AM ECONOMIC EVALUATION OF
THE REPLACEMENT OF OIL-FIRED
GENERATION CAPACITY WITH
COAL-FIRED CAPACITY
Prepared for
Energy Policy Division
Office of Planning and Evaluation
U.S. Environmental Protection Agency
Prepared by
Putnam, Hayes and Bartlett, Inc
50 Church Street
Cambridge, Massachusetts 02138
March 1981
The assumptions, findings, conclusions, judgments,
and views expressed herein are those of Putnam, Hayes an
Bartlett, Incorporated and shculd not be interpreted as
necessarily representing the official policies of the U.
Government.

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AN ECONOMIC EVALUATION OF
THE REPLACEMENT OF OIL-FIRED
GENERATION CAPACITY WITH
COAL-FIRED CAPACITY
Prepared for
Energy Policy Division
Office of Planning and Evaluation
U.S. Environmental Protection Agency
Prepared by
Putnam, Hayes and Bartlett, Inc.
50 Church Street
Cambridge, Massachusetts 02138
March 1981
The assumptions, findings, conclusions, judgments,
and views expressed herein are those of Putnam, Hayes and
Bartlett, Incorporated and should not be interpreted as
necessarily representing the official policies of the U.S.
Government.

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TABLE OF CONTENTS
PAGE
I.	INTRODUCTION AND SUMMARY	1-1
Summary of Results	1-2
Methodology	1-3
Plan of this Report	1-6
II.	REPLACEMENT OF OIL PLANTS	II-l
Economic Evaluation of Oil Plant
Replacement	II-l
Reasons Replacement is Not Occurring	II-3
Uncertainty	II-3
Effect of Rate-Setting Practices	II-5
Financing Difficulties	11-12
Effectiveness of Proposed Incentives	11-14
A.	DATA AND ASSUMPTIONS	A-l
Fuel Prices	A-l
Coal Plant Construction Costs	A-3
Operating and Maintenance Costs	A-3
Capital Costs	A-4
Tax Assumptions	A-5
Undepreciated Portion of Oil Plant	A-6
B.	FINANCIAL ANALYSIS OF SIX NORTHEASTERN
UTILITIES	B-l
Public Service Company of New Hampshire	B-l
United Illuminating	B-2
Long Island Lighting	B-3
Connecticut Light and Power Company	3-4
New England Power	3-6
Boston Edison	3-7

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SECTION I
INTRODUCTION AND SUMMARY
In March 1980 the Carter Administration proposed a
legislative program to convert and replace oil and gas-fired
electricity generating capacity with alternative sources of energy.
The proposed program was designed to displace .750,000 barrels of
oil per day and the natural gas equivalent of 250,000 barrels of
oil per day by 1990. The electric utility industry, which con-
sumes approximately 3 million barrels of oil and natural gas
equivalent per day was the prime target of this proposed program
to reduce our dependence on foreign oil.
The proposed program had two phases. The first phase
would have required an amendment to the Powerplant and Industrial
Fuel Us.e Act to prohibit oil burning at 107 utility boilers capable
of converting to coal or other alternative fuels.^ Grants total-
ing $3.*6 billion would have been available to assist utilities
with the mandatory conversions. The second phase provided for
$6 billion in grants to encourage reduced oil and gas consumption
by retiring additional oil and gas-fired generating units. The
oil and gas displacement could be achieved through energy conser-
vation, renewable resources, or the replacement of oil and gas-
fired generation with alternative resources (coal, nuclear or
synthetic fuels).
This report does not address the issue of conversion from
oil to alternative- fuels. Rather it focuses on the economics of
the replacement of existing oil-fired units with new coal units
(Phase II of the Carter Administration's proposal) and discusses
the disincentives that currently exist for such replacement. The
first section of the report summarizes the results of this analysis,
describes the methodology used to analyze the economics of oil
plant replacement, and presents the organization of the remainder
of the report.
I	
The Senate has since reduced this number to 80 oil-fired units.

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1-2
SUMMARY OF RESULTS
Strictly from an economic standpoint, absent the
effects of rate regulation, the capital costs of constructing
a new coal plant are more than offset by the savings in fuel
costs over -the life of the plant.^ The present value of the
cost of providing power from the coal plant—both fuel and
capital costs—is approximately 85 percent of the cost of fuel
for providing an equivalent amount of power from an existing
oil plant over the life of the coal plant.
While the replacement of oil-fired units with coal
units is favored from an economic standpoint, four conditions
exist which provide a disincentive to utilities to undertake
such investments. These disincentives include:
•	1 .\e significant uncertainty regarding the cost of
£• new coal plant compared to the costs of an exist-
ing oil plant,
•	rate-setting procedures which make such replacement
unattractive for the utility's customers and/or
stockholders,
•	The inability of the utilities to finance replace-
ment capacity in addition to the capacity needed to
serve load growth, and
•	The difficulty in siting and obtaining licenses for
new plants.
The first three of these disincentives are analyzed in Section II
of this report. The following conclusions concerning the first
three disincentives can be drawn from this analysis:
The economics of such replacement are, of course, dependent upon
the assumptions used in the analysis. All of these assumptions
are detailed in Appendix A of this report. Section II of this
report illustrates the sensitivity of the results to some of
the key assumptions.

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1-3
•	Uncertainty in costs may cause a utility to prefer
the continued use of an existing oil plant.
—Construction costs of $1852 per kilowatt in 1979
dollars would make the replacement of oil-fired
capacity uneconomical.^
—If coal costs per kilowatt-hour were to rise to 72
percent of the cost of oil, oil plant replacement
would be uneconomical.
—Coal costs 20 percent higher than anticipated com-
bined with a capital cost of $1430 per kilowatt
would make the replacement uneconomical.
•	Rate-setting practices provide a significant disincen-
tive for new plant construction.
—Rate-setting practices such as flow-through accounting,
the exclusion of construction work in progress from
the rate base, inadequate allowed rates of return,
regulatory lag, and, in some cases, fuel adjustment
clauses provide a disincentive to the utility to
replace oil-fired generating capacity.
—Under standard rate-setting practices, the construction
of a coal plant will result in higher rates for con- -
sumers in the near term and lower rates in the future.
Regulators may be hesitant to approve construction
plans which result in increases in rates in the short
run. However, if the consumers' discount rate is
below 17 percent, the consumers would prefer to have
the utility replace the oil plant.3
•	The financial condition of some utilities is currently
so poor as to preclude the investment in a new coal
plant.
The cost per Kilowatt of a new coal plant has been estimated to
be $97 3 but the cost can be significantly higher depending upon
siting oroblems and pollution control requirements.
2
The customer must pay capital costs en the new coal plant as
well as fuel costs if the coal plant is constructed. In the
near term the differential between oil ana coal costs is lower
than the capital costs of the coal plant borne by the customer;
however, in the future the capital costs borne bv the customer
are lower than the differential between oil and coal costs.
^The consumers1 discount rate is the time value placed on money
by the utility's customers.

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1-4
—The financial condition of some of the utilities in
the Northeast is sufficiently poor such that these
utilities will not be able to finance the replacement
of oil-fired capacity in addition to its current
capital requirements.
The first conclusion implies that rate-setting proce-
dures, regulatory practices, and/or economic conditions which
serve to reduce the uncertainty associated with the construction
of new coal plants would eliminate some of the existing disincen-
tive to construct new plants. Examples of measures which would
reduce uncertainty would be adequate and predictable rate increases,
inclusion of construction work in progress in the rate base,
streamlined procedures for obtaining licenses for new plants and
a reduction in the general rate of inflation throughout the
economy.
The second conclusion means that the Public Utility
Commission (PUC) must ensure that the return on the coal plant
investment is adequate so that the utility has an incentive to
invest in the new coal plant. In addition, the PUC should con-
sider optimizing the time pattern of the utility's recovery of
costs such that the consumer gains in the short term from the
construction of a coal plant.
The final conclusion implies that, in some cases,
regardless of the economics of oil replacement, such replacement
will not occur without a substantial improvement in the utilities'
overall financial -positions. In these cases, the reduction in
the uncertainty associated with construction and fuel costs and/
or more favorable rate-setting practices may not be adequate
incentive to encourage the replacement of oil-fired capacity.
The provision of $6 billion in grants may provide much needed
financial assistance to utilities. Whether or not this amoun-
is sufficient to enable utilities to finance the replacement of
oil-fired generating capacity is not analyzed in this report.

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1-5
However, this report did consider whether the grant or other
proposed incentives would be effective in reducing the dis-
incentives that currently exist. This analysis is discussed
briefly at the end of Section II.
METHODOLOGY
In order to understand the economics of replacement
under various regulatory and economic conditions, the cost of
providing power from a coal plant and an oil plant was simulated
using a utility financial simulation model. This model was
used to simulate the incremental effects on the utility's revenue
requirement, cash flow, and rate base of an investment in a 410
iMW coal plant. The coal plant was assumed to run at 50 percent
of its effective capacity of 375 MW.1
This model can be used to analyze the financial condi-
tion of an entire utility or group of utilities or, as in this
case, the economics of a single investment decision. Estimates
of fuel costs, construction costs, operating and maintenance
costs, and capital costs are input into the model." The model
then produces a set of financial statements—income statement,
balance sheet, and funds flow—resulting from these costs and
the regulatory conditions imposed on the model. The regulatory
conditions include flow-through or normalized accounting, the
^This is a worst case assumption. Larger coal plants run at a
higher capacity factor will be more economical.
2
The model compares the fuel costs, operating and maintenance
costs, and capital costs of a new coal plant with the fuel and
operating and maintenance costs of an existing oil plant. In
each case—whether or not the coal plant is constructed—it
was assumed that the capital recovery charges for the oil plar.-
(remaining depreciation and the return on the undepreciated
portion of the plant) would be the same. Therefore, capital
recovery charges for the oil plant were net considered in this
comparative analysis.

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1-6
inclusion or exclusion of contruction work in progress (CWIP)
from the rate base, the period of regulatory lag for fuel costs
and for capital costs, and the allowed rate of return.
In addition to the analysis performed using the utility
financial simulation model, a financial analysis of six Northeast
utilities was performed. This analysis reviewed the ability of
these utilities to finance the replacement of cil-fired capacity.
While these utilities are not typical of all utilities, they are
typical of utilities with old oil-fired generating units. In-
cluded in this analysis is a review of each utility's internal
and external financial capability, as well as a review of the
capital requirements of the utility's current construction plans.
PLAN OF THIS REPORT
The remainder of this report is orga: ized as follows:
•	Section II presents the results of the analysis of
the economics of oil plant replacement and the
disincentives which exist for. such replacement.
•	Appendix A presents the assumptions and data used
in the analysis.
•	Appendix B summarizes the analysis of the financial
condition of six Northeast utilities.
All exhibits are located at the end of each Section or Appendix.

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SECTION II
REPLACEMENT OF OIL PLANTS
Phase I of the Carter Administration's proposed oil
backout program would have required the conversion of 107 oil-
fired generating units to coal.* Grants totaling $3.6 billion
would have been provided to assist the utilities required to
convert. Phase II of this program provided for $6 billion in
grants to encourage voluntary replacement of additional oil-fired
generating units with alternative power sources including con-
servation, renewable resources, and alternative fuels such as
coal, nuclear and synthetic fuels. This section reviews the
economics underlying the replacement of oil-fired units with coal
units. A discussion of some of the disincentives for this replace-
ment is then provided. Finally, the ability of Phase II of the
proposed oil backout program to eliminate some of these dis-
incentives is reviewed.
ECONOMIC EVALUATION OF OIL PLANT
REPLACEMENT
To evaluate the desirability of replacing cider oil
plants with new coal plants from an economic standpoint absent
rate-setting effects, the savings from the lower fuel costs
should be compared to the cost of the new plant, less all related
tax consequences. All costs are discounted to their present
value equivalent recognizing that a dollar a year from now does
not have the same value as a dollar today. This "capital budget-
ing" type of analysis would determine whether, absent rate-
setting effects, it is desirable from the utility stockholders'
pcir.t of view to replace older oil plants with new coal plants.
*In the Senate version of this legislation, the number of plants
which would be required to convert was reduced to 80.

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II-2
Exhibit II-l presents the cash flows resulting from
the investment in a new coal plant.^ These cash flows include:
•	The cost of plant construction;
•	The investment tax credit which reduces the tax
liability of the firm by 10 percent of all qualify-
ing investments;
•	The tax shield resulting from the depreciation of
the plant;
•	The cost of fuel and of operating and maintaining
the coal plant; and
•	The investment in working capital, predominantly
for fuel inventories.
These cash flows are summed and discounted at the utility's after-
2
tax weighted average cost of capital. As shown in Exhibit II-l,
the present value of the coal plant investment is $1133 million,
including fuel costs over the life of the plant.
The present value of the costs of operating the oil-
fired plant is shown in Exhibit II-2. The cash flows considered
include the cost of fuel, the cost of operating and maintaining
the oil plant, and the investment in working capital (fuel inven-
tories).^ The present value of these costs is $1337 million.
Thus, strictly from an economic standpoint, the replacement of oil
capacity with coal capacity will represent a savings of $204
million ($1337 million less $1133 million).
xThe data and assumptions on which this analysis is based are pre-
sented in Appendix A. The results of this analysis are highly
dependent upon these assumptions.
^Since we are concerned with the economics of replacement from
the utility stockholder's point of view, absent rate-setting
effects, these flows are discounted at the utility's actual cost
of capital assumed in the analysis (which assumes a 15 percent
rate of return on equity) and not the rate of return or. capital
allowed by the Public Utility Commission (which includes a 13.5
percent return on equity capital).
3 As explained in Section I and Appendix A, these costs do not
include the capital recovery charges associated with the oil
plant since these capital recovery charges will be incurred
whether or not the coal plant is constructed.

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II-3
REASONS REPLACEMENT IS NOT OCCURRING
There may be several reasons why oil plant replacement
is not taking place currently. The disincentives which exist
include:
•	The uncertainty regarding the cost of a new coal
plant versus the cost of an existing oil plant,
•	Rate-setting practices which can make replacement
uneconomical for the utility's consumers and/or
stockholders.
•	The inability of the utilities to finance replace-
ment capacity in addition to capacity needed to
serve load growth, and
•	The difficulty in siting and obtaining licenses for
new plants.
The first three reasons cited are analyzed below.
UNCERTAINTY
The economics of the replacement of oil-fired generating
capacity depend upon the estimated future cost of oil versus coal
and the anticipated cost of constructing a new coal plant. Both
future fuel and construction costs are highly uncertain. Given
this uncertainty, the utility may be hesitant to construct a new
coal plant.
To understand how uncertainty affects the decision to
construct a new ccal plant, a "breakeven" analysis is presented
below. This analysis calculates the amount of increase in con-
struction costs and fuel costs which can occur before the con-
struction of the coal plant becomes unattractive from an economic
standpoint.

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II-4
Construction Costs
As discussed in Appendix A, it was assumed that a
bituminous coal plant constructed in the Northeast would cost
$723 per kilowatt for generating capacity, $100 per kilowatt
for transmissions and distribution facilities, and $150 per
kilowatt for related pollution control equipment—a total of
$973 per kilowatt in 1979 dollars. Recent experience with the
construction of coal plants indicates that delays in construction
and higher than anticipated inflation have often resulted in
increased construction costs. The economics of oil plant re-
placement depend upon the anticipated construction cost of the
new coal plant. If the investment cost of coal plant amounted
to $1852 per kilowatt (1979 dollars) rather than $973 per kilo-
watt, the replacement of the oil plant would no longer be
desirable from an economic standpoint.
Even if the construction of the coal cflant were still
economically justifiable, increases in construction cost may be
difficult for the utility to finance. Financing difficulties
are discussed in more detail below.
Coal and Oil Costs
An additional uncertainty lies in the projections of
the differential between oil and coal costs. Currently the cos-
of bituminous coal in the Northeast equals 50 percent of the cost
of fuel oil #6 per kilowatt-hour. However, according to one
forecast, coal costs are projected to rise at a 5 percent real
rate (net of inflation) in the near term; while oil costs are
projected to rise only 3 percent in real terms.^ This trend
^"This forecast reflects the projections published by Data Resources,
Inc. in their Energy Review, Winter 19 80.

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II-5
then reverses itself after 1986 when oil costs are projected to
increase at a steeper rate than coal costs.
If instead coal prices continued to rise at the 5 per-
cent real rate until 1992 and then rose at the same rate as oil
prices in the remaining years of the analysis, the cost of coal
per kilowatt-hour would rise to approximately.72 percent of the
cost of oil by 1992. This increase in coal costs would result
in the coal plant having a higher present value cost than the
oil plant.
Such an increase implies coal prices approximately 3 8
percent higher than projected each year. While this may appear
extreme, uncertain fuel costs together with uncertain coal plant
construction costs may lead to hesitance on the part of utilities
to replace oil plants. For example, if coal costs were 20 percent
higher than projected and construction costs were $1430 per kilo-
watt (1979 dollars), the economics again would favor not replac-
ing the oil plant.
EFFECT OF RATE-SETTING PRACTICES
•
Although the decision to replace oil plants may be sound
from a purely economic standpoint, the rate-setting environment
may cause the utility to favor maintaining the oil plant. The
rate-setting practices may make replacement unattractive for the
utility's stockholders and/or customers. The effect of the dif-
ferent regulatory 'practices on the stockholder and the customer
is discussed below.
Stockholder Impact
The Public Utility Commission (PUC) determines the rates
the utility will be allowed to charge customers for the electricity
provided. These rates are calculated by determining the "revenue
requirement" of the utility. The "revenue requirement" is, in

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11=6
theory, sufficient to compensate the utility for its operating
costs, including taxes, plus provide a return on the capital
invested in the plant. In theory, the impact of the construc-
tion of the coal plant should result in em after-tax revenue
requirement^" over the life of the plant equal to $1133 million.
This would exactly equal the present value of the cost of the
coal plant investment.
If the revenue requirement resulting from the construc-
tion of the coal plant does not cover the costs of constructing
coal plant, profits will decline and hence, the rate of return
cn common equity will decline. Thus, the utility's common
stockholders will find the construction of the coal plant
unattractive.
There are many reasons why the revenue requirement in
practice does not precisely reflect the costs calculated above.
These reasons include rate-setting practices which affect either
the timing or the amount of the utility's revenue. These rate-
setting practices include:
•	Flow-through accounting which requires the utility to
immediately pass on the benefits of the investment
tax credit and the benefits of accelerated deprecia-
tion to the consumer, instead of allowing the utility
to "normalize" these credits and pass them onto.the
consumer over the life of the plant;
•	Allowance for Funds Used During Construction (AFDC)
which requires the utility to capitalize the capital
costs of* the investment during the construction period
and then allows the utility to recover these costs
The revenue requirement after taxes will equal the utility's
revenue requirement multiplied by one minus the utility's
marginal income tax rate. The revenue requirement is nc:
normally stated on an after-tax basis. However, in this case,
it is necessary to do so in order to be able to directly com-
pare rhs present value of the revenue requirement to the present
value of the after-tax costs of the coal plant -computed above.

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II-7
over the life of the plant/ rather than allowing the
utility to include construction work in progress
(CWIP) in the rate base and thus to earn a cash re-
turn on the plant during the construction period;!
•	An inadequate allowed rate of return which does not
provide a sufficient return on the utility's equity
shareholders; and?
•	Regulatory lag which allows the utility to recover
the capital cost incurred only after some lag.3
Many PUC's exclude construction work in progress (CWIP) from
the rate base. However, to offset the cost of funds tied up
in construction, PUC's provide for an "allowance for funds
used during construction (AFDC)." A return on CWIP is calcu-
lated annually. This return (AFDC) is added to the utility's
net income and a corresponding amount is added to the CWIP
account on the balance sheet, thereby increasing the asset value
of the plant. When the plant is completed, the total amount of
the construction costs plus accumulated AFDC is added to the
rate base. The utility is then allowed to earn a return on this
increased rate base and is allowed to depreciate the total
amount—both the construction costs and accumulated AFDC—for
rate-making purposes. The effect of this calculation is to
postpone the receipt of cash earnings on"the investment until
the plant is actually placed into service.
The credit to net income and corresponding debi i to CWIP on the
balance sheet is an accounting transaction only and does not
represent an increase in the cash earnings of -he utility.
Therefore, AFDC represents non-cash income and as such should
not be regarded as a source of funds for the utility. This
lowers the "quality of earnings" of the utility.
If the AFDC rate is set too low and/or the utility is not allowed
to earn a return on past AFDC (that is, a compound rate of return
on CWIP), the AFDC will be inadequate to compensate the utility
for the cost of capital for construction of the plant.
2	-
An inadequate rate of return will cause the market price of the
stock to fall below the book value of the stock. This makes it
difficult for the utility to issue common stock to raise funds
for its construction program since any new comr;on stock will
dilute the book value of the current shareholders' stock.
^In this analysis, it is assumed that fuel and other operating
costs are recovered without lag through a fuel adjustment clause.
In reality, a lag of one or more months may be built into the
fuel adjustment clause.

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II-8
To measure the effect of altering the rate-setting
practices, the allowed after-tax revenue requirements resulting
from the coal plant construction under different rate-setting
practices was compared to the cost of constructing the coal
plant. The base case rate-setting practices assume flow-through
of all tax credits/benefits to the consumer, the exclusion of
CWIP from the rate base, an allowed rate of return of 9.66 per-
cent compared to an actual cost of capital of 10.2 percent,^" and
a one year lag in the recovery of capital costs and no lag in the
recovery of fuel costs.
The effect of the first two of the above regulatory
practices is shown in Exhibit II-3. As shown in this exhibit,
the after-tax revenues allowed to be recovered by the utility
as a result of the coal plant investment of $1078 million over
the life of the coal plant investment if the utility is not
allowed to include CWIP in the rate base and is required to
flow-through all tax credits and benefits (base case). If the
utility is allowed to normalize all tax benefits and to include
CWIP in its rate base, the allowed after-tax revenues are $1094
million. However, the allowed after-tax revenues are still below
the cost of constructing the coal plant of $1123 million. Thus,
the utility's profits will decline as a result of constructing
the new coal plant and the return to the common stockholders
will also decline.
The incremental effects of allowing the utility to earn
an adequate rate at return and of eliminating the regulatory lag
are shown in Exhibit II-4. As this exhibit shows, an increase in
the rate of return from 9.66 oercent to 10.20 percent increases
i
~he allowed after-tax revenues to $1108 million." Eliminating
"""The rate of return of 9.66 percent is a weighted average cost of
capital which includes an assumed allowed rate of return on
equity of 13.5 percent rather than the actual cost of equity
capital assumed to be 15 percent.
2
This scenario assumes that the utility is allowed to normalize
all tax credits and is allowed to include CWIP in the rate base.

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II-9
regulatory lag increases the allowed after-tax revenues to
$1118 million. Combining the increase in allowed return with
the elimination of regulatory lag causes the allowed after-tax
revenues to increase to $1133 million which exactly equals the
cost of constructing the coal plant. Thus, the utility's stock-
holders would be indifferent to the replacement of the existing
oil plant with a new coal-fired plant.
In order to have the after-tax revenue
requirement match the costs incurred by the utility, rate-
setting practices in some states would have to be altered. The
utility's stockholders would be adversely affected by investment
in a coal plant if tax credits are flowed through to consumers,
CWI? is not allowed in the rate base, an inadequate return is
allowed, and/or regulatory lag is present. When the allowed
after-tax revenue requirements is less than the cost of the
investment, the utility has a disincentive to replace oil plants
with coal plants.
Customer Impact
The PUC must consider the impact of the coal plan:: in-
vestment on the price of power to consumers. These prices will
vary depending upon the rate-setting practices imposed by the
PUC.
As discussed above, the PUC determines the revenue re-
quirement of the utility. This revenue requirement divided by
the kilowatt-hours provided gives the average cost of electricit
per kilowatt-hour for the customer. Exhibit II-5 illustrates
graphically the cost of kilowatt-hour of power from the oil plan
versus -he coal plant uncer different rate-settinc conditions.
In all cases, the cost of a kilowatt-hour from the coal plan- is
higher in the years immediately after the coal plan- is ccmplere
This is due to the large increase in the rate base in this year

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11-10
and consequently, higher capital costs are Included in the revenue
requirement. The utility earns a rate of return on the value of
its plant less accumulated depreciation (net plant). Since the
value of its net plant for any single investment declines over
time, the capital recovery decreases over time. This "front
loading" of the capital charges results in higher consumer prices
in the near term and lower costs in the future for the coal plant
as compared to the oil plant.^
It is possible to spread these capital charges more
evenly over the life of the investment. Depending upon the con-
sumers' discount rate, the consumer may prefer to realize some
of the benefits of the lower fuel costs earlier and pay slightly
higher costs in the future. To accomplish this the PUC could
levelize the recovery of the capital costs in nominal or in real
terms. This is illurtrated in Exhibit II-6. This exhibit shows
the amount of capital recovery for the new plant included in the
rates under the current method, under levelized capital recovery'
in nominal terms, and under levelized capital recovery in real
terms. In each case the total present value of the capital re-
covery charges is equal using a discount rate equal to the rate
of return allowed by PUC. A discount rate equal to the rate of
return allowed the utility by the PUC is used to levelize the
capital charges in order to ensure that the revenue requirement
in each case would adequately cover the capital costs incurred by
the utility if the allowed rate of return reflected the actual
cost of capital to the utility.
The utility, however, will not be indifferent to the
capital recovery method chosen if the discount rate used to
levelize the capital recovery charges is lower than the actual
T
"As explained previously, the capital costs of the coal plant
exceed the fuel savings (the cost of oil less the cost of coal)
in the near term. However, in the future the capital costs of
the coal plant are lower than the fuel savings.

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11-11
cost of capital. The present value to the utility, discounting
at their actual cost of capital, is highest under the current
method of capital recovery.^" Therefore, an additional alterna-
tive is considered which includes an increase in the allowed
rate of return along with levelized capital recovery in real terms.
The pattern of rates under each capital recovery method
is compared to the rates for the oil plant in Exhibit II-7. As
shown in this exhibit, the rates under the levelized capital re-
covery method in real terms are equal or less than the rates for
the oil plant over the entire period (even with an increase in
the future (after 1996) under both methods of levelizing the
capital recovery compared to the rates using the current method
of capital recovery).
As stated above the preferred pattern of rates from the
consumers' standpoint will depend upon the consumers' discount
2
rate. Exhibit II-8 gives the present value of the cost or a
single kilowatt-hour each year using various discount rates under
the different capital recovery methods and different regulatory
conditions.
The following observations can be made from this exhibit:
• The consumer prefers the coal plant investment for each
of the discount rates given.3
The higher the discount rate the more valuable are cash flows
which occur in the near term compared with cash flows in the
distance.
"The consumers' discount rate refers to the time value placed
on money by the utility's customers. This analysis is accurate
for the group of consumers in the service territory assuming
that their discount rate does not change over time as a result
of changes in the composition of the group over time.
"This is true for discount rates as high as 17 percent. At 17
percent, the consumer would prefer to pay the cost of the oil
plant rather than the cost of the coal plant under the regulatory
conditions assumed in Scenario 4.

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11-12
•	At consumer discount rates below 10.2 percent the
consumer would prefer the utility normalize rather
than flow-through its tax credits. (Scenario 2
versus Scenario 1.)
•	The consumer would prefer to exclude CWIP from the
rate base at discount rates above 8 percent.
(Scenario 1 versus Scenario 3.)
•	For discount rates above 10.2 percent the consumer
would prefer either method of levelizing the capital
recovery charges. (Scenarios 5 and 6 versus
Scenario 1.)
•	At discount rates above 11 percent, the consumer would
prefer the utility be allowed to earn 15 percent re-
turn on equity using .a levelized capital recovery
in real terms rather than the current method of capital
recovery with a 13.5 percent return on equity.
(Scenario 7 versus Scenario 1 and Scenario 8 versus
Scenario 2.)
•	At a 15 percent discount rate the consumer would
prefer the utility be allowed to normalize tax credits
and earn a 15 percent return on equity using levelized
capital recovery in real terms rather than flow-through
these credits and earn a 13.5 percent return on equity
using the current method of capital recovery.
(Scenario 8 versus Scenario 1.)
The PUC1s should give some thought to optimizing the
time pattern of the utility's recovery of costs such that the
consumer gains from the construction of a coal plant. This,
hopefully, would reduce consumer and regulator resistance to the
construction of economical coal plants.
FINANCING DIFFICULTIES
Some of the Northeastern utilities are contesting Depart-
ment cf Energy orders to convert oil-fired generating units to coal.
The reason cited for the appeals is the lack of available funding
for the conversions. Thus, even if the PUC were to adopt more
liberal rate-settinc practices, the utility might still find it
difficult to replace oil plants.

-------
11-13
The funds required for constructing the coal plant are
shown in Exhibit II-9. This exhibit shows the total funds re-
quired for the investment less the funds available from any
investment tax credits which are not flowed through to consumers
and funds available from the return earned on any CWIP allowed
in the rate base. The total funds required range from $719.6
million for a utility which flows through its-tax credits and
is not allowed to include CWIP in its rate base to $577.0 million
for a utility allowed to normalize its tax credits and include
all CWIP in the rate base. Therefore, changes in rate-setting
practices can amount to as much as a 20 percent difference in the
funds required. However, the funds required in all cases are
still substantial.
To understand the magnitude of the financing difficul-
ties for some utilities, a brief financial review of six North-
eastern utilities was performed.^" A summary of this review is
2
provided in Exhibit 11-10. This exhibit indicates that:
•	All of the utilities will be required to finance over
60 percent of their construction programs over the
next five years with externally-generated funds.3
•	In 1979 the proportion of earnings comprised of non-
cash AFDC ranged from 36 percent for Connecticut Light
& Power to a staggering 92 percent for the Public
Service Company of New Hampshire.4
•	Two of the six utilities have applied for exemptions
from Department of Energy orders to convert oil-fired
units to coal. (United Illuminating and Connecticut
Light an'd Power.)
^"These utilities are not representative of all utilities but are
indicative cf utilities with old oil-fired units.
o
~A discussion oz each utility is included m Appencix 3.
"'Nationally, 64 percent of funds were generated externally in 1979.
,1
\-.3 explained above, AFDC is a non-cash credit to earnings. The
internal cash flow available to the utility for the payment of
dividends and for funding capital expenditures is net income less
AFDC plus depreciation and any other non-cash expenses.

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11-14
•	Four of the six utilities are prohibited by bond
indenture provisions £rom issuing new unsubordinated
debt. (The exceptions are Boston Edison and New
England Power.)
•	Five of the six utilities have construction plans
dominated by nuclear plants. The only exception is
New England Power which is aiming to reduce peak
demand growth from 3.1% to 1.9% by relying on con-
servation and load management programs.1
As these points indicate, four of these Northeastern
utilities are severely strained financially and an additional
capital requirement of $0.6 billion for the construction of a
coal plant cannot be absorbed in the short term even under rate-
setting practices favorable to the utility.
Financial pressures would be eased if the pending legis-
lation passes. This would provide $6 billion in grants to utili-
ties who voluntarily replace oil-fired capacity. This analysis
did not consider whether' or not the amount of grants available
to specific utilities would be sufficient to enable them to
finance the replacement of oil capacity. However, the analysis
did consider whether the grant or other proposed incentives would
help to eliminate the disincentives which currently exist. This
analysis is reviewed below.
EFFECTIVENESS OF PROPOSED
INCENTIVES
Several .proposals, in addition to the oil backout pro-
gram, have been suggested as incentives to encourage the utilities
to replace oil-fired generation with ccal-fired plants. These
programs include:
"""The addition of zhese nuclear plants may permit some of these
utilities to retire their older oil-fired plants.

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11-15
•	A dollar per barrel bounty for each barrel of
oil per day eliminated,
•	Grants or loans which are repaid on the basis
of fuel savings,
•	Sale/leaseback arrangements for coal plants,
•	Splitting the total cost savings between the
utility's stockholders and its customers,
•	Modifying the recovery of the capital costs of
the plant and providing for a higher rate of
return on equity for the utility's stockholders,
and
•	' Elimination of the fuel adjustment clause.
Each of these proposals is discussed below in terms of how likely
they are to reduce the disincentives for oil plant replacement
discussed throughout this report—uncertainty regarding the
economics of oil plant replacement, rate-setting practices, and
the poor financial condition of the utilities.
Dollar Per Barrel Bounty
Phase II of the proposed oil backout prog'ram provided
for a bounty to be paid to the utility for each barrel of oil
per day eliminated. This bounty would have amounted to $10,000
per barrel. If the utility retired a 410 MW plant which ran at
50 percent of its 37 5 MW capacity, it would eliminate 6700
barrels per day of oil.^" A grant for the amount $67 million
would have been gi-ven to the utility during the construction
period. Using the costs cited above, this would amounted to 17
percent of the initial investment in 1979 dollars.
'Assuming a barrel of residual oil contains 6.237 million 3-u's
and the plant has a heat rate of 9,340 3tu/Xwh.

-------
11-16
This proposed program would help ease the financing
burden faced by the utility by providing cash when it is most
sorely needed—during the construction period. It would also
reduce the cost of the coal plant and hence reduce the uncertain-
ty concerning the economics of the new coal plant. The dis-
incentives for coal plant construction which stem from rate-
setting' procedures are not likely to be reduced as a result of
this program.
Grants Repaid out of Fuel Savings
One proposal suggests that the utility be given a
grant during the construction period. The utility would then
repay this grant out of the fuel savings it achieves through
the replacement of oil with coal or nuclear fuel. An arrange-
ment very similar to this has been in effect for several years
in Ontario, Canada. Government loans were provided to Ontario
Hydro for the construction of a nuclear plant. These loans are
being repaid from the fuel savings realized by Ontario Hydro
over the life of the plant.
This arrangement will help ease the financing burden
of the utility. It will also significantly reduce the economic
uncertainty regarding oil plant replacement since the utility
need not repay the grant if no fuel savings are realized. The
existing rate-setting disincentives are unlikely to be reduced
by this proposal.
Sale/Leaseback Arrangement
This proposal would allow investors other than the
utility to construct coal plants and then lease their: to the
utility for the life of the plant. This would eliminate the
financial problems facing the utilities since they would not

-------
11-17
need to provide the funds for the initial construction of the
plant. The uncertainty concerning the economics of a coal
plant is not reduced; it is merely transferred from the utility
to the other investors. The rate-setting procedures which
currently provide a disincentive for. investment may or may not
be reduced depending upon the structure of the lease payments
and the recovery of these lease payments through rates. If the
lease payments are constant, the effect will be to levelize the
recovery of the capital costs in the revenue requirement. As
shown above, the consumer may prefer this under certain discount
rates. The disincentives stemming from rate-setting procedures
that exist from the point of view of the utility's stockholders
will be eliminated as long as the full amount of the lease pay-
ments is recovered in the rates in a timely fashion.
Splitting of Total Cost Savings
Under this proposal the utility's shareholders and
customers would share the cost savings realized by replacement
of an oil-fired plant with a coal-fired plant. Under current
rate-setting practicas, all savings are passed onto the customers
of the utility.
This proposal would not ease the financing faced by
the utilities nor. would it reduce the uncertainty regarding the
economics of oil plant replacement. The likely effect of this
proposal would be an increase in the rate of return to the equity
shareholders. This would eliminate some of the current disincen-
tive that exist due to rate-setting practices from the point of
view of the stockholder. Consumers would be worse off under this
proposal and thus, any existing rate-sec-ting disincentives which
exist from the point of view of the consumer would increase.

-------
11-18
Modifying the Recovery of Capital Costs
and Higher Returns on Equity
This proposal has been discussed in some detail above.
The capital charges in the revenue requirement each year would
be levelized in real or nominal terms rather than being based
on depreciated book value. In addition, the rate of return on
equity allowed by the PUC would be increased.
As demonstrated above, this proposal could eliminate
some of the existing rate-setting disincentives for both the
stockholder (by providing a higher rate of return) and the
consumer (by allowing the cost savings to be realized earlier
and slightly higher rates to be paid later) . This proposal has
no impact on the cash available for new construction nor does
it reduce the uncertainty regarding the economics of oil plant
replacement.
Elimination of the Fuel Adjustment Clause
The elimination of the fuel adjustment clause would
require the utility to file for a rate increase each time izs
fuel costs rise, just as the utility must currently file a rate
case in order to recover increases ir. capital costs. This
would equalize the lag between the recovery of fuel and capital
charges. Thus the utility would have no incentive to minimize
capital costs in trade for higher fuel costs.
This proposal would worsen the financial positicr. of
-he utilities by increasing the lag in the recovery of increased
fuel costs. Thus the utilities' abilizv to finance new plants
would be reduced even further. The uncertainty regarding coal
plant construction costs and fuel costs would not be reduced

-------
11-19
under this proposal. Whether or not the disincentives for coal
plant construction due to rate-setting procedures is increased
or decreased would depend upon the current lag in the recovery
of fuel costs. A substantial increase in the lag in the re-
covery of increases in fuel costs could provide an incentive to
both stockholders and consumers to have the utility replace a
high fuel-low capital cost oil-fired unit with a low fuel-high
capital cost ccal-fired unit.

-------
LIXlliniT I I-I
COfii OF NF.W COM. I'J.AMT1
(Ml 1.1.KINS OF IMII.I.AHS)
Yuat
Investment.
1 lives t. mi mi t
Tax CreiliL
Tux .Sll ieIII
From Dopioci.ll.
i mi
Af Ler-Tax
_Ex|iun;



Pollution Control
Other
o|m
Futil
1900
9.0?
( 0.80)


3. 19
27.75
1981
1 1. (.0
( 1.20)


1.44
30. B4
1982
22.66
( 1.99)


3.72
34.29
1983
45.22
< 4.0 1)


4.01
30.17
1984
123.3 7
(ii. ir»)


4.33
4 2.47
1985
1')(). II »
(1 / . r.(.)


4 .68
47.27
19B6
202.51
( IU. 3M


5.06
52.58
1987


(8.62)
(21.05)
9. 36.
36.4 7
1980


(0.62)
(20.14)
10.11
40. 37
19 89


(U.62)
(19.22)
10.92
44.68
1990


(8.62)
(IS. 11)
1 1.79
49.15
1991


(8.62)
(17.39)
12.73
54 .07
1992



(i r>. 4 u)
13.75
59.51
1993



(15.50)
14.05
64 . B9
1994



(14.65)
16.04
72.03
1995



(11.73)
17.32
78.95
J 996



(12.81)
18. /I
86. 54
1997



(11.90)
20. 20
94.05
199U



(I0.9B)
21 . 82
104.04
1999



(10.0/)
2 1.57
113.99
' I ncl uclivi ill lel.ileil 111 j I I ill I mi control investments.
Additions Total Cash	Present Value
to Wtirk in'j Cap! tal	Fi cjw 	 of Cash Flow at 10. 2>
0. 74
39.95
39.95
0. 81
47.49
43.09
0.91
59. 59
49.07
1 .02
84 . 39
63.06
1.13
159.94
108.45
1 . 26
226.48
139.35
1 . 39
243.22
135.80
(2.08)
13.28
6.73
1.13
22.85
10.51
1.25
29.01
12.10
1 . 30
35. 31
13. 37
1.43
42.22
14.51
1 . 57
58. 15
18.19
1 .58
65. 76
18.60
2.0 3
75.45
19. 37
2. 00
84.54
19.69
2 .19
94.63
20.00
2. 39
105.54
20.25
2.63
117.51
20.46
2. 85
130.34
20.59

-------
iiXIIIlUT JI — 1 (conl inueit)
COST OF NEW COAI. I'l.AHT1
(MII.I.IOMU OF DOLLARS)
lnvt'st ment	Tax Shield
Year Investment Tax <^rei)^t	From fte[>ret:lat^oii After-Tax Expenses
I'olluilon Control Oilier	OSM	Fuel
2000	( 'J. 15)	25.45	125.02
2001	( 8.24)	27.49	137.02
2002	( 7.12) 29.69	14B.56
200J	( 6.41) 32.06	162.83
2004	( 5.49)	34.6)	178.52
2005	( 4.50)	17.40	195.66
2006	( 3.66) 40.39	214.49
2007	( 2.75) 43.62	235.16
2008	( 1.83) 47.11	257.78
2009	( 0.92)	50.88	282.61
2010	54.95	309.75
2011	59.34	339.61
20)2	64.09	372.28
201)	69.22	408.04
2014	74.76	447.28
2015	80.74	490.38
2016	87.20	532.29
2017
Ciiiiin lal i v«; l'i osont Value
'inclmli'ii fill rolut oil pollution control Investment b .
2
Kefiuul of woikimi c.ipilnl at I he en<) of the lifc> of the plant.
Additions	Total Cash	Present Value
to Working Capital Flow of Cash Flow at 10.2%
3.15
144.47
20.71
3.42
159.69
20.77
3. 35
174.28
20.57
4.05
192.53
20.62
4.45
212.11
20.62
4.85
233.33
20.58
5. 32
256.54
20.53
5.83
281.86
20.47
6. 36
309.42
20.39
6.97
339.54
20.31
7.60
372.30
20.20
8. 35
407.30
20.06
9.12
445.49
19.91
9.96
487.22
19.76
10.91
532.95
19.61
11.96
583.08
19.47
11.79
631.28
19.13
(144.17)3

(3.96)
$1,132.89

-------
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
11-22
EXHIBIT II-2
COST OF EXISTING OIL PLANT
(MILLIONS OF DOLLARS)
Present Value
Additions to Total Cash Cash Flow
After-Tax Expenses Working Capital Flow	at 10.2%
O&M Fuel
3.19
27.75
0.74
31.68
31.68
3.44
30.84
0.81
35.09
31.84
3.72
34.29
0.91
38.92
32.05
4.01
38.17
1.02
43.20
32.28
4.33
42.47
1.13
47.93
32.50
4.68
47.27
1.26
53.21
32.74
5. 06
52.58
1.39
59.03
32.96
5.46
58.48
1.54
65.48
33.18
5.90
65.05
1.71
72.66
33.41
6.37
72.38
1.-90
80.65
33.65
6.88
80.47
2.10
89.45
33.87
7.43
89.57
2.35
99.35 •
34.13
3. 02
99.59
2.59
110.20
34.36
8. 66
110.80
2. 89
122.35
34.61
9.36
123.27
3.21
135.84
34.87
10.11
137.09
3.55
150.75
35.12
10.91
152.51
3.95
167.37
35. 38
11. 79
169.95
4.46
186.20
35.72
12.73
188.74
4.81
206.28
35.91
13.75
209.98
5.42
229.15
36.20
14.85
233".57
6.02
254.44
36.47
16. 04
259.77
6 . 67
282.43
36. 74
17.32
239.01
7.44
313.77
3 t . o 4
18.70
321.45
8.24
34S.39
37. 31
20.20
357.60
9.17
3S6.97
37. 51
21.82
397.79
10.19
429.80
37.91

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2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
11-23
EXHIBIT II-2 (continued)
COST OF EXISTING OIL PLANT
(MILLIONS OF DOLLARS)
Present Value
Additions to Total Cash Cash Flow
After-Tax Expenses Working Capital Flow	at 10.2%
O&M Fuel
23.56
442.53
11.33
477.4J
38.21
25.45
492.25
12.57
530.27
38.51
27.48
547.56
12.96
587.90
38.74
29.68
609.20
16.57
655.45
39.20
32.06
677.62
17.25
726.93
39.-45
34.62
753.79
19.19
807.60
39.77
37. 39
838.56
21. 33
897.28
40.10
40.38
932.76
23.68
996.82
40.42
43.61
1,037.67
26.35
1,107.63
40.76
47.10
1,154.28
29.27
1,230.65
41.09
50.87
1,284.02
32.53
1,367.4.
41.43

Cumulative
Present
value
$1,337.22

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11-24
EXHIBIT II-3
REVENUE REQUIREMENT	i
RESULTING FROM COAL PLANT INVESTMENT
(1980 PRESENT VALUE, MILLIONS
OF DOLLARS AFTER TAX)
Tax Credits
Flow-Through
Normalized
CWIP Allowed in Rate Base
No	Yes
Base Case
$1078
$1084
$1088
$1094
Assuming an allowed rate of return after-tax of
9.56% and a one year delay in recovering capital
cost.

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11-25
EXHIBIT II-4
REVENUE REQUIREMENT	,
RESULTING PROM COAL PLANT INVESTMENT
(1980 PRESENT VALUE, MILLIONS
OF DOLLARS AFTER TAX)
Regulatory Lag
One Year	None
Rate of Return
Base Case
9.66%	$1094	$1118
10.20%	$1108	$1133
^"Assuming tax credits are normalized and CWIP
allowed the rate base.

-------
kxiijiut J i-5
COMI'AIUfiON OF ROTHS
IJNIJKR AL/l'M(NATIVE
IUiXa If ATOPY CONDITIONS
(1900 C/kwIi)
IO-1
Electricity
Hales
(I9UO c/kwli)
8»-
4 -
— OIL PLAN I
COAL PLANT (llow through oi lax credