ORDES
ENERGY PRODUCTION AND RESIDENTIAL HEATING:
TAXATION, SUBSIDIES, AND COMPARATIVE COSTS
PHASE II
OHIO RIVER DASIK ENERGY STUDY
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March, 1980
ENERGY PRODUCTION AND RESIDENTIAL HEATING:
TAXATION, SUBSIDIES, A'tt) COMPARATIVE COSTS
By
Duane Chapman
Kathleen Cole
Michael Slott
Cornell University
Ithaca, New York 1U853
Prepared for
Ohio River Basin Energy Study (ORBES)
Subcontract under Prime Contract R805588
OFFICE OF RESEARCH AND DEVELOPME'fT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20U60
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ABSTRACT
This analysis was undertaken in support of the Ohio River Basin Energy
Study. It is intended to clarify the effect of economic incentives upon
private and public decisions affecting energy production and use. It fo-
cuses upon the economics of coal and nuclear power generation, and upon the
economics of household space and water heating. The impact of tax incentives
is important in each case, and the general problem of renewable versus con-
ventional energy use is partially addressed.
Southern Indiana is taken as a representative ORBES area. A simulation
model of utility economics relevant to power plant costs examines the con-
struction and operating periods of coal and nuclear plants. The major
findings are:
1. The amortized, annual equivalent tax liability on revenue from new
coal and nuclear plants is negative.
2. The timing of tax credits and deductions promotes the premature con-
struction of new plants and the premature retirement of existing
plants.
3. Because nuclear power is more capital intensive than coal power, it
receives a tax subsidy nearly three times greater than coal genera-
tion.
U. For utility analysis of future generating costs, coal power appears
to be slightly less costly to the utility when costs are conven-
tionally expressed as after-tax, levelized, annual costs over the
plant's operating life.
5. As an illustration: in 1988 dollars, the cost of nuclear power may
be 7.3 $/kWh with a 3.7 ^/kWh tax subsidy; coal generation may cost
6.3 tf/kWh with a 1.3 <£/kWh subsidy.
6. Higher general inflation and interest rates will increase nuclear
cost more than coal cost, and increase the nuclear subsidv more than
the coal subsidy.
7. In the absence of corporate income tax subsidies, utilities in the
ORBES region would find coal generation less costly than nuclear
power.
Southern Indiana is also the locus of the comparative analyses of home
space and water heating costs. Several possible future cases of real energy
price inflation, general inflation, and interest rates are examined for a
representative owner-occupied new home. The major conclusions are:
1. Natural gas space and water heating is usually less costly than any
other alternative.
ii
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2. Electric resistance space and water heating is always the most expen-
sive mode when costs are expressed on an annual basis.
3. Installation costs for electric resistance space and water heating
are less than those of other systems.
U. Solar heating receives considerable tax subsidy through the Indiana
property tax exemption and the Federal personal income tax interest
deductions and solar tax credit.
5. With real energy price inflation interacting with general inflation,
solar, wood, and heat pump systems become less costly than conven-
tional oil heat and electric resistance space and water heat.
6. If natural gas prices reach parity with oil on a Btu basis in 5
years in an economic environment of high inflation, interest rates,
and energy price growth, then a solar/gas space heating system is
the least costly.
iii
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CONTENTS
Abstract ii
Contents iv
List of Figures and Tables v
List of Abbreviations vi
Acknowledgement vii
1. Introduction 1
2. Utility Cost: Coal and Huclear Power ^
Assumptions
Annual equivalent cost
Tax subsidies
Timing of taxation and income
Inflation and interest
3. Space and Water Heating Cost 21
Assumptions
Annual equivalent cost
Tax subsidies: corporate and personal
Water heating
U. Conclusions 3b
Bibliography 37
Appendix 39
Corporate income tax provisions affecting power generation
iv
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LIST OF FIGURES AND TABLES
FIGURES
Number
1. Representative nuclear power cost, constant real price method 11
and rate base method
2. Representative coal power cost, constant real price method and 12
rate base method
3. Nuclear power: after-tax net income, tax liability, and cash flow 16
k. Coal power: after-tax net income, tax liability, and cash flow 17
5. Inflation and interest rates, 19^6-79 !9
TABLES
1. Recent coal and nuclear power cost estimates: industry sources 5
2. Assumptions in Cornell comparative cost and tax subsidv analysis 6
3. Nuclear fuel cycle assumptions 9
U. Constant real cost and tax subsidies for representative nuclear 13
and coal plants
5. High inflation, interest, and return to capital 20
Part A. Basic financial assumptions
Part B. Impact of high inflation and interest rates
6. Heating system assumptions 23
Part A. Space heating
Part B. Water heating
7. General assumptions for space and water heating systems 25
8. Comparative costs and tax subsidies: constant 1979 dollars, 0.5;? 28
interest, no real energy price inflation
9. Comparative costs of space heating 29
10. Illustration: total tax subsidies for home heating 31
11. Comparative costs of water heating 33
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LIST OF ABBREVIATIONS
Btu — British thermal unit(s)
CEC — California Energy Commission
kWh — Kilowatt-hour(s)
MBtu — Millions of British thermal units
MWe — Megawatts (electric)
ORBES — Ohio River Basin Energy Study
PSI —• Public Service Indiana, a private electric utility corporation
SIMCON — A computer simulation model of power plant construction, operation,
and decommissioning (for a nuclear plant) as it effects utility
economics
TMI ~ Three Mile Island Nuclear Power Station, HarrisburR, Pennsylvania
vi
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SECTION 1
INTRODUCTION
This study explores a segment of the economic incentives which influ-
ence energy production and use decisions in the Ohio River Basin. A particu-
lar sub-region within the Ohio River Basin Energy Study (ORBES) region is
used as a locus for analysis. The decision to use a specific area is based
upon the availability of specific data, permitting both analysts and review-
ers to examine these complex subjects in a specific setting. Of course the
virtue of specificity in analysis and assumptions carries a parallel defect:
generalization to the entire ORBES region is difficult without careful con-
sideration of the assumptions, methods, and conclusions of the analysis.
Southern Indiana is used as the representative area for several reasons:
(l) It is an area where coal and nuclear power are believed to be economi-
cally competitive; (2) If Alaskan natural gas is delivered to an Illinois
terminus, it will probably be available to southern Indiana; (3) It was anti-
cipated that each of the renewable residential energy sources (solar water
heating and wood space heating) might be competitive; and (U) Residential
electric heating has been increasing rapidly. Phrasing these points more
generally, we think southern Indiana shows the interaction of all the major
economic influences which affect utility decisions on coal versus nuclear
power and residential homeowners' decisions on space and water heating.
Discussion with ORBES Core Team members confirmed our opinion on these
points.
Two types of decisions are examined in the study. The first decision
area is the electric utility choice between coal and nuclear power. The
second decision area is the homeowner's choice of space and water heating
systems. A common dimension to both types of decisions is the tax system
and its influence on comparative costs.
For electric utilities, nuclear power has been widely believed to be
less costly than coal power for electric utilities and their customers. We
examine a representative area in southern Indiana to determine if this widely
believed conclusion is appropriate to current circumstances.
The means by which this problem is addressed is a simulation by computer
of the economic aspects of hypothetical coal and nuclear power plants in the
southern Indiana area. The model for the nuclear plant!.' examines 110
r/"Yt "is described more fully in Duane Chapman, "Nuclear Economics: Taxation,
Fuel Cost, and Decommissioning," prepared for the California Energy Commis-
sion. It is available from that Commission of from the author.
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variables which have different annual values over part or all of a l*7-year
period of construction, operation, and decommissioning. Fifty-five other
variables have single values. The coal plant model is similar. Occasionally
these models are referred to as SIMCON, an acronym taken from the words
''simulation by computer".
There are two methods of price determination utilized in the analysis.
The first is a behavioral representation of normal regulatory policy. Reve-
nues each year are the sum of fuel expense, operating cost, tax allowance,
and return to capital. As rate base depreciates, return to capital declines,
and this partially offsets rising fuel and operating costs.
The second method of price determination is analogous to the concept of
"levelized" cost. A price is found which, if inflated each year at a general
inflation rate, would exactly pay all costs, taxes, and the allowed return
to capital.
An integral part of this model is its examination of the tax effects of
a new plant on the economics of the utility. Both Indiana and Federal provi-
sions are examined. The most significant elements of income tax treatment
relate to the investment tax credit, the allowance for funds used during con-
struction, interest deductions, accelerated depreciation, and arbitrary short
tax lives. In the Appendix, these provisions are summarized as they affect
utility economics.
The analysis here finds that these provisions have a crucial influence
on the coal/nuclear choice, that they have considerable impact upon customer
costs, and that they influence the timing of new plant construction and old
plant retirement. Increasing inflation and interest rates magnify the tax
effects in each case.
The homeowner's choice of mode of space and water heating for a new home
is complex. Of course all energy prices are rising, and at unpredictable
rates. Utility rate structures are being revised to eliminate promotional
discounts for high quantity consumption.
The system with lowest installation cost may not be the system with
least total annual cost.
We address the problem by examining all (or nearly all) of the economic
factors affecting annual costs. There are initial costs and annual mortgage
payments, maintenance expense, fuel cost and performance efficiency, Indiana
and Federal personal income tax deductions, the Federal solar energy tax
credit, and property and sales taxes.
