
6 3,900 1 1,000
9 5,850 2 2,000
4 2,600 0
54 35,100 9 9,000
44,100
1985-2000
Coal
No. SPE Mwe No
15
20
19
20
14
14
102
15
20
19
20
14
14
102
20
27
31
32
16
25
151
9,750
13,000
12,350
13,000
9,100
9,100
66,300
9,750
13,000
12,350
13,000
9,100
9,100
66,300
13,000
17,550
20,150
20,800
10,400
16,250
98,150
Nuclear
. SPE Mwe
0
0
0
0
0
0
0
1
1
0
11
8
0
21
0
0
0
1
0
0
1
__
66,300
1,000
1,000
11,000
8,000
21,000
87,300
__
1,000
1,000
99,150
SPE units of nuclear are 1,000 Mwe. SPE units of coal are 650 Mwe.
CONCEPT regions are Chicago (5), Cincinnati (6) and Pittsburgh (17)
Source: Exhibit 3.
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Exhibit 1.5
COAL PRICESa'b/C
($ per million btu)
State
IL
Year
IN
KY
OH
PA
WV
1976
1985
2000
.782
1.148
1.360
.652
1.371
1.543
.665
1.168
1.944
.918
1.185
1.547
.907
1.379
1.938
.911
1.196
1.99
,a,b,c
COAL PRICES
($ per ton)
State
IL
IN
KY
OH
PA
WV
Year
1976
1985
2000
16.42
25.54
29.97
14.17
32.25
34.62
14.59
26.80
45.79
19.85
28.44
37.13
21.69
33.10
46.51
21.45
28.70
47.76
SOURCE: Walter Page, ORBES Memorandum, December 6, 1979.
within +_ .05 per MBTU.
Table 1, rounded
a. Coal prices are based on three considerations: CD coal assignments
for Northern Appalachia, Central Appalachia, Southern Appalachia and Eastern
Interior provided by D. Blome to Teknekron Research, Inc., for use in con-
nection with Teknekron's USM model; (2) initial estimates of coal prices
based on Teknekron's use of ICF coal supply functions in the USM model; and
(3) adjustments to Teknekron's preliminary estimates of future supply region
prices in light of Page's work on the cost effects of resource depletion.
All prices reported are weighted averages (weighted by btu content of supplied
coal) as between the four supply regions serving the states as well as the
tonnage of cleaned and uncleaned coal. Scenario specifications determined
the relative tonnage of cleaned and uncleaned coal used in a specific state.
b. All prices are in terms of real 1975 dollars.
prices are reported.
In all cases, delivered
c. Cleaned coal is that produced by a level 4 cleaning plant (BOM definition)
Essentially this means a dense media separation to 28 mesh particulate size,
washed, and thermal dried.
d. Coal characteristics call for blends meeting 1.8% sulphur shipped, by weight.
10
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they ignore and underplay the role of inter-state competition in moderating
delivered coal prices. This may help to explain certain anomolies in results.
On the demand side, fuel prices were not considered by ORBES to be the
determining factor in their plant choices after 1985 when the ORBES
scenarios site nuclear and coal plants independently of competitive market
considerations. In defense of this simplified approach, one can say that
no better estimates of relative busbar costs would occur if an elaborate
optimization program had been attempted or if the potential supply func-
tions of individual regions were adopted from other studies, given the
state of the modeling art and information in seam reserves.
On the cost engineering side, the assumptions behind the nuclear fuel
cycle cost estimates are also frequently obscure in the literature whether
one resorts to government or to industry publications. The assumptions
employed here are based on the most current engineering estimates available.
The results can be compared with those of the recent authoritative studies
(Exhibit 1.6) . Estimates of Rossin and Rieck, Wash, Chapman, TRW and
Zebroski and Levenson are stated in 1975 dollar equivalents for comparison
purposes. The price of yellowcake is taken at $20.00 for 1975. This may
be fairly representive of long run average cost. It is closer to existing
contract average costs than to marginal cost because the United States
Geological Survey potential supply function is accepted and this is
relatively elastic. Real prices today are approximately at this level and
$20.00 is accepted for 1985. The price is permitted to double in real terms
over the subsequent fifteen years. To the extent this estimate is conser-
vative, the results of the study are biased toward nuclear. Section two
discusses the nuclear cycle calculations in detail.
In all the cost engineering exercises comparing nuclear and coal fired
power plants significantly higher capital investment is shown to be required
for nuclear plants than for coal. The associated fixed charges added to
this capital burden are also higher than coal. These costs cannot be off-
set by lower nuclear fuel costs alone for the next twenty-five years under
any set of realistic assumptions. If nuclear plants are shown competitive,
additional offsets must come, therefore, (i) from assumed site-specific ad-
vantages that eliminate transportation and transmission costs for nuclear
plants, (ii) by scale advantages, and by greater availability and loading
factors, or (iii) by the elimination of certain nuclear use charges to the
utility through the conventions of joint costing at various fuel cycle
steps, the assumption of tax subsidies, and so on. A very common offset
comes from assumed higher nuclear plant scales. Economies of scale are
very significant in both coal-fired and nuclear fueled plants. The
elasticity of busbar cost with respect to increases in scale assumed in the
Oak Ridge models comes out to be about .6 for both types of plant between
the scales of 650 and 1,000 MW. In the typical (Pittsburgh) case, CONCEPT
V shows the 1975 dollar cost of coal plant per kw falls from $861 to $741
for an increase in scale from 650 to 1,000 MW. The decline is from $1,208
to $963 per lew for nuclear plants over the same range. On the other hand,
any stretch-out of nuclear plant construction time, rise in the interest
rate, fall in rated capacity or availability, decrease in debt ratio,
decrease in corporate income tax or increase in ad valorem tax will work
11
-------
Exhibit 1.6 VARIOUS NUCLEAR FUEL CYCLE STUDY ASSUMPTIONS
(1985 price in 1975 $)
Study
(Date)
Rossin/Rieck (1)
(1978)
Wash 1174-74 (2)
(1974)
Chapman, et. al. (3)
(1980)
TRW (4)
(1976)
E. Zebroski & (5)
M. Levenson
(1976)
Time Period
of Interest
late 80' s
1982
1980-2017
1980-2005
1984-1985
Yellowcake
Price ($/U308)
35.90
14.25
35.60
scenario
dependent
25.00
Conversion Cost
S/kg. U
5.45
3.60
3.40
3.30
4.00
Cost of Separative
Work Unit $/kg. SWU
67.30
82.20
72.60
100.00
100.00
Fabrication Costs
$/kg. U
98.70
76.70
76.85
100.00
116.60
Back-end1
Costs $/kg. U
250
25
265
125
150
'Assume no reprocessing occurs. Projected costs not adjusted to 1975 $ because of the extreme uncertainty associated with this
activity.
-------
against the nuclear plant more heavily than the coal-fired plant. This is
due both to the higher scales assumed and to the greater nuclear capital
intensity at given scales. In the CONCEPT V cost functions this inten-
sity disadvantage adds 25% to 33% to nuclear costs when construction
times are stretched to double coal plant times for equivalent scale.
However, the CONCEPT V program neglects many site-specific construction
advantages obtaining for typical coal-fired plants, and to this extent
the intensity disadvantages are somewhat modified.
The comparisons of Table 2.6 below confirm that differential local
construction costs are probably not significant in the ORB. Certainly
they are not large relative to the scale and intensity effects discussed
above. The cost of construction stretch-out is very high. For nuclear
construction, raising this from 5 to 10 years raises the cost of a
1,000 MW nuclear plant from $963 million to $1,560 million! Assuming
that 1985 prices are double 1975, the comparison between a coal design
completed in six years to a nuclear design taking eleven years would
leave the coal plant cheaper by $1,632 per kw, or nearly half the cost
of nuclear per unit. These capital aspects of cost comparisons dominate
the discussion of technical choices in current utility planning and in
the comparisons that follow.
13
-------
SECTION 4
METHODS USED TO COMPUTE CAPITAL REQUIREMENTS AND BUSBAR COSTS
Capital Requirements
Two sorts of data are needed to compute capital requirements by state
for the three scenarios. These are: (.1) the projected number of plants
by state for each scenario, and (2) the construction cost of plants by
state.
The number of plants required is computed from Tables 1 & 3,
Electric Generating Unit Inventory, 1976-1986, Steven 0. Larsen, Energy
Resources Center, University of Illinois at Chicago Circle, No. 1978,
and Supplementary Reports by Gary Fowler, June 20, 1969 (2, 2n) and
November 26, 1979 C7). For the capital requirements calculations plant
sizes are taken at 650 mwe for coal and 1,000 mwe for nuclear.
The construction costs of plant by state are arrived at by using
CONCEPT-V, a cost model developed by the Oak Ridge National Laboratory.
The CONCEPT computer code package has the capability of simulating
hypothetical capital cost estimates for various types of nuclear-fueled
and fossil-fired power plants as a function of a large number of para-
meters, including regional and site specific factors.
The parameter values used in this task and associated capital costs
are shown in Exhibit 2.1. As shown, the coal plant examined is a "stand
alone plant," using a cross-compound turbine and containing a scrubber.
The nuclear unit is a PWR stand alone plant.
The capital requirements for the three scenarios are shown in
Exhibit 2.2. The CONCEPT program provides capital cost variations due
to geographic factors for 22 cities in the U.S. and Canada. In this
study three CONCEPT regions are employed representative of the Chicago,
Cincinnati, and Pittsburgh areas. Chicago is taken to be representative
of Illinois; Cincinnati is assumed to represent Pennsylvania and West
Virginia. (Note that the variation among these CONCEPT locations does
not exceed 2%.)
All the methods used to compute busbar costs for 1985 and 2000 are
straightforward. These costs are divided conventionally into the
principal components of busbar costs: capital costs, operations and
maintenance costs, fuel costs, and fuel inventory carrying costs. Task
results are shown in Exhibit 2.3.
14
-------
Exhibit 2.1 CAPITAL COSTS FOR COAL AND NUCLEAR PLANTS AS A FUNCTION OF VARIOUS INPUT PARAMETERS
Location
(CONCEPT Region)
Pittsburgh (17)
Cincinnati (6)
Chicago (5)
Pittsburgh (17)
Cincinnati (6)
Chicago (5 )
Pittsburgh (17)
Pittsburgh U7)
Cincinnati (6)
Chicago (5 1
Pittsburgh (.17)
Plant
Size
650 mwe
650 law.
e
650 mwe
1,000 mwe
1,000 mwe
1,000 mwe
1,000 mwe
1,000 mwe
1,000 mwe
1,000 mwe
1,000 mwe
Steam Supply
System
Type Purchase (Yr.)
Coal1
Coal
Coal
Coal
Coal
Coal
Coal
Nuclear2
Nuclear
Nuclear
Coal
1
1
1
1
1
1
1
1
1
1
1
Construction
Permit
(Yr.)
2
2
2
2
2
2
2
2
2
2
2
Commercial
Operation
(Yr.)
7
7
7
7
7
7
7
7
7
7
7
Total Capital
Cost
106 1975 $
561.181
569.301
562.919
741.244
753.260
744.634
1,199.161
963.266
981.985
963.121
1,560.182
Capital
Cost per kw
1975 $
861.8
875.8
866.0
741.2
753.3
744.6
1,199.2
963.3
982.0
963.1
1,560.2
Coal-fired with SO,, removal system; using cross-compount turbine; single unit (stand alone plant)
Pressurized-water reactor; single unit (stand-alone plant)
-------
Exhibit 2.2
CAPITAL REQUIREMENTS BY STATE FOR THE TIME PERIODS 1975-1985 AND 1985-2000 FOR SCENARIOS 2, 2n, AND 7
in constant (1975) dollars (000)
1975-1985
COAL
Scenario
#2
#2n
#7
State
(CONCEPT Region)
Illinois (5)
Indiana (6)
Kentucky (6)
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
Illinois (5)
Indiana (6)
Kentucky (6)
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
Illinois (5)
Indiana (6)
Kentucky (6)
Ohio (6)
Pennsylvania (17)
West Virginia (17)
Subtotal
TOTAL
ftSPE
7
14
14
6
9
4
54
7
14
14
6
9
4
54
7
14
14
6
9
4
54
Capital
Requirements
(103 1975 $)
3,940,433
7,970,214
7,970,214
3,415,806
5,041,629
2,240,724
30,579,020
3,940,433
7,970,214
7,970,214
3,415,806
5,041,629
2,240,724
30,579,020
3,940,433
7,970,214
7,970,214
3,415,806
5,041,629
2,240,724
30,579,020
#SPE
4
2
0
1
2
0
9
39,303,991
4
2
0
1
2
0
9
39,303,991
4
2
0
1
2
0
9
39,303,991
NUCLEAR
Capital
Requirements
(103 1975 $)
3,852,484
1,963,970
981,985
1,926,532
8,724,971
3,852,484
1,963,970
981,985
1,926,532
8,724,971
3,852,484
1,963,970
981,985
1,926,532
8,724,971
1985-2000
COAL
ttSPE
15
20
19
20
14
14
102
15
20
19
20
14
14
102
20
27
31
32
16
25
151
Capital
Requirements
(103 1975 $)
8,443,785
11,386,020
10,816,719
11,386,020
7,842,534
7,842,612
57,717,612
8,443,785
11,386,020
10,816,719
11,386,020
7,842,534
7,842,534
57,717,612
11,258,380
15,371,127
17,648,331
18,217,632
8,962,896
14,004,525
85,462,891
#SPE
0
0
0
0
0
0
57,717,612
1
1
0
11
8
0
21
78,320,612
0
0
0
1
0
0
1
86,444,876
NUCLEAR
Capital
Requirements
(103 1975 S)
__
963,121
981,985
10,801,835
7,855,880
20,602,821
981,985
981,985
-------
Fuel Inventory Carrying Charges
A specified amount of fuel inventory is treated as a capital cost
because the inventory is maintained over the life of the plant and thus
actually represents a capital investment. For the coal plant a 90-day
inventory is assumed. For the nuclear plant the inventory is the material
that the utility owns everywhere in the fuel cycle. This depends on when
purchases are made in relation to a specific core refueling. For this
study we assume the following lead times:
Fuel Cycle Activity Lead Time
Uranium Ore 3
Conversion 3
Enrichment 2
Fabrication 1
The busbar cost component of the fuel inventory is arrived at in a
similar manner as for the plant. The difference is that the fixed charge
rate is non-depreciating and insurance costs are zero. The non-depreciat-
ing fixed charge rate employed in this task is shown in section 2.1.
17
-------
Exhibit 2.3 BUSBAR COSTS IN MILLS/KWH (1975 $) BY STATE FOR 1985 AND 20001'2
State
(CONCEPT Region)
Busbar Costs
Capital*
O S M
Fuel
Fuel Inventory
carrying chg.
TOTAL
State
(CONCEPT Region)
Busbar Costs
Capital*
O S M
Fuel
Fuel Inventory
carrying chg.
TOTAL
Illinois (5)
Coal1 Nuclear2
34.4
3.7
11.3
.6
50.0
38.3
2.5
6.3
2.5
49.6
Illinois (5)
Coal Nuclear
34.4
3.7
13.0
.7
51.8
38.3
2.5
9.2
4.1
54.1
Indiana (6)
Coal Nuclear
34.8 39.0
3.7 2.5
13.0 6.3
.7 2.5
52.2 50.3
Indiana (6)
Coal Nuclear
34.8 39.0
3.7 2.5
14.8 9.2
.8 4.1
54.1 54.8
1985
Kentucky (6)
Coal Nuclear
34.8
3.7
11.3
.6
50.4
2000
39.0
2.5
6.3
2.5
50.3
Kentucky (6)
Coal Nuclear
34.8
3.7
18.6
1.0
58.1
39.0
2.5
9.2
4.1
54.8
Ohio
Coal
34.8
3.7
11.3
.6
50.4
Ohio
Coal
34.8
3.7
14.8
.8
54.1
(6)
Nuclear
39.0
2.5
6.3
2.5
50.3
(6)
Nuclear
39.0
2.5
9.2
4.1
54.8
Pennsylvania ( 17 )
Coal Nuclear
34.2
3.7
13.0
.7
51.6
38.3
2.5
6.3
2.5
49.6
Pennsylvania ( 17 )
Coal Nuclear
34.2
3.7
18.6
1.0
57.5
38.3
2.5
9.2
4.1
54.1
West Virginia (17)
Coal Nuclear
34.2
3.7
11.3
.6
49.8
38.3
2.5
6.3
2.5
49.6
West Virginia (17)
Coal Nuclear
34.2
3.7
18.6
1.0
57.5
38.3
2.5
9.2
4.1
54.1
*Coal Plant Size: 650 mwe ( 5 year construction period)
^Nuclear Plant Size: 1,000 mwe (5 year construction period)
-------
Capital Costs
The formula employed for computing the capital cost component of
busbar costs is as follows:
(Capital Cost in $) (1,000 mills)(Fixed Charge Rate)
(Plant Size in kw)(1*)(8,760 hrs.)(Plant Factor)
The capital costs used are those shown in Exhibit 2.1. The task
results are given for the 650 mwe coal unit and the 1,000 mwe PWR both
assumed to have 5-year construction periods. A plant factor of .6 is
assumed for both generating units. Calculations for different assumptions
as to plant size for coal and construction period for nuclear were also
made and will be discussed below.
The fixed charge rate is expressed as a percentage of the original
capital investment and when multiplied by that investment gives a yearly
levelized revenue requirement which will recoup all the costs associated
with the capital investment. This revenue requirement is then allocated
to the projected kwh's to be produced from the plant during the year.
Following are the fixed charge rates and underlying assumptions employed
in this task.
Fixed Charge Rates (%)
Non-Depreciating
Depreciating (for fuel inventory)
Weighted Average Cost of
Capital1 14.0 14.0
Sinking Fund Depreciation2 .28
Federal, State S Local Taxes3 5.6 7.1
Insurance 1.0
20.88 21.1
Debt ratio = .5; debt cost = 13.0; common equity ratio = .5;
common equity cost = 15.0.
Economic life of 30 years assumed for both plants.
Federal tax rate = .48; state and local taxes = 1.5. Taxes
expressed as a ratio of equivalent annual income taxes to
first cost of plant.
Nuclear liability insurance contained in the operatives and
maintenance component of busbar costs.
In our capital cost computation we have chosen to ignore tax prefer-
ences, i.e., accelerated depreciation for tax purposes and the investment
tax credit. In the first place these are often neglected in an analysis
19
-------
of investments to be made very far in the future because of their history
of frequent changes. For the ORBES research, as observed by Chapman, they
constitute tax subsidies which bias economic studies toward nuclear plants
because they are capital intensive. Their impact is measured by Chapman's
Report. *
All of the components of the fixed charge rate vary spatially and/or
temporally. For example, state and local taxes can vary widely from
utility to utility. Additionally tax preference allowances, such as
accelerated depreciation and the investment tax credit have varied over
time. On top of that different accounting methods are used with tax
preference allowances depending on the desires of the regulatory body.
The cost of debt and equity and a utility's capital structure vary over
time.
The "bottom line" result is bothersome because fixed charge rates
used in economy studies vary widely depending on the underlying assump-
tions employed. Unfortunately the busbar cost of electricity is fairly
sensitive to such changes in the fixed charge rate. This sensitivity in
CONCEPT-V can be seen in Figure 1. For a 1,000 mwe PWR plant, built in
Pittsburgh or Chicago, a change in the fixed charge rate of one percentage
point changes the busbar cost component about two mills. This is approxi-
mately equal to the total operating and maintenance (O & M) cost. A four
percentage point difference in the fixed charge rate produces a change
approximately equal to the total of fuel and 0 & M costs.
Figures 1 and 2 show the capital cost component of busbar costs as
a function of the fixed charge rate for all plants listed in Table 2.1.
Not all plants are graphically depicted, but multiplicative ratios which
can be applied against specified base plants are shown. Also shown along
the horizontal axis in Figure 1 is a range which encompasses fixed charge
rates used in the studies referenced in the bibliography.
Operations and Maintenance Costs
Nonfuel operations and maintenance costs were obtained using
ONCOST, a computer program designed by the Office of Energy Systems
Analysis, Division of Reactor Research and Development, U. S. Energy
Research and Development Administration. OMCOST was "designed to assist
in examining average trends in costs, in determining sensitivity to
technical and economic factors, and in providing cost projections."
The program accepts 26 input data variables related to the generating
unit itself, characteristics of oil or coal if the plant uses these fuels,
and various escalation rates. Plant parameters include plant type (e.g.,
coal or PWR or BWR etc.), type of heat sink, plant capacity factor, net
electrical output, and the number of units per station. Fuel characteris-
tics input to the program include heating value and sulfur content.
The program costs are indexed to 1975, but the program accepts various
escalation rates to the year of initial operation. Escalation rates are
20
-------
FIGURE I-CAPITAL COST COMPONENT OF BUSBAR COSTS
(IOOOMW PWR)
45
40
35
30
BUSBAR
COSTS,
MILLS/KWH
25
20
15
^PITTSBURGH/CHICAGO
(5-YR.CONSTRUCTION CYCLE)
Cincinnati = (/.OI9)(Pittsburgh/Chicogo)
(AM 5 Yr. Construction Cycle)
0 = (/.6l97)(Pittsburgh/Chicogo)
(10 Yr. Construction Period)
10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25
FIXED CHARGE RATE-%
21
-------
FIGURE 2-CAPITAL COST COMPONENT OF
BUSBAR COSTS
(COAL)
45
40
35
-
-
!
_
Location
Cincinnati
Chicago
Cincinnati
Chicago
Pittsburgh
Size
MW
1000
1000
650
650
1000
Construction
Period
5
5
5
5
10
Ratio to
Pittsburgh cost
1.0162
1.0046
1.0163
1.0049
1.6178
same
size
30
BUSBAR
COSTS
25
20
15
650 MW
Pittsburgh
(Syr.) Construction
1000 MW Pittsburgh
(5yr. Construction)
10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25
Fixed Charge Rate (%)
22
-------
specified for eight parameters. These include materials, wages, sludge
disposal, limestone, nuclear liability insurance, operating fees, and fuel
oil. We assume a 4.0% per year real escalation on all of these factors to
1985, but assume that they then remain constant to the year 2000. 0 & M
costs shown in Exhibit 2.3 are also in 1975 dollars.
Fuel Costs
Coal
Coal prices used in this task are shown below:
Delivered Coal Prices ($ per million btu, 1975 $)
Year Illinois Indiana Kentucky Ohio Pennsylvania West Virginia
1976 .78 .66 .66 .91 .91 .91
1985 1.19 1.37 1.19 1.19 1.37 1.19
2000 1.37 1.55 1.55 1.15 1.95 1.95
The coal cost component of busbar costs is then computed as follows:
($/MMBTU) (1,000 mills/$) (341?PTU) (i-)
KWn y
where, y is the efficiency of the coal plant.
For the 650 mwe coal unit used in this study y = .3585 as specified in the
CONCEPT-V program.
To obtain an idea of the sensitivity of the busbar cost to the fuel
price, the busbar cost is computed as a function of the delivered fuel
price. This computation is graphically depicted in Figure 3. The CONCEPT-
V efficiency for the 1,000 mwe coal plant is also used to compute the bus-
bar cost as a function of price. Also plotted is the case for y = .33.
This last value is a rough approximation of the average value of all coal
plants currently on line.
Nuclear Fuel Cycle
Nuclear fuel cycle cost assumptions for 1985 and 2000 are shown below
in Exhibit 2.4.
23
-------
FIGURE 3- FUEL COST COMPONENT OF BUSBAR COSTS
(COAL)
30-
BUSBAR
COST ,
MILLS/KWH
650 MW; Y =0.3535
1000 MW; Y=0.37I5
0.50 1.00 1.50 2.00 2.50
DELIVERED FUEL PRICE, $/IC6Btu; 1975$
24
-------
Exhibit 2.4 NUCLEAR FUEL CYCLE COST ASSUMPTIONS (1975 $)
Fuel Cycle
Activity
1985
2000
Ore $/lb. U,0g
Conversion $/kg. U
Enrichment $/kg. SWU
Fabrication $/kg. U
Storage and Disposal Fees"
($Ag. U)
20
4
100
100
265
40
4
150
100
265
To translate these costs into a cost per kwh requires only that the
amount consumed per year be known. These quantities are calculated for
a plant at equilibrium in order to bypass the variations associated with
the first and last cores. The equilibrium annual quantities for three
enrichment tails assay's are shown in Exhibit 2.5. Also shown on Exhibit
2.5 are more detailed assumptions about the 1,000 mwe PWR.
It should be noted that the burn-up figure shown is an average for
PWR's. However, it is in fact inconsistent with the assumed plant factor
and refueling schedule assumptions. Fuel cycle optimization involves a
complex interplay of a number of different factors which produce cost
minimizing batch sizes, enrichments, cycle times, in-core loading patterns
and fuel designs. Such factors include costs of back up power, unexpected
outages, and load changes to name a few. For this task we make an
assumption which reflects actual operating experience in the industry,
viz., that 1/3 of the core is replaced annually.
In Exhibit 2.5 equilibrium quantities are shown as a function of the
enrichment tails assay. The optimum tails assay can be determined by the
ratio of feed cost to the cost of separative work. This relationship is
shown in Figure 4. Thus for this task equilibrium quantities are used for
a 0.30% tails assay in 1985 and for 0.20% in 2000.
As we have done for the other components of busbar cost, we show the
busbar cost as a function of the cost of all the nuclear fuel cycle activi-
ties. These are shown in Figures 5-9. These graphs are specific to the
equilibrium quantities shown in Exhibit 2.5. All costs are in 1975 dollars.
Nuclear fuel cycle cost assumptions also vary widely among study groups.
The assumptions associated with some recent studies are shown in Exhibit
1.6. The assumptions were taken to 1985 for reference purposes and are
shown in 1975 dollars.
25
-------
Exhibit 2.5 EQUILIBRIUM ANNUAL QUANTITIES REQUIRED FOR THE NUCLEAR FUEL CYCLE AS A FUNCTION OF ENRICHMENT TAILS .ASSAY
to
cn
Fuel Cycle Equilibrium Annual Quantities
Activity Enrichment Tails Assay = 0.20%
Yellowcake (U308)
Conversion
Enrichment
Fabrication
Storage and Disposal
433,623
167,136
126,096
33,447
33,447
Ibs.
kg. U
kg. SWU
kg. U
kg. U
Equilibrium Annual Quantities
Enrichment Tails Assay = 0.25%
470,309
282,384
111,044
33,447
33,447
Ibs.
kh. U
kg. SWU
kg. U
kg. U
Equilibrium Annual Quantitites
Enrichment Tails Assay = 0.30%
517,167
199,344
99,672
33,447
33,447
Ibs.
kg.
kg.
kg.
kg.
U
SWU
U
U
Nuclear Plant Assumptions
1,000 mwe PWR
P.F. = .6
3 region core: refueled annually (1/3 of core)
core loading: 100,341 kg. U
fuel enrichment: 2.75%
burnup: 33,000 megawatt-days per ton
-------
FIGURE 4.- OPTIMUM TAILS COMPOSITION (NUCLEAR)
.7
.6 -
.5 -
.4 -
OPTIMUM
TAILS
COMPOSITION
WT. (%) -3
.2 -
CECO
I
I I I I
I I I I
0.0 O.I 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 I.I 1.2 1.3 1.4 1.5
Ratio of Feed Cost to Cost of Separate Work
27
Source" Nuclear Power Plant Design
Analysis, Alexander Sesonske
1973, USAEC, NTIS-TID- 26241
-------
FIGURE 5-YELLOWCAKE COMPONENT OF BUSBAR COSTS
(NUCLEAR)
10
9
8
7
6
BUSBAR
COSTS, 5
MILLS/KWH
4
3
2
I
0
^0.20% TAILS ASSAY
0.30%TAILS ASSAY
-025% TAILS ASSAY
10 20 30 40 50 60 70 80 90 100
MINING AND MILLING, $/LB. U308
FIGURE 6- CONVERSION-TO-UFg COMPONENT OF BUSBAR COSTS
(NUCLEAR)
.50
.40
BUSBAR .30
COSTS,
MILLS/KWH20
.10
0.30% TAILS ASSAY
0.20% TAILS ASSAY
0.25%TAILS ASSAY
234 56789
CON VERSION TO UF , $/KG. U
28
10
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FIGURE 7. SWU COST COMPONENT OF BUSBAR COSTS (NUCLEAR)
10.0
9.0
8.0
7.0
BUSBAR 6'°
COST
(MILLS/KWH) 5-°
4.0
3.0
2.0
1.0
0.20% Tails
0.25%
f Tails Assay
0.30% Tails Assay
1.00
0.90
0.80
0.70
BUSBAR °'60
COST
(MILLS/KWH; 0.50
0.40
0.30
0.20
0.10
50 100 150
Cost of Separative Work, $ / Unit
FIGURE 8. FABRICATION COST
(NUCLEAR)
200
250
i i i i
I
50 100 150 200
Fabrication Cost ($/Kg. U.)
29
250
-------
FIGURE 9- SPENT FUEL SHIPPING AND WASTE MANAGEMENT
COMPONENT OF BUSBAR COSTS (NUCLEAR)
30
20
BUSBAR COST,
(MILLS/KWH)
10
100 200 300 400
SPENT FUEL SHIPPING AND WASTE MANAGEMENT-$/Kg.U
30
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APPENDIX
This report presents two formulations of cash flow models for the
assessment of capital and operating costs of individual utilities supply-
ing energy to the ORB region under alternative assumptions. The models
provide the computational means of analyzing the impacts on costs of
varying parameters specific to sites, the scales of activity, the move-
ment of subordinate cash flows (wages, taxes), and so on. The work draws
heavily on past and on-going studies at West Virginia University (WVU)
in the College of Mineral and Energy Resources (COMER) and Engineering
(COE) on the siting of such facilities.
The cash-flow models represent facilities for low and high sulfur
coal-based conventional steam generated electric power, with and without
stack gas desulfurization equipment (scrubbers), for light-water nuclear
reactors and heavy-water nuclear reactors.
The basic model is CONCEPT-V which compares nuclear with conventional
power generation using coal directly made available by Argonne National
Laboratories. The schema for CONCEPT-V is shown in Exhibit Al. Lists
of major variables are given in Exhibits A2 to A4.
Plant costs are separated into individual components, appropriate
cost indexes applied and the adjusted components summed. Three sets of
cost indexes as functions of time and location are used to adjust the costs
of equipment, labor, and materials respectively. The equipment cost indexes
are calculated from basic parameters. These include wage rates for the
various crafts, labor productivity, and overtime considerations. The
materials cost indexes are calculated from unit costs for site-related
materials. These include structural steel, reinforcing steel, concrete
and lumber. A very detailed breakdown is made of the labor and materials
categories.
Historical cost data for craft labor and site-related materials are
stored for 22 areas in the LAMA data file by a CONLAM auxiliary program.
These data consist of construction labor rates and materials costs that
are reported monthly in Engineering News-Record. It is possible to enter
cost data for other locations if data are available.
The labor cost data consist of hourly rates (including union-
negotiated fringe benefits, but not including employers' contributions
for social security and workmen's compensation insurance) for 16 classifi-
cations of craft labor. The materials cost data consist of market quota-
tions for seven classifications of materials. The present data set
includes 15 years of historical cost data taken from Engineering News-
31
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Record, beginning with 1961 and ending with 1975. The file has space
allocated for 30 time entries and several hundred locations.
The model for assessing non-fuel operating costs is OMCOST, and
can be used independently or in combination with CONCEPT-V. A list of
major OMCOST variables is given in Exhibit A5.
32
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PREOPERATIONAL LEVEL
LABOR AND
MATERIALS
COST DATA
FILE (LAMA)
OPERATIONAL LEVEL
Exhibit Al. The CONCEPT Package
33
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Exhibit A2
CONCEPT Variable List
MWE
TYPE
LOG
YRSSS
YRPER
YRCOP
RIB
AA(I,J)
The net capacity of the desired unit in MWe.
Type of power plant.
The city where the plant is to be located.
Date steam supply system is purchased.
Date construction permit is issued.
Date of initial commercial operation.
Average annual interest rate for interest during
construction, %. (If not input, 7%/yr. will be
used) .
Scaling coefficients for adjusting the direct and
indirect costs as a function of size according
to the relation
APC(I)?
BPC(I)J
COB(I)?
COS(I))
CONTL(I) }
CONTM(I) |
CONTE(I)-'
DEOT(I)
OTP(I)
OVERS (I)
j
FACS1(I,J)]
FACS2(I,J) Y
FACS3(I,JK
FILS (J) 7
ISITE(J) J
RINT(J)
for each two-digit account.
(I = 1,3 determines the a. & J = 1,11 defines
the account)
Productivity indices for each two-digit direct and
indirect cost account. (I = 1,11).
Contractor's overhead burden factor for each two-
digit direct and indirect cost account in the
base model (COB) and the specific case (COS) .
(I = 1,11).
Contigency percentage for labor, material, and factor
equipment, respectively, for each two-digit direct
and indirect cost account. (I = 1,11) .
Labor efficiency coefficient, overtime payment premium,
and labor efficiency factor, respectively, for each
two-digit direct and indirect cost account.
(I = 1,11).
Weighting factors for labor, material, and equipment,
respectively, for each two-digit direct and in-
direct account (j = 1,11). The first dimension,
I, correlates a weighting factor to a specific
labor, material, or equipment index in the CONLAM
file.
Weighting factor and site location number for up to
twenty locations to be combined in a composite
site. (J = 1,20) .
Interest rate expressed as a decimal number for each
of the fifty time periods between the steam supply
date and commercial operation date. (J = 1,50).
(continued)
34
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Exhibit A2 (continued)
YFIRST I The first and last dates to be considered in per-
YLAST J forming a linear regression on the historical
equipment, labor, and material file.
HWI (J) '/ The number of hours worked per week for each two-
HW j digit direct and indirect cost account (J = 1,11) ,
or, alternately, the number of hours worked per
week in all the accounts.
FACE(I,J) An escalation factor for equipment, labor, and
material (I = 1,3) in each of the two-digit
direct and indirect cost account. (J = 1,11).
AMAN The direct labor man-hours per kilowatt for the
specific case being run.
CFCA(I,J) Cash flow date for each two-digit direct and indirect
cost account (I = 2,12) in each of the fifty time
periods between the steam supply date and commer-
cial operation date. (J = 1,50).
D(I,J) Lowest-digit account direct and indirect costs
divided into equipment, labor, and material
(I = 1,3) for a given account. (J = 1,350).
35
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Exhibit A3
CONLAM Variable List
NOPER Number of actual data points stored on file,
less than or equal to MAXREC.
MAXREC Maximum number of time periods on file for each
location, not to exceed 30.
NCITY Number of locations on file, presently 24.
E(l) Hourly rate for building labor.
E(2) Hourly rate for heavy construction.
E(3) Hourly rate for bricklayers.
E(4) Hourly rate for carpenters.
E(5) Hourly rate for structural ironworkers.
E(6) Hourly rate for plasters.
E(7) Hourly rate for electrical workers.
E(8) Hourly rate for steamfitters.
E(9) Hourly rate for operating engineers.
E(10) Hourly rate for small tractor operators.
E(ll) Hourly rate for scrapper operators.
E(12) Hourly rate for crane operators.
E(13) Hourly rate for air compressor operators.
E(14) Hourly rate for truck drivers. (<4 yd3).
E(15) Hourly rate for boilermakers.
E(16) Hourly rate for all other crafts.
F(l) Material costs for channels. $/100 Ib.
F(2) Material costs for I-beams. $/100 Ib.
F(3) Material costs for W-flanges. $/100 Ib.
F(4) Material costs for re-bars. $/100 Ib.
F(5) Material costs for 3000-psi Redimix concrete.
$/yd3.
F(6) Material costs for 3/4-in. B-B plyform.
$/1000 ft2.
F(7) Material costs for 2x4 fir or pine lumber.
$/1000 bd. ft.
F(8) Cost for land, $.
36
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Exhibit A4
CONTAC Variable List
TYPE Plant type.
BWE Plant capacity, MWe.
YBC Year of reference case costs.
PO Fraction of time expended up to date of construc-
tion permit.
MHT Total craft labor in thousands of man-hours for
direct cost accounts for reference plant.
MHP(l) Craft labor in thousands of man-hours for each
direct cost account. (I = 1,7).
AEB(l) Coefficient used for factory equipment rate.
(I = 1,7).
AMB(l) Coefficient used for site-related materials rate.
(I = 1,7).
ALB(l) Coefficient used for craft wage rate. (I = 1,7)
AI(J) Constants for equation describing indirect cost
curves.
AA(J) Constants for equation describing direct costs,
minus contigency and spare parts, for two-
digit accounts.
D(J,I) Array containing direct costs at lowest-level
accounts (J = 1,3).
CFCA(J,I) Array containing cash flow curves for each direct
cost account. (J = 1,8 & I = 1,50).
FACS1(J,I) Weighting factors for site labor. (J = 1,7 &
I = 1,16).
FACLAB(J,I) Labor categories. (J = 1,2 & I = 1,16).
FACS2(J,I) Weighting factors for site material. (J = 1,7 &
I = 1,16).
FACMAT(J,I) Material categories (J = 1,2 & I = 1,16).
37
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Exhibit A5
Major OMCOST Variables
Variable
YEAR
TYPE
SINK
PLTFAC
MWT
MWN
ISOX
UNITS
WAGERT
FRINGE
nuclear
Definition
Yr. of operation
Plant type
PWR = pressurized water
reactor
BWR = boiling water
reactor
HTGR = high-temperature
gas-cooled reactor
LMFBR = liquid metal-cooled
fast breeder reactor-
COAL
OIL
GAS
Type of heat sink
NET = natural-draft evaporative
cooling tower
MET = mechanical=draft evapora-
tive cooling tower
RUN = once-through or run-of-
river cooling
Plant capacity factor
= Kwh generated/yr.
rated capacity in Kw x 8760 hr/yr.
Base load = 0.7, midrange = 0.4,
peaking = 0.15
Thermal input to plant (single unit),
MW can be calculated by = 100 x
MWN/nnet. nnet stored in the
program is shown in Table 5.1,
p. 35
Net plant electrical output (single
unit), MW present industrial ave =
-600, by 1980-85: ~1000
= 1, SO2 removal specified
= 0, SO- removal not specified
No. of units per station, (can be 1,
2, 3, 4) 1975
Wage rate before adders (base yr),
$/hr ($4.50 ~ $7.50?)
Operator fringe benefits as % of
wage rate (30 ~ 35%?)
Default
1975
PWR
NET
0.80
3092
1000
0
1
5.75
5.75
(continued)
38
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Exhibit A5 (continued)
Variable
Definition
Default
SUPER
BTUCOL
BTUBBL
XLIMS
PCTS
PCTSUL
SLURRY
COSLM
ESWAGE
ESOIL
ESSLUR
ESLIME
ESCINS
ESGINS
ESFEES
ESMATL
Pjant supervision as % of wages +
fringe benefits (10 ~ 15%?) 30
Heating value of coal, Btu/lb. 11,000
Heating value of oil, million
Btu/barrel 6.2
Tons of limestone per ton of
sulfur 4
Sulfur in oil, % 2.5
Sulfur in coal, % 3.5
Cost of sludge disposal (base yr),
$/ton 5.
Cost of limestone (base yr), $/ton 5
Escalation rate on wages, %/yr. 7
Escalation rate on cost of fuel oil,
%/yr. 10
Escalation rate on cost of sludge
di spo sa1, %/yr. 6
Escalation rate on cost of limestone,
%/yr. 6
Escalation rate on cost of commerical
liability insurance 5
Escalation rate on cost of govern-
ment liability insurance 5
Escalation rate on cost of operating
fees 3
Escalation rate on cost of materials
and supplies (expenses) 6
39
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REFERENCES
1. Hudson, C. R. II. CONCEPT-5 Users Manual. Oak Ridge National
Laboratory. Springfield, VA: National Technical Information
Service, January, 1979.
2. Rudasill, C. L. "Revenue Requirements for Utility System Analysis."
In Proceedings of Engineering Economic Analysis Workshop.
Mitre Technical Report 7611. McLean, VA: The Mitre Corporation,
August, 1977. p. 139.
3. Chapman, Duane, Kathleen Cole and Michael Scott. Energy Production
and Residential Heating; Taxation, Subsidies, and Comparative
Costs. Prepared for Ohio River Basin Energy Study, EPA.
Ithaca, NY: Cornell University, March, 1980.
4. Office of Energy Systems Analysis, U. S. Energy Research and Develop-
ment Administration. A Procedure for Estimating Nonfuel Operat-
ing and Maintenance Costs for Large Steam-Electric Power Plants.
Springfield, VA: National Technical Information Service,
October, 1975.
5. The Bureau of National Affairs. "DOE Says Administration Opposes
State Veto Powers Over Waste Sites." Energy Users Report,
No. 286, February 1, 1979. p. 9.
6. Sesonske, Alexander. Nuclear Power Plant Design Analysis, TID 26241.
Springfield, VA: National Technical Information Service,
January, 1979.
7. Rossin, A. D. and T. A. Rieck. "The Economics of Nuclear Power."
Science, Vol. 201, August 18, 1978. p. 582.
8. U.S. Energy Research and Development Administration. The Nuclear
Industry, 1974. WASH 1174-74. Washington, DC: U.S. Government
Printing Office, 1974.
9. TRW, Energy Systems Planning Division. "Electric Utilities Study An
Assessment of New Technologies from A Utility Viewpoint."
Prepared for the Office of Technical Assessment, Office of
Planning and Analysis, Energy Research and Development Adminis-
tration. McLean, VA: November 30, 1976.
10. Zebroski, E. and M. Levenson. "The Nuclear Fuel Cycle." In Annual
Review of Energy, Vol. 1. Palo Alto, CA: Annual Review, 1976.
40
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