Conventional systems considered are oil, natural gas, electric resis-
tance, and electric heat pump. Renewable resource systems studied are wood
burning and solar space and water heating.
In the ORBES area studied, growth in electric heating customers is ex-
ceeding total customer growth. This increases the significance of examining
both initial and annual system cost, and the tax subsidies influencing each
system.
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The comparability of personal and corporate tax incentives is limited.
In the narrow context of this analysis, these two kinds of tax subsidies are
compared to determine their impact upon customer cost and total cost.
This latter concept of total cost approaches the meaning of social cost.
When calculating tax subsidies, ve look at part of the "hidden" cost of an
energy system. To the extent that the subsidy analysis is comprehensive and
accurate, subsidies — in combination with actual customer cost — indicate
the costs of particular energy systems for the national economy.
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SECTION 2
UTILITY COST: COAL AND NUCLEAR POWER
Assumptions
In 1976, the ORBES region had 93,000 MWe of Reiterating capacity. Two
percent of this capacity was nuclear power, and 88$ was coal capacity. How-
ever, according to the ORBES inventory of utility plans for additional capa-
city, nuclear power would constitute 9% of a 126,000 MHe total capacity in
1986. Coal would be 83* of the total. Growth in nuclear power generation,
then, equals 20? of the utilities1 planned growth in region capacity^/
To a considerable degree, growth in nuclear power has been predicated
upon the apparent economic advantage to the utility which is believed to re-
sult from nuclear power generation. Table 1 shows two industry cost esti-
mates, one before and one after the Three Mile Island (TMI) accident.
Brandfon's analysis is post-TMI. His cost basis is levelized cost
during the operating period with overall inflation assumed to be 6% per year.
In other words, he concludes that, if fl.
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TABLE 1. RECENT COAL AND NUCLEAR POWER COST ESTIMATES
INDUSTRY SOURCES
Author(s): W.M. Brandfon A.D. Rossin and T.A. Rieck
Affiliation: Sargent & Lundy Engineers; Commonwealth Edison Company;
Atomic Industrial Forum American Nuclear Society
Date of pub.: July 12, 1979 August 18, 1978
Cost "basis: levelized cost, 1990-2020 levelized cost, 1977 dollars
Nuclear Generation (#/kWh)
0, M, I, D 0.6 0.2
Fuel 2.5 0.7
Capital Charges 3.8 2.6
Total 8.9 3.5
Coal Generation (#/kWh)
0, M 1.2 0.5
Fuel 5-0 1.3
Capital Charges h_._l_ 2.H
Total 10.3 U.2
Note: 0, M, I, D represent, respectively, operations, maintenance, insurance,
and decommissioning cost.
Both analyses conclude high sulfur coal with scrubbers is the least
costly coal/oil alternative which meets air standards, and this is the basis
for both coal estimates. Sources are William W. Brandfon, ''Comparative Costs
of Coal and Nuclear Electricity Generation," Over sight ILeajring_s_ 25. itiP^A^.
Ecpjn^micjs, Hearings, U.S. House Interior Committee, Subcommittee on Energy
and~"the Ynvironment, July 12, 1979; A.D. Rossin and T.A. Rieck, "Economics of
Nuclear Power," Science, vol. 201, 18 August 1978, pp. 582-589.
5
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TABLE 2. ASSUMPTIONS IN CORNELL COMPARATIVE
COST AND TAX SUBSIDY ANALYSIS
1. Capital structure for new plants (Refs. 5> 6, 7)
50$ debt at 9.5% interest
common stock equity at lU.7$ after-tax return
preferred stock equity at 9«5$ after-tax return
2. Construction period
a/
Nuclear power: 10 years-
Coal power: 5 years (Ref. 7, p. 10)
3. Capacity, electrical
Nuclear plant: 1,000 MWe
Coal plant: 650 MWe
U. Capacity factor
Nuclear plant: rises, stabilizes, and declines. Average is 62$
(Ref. 2, pp. 29-30)
Coal plant: 60$ (Ref. 6)
5. Operating life
Nuclear plant: 30 years (Refs. 1, 2)
Coal plant: 35 years (Ref. h, p. 8l)
6. Fuel cost
Nuclear plant: 0.8 tf/kWh in 1978, in 1978 dollars (see text and Table 3)
Coal plant: $1.06/MBtu in 1978 in 1978 dollars (Ref. 7, p. 31*), and
10,600 Btu/kWhk/
7. Operations, maintenance, insurance, and administration cost
Nuclear plant: $UO million in 1978, in 1978 dollars (Ref. 2, p. 31)
Coal plant: 6.U5 mills/kWh in 1978, in 1978 dollars (Ref. 6)
8. Capital cost
Nuclear plant: $l,oH7/kW in 1978, in 1978 dollars (Ref. 2, p. 19)
Coal plant, incl. scrubber: $700/kW in 1978, in 1978 dollars (Ref. 6)
(continued)
6
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Table 2 (continued)
9. Inflation and escalation
Note: Specific escalation equals the product of overall inflation and
real inflation. E.g., for nuclear investment, (1.07)*(1.065) = l.l1*.
General: 7$, from 1978 through the entire period-
Nuclear investment: 6.5% real inflation, 1978 through 1987-
e/
Coal investment: 1.9% real inflation, 1979 through 198U-
f/
Nuclear fuel: equivalent to 0.8$ real inflation, 1978 onward-
Coal fuel: 2.8% real inflation, 1978 onward^-'
Nuclear OfcM: equivalent to -2.3!? real inflation after 1P78-'
Coal O&M: -1.9$ real inflation after 1978-
10. State and federal taxation*-
Federal corporate income tax rate:
Indiana corporate income tax rate: 3%
Indiana gross receipts tax: 1.5!? in 1978, declining .05^ annually
Indiana property tax: 1%
Footnotes, Table_ 2_
a/ Wilfrid Comtois, "Power Plant Construction Schedules, Escalation, and
Interest During Construction," presented at the American Power Conference,
April 21, 1976.
The construction period is not intended to give the full length of the
planning and approval process, but to represent the period in which signifi-
cant expenditures are experienced.
b_/ Suggested by utility analysts at Ohio River Basin Energy Study Meeting,
Lexington, Kentucky, October 5, 1979-
c/ A year ago, a 1% general inflation assumption was common. However,
twelve-month inflation in the Consumer Price Index is currently an annual
11.5*, and inflation in the Gross National Product implicit price deflator
is an annual 8.6%. Both appear to be rising.
d/ California Energy Commission analysis shows nuclear plant costs increased
22% per year, 1971-76. A lk% escalation is 2/3 of this. (See also Ref. 2,
p. 19.) The product of general inflation (1%) and real inflation (6.5%} de-
fines actual escalation (lU?). It is of interest to note that no new plants
have been ordered for use in the United States since 1976.
(continued)
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Footnotes, Table 2 (continued)
§_/ In Ronald Knecht, "Review and Critique of California Electricity Genera-
tion Methods Assessment Final Report," CEC, 1977, Knecht concluded that a 9%
escalation rate was appropriate for coal plants. This is probably lower than
actual experience in the past two years. Escalation (1.09) = overall infla-
tion (1.07) * real inflation (1.019).
f/ This inflation assumption for nuclear fuel is reasonable in terms of the
p'ast year where there has been little overall increase. In the early 1970s,
escalation in 11303 cost was spectacular, averaging 23% per year from 1973 to
1977. However, the actual market price has fallen from $19.75/lb on 1/1/77
to $l8.05/lb on 1/1/79. See text and Table 3.
g/ Actual inflation for PSI has been 155? annually (Ref. 7, pp. 3^-35). We
a'ssume 2/3 of this, or 10$ annually. The real inflation rate is 2.8$.
(I.e., 1.028 * 1.070 = 1.100.)
h/ See Ref. 2, p. 31.
ij See Knecht, "Review and Critique," op. cit.
J/ See our note for the 5 October 1979 ORBES meeting, "Federal Income Tax
Provisions Affecting Nuclear Power." It is included as Appendix A to this
report. Differences between Indiana and IRS regulations and between coal and
nuclear power are noted there.
References, Table 2_
1. K.B. Cady and A.C. Hui, "NUFUEL - A Computer Code for Calculating the
Nuclear Fuel Cycle Cost of a Light Water Reactor," Cornell University,
August, 1978.
2. TXiane Chapman, "Nuclear Economics: Taxation, Fuel Cost, and Decommis-
sioning," draft final report submitted to the California Energy Commission
(CEC), October 29, 1979 (revised).
3. Ronald Knecht, "Testimony on Power Generating Economics and Planning,"
Wisconsin Public Service Commission, Northern States Power Company Applica-
tion for Tyrone Nuclear Unit, December 28, 1978.
U. Ron Knecht, et al., "Comparative Cost Analysis (Pevised)," Supporting
Document No. 9, California Energy Commission, Spring, 1978.
5. Ben Koebel, Chief Accountant, Indiana Public Service Commission, letter
to Kathleen Cole, August 29, 1979-
6. James H. Pennington, Vice President - Financial Operations, Public Service
Indiana, letter to Duane Chapman, September 10, 1979.
7. Public Service Indiana, Annual Report.
8
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TABLE 3. NUCLEAR FUEL CYCLE ASSUMPTIONS
Fuel cycle
activity
Price
mid-1979
Real
inflation
rate
Equilibrium
annual
quantities
Lead (+) or
lag (-) years
from first use
uranium ore
conversion
enrichment
fabrication
spent fuel
transportation
$l*3.60/lb U30
$l*.lH/kp; U
$89. 02 /kg SWU
$100.00/kg U
$l6.00/kg U
0%
vaste disposal $250.00/kg U
lb U30
173,300 kg U
llU,127 kg SWU
27,lU3 kg U
27.1U3 kg U
27,1^3 kg U
+3
+3
+2
+1
-3
-3
Note: The inflation rates in this table interact with the overall inflation
rate as in Table 2. The product of general overall inflation and real infla-
tion defines the specific rate. For example, for uranium ore, 1.07*1.01 =
1.08. The specific rates are commonly referred to as escalation rates.
Waste fuel disposal is the subject of specific analysis in a later section.
General sources of information are the U.S. Energy Information Administra-
tion's Monthly Energy Review, and its Annual Report tp_ Congress, and Cady
and Hui, "NUFUEL".
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Tables 2 and 3 show the "basic assumptions employed by us in our examina-
tion of costs in southern Indiana.
Table 2 Rives cost, finance, and operating assumptions for coal and
nuclear power. The reference numbers (i.e., Refs. 1-5) refer to the publi-
cations listed after the footnotes to Table 2.
Nuclear fuel cost is particularly difficult to represent in the format
utilized in Table 2. The value of 0.8 tf/kWh (item 6, Table 2) is derived
from the assumptions given in Table 3. The SIMCON model includes a repre-
sentation of three methods of fuel cost calculation. These three methods are
(l) actual current cash expenditures, (2) batch amortization for net income
purposes, in which expected disposal costs are recognized as each batch of
fuel is used, and (3) batch amortization for tax purposes, which amortizes
acquisition cost as each batch is used in each year, but charges disposal
costs as incurred. The 0.8 tf/kWh value is based upon actual cash expendi-
tures during equilibrium operationsi/
Annual Equivalent Cost
As described in the Introduction, we calculate generating costs in two
ways. The first approach defines n. constant real price. This constant real
price is escalated at the overall inflation rate. The second approach de-
fines a price pattern based upon conventional regulatory methods. Here,
price is determined by rate base, return to capital, and fuel and operating
costs.
Both methods are used in Figures 1 and 2 for the representative coal and
nuclear plants.
The constant real price curve is similarly shaped for the nuclear and
coal facilities. For each, price increases 1% per year.
However, the rate base method gives different patterns for coal and
nuclear power. For coal, the curve is concave throughout. Fuel cost is a
large and growing component of total cost. In 198'< (the first year of the
coal plant), fuel cost is Hof5 of total allowed cost. In the succeeding
years, fuel cost escalates at 10$ annually, while rate base deterioration
causes return to capital to decline. As a consequence, by 2019 fuel cost has
become 92/S of total allowed cost.
In contrast, nuclear power is more capital intensive. Fuel cost is a
lower fraction of total allowed cost in every year. In addition, nuclear
fuel cost is presumed to escalate at 7-8$ annually, less than coal escala-
tion. As a consequence, rising fuel cost is offset by falling return to the
l"/ See Chapman, "Nuclear Economics," pp. 23-29. The three fuel cost accoun-
ting methods are described there. However, the data in Tables 2 and 3 are
specific to this study. Fuel cycle operations are in equilibrium for those
years in which the amount of new fuel loaded in the reactor is fully uti-
lized. For a 30-year operating life with annual refueling, this definition
of the equilibrium period covers years 3-28.
10
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FIGURE I. REPRESENTATIVE NUCLEAR POWER COST, CONSTANT REAL PRICE METHOD
AND RATE BASE METHOD (cents per kWh)
60,-
50
40
30
20
10
Constant Real Price Method
CONSTRUCTION
10 YEARS
OPERATIONS
30 YEARS
Rate Base Method
DECOMMISSIONING
7 YEARS
H H
78 ' 82 84 86 88 ' 92 94 96 98 ' 02 04 06 08 ' 12 14 16 18 ' 22 24
1980 1990 2000 2010 2020
Year
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K>
FIGURE 2. REPRESENTATIVE COAL POWER COST, CONSTANT REAL PRICE METHOD AND
RATE BASE METHOD (cents per kWh)
60 i-
20
L
oL
•CONSTRUCTION!
r*~ 5 YEARS H
Constant Real Price Method
Rote Base Method
OPERATIONS
35 YEARS
82 84 86 88 ' 92 94 96 98 ' 02 04 06 08 12 14 16 18
1980 1990 2000 2010
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declining rate base for much of the operating period for the nuclear plant.
In the last few years (e.g., 2010-2017), this pattern changes because fuel
cost and actual tax liability grow significantly. The last fuel batch is
charged to the last year, and the second-to-last batch is charged to the last
two years.
Table U summarizes the results of the real cost method applied to both
plants. Coal and nuclear power are very similar in estimated real cost in
1988 dollars for the utility. Nuclear cost is 7.3 <£/kWh, and coal cost is
6.3 <£/kWh. These values are with present tax provisions. They may be de-
flated and compared to the Rossin-Rieck 1977 values in Table 1. In 1977
dollars, nuclear power cost would be 3.5 #/kWh, which is, surprisingly, iden-
tical to the Rossin-Rieck estimate. The coal estimate from Table k of 6.3
<£/kWh (in 1988 dollars) would be 3.0 tf/kWh in 1977 dollars. This is consi-
derably below Rossin-Rieck*s k.2 tf/kWh estimate. The major causes for this
difference in coal generation may be higher fuel cost and tax liability
assumptions for Rossin-RiecteLl
However, it is clear that our analysis does not support the conclusion
that, for a utility, nuclear power is less costly than coal power in our
study of a representative ORBES area.
TABLE 1*. CONSTANT REAL COST AND TAX SUBSIDIES FOR
REPRESENTATIVE NUCLEAR AND COAL PLANTS
(all economic values in 1988 dollars)
Nuclear Coal
Plant Plant
Conventional after-tax cost to
utility, present tax subsidies 7.3 <£/kWh 6.3
Cost to utility with no
tax subsidy 11.0 tf/kWh 7.6 <£/kWh
Tax subsidy 3.7 tf/kWh 1.3 tf/kWh
Average generation for 1,000 MWe of
capacity, billion kWh/y 5-^35 5.260
Approximate annual tax subsidy for
1,000 MWe capacity $201 million $68 million
I/ Rossin-Rieck assumed coal cost at $1^20 per million Btu (MBtu) in 1977
dollars, or $1.28 in 1978 dollars, 22^/MBtu above our Table 2 assumption.
13
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Tax subsidies
As a result of our earlier analysis of tax subsidies and nuclear power
in California, we learned that nuclear power receives a major tax subsidy on
the order of $200 million per year—( In the ORBES study, we wish to know to
what extent comparative costs of coal and nuclear power are influenced by tax
subsidies.
To define a corporate income tax structure without tax subsidies, we
assume revisions in major provisions affecting deductions and credits. We
make these specific assumptions:i/
(l) Interest payment deductions are eliminated. This causes the treatment of
debt payments to be identical to the treatment of payments to common and pre-
ferred stock holders. Both are liable to taxation.
(2) The investment tax credit is eliminated.
(3) Method of depreciation for tax purposes is made identical to depreciation
for net income purposes. Normal straight line depreciation is used.
(1*) Tax lives are made identical to depreciation periods used in net income
calculation. Consequently, nuclear power investment is depreciated over 30
years and coal plant investment is depreciated over 35 years.
(5) AFUDC allowances in the construction period are treated as net income,
but are not taxed as earned. Income flowing from AFUDC increments to rate
base is taxed as received during the operation period. For AFUDC, then, the
subsidy and non-subsidy treatment is uniform.
The SIMCON model is used again to estimate the economics of nuclear and
coal power without Federal and Indiana corporate tax subsidies. The results
appear in the second row in Table U. Nuclear cost is now 11.0 #/kWh, while
coal cost is 7.6 0/kWh.
An important conclusion follows. V/ithin our present corporate income
tax structure, nuclear power cost is slightly higher than or comparable to
coal-generated electricity (e.g., Table 1; Table b, row 1). However, when
tax subsidies are excluded, nuclear power appears to be considerably more
expensive (Table k, row 2). The subsidy received by nuclear power is almost
threefold greater than the subsidy received by coal power (Table U, row 3).
The explanation of the cause of the magnitude of this difference in tax
subsidies appears to lie in the difference in capital intensity for the two
processes. In 1988 dollars, the representative nuclear plant has a rate base
investment of $3,238 per kW at the beginning of operation in 1988. The coal
plant has a rate base investment of $1,361+ per kW in 1988 dollars at the be-
ginning of its operation in 198U.
It would appear that, at the present time, nuclear power growth in the
ORBES region is predicated upon a major differentiation in tax subsidies re-
ceived by coal and nuclear power, or upon different assumptions with respect
to economic parameters, or both.
I/ "Nuclear Economics," pp. 52-53-
21 Recall that corporate income tax provisions affecting power generation are
described in the Appendix.
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Timing of Taxation and Income
It was anticipated that the timing of net income, tax liability, and
funds flow would create particular incentives for utility planning. Figures
3 and U show these accounts for the representative ORBES nuclear and coal
plants located in southern Indiana. In this discussion the rate-base pricing
algorithm is used in the SIMCON model. This provides a representation of
actual regulatory behaviori'
In Figure !», note that net cash earned is less than $20 million annually
for the last 11 years of operating the coal plant. During this period, reve-
nue requirements rise from $800 million per year in 2008 to $1.9 billion in
2018. It appears that there is little financial incentive to operate the
hypothetical coal plant during the last third of its operating life. The
after-tax net income curve is similar, being less than $10 million annually
during the 2008-2018 period. In fact, net cash income is negative in 2016-
2018, and net income itself is negative in the last year.
However, tax liability is high during these last years, and is declining
from $26 million in 2008 to $17 million in 2018.
In contrast, the construction period and the first years of operation
show quite a different pattern. Tax liability is negative in the construc-
tion period and the first two operating years, and remains below $5 million
until 1989.
After-tax profit actually reaches its highest level during the construc-
tion period, being above $50 million in 1982 and 1983. Net cash income is
negative during the construction period. It is $U5 million during the first
operating year, and rises to $57 million in the sixth operating year before
beginning to decline.
The pattern described here is equally appropriate for nuclear and coal
plants. It arises from the interaction of regulatory, tax, and net income
accounting. Regulatory policy gives a constant return to capital on a nor-
mally depreciating rate base. Consequently, annual return to capital de-
clines in parallel to the normally depreciating rate base.
Tax policy will give the lowest after-tax cost to utilities and their
customers if credits, exclusions, and deductions are claimed at the earliest
possible dates. As a result, no depreciation deductions will be available in
the last years of a plant's life.
Net income and net cash flows follow from the regulatory and tax poli-
cies, and are very low or negative in the last years of a plant's life.
The overall result is the creation of a financial incentive for prema-
ture construction of new plants and premature retirement of old plants.
I/ It is surprising to see that overall liability is comparable with both
pricing methods. The ^7-year annual equivalent tax liability for the nuclear
plant with the theoretical real cost method is -$8 million per year. The
rate-base pricing method has an annual equivalent tax liability of -$5 mil-
lion.
15
-------
FIGURE 3. NUCLEAR POWER: AFTER-TAX NET INCOME, TAX LIABILITY, AND CASH
FLOW (million dollars)
300
200
100
-100
-200
-300
After Tax Net
Income
CONSTRUCTION
IO YEARS
OPERATIONS
30 YEARS
M032.7)
DECOMMISSIONING
»«— 7 YEARS
I 1 1
I I j
78 ' 82 84 86 88 ' 92 94 96 98 ' 02 04 06 08 ' 12 t4 16 18 " 22 24 26
1980 1990 2000 2010 2020
Year
-------
FIGURE 4. COAL POWER: AFTER-TAX NET INCOME, TAX LIABILITY, AND CASH FLOW
(million dollars)
Cash Flow
(-167.2)
.CONSTRUCTION
[lyi^s i nut i IUNI
r*~ 5 YEARS ~*T*~
OPERATIONS
' 35 YEARS "
78 ' 82 84 86 88 ' 92 94 96 98 ' 02 04 06 08 ' 12 14
1980 1990 2000 2010
Year
16 18
-------
. _ Interest
The assumptions with respect to general inflation and interest rates
which we used in the preceding discussion are typical of much current work.
An overall inflation rate of 1% is typicali-C and the 9-5% interest rate for
utilities was applicable to Public Service of Indiana.
However, the economic situation in late 1979 is quite different from
that of the recent past. Prime commercial lending rates have exceeded lU$,
and new utility bonds have yielded between 11 1/2% and 12%. At the same time,
inflation in the Consumer Price Index has been at annual rates between 8 1/2%
and 9 1/2$ in the past three quarters.
Although utility bond rates of 12% are historically very high, they de-
fine a real interest rate which is currently zero or negative with respect to
the Consumer Price Index.
Similarly, home mortgage rates have increased rapidly.
Figure 5 provides perspective on this problem. The era between the
Korean and Vietnamese wars (roughly 1952-19^5) ^a^ a basic price stability.
Wage and price controls brought a brief return to price stability (1970-72).
However, this price stability ended with the cessation of controls and the
energy price increases which began in 1973.
Since, as noted, coal and nuclear power differ in capital intensity, we
are concerned about the impact of higher inflation and interest rates on the
real cost of generation. To examine this impact, we evaluate the represen-
tative coal and nuclear power plants through the SIMCON model. Each interest
rate and return to capital is increased by adding 5*. Overall inflation is
increased by 5#, from 1% to 1?%. liach cost factor experiences an inflation
equal to the product of general inflation and real inflation for that factor.
(E.g., from Table 3, uranium ore price increases by 13.1$ per year, the re-
sult of 1.1P * 1.10 = 1.131.) These new assumptions are summarized in Table
5, Part A.
The effect of higher inflation and returns to capital are summarized in
Table 5, Part D. After-tax costs for coal and nuclear power each increase by
one-half. The margin favoring coal power is in percentage terms essentially
unchanged. The overall tax liability remains negative for both the coal and
nuclear plants.
The cost to utilities without tax subsidies is again calculated, and is
shown in Table 5, Part B, row ?.. The tax subsidy for nuclear power more than
doubles, from 3.7 tf/kWh (Table M to 7.8 tf/kWh (Table 5). The coal subsidy
rises less, from 1.3 <£/kWh to 2.0
I/ General inflation assumptions were 1% in Knecht's work (1978); Brandfon
Tl979) assumed Q% in 1979, 1% for 1980-8U, and 6% for 1985 and thereafter.
18
-------
FIGURE 5. INFLATION AND INTEREST RATES, 1946-79
15
10
0
-5
CPI - Consumer Price Index (% annual change)
GNP- Implicit Price Deflators for GNP (% annual change)
Home Mortgage Rates
Utility Bond Rates
I
I
I I
46 48 ' 52 54 56 58 ' 62 64 66 68 ' 72 74 76 78 J F M A M J J A S
1950 I960 1970 I979
SOURCE: SURVEY OF CURRENT BUSINESS, AND ECONOMIC REPORT OF THE PRESIDENT
-------
We conclude that, if the high inflation and interest rates of late 1979
become characteristic of the future, then (l) coal power will slightly in-
crease its margin over nuclear power with respect to utility after-tax cost,
and (2) the tax subsidy enjoyed by nuclear power will increase.
On this latter point, we note that with low inflation and interest as-
sumptions, the nuclear tax subsidy equals 50$ of utility cost (Table k).
With high inflation and interest assumptions (Table 5), the nuclear tax sub-
sidy equals 70$ of utility cost.
TABLE 5. HIGH INFLATION, INTEREST, AND RETURN TO CAPITAL
Part A . Basic Financial Assumptions
Low inflation High inflation
Overall inflation 1%
Interest rate 9-5% 1>*.5$
Return to preferred equity 9.5$ 1^.5$
Return to common equity lU.7$ 19.7$
AFUDC rate 9-5$ I1*. 5$
Part B_. Impact of_ High Inflation and Interest Rates, 1988 Prices
Nuclear plant Coal plant
Present subsidies, after-tax
cost to utility 11.1 0/kWh 9-3 <£/kWh
Cost to utility with no subsidies 18.9 <#/kWh 11.3 <£/kWh
Tax subsidy 7.8 tf/kWh 2.0 <£/kWh
Average generation for 1,000 MWe
capacity, billion kWh/y 5.!*35 5-260
Approximate annual tax subsidy $1»2U million $105 million
20
-------
SECTION 3
SPACE AND WATER HEATING COST
The last section analyzed the comparative costs of nuclear and coal
power generation.
It examined the impact of corporate and state income tax policy on util-
ity economics, and explored the significance of much higher interest and in-
flation rates.
This section investigates comparative home heating costs for space and
water.
Space heating is causally connected with coal use by means of electric
heating. Each Btu of coal-generated electric energy utilized in residential
heating will require at least 3.7 Btu of direct coal energyi/ This is in-
herent in the technology, a consequence of steam generation of electricity
and losses in transmission and distribution. If the energy requirement of
coal mining and transportation and of utility, mine, and rail system con-
struction could be estimated, total energy per Btu utilized in home heating
may approach 5:1.
It is therefore of considerable interest to the ORBES investigation to
determine to what extent electric heating will be developed in the region.
A typical home utilizing electric heating may require 30,600 kWh of electri-
city for this purposed In the area studied, growth in electric heating ex-
ceeds growth in the total number of customers!/ The current residential
average use is 10,500 kWh per customer, 20% above the 1973 average. If elec-
tric heating continues to grow, it will create considerable new demand for
electricity, and for coal or nuclear energy to generate that electricity.
Assumptions
Our analysis of comparative costs is based in part on the assumptions in
Tables 6 and 7. Purchase cost in Table 6 is the estimated variation in new
I/ Assume 33# efficiency in generation, 10% transmission loss to home, and
10$ energy loss_in the home.
2_/ Assuming 91* MBtu annual heating requirement. See Table 7.
3/ PSI Annual Report, op. cit.
21
-------
home cost associated with the choice of heating system. It is immediately
apparent that a builder installing electric resistance heating has the lowest
installation cost.
Actual performance indicates the expected lifetime efficiency in pro-
viding heat energy. For the oil, gas, electric resistance, and wood systems,
the performance ratio is, simply, the ratio of heat energy delivered into the
home to energy contained within the fuel. A .5 performance ratio for wood
means 2 Btu of energy in the wood are required for each Btu of heat energy
in the home.
For the heat pump, the performance ratio gives the amount of heat energy
transferred into the home for each Btu of electrical energy used by the heat
pump. For example, utilizing 3,1(12.8 Btu (one kWh) in the heat pump trans-
fers 6,ll+3 Btu of energy from the outside into home heat.
Performance for a solar system means the proportion of annual heat
energy (or water heat energy) which the system can supply. We assume a solar
system can supply 60% of the needed space heat, and that a solar hot water
system can supply 70$ of the energy required for water heating.
Major differences exist in end-use efficiencies for oil, gas, resis-
tance, and wood heat. Wood burning is least efficient in deriving energy,
converting only 50$ of the energy in wood into space heat energy.
All energy prices are given in customary units and in dollars per mil-
lion Btu ($/MBtu). A price of $100 per cord of wood assumes a cut and de-
livered price, making its price similar in definition to that of other energy
forms. Note that electricity price is highest on a Btu basis. Natural gas
is lowest, followed by wood.
The last row of Table 6, Part A, expresses energy conversion factors.
For example, one gallon of fuel oil has .lUl million Btu.
Part B in the Table shows additional assumptions for water heating.
Again, purchase cost is lowest for a conventional electric hot water heater,
and highest for a solar unit.
Performance efficiencies in hot water units are assumed to be identical
to those in space heating, except for the solar system.
A solar hot water system operates 12 months a year, and is operating
during the summer period of maximum solar insolation. We assume the solar
hot water system delivers 70% of the annual energy requirement. This might
be visualized as 95% delivery in the summer, ^5% in the winter, and 70% in
the spring and fall.
Solar back-up systems are full scale for both space and water heating.
No attempt is made to evaluate the alternatives with respect to conve-
nience or impact upon associated activities. As examples of points not con-
sidered with respect to wood burning: (l) consequences of system failure in
22
-------
TABLE 6. HEATING SYSTEM ASSUMPTIONS
Part A. Space Heating
Fuel type
Purchase cost
Performance
Electric systems
Fuel oil Natural Resistance Heat Solar Wood
gas pump
$3200
.7
$2500
.8
Unit price
(1979 $)
Energy price
(1979 $/MBtu)
MBtu/unit
89.9 tf/gal
$6.376
0.11*1
$1.698/MCF
$1.672
1.016
$1800 $5500 $8200 $3000
.9 1.8
3.91 tf.
.00311*28
.5
$100/cord
22.52
Part B. Water Heating
Fuel oil Natural gas Electric resistance Solar
Purchase cost
Performance
.7
$350
.8
$250
.9
$2800
.7
23
-------
winter on plumbing or family members, (2) probability of accidents, (3) wood
availability.
Another example of excluded considerations arises with respect to elec-
tric heat pumps. Heat pumps are least efficient when they are most needed.
In very cold weather, when space heat energy is in greatest demand, the heat
pump is at its minimum efficiency in extracting heat from the outside envi-
ronment. Consequently, peak demand (measured in kW) increases more rapidly
than energy demand (measured in kWh) in cold weather. As with the wood sys-
tem, no attempt is made to consider (l) system failure, here including the
utility, (2) probability of accidents for either coal or nuclear power, and
(3) availability.
The comparison, then, is solely economic, and examines customer costs
and tax subsidies.
Other assumptions which are generally applicable to all systems appear in
Table 7. We are considering a representative 1500 square foot house in
southern Indiana. It requires 9^ MBtu space heating energy and 21.5 MBtu
water heating energyi/
These are not conservative values. We would not be surprised to find
future new homes with one-half these energy requirements. Such homes would
make extensive use of energy_conservation practices and passive solar heating.
However, these values of 9^ MBtu space heating and 21.5 MBtu water heating
are representative of current planning.
The family income is assumed to be $25,000 and the marginal tax rates are
.28 for the Federal personal income tax and .02 for the Indiana personal in-
come tax. The solar system qualifies for the Federal solar tax credit which
is 30/? of the first $2000 and 20/2 of the next $8000 of purchase cost.
The property tax rate is 12.8397/5 on assessed valuation, and assessed
value is about 26.5% of market value. Consequently, the property tax rate
is assumed to be 3.U/J on original cost. The solar system is exempt.
The Indiana State sales tax rate is U/£ on fuel purchases.
Maintenance expense is assumed to be 2% of purchase cost for each system.
However, for the back-up source in the solar system, maintenance expense is
1% of purchase cost—'
!_/ With 5699 degree days in southern Indiana, 1500 square feet, and an aver-
age energy requirement of 11 Btu per degree day per square foot, the result
is 9^ MBtu per year. The hot water requirement of 21.5 MBtu is equivalent to
the original energy requirement to heat 86 gallons per day from UU°F to 130°F.
This latter calculation excludes energy for temperature maintenance. See
William D. Schultze et al., "The Economics of Solar Home Heating," Print,
Joint Economic Committee, U.S. Congress, 95th Cong., 1st Sess., March 13,
1977; and U.S. Energy Research and Development Administration, "An Analysis
of Solar Water and Space Heating," November, 1976.
2_/ Recall that, compared to a normal system, a back-up system will be used
as much for space heating, and 30$ as much for water heating.
-------
TABLE 7- GENERAL ASSUMPTIONS FOR SPACE AND WATER HEATING SYSTEMS
Life of systems
Discount/interest rate
Amortization factor
Annual maintenance expense, % of purchase cost
Property tax rate, conventional and wood
Property tax rate, solar
Assumed income level
State personal income tax marginal rate
Federal personal income tax marginal rate
Sales tax rate on fuel and wood
General inflation rate
Heating degree days
Annual space heating requirement
Annual water heating requirement
Real inflation, oil and electricity
Real inflation, natural gas price
Real inflation, wood price
20 years
9.5% or 1U.5*
.1135 or .1551*
2%
.03**
0
$25,000
.02
.28
k%
1% or 12%
5699
91* MBtu
21.5 MBtu
Of, or 3.555
05?, 3.5?, or oil
price parity, 5 yrs.
OJ5, 1.75#, or 3.5$
25
-------
As suggested by the discussion in the previous section, interest rates
of 0.5/S and l'f.5$ 'ire examined.
All systems are assumed to have a 20-year life without salvage value.
General inflation is, as in the preceding section, assumed to take place
at rates of either 1% or 12$. General inflation affects maintenance expense,
fuel cost, and sales tax on fuel.
Real inflation in oil and electricity energy prices is examined in two
dimensions. First, real inflation is assumed in some cases studied to be
zero — energy prices prow at rates exactly equal to general inflation.
Second, real inflation is assumed in other cases to lead to a doubling in
real energy prices in 20 years. This doubling requires a real inflation rate
of 3.5? annuallyi/
Real inflation in natural gas price includes the assumptions for oil and
electricity: cases with 0% or 3.5$ real inflation interacting with general
inflation. However, natural gas also is examined with a third price assump-
tion. Whatever the oil price on a Btu basis, natural Ras is assumed to reach
the same Btu price in 5 years, and from that point on oil and natural gas
have the same Btu price and grow at the same rate.
Real inflation in wood prices has three alternative assumptions: zero,
one-half the 3.5? rate, and 3.5$. The 1.75$ rate might apply if improved
forestry management and lower costs in wood fuel preparation caused wood fuel
price to rise less rapidly than oil, natural Ras, or electricity prices.
It should be understood that even the lowest inflation assumption raises
nominal prices considerably. A 1% general inflation raises oil prices from
89.9tf/gallon to $3.US/gallon in 20 year*. A high general inflation (12$)
linked with a real inflation of 3.5/S raises the oil price to $17.20.
In the discussion which follows, we shall attempt to determine what con-
sistent patterns may be observed amidst these widely varying assumptions.
Annual Equivalent Cost_
Given the assumptions described above, there are 108 possible cases
based upon varying assumptions in interest rate, general inflation, and real
energy price inflation rates. Several can be dismissed as illogical. First,
we note that an overall inflation rate exceeding the interest rate defines a
20-year period in which credit institutions lend at negative real interest.
We exclude the cases with ll»/5 inflation and 9-5% interest. Second, the
closely parallel paths of inflation and interest, and the general difference
of 3%-5% indicate that a 7-5$ difference has not existed previously and is
unlikely to in the future. We exclude the cases with l'».5$ interest and
I/ Recall from the previous section that a real inflation rate interacts with
an overall rate: 1.035*1.12 = 1.159 means a nominal inflation of 15.9$ in
fuel. Then, (1.159)**20 = 2»(1.12)»»20.
26
-------
general inflation of 0% and 1%. Finally, we suppose that inflation in real
energy prices is a major factor in overall inflation. Consequently, the only
cases reported for the I1*.5/5 interest rate have overall inflation at 12% and
real energy price inflation.
As a result of this logic, we focus upon 6 cases.
The structure of the analysis is indicated by Table 8. In that Table,
all amounts are expressed in constant 1979 dollars with 1979 prices. The
low interest assumption of 9«5# is used.
The annual equivalent value!/ of each term discussed previously is re-
ported in Table 8.
The natural gas system has the least cost to the customer over the 20
years. Its annual equivalent cost is $U7** per year, considerably lower than
the solar/gas system ($10U8) or the wood system ($1192)—{
Since electric resistance had the lowest purchase cost, it has the low-
est mortgage payment ($20b). However, it is the most expensive system for
the customer to use.
With these assumptions, non-availability of natural gas would result in
wood fuel being the least costly (at $1192) followed by the heat pump (at
$1215) and oil ($1235).
The greatest total subsidy ($802) is received by the solar/gas system.
The largest component of this subsidy is the exclusion of property tax lia-
bility which would be $28oi'per year. The Federal solar income tax credit
has an annual equivalent value of $191, and interest deductions on mortgage
payments for State and Federal income taxes constitute the remainder of the
solar/gas subsidy.
I/ The precise formulation is AECj = a(i)*PVj(i). Annual equivalent cost for
item J is AEC«. The amortization factor for interest rate i is a(i), and is
defined by a(i) = i(l+i)*»20/(((l+i)**20)-l). The present value of item J
is PVj = Cjt/(l+r)**t over 20 years, t = 1, 20. Cit is cost or credit
item j as actually occurring in year t. Total customer cost is the sum of
the annual equivalent cost of each of the first eight items in Table 8.
2_/ In the preceding section on utility generation costs, dollar values are
expressed in annual equivalent costs over the operating periods of the plants.
In this section, the residential systems were assumed operable in 1979> and
annual equivalent costs cover the period 1979-1999- The two can be compared
by deflating the 1988 dollars to 1979 dollars. For the 1% inflation assump-
tion, the deflation factor would be 1.838. For the 12$ inflation assumption,
the deflation factor would be 2.773. For example, the 7.3 tf/kWh figure from
Table U could be expressed as U.O tf/kWh in 1979 dollars. I.e., 1*.0 -#/kWh =
7.3 tf/kWh 4 1.838.
3_/ The annual property tax on the solar system would otherwise be $8200*.03^*2,
equal to $280.
27
-------
TABLE 8. COMPARATIVE COSTS AND TAX SUBSIDIES: CONSTANT 1979 DOLLARS, 9-5^ INTEREST,
HO REAL ENERGY PRICE INFLATION (rounded to nearest dollar). CASE #1
Single Systems
Solar Gas & Electric Systems
Mortgage
payment
Maintenance
Fuel cost
State income
tax savings
CD Federal income
tax savings
Federal solar
tax credit
Property tax
Sales tax:
fuel
Total customer
cost
Rank
Subsidy
Total vithout
subsidies
Rank
Oil
363
6U
856
-13
-179
0
109
31*
1235
5
192
1U72
3
Natural
gas
28U
50
196
-10
-litO
0
86
8
U7U
1
150
62li
1
Electric
resistance
20l
36
1197
-7
-101
0
62
U8
1U39
7
108
15U7
It
Heat
pump
62U
110
598
-22
-307
0
188
2U
1215
U
329
15»»5
It
Wood
3^0
60
835
-12
-168
0
103
3U
1192
3
180
1372
2
Solar
931
161»
0
-12
-169
-191
0
0
722
652
137^
Gas
backup
28U
25
78
-10
-1»+0
0
86
3
326
150
1*76
Total
1215
189
78
-22
-309
-191
86
3
10U8
2
802
1850
6
Solar
931
16U
0
-12
-169
-191
0
0
722
652
137*1
Electric
backup
20U
18
U79
-7
-101
0
62
19
67*
108
782
Total
1135
182
»*79
-19
-270
-191
62
19
1396
6
760
2156
7
-------
TABLE 9- COMPARATIVE COSTS OF SPACE HEATING ($/year)
(rounded to nearest $5; the tvo least-costly
solar systems are shown in each case)
1979 dollars
9-5? interest
no real fuel inflation
case #1
ro
\o
gas
solar/gas
wood
heat pump
oil
solar/elec.
electric
$ »*75
1050
1190
1215
1235
1395
1979 dollars
o.5$ interest
real fuel inflation
case #2.
gas $ 530
solar/gas 1070
inexp. wood 1301
heat pump 1385
exp. wood 1^30
oil 1U85
solar/elec. 1535
electric 1785
1979 dollars
9-55? interest
no real fuel inflation
ease #3
pas
solar/gas
heat pump
solar/wood
wood
oil
electric
$ 6»*5
12UO
1710
1730
1820
1885
2305
Low inflation (1%)
9.55? interest
real fuel inflation
case
pas $ 775
solar/gas 1285
solar/inexp. wood 1830
inexp. wood 2070
heat pump 2105
exp. wood 2370
oil 2^5
electric 3095
High inflation (12?5)
1U.5$ interest
real fuel inflation
case #5
gas $1020
solar/gas 1670
solar/inexp. wood 2390
inexp. wood 2730
heat pump 2775
exp. wood 3130
oil 32UO
electric 1*095
Oil/gas parity
high inflation (12%)
lU.5$ interest
maximum real inflation in oil,
electricity, and wood prices
case #6
solar/gas
solar/exp. wood
gas
heat pump
solar/electric
exp. wood
oil
electric
$2390
2510
2570
2775
2850
3130
321*0
1*095
-------
TABLE 10. ILLUSTRATION: TOTAL TAX SUBSIDIES TOR HOME HEATING
($/year; Case #1)
Type of System:
Type of Subsidy
Personal income and
Solar/Electric
solar electric total
backup
Wood Electric Electric
(coal) (nuclear)
property tax
Property tax exclusion
State income tax deds.
Federal inc. tax deds.
Federal tax credit
Total
Corporate income tax,
utility generation
$280
12
169
121
652
0
$ 0
7
101
0
108
86
$280
19
270
121
760
86
$ 0
12
168
0
180
0
$ 0
7
101
0
108
2lU
$ 0
7
101
0
108
612
Total subsidies in
illustration
Cost to customer
Total economic cost:
subsidies plus
customer cost
652 191* 8U6 180
722 67U 1396 1192
137U
868
22U2 1372
322
1761
720
2159
31
-------
If each subsidy listed in Table 10 were eliminated, the least costly
system would be wood, then electric (coal generation), followed by electric
(nuclear generation), and the solar/electric system would rank last.
However, these figures should be interpreted cautiously. Basic weak-
nesses are apparent in this approach. For example, the property tax subsidy
for the solar component is based upon the exemption from a 3.^2% annual pro-
perty tax. This amount ($280) would, in the absence of the exclusion, be due
each year. But in the utility analysis, property tax liability is assumed to
begin at 1% of cumulative expenditures and decline on a straight line basis.
And AFUDC earnings are excluded from the property tax basis, although viewed
as income earning investment by the regulatory commission.
This can be summarized as follows: each $100 invested in a non-solar
home heating system has a $3.^2 annual property tax liability each year for
20 years. Each $100 of rate base investment in a nuclear plant has a $0.008
property tax liability in the first year, and this declines to $0.005 in the
tenth year, $0.003 in the twentieth year, and $0.0003 in the last year.
Clearly, Table 10 might be amended to define a property tax subsidy for
the electric utility. However, we assume for the present that differential
property tax liability is normal, and so attribute a $280 annual subsidy to
the solar system exclusion from property tax liability.
Besides this problem of property tax definition, we have no basis for
calculating tax subsidies received by solar equipment manufacturers, wood
stove fabricators, power plant contractors and fabricators, or by the indus-
tries which supply these manufacturers.
Table 10 has limited value for comparing corporate/personal tax liabili-
ties between systems. However, it does show that the corporate tax subsidies
are a significant factor in reducing the customer's cost of electric space
heating and that nuclear power is particularly affected.
Water Heating
Table 11 summarizes the results of the water heating cost analysis.
They are similar to the space heating analysis. Natural gas appears to be
the least costly method, and electric water heating is always the most costly.
The analysis in which natural gas price reaches Btu parity with oil price
also does not disturb this ranking. For natural gas/oil price parity, gas
cost is $5^5 rather than $200 in Case 5, and solar/gas cost is $560 rather
than $UUO.
As with space heating, the system with lowest initial cost — electric
— has the highest annual customer cost!/
Solar/gas and solar/electric are less costly than solar/oil in the first
three cases, but solar/oil is less costly than solar/electric in the last two
cases.
I/ See Table 6 for initial purchase cost of each system.
32
-------
Whenever inflation occurs (the last four cases), a solar/electric system
is always less costly than a conventional electric hot water system.
Finally, the impact of higher interest and inflation is evident from
comparing the last two cases in Table 11. While all systems are more costly,
the ordering is almost unchanged, and each conclusion directly above remains
unaltered.
TABLE 11. COMPARATIVE COSTS OF WATER HEATING ($/year)
(rounded to nearest $5)
1979 dollars
9-5% interest
no real fuel inflation
case
1979 dollars
9.5% interest
real fuel inflation
case #2
Low inflation (1%)
9.55? interest
no real fuel inflation
case #3
gas
oil
solar/gas
electric
solar /elec .
$ 85
256
285
310
31+0
gas
solar/gas
oil
solar/elec .
electric
$ 100
285
315
365
390
gas
solar/gas
oil
solar/elec .
electric
$ 120
330
1*00
UUO
505
Low inflation (1%)
9.5% interest
real fuel inflation
case #U
gas
solar/gas
solar/oil
solar/elec.
oil
electric
$ 150
31*0
U60
U95
530
690
High inflation (12$)
1U.5/S interest
real fuel inflation
case #5
gas
solar/gas
solar/oil
solar/elec.
oil
electric
$ 200
UUO
605
6U5
700
910
33
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SECTION 1*
CONCLUSIONS
Our analysis has focused upon several economic factors which will in-
fluence future energy production and use in the ORBES region. Although
industry analysts generally conclude that nuclear power is less costly to the
utility, our finding is that coal power is somewhat less costly. If interest
and inflation rates should increase, we find that the coal advantage in-
creases.
Tax subsidies are a major consideration in utility economics. For pro-
spective coal and nuclear plants in the representative ORBES area studied,
the annual equivalent tax liability is negative. The greater capital inten-
sity of nuclear power results in its tax subsidy reaching 3.7 tf/kWh in future
1988 dollars, almost three times the coal subsidy.
Higher interest and inflation rates increase tax subsidies. The nu-
clear subsidy equals 70$ of the utility cost, and the coal subsidy is esti-
mated to be 22% of utility cost.
The timing of tax liability and revenue is such that little after-tax
net income is received by the utility in the last years of a plant's opera-
tions. Tax liability is high. The pattern is reversed in the construction
period and first years of operations: after-tax net income is high and cur-
rent tax liability is negative.
Consequently, the tax and regulatory systems interact to create incen-
tives for premature construction of new plants and premature retirement of
existing plants. The timing pattern seems equally applicable to coal and
nuclear power.
This discussion of comparative costs does not attempt to examine known
or possible environmental costs associated with coal or nuclear power. We
make no attempt here to investigate nuclear fuel disposal in the ORBES re-
gion, decommissioning, or reactor safety. Similarly, we do not study coal
mine health and safety, strip mine regulation, air pollution damage, or the
climatological impact of accelerated coal use.
Our study is limited to comparative costs and tax incidence. Within
this boundary, we conclude that coal power is less costly than nuclear power
in the ORBES region, and that the tax subsidy received by coal power is sig-
nificant but considerably less than the subsidy enjoyed by nuclear power.
3U
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In the absence of this tax subsidy, it is apparent that no utility-
would prefer nuclear to coal generation for economic reasons. One author of
this report has estimated elsewhere that, if major problems arise with re-
spect to waste fuel disposal, reactor decommissioning, safety requirements,
and uranium availability, there is a very small possibility that nuclear
power cost may be as high as 22 <£/kWhi/
Volatility in energy prices creates considerable uncertainty with re-
spect to future space and water heating costs. Our examination of costs of
providing heat and hot water to an owner-occupied home considered a diverse
set of inflation and interest rate assumptions. We found that, for a new
home first occupied in 1979, natural gas is the least costly source of space
and water heating. Electric resistance heating is the most costly system for
the customer on an annual basis, and this is true for both space and water
heating.
Although natural gas appears to be the least costly system at present ,
there is little doubt that natural gas availability will decline. The U.S.
Energy Information Administration forecasts that domestic gas production will
continue to decline from its 1973 maximum of 22 quadrillion Btu. Including
every source of new production, total production may be as low as 15 quadril-
lion Btu by
If natural gas prices reach parity with oil prices on a Btu basis in 5
years, and if both continue to accelerate in an economic environment of high
inflation and interest rates, a solar /gas space heating system is less costly
than a separate gas system. It may be desirable to consider making future
natural gas use by homeowners contingent upon installation of solar or wood
burning space and water heating.
Comparing corporate and personal income tax subsidies for four sources
of home heating, we find the subsidies accruing to a solar/electric system to
exceed those received by an electrically heated home using nuclear power
generation. For the solar/electric system, the largest subsidies are the
Indiana property tax exemption, and the Federal personal income interest de-
ductions and solar tax credit. The nuclear power-electric home heating sys-
tem has its primary tax subsidy through the Federal and Indiana corporate
income tax. Tax subsidies going to electric heating by coal power are less,
and for wood burning are minimal.
It was a modest surprise to find that, in the two cases with general
inflation and with real energy price inflation in excess of general inflation,
solar, wood, and heat pump systems have less annual cost than conventional
oil or electric systems. This is true for low general inflation and interest
rates as well as high inflation and interest. It is applicable to both space
and water heating.
I/ Chapman, "Nuclear Economics," op. cit., Table 18, Section 6.
2_/ U.S. Energy Information Administration, Forecasts, Annual Report to Con-
gress 1978, Vol. 3, Ch. 10.
35
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The problem, of course, is that oil or electric space or water heat
cost less for a contractor to install, but solar, wood, or heat pump systems
have less total cost to the customer.
Our conclusions should be qualified by emphasizing three important lim-
itations. First, our focus is on energy production and use. We have not
studied conservation technologies and policies and their effects upon utili-
ties, customers, and the national economy. It may be the case that energy
conservation is at present a better general economic policy than energy pro-
duction. If so, it may have unexpected consequences upon many subjects con-
sidered here. We may speculate that efficient energy conservation policies
would render less desirable the more costly technologies studied here. In
particular, we would expect nuclear power generation and electric space and
water heating to be displaced.
A second qualification: our specific analysis applies only to a part of
the ORBES region. We chose southern Indiana as the locus of study for one
major reason. It is a location where nuclear power and coal generation are
economically competitive. In addition, all of the conventional residential
fuels are available, and the renewable energy resources (wood heating and
solar hot water heating) are economically competitive with conventional
fuels. However, our conclusions may not be applicable to other areas in the
ORBES region. Variations in coal cost and state corporate income tax policy
may alter the coal/nuclear comparison. Similarly, price and availability for
natural gas, wood fuel, and solar hot water systems may vary.
Finally, we do not examine the distributional or equity aspects of the
cost and taxation questions. Do upper income families benefit dispropor-
tionately from the residential tax subsidies accruing to solar hot water
heating? How are utility tax benefits distributed among customers, manage-
ment, and shareholders? What is the regional and national incidence of the
Federal corporate and personal income tax subsidies? We have no opinion or
information on this question of equity, but realize it is of considerable
interest.
It is our overall opinion that these three qualifications (i.e., omis-
sion of conservation economics, narrow geographic focus, and absence of dis-
tributional information) clearly limit the broad applicability of our
findings. However, we believe that further research into these three rele-
vant and important areas would not alter our conclusions, but would instead
broaden the context in which they would be interpreted.
36
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BIBLIOGRAPHY
Brandfon, William W., "Comparative Costs of Coal and Nuclear Electricity Gen-
eration," Testimony, Oversight Hearings on Nuclear Economics, U.S. House
of Representatives, Committee on Interior and Insular Affairs, Subcom-
mittee on Energy and the Environment, July 12, 1979.
Cady, K.B., and A.C. Hui, "NUFUEL - A Computer Code for Calculating the Nu-
clear Fuel Cycle Cost of a Light Water Reactor," Cornell University,
Ward Laboratory of Nuclear Engineering, Ithaca, N.Y., August, 1Q78.
Chapman, Duane, "Nuclear Economics: Taxation, Fuel Cost, and Decommissioning,"
draft final report submitted to the California Energy Commission, Octo-
ber 29, 1979 (revised).
Chapman, Duane, and Kathy Cole, "Federal Income Tax Provisions Affecting
Nuclear Power," prepared for the October 5, 1970, ORBES meeting in
Lexington, Ky.
Comtois, Wilfrid, "Power Plant Construction Gchedules, Escalation, and In-
terest During Construction," presented at the American Power Conference,
April 26, 1976.
Galvin, Michael, "Report on the Reasonableness of the Income Tax Allowance
for Pacific Gas and Electric Company," California Public Utilities Com-
mission, February 11, 1977-
Jansen, Steven D., "Electrical Generating Unit Inventory 1976-86," Prepared
for ORBES, November, 1970.
Knecht, Ronald L., Review and Critique of_ California Electricity Generation
Methods Assessment Project Fjlnal_ Report, May 1, 1977, prepared for the
California Energy Commission.
Knecht, Ronald, "Testimony on Power Generating Economics and Planning," Wis-
consin Public Service Commission, Northern States Power Company, et al.,
Application for Tyrone Nuclear Unit, December 20, 1978.
Knecht, Ron, et al., "Comparative Cost Analysis (Revised)," Supporting Docu-
ment No. 0. California Energy Commission, Spring, 1970.
Koebel, Ben, letter to Kathleen Cole, August 2Q, 10-79.
37
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Romanoff, Charles, "A Comparison of Nuclear and Coal Costs," Testimony, New
Jersey Board of Public Utilities, October 9, 1978.
Pennington, James H., letter to Duane Chapman, September 10, 1979-
Public Service Indiana, Annual Report 1978.
Rossin, A.D., and T.A. Rieck, "Economics of Nuclear Power," Science, Vol. 201,
18 August 1978, pp. 582-89.
Schultze, William D., et al., "The Economics of Solar Home Heating," Print,
U.S. Congress, Joint Economic Committee, 85th Cong., 1st Sess., March 13,
1977.
U.S. Council of Economic Advisors, Economic Report of the President, January,
1979.
U.S. Department of Commerce, Bureau of Economic Analysis, Survey of Current
Business, monthly.
U.S. Department of Energy, Energy Information Administration, Annual Report
to Congress 1978, Vol. 3: Forecasts.
U.S. Department of Energy, Energy Information Administration, Monthly Energy
Review, August, 1979. and November, 1979-
U.S. Energy Research and Development Administration, "An Analysis of Solar
Water and Space Heating," November, 1976.
U.S. Internal Revenue Service, "Tax Information on Depreciation," Publication
53U, 1979-
38
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APPENDIX-''
CORPORATE INCOME TAX PROVISIONS AFFECTING POWER GENERATION
AFUDC_ income
The allowance for funds used during construction (AFUDC) has two compo-
nents. One is an equity component which is added to operating income in ar-
riving at total income. The other, the debt component, reduces actual inter-
est expense in arriving at net interest charges. Net income, while being the
difference between total income and interest charges, always includes AFUDC
as a positive amount.
The significance of AFUDC, of course, arises from its inclusion in ac-
cumulated rate base which is the basis for future rates.
AFUDC when earned is wholly excluded from Federal income taxation. How-
ever, the Internal Revenue Service (IRS) does treat income derived from AFUDC
rate base as normal income. The rationale is that AFUDC is an accounting
entry rather than an actual income item, so no tax liability should be im-
posed.
By way of illustration, a nuclear plant with construction cost of $2.5
billion might have an 8$ AFUDC rate applied to actual plant expenditures and
to nuclear fuel inventory acquisition. For a representative $2.5 billion
plant having a 10-year construction period from 1978 to 1987, AFUDC would add
$600 million to the plant rate base and $Ho million to the fuel rate base.
None of this is taxed as earned, and all is defined as part of net income.
interest deductions
Interest expense payments are generally viewed in the United States as
ordinary business expenses and thereby deductible from taxable income. How-
ever, the other form of capital contribution — stock and equity — have pay-
ments made to them subject to tax liability. Consequently, utilities prefer
debt to new stock issues in part because a dollar of new debt reduces overall
tax liability while a dollar of new equity does not.
I/ This material is based upon "Nuclear Economics," Section U, and is taken
from "Federal Income Tax Provisions Affecting Nuclear Power," prepared for
the October 5, 1979, ORBES meeting in Lexington, Ky.
39
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Value-added taxation of corporate revenue is widely used in Europe. In
this form of taxation, taxable value equals revenue less cost of poods, wages,
and salaries. Therefore interest, as well as dividends, is subject to this
form of corporate income tax.
During the period of plant operations, bond payments to amortize debt
may have more than 90$ of the payment going to interest in the early years.
investment tax credit
The investment tax credit is a direct reduction in tax liability. At
the maximum rate, it is equal to 11 If2% of qualified investment. Qualified
investment is essentially construction cost excluding land and structures.
AFUDC is not included. Qualified investment is thus approximately 95$ of
construction cost. The maximum effective rate, then, is 10$ of actual con-
struction cost.
This is a significant tax subsidy, its value for a hypothetical new
plant being about $725 million. With flow-through accounting and amortiza-
tion of the credit in five years, customer costs are reduced by nearly $100
million for five years.
A major problem arises from the last 1 1/2$ of the investment tax credit
and its use as compensation for utility employees; this is discussed below,
under "conflict of interest".
accelerated depreciation
For net income determination as well as rate-making, depreciation ex-
pense is defined by the normal straight-line basis. Depreciation expense is
simply assumed to be spread equally over each year of the plant's life, and
is each year equal to 3 1/3$ of original cost.
Accelerated depreciation literally speeds up depreciation for tax pur-
poses. By placing larger deductions in earlier years, it shelters signifi-
cant income in those years from tax liability. The double declining balance
method is most effective in terms of maximum tax reduction.
The normal rate is doubled, from 3.33$ to 6.67$. This percent is ap-
plied to the undepreciated basis at the beginning of each year, and the re-
sult is current depreciation for tax purposes.
tax life
The arbitrary tax lives assigned to nuclear power equipment provide an
additional tax subsidy. The IRS permits depreciation to be based upon a 16-
year period rather than the 30-year expected life. Consequently, the double
declining balance method, applied to a 16-year tax life, gives a 12.5$ depre-
ciation expense rate. After eight of the 16 years the utility switches over
to normal straight line depreciation for the remaining basis. This ensures
total depreciation in 16 years.
hO
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Similar arbitrarily short Federal tax lives apply to other utility pro-
perty: 22.5 years for fossil fuel generating systems and 2h years for trans-
mission and distribution equipment!.;
For a $2.5 billion plant, Federal depreciation deduction is $31^ million
in the first year. Normal depreciation for rate base investment is $10^
million. The plant is wholly depreciated for Federal tax purposes by 2003,
and no further depreciation expense deductions can be applied to taxable in-
come for the Federal corporate income tax.
repair allowance
The IRS repair allowance has been interpreted to allow a company to
elect the larger of either actual repair expenses or the IRS percentage al-
lowance as deductible expense—; Utilities frequently select the percentage
allowance because it exceeds actual expense.
The repair allowance rate for a nuclear power plant is 3$, giving an al-
lowance of $75 million in 1988 for a hypothetical plant.
non-taxable dividends
As effective tax management brings the utility into a position with no
significant tax liability, the utility may exempt its dividend payments from
income tax liability for the recipients of the dividends.
Suppose a company normally has a positive and significant net income and
net cash receipts: it is in a position to make dividend payments if it elects
to do so. Suppose it has, for tax purposes only, no taxable profits. Then,
all its dividends would be tax-exempt for dividend recipients: it is essen-
tially a fictional capital repayment.
If dividend payments total $X million, and taxable profit is a smaller
$Y million, then Y/X/5 of each dividend is taxable for recipients.
In determining non-taxable dividends, taxable income is recalculated as
"earnings and profits". Essentially, depreciation is recomputed on a
straight line basis with arbitrary tax lives.
For the dividend recipient, these tax-exempt dividends remain exempt
until they sum to the original purchase price of the stock. At that point,
additional tax-exempt dividends become liable to capital gains tax.
I/ See U.S. Internal Revenue Service, "Tax Information on Depreciation,"
Publication 53U, 1979, p. 35.
2_/ See Michael Galvin, "Report on Reasonableness of the Income Tax Allowance
for Pacific Gas and Electric Company," California Public Utilities Commission,
February 11, 1977, pp. 2-U.
Ul
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It can lie noted that this provision increases the value of tax subsidies
pertaining to new construction Toy creating deductions which can be passed
along to shareholders. One New York utility reported 85$ of its dividend
payments were tax exempt in 1977.
conflict of interest
Under present Federal tax law, the last 1 1/2% of the 11 1/2$ in the
investment tax credit may be used directly to finance employee stock owner-
ship plans. The maximum rate (11 1/2$) requires employees to match the final
1/2% contribution.
Put in its simplest terms, this portion of the investment tax credit
uses public funds to increase the compensation of utility managers who choose
to construct a new plant. This interpretation has not been seen as invalid
by Treasury Department personnel with whom I have discussed this problem.
As an illustration with data utilized in this study, the investment tax
credit reduces the company's tax liability by a sum of $275 million!/ Of
this amount, $36 million is contributed to the stock ownership planfll In
addition, the cost of administering the plan is creditable against tax lia-
bility.
The possible conditions on participation in the plans are such that
utility executives will be disproportionate beneficiaries. Persons under age
25 or with less than three years employment may be excluded. Unions may
elect to exclude their members from participation. Within the pool of parti-
cipants, stock contributions are based upon salary up to a $100,000 limit.
Treasury Department staff believe utilities are the major beneficiaries
of this program^?
In my opinion, this creates a major conflict of interest. Utility mana-
gers must decide the desirability of new construction programs for their com-
panies and customers, yet if they decide affirmatively, they will be person-
ally rewarded for doing so.
Indiana corporate income taxation
Indiana tax provisions differ in four ways. First, the rate is 3$
rather than 1*5/2 on net income. Second, there is also a revenue tax. Third,
no investment tax credit is applicable. Finally, the Indiana tax liabilities
are deductions from Federal taxable income.
I/ See "investment tax credit", above.
2/ Qualifying expenditures, recall, are 95$ of total. $2.5 billion x .95 x
.015 = $36 million.
3/ Personal communication.
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nuclear and coal generation comparison
As noted above, the minimum Asset Depreciation Range tax life is 22.5
years for a fossil fuel plant and 16 years for a nuclear plant. In addition,
the repair allowance is % for a fossil plant rather than the 3% for a nu-
clear plant. In other respects there is no differentiation for tax purposes.
However, to the extent that nuclear power is more capital intensive, it ac-
crues a greater magnitude of tax subsidies per kilowatt-hour.
1*3
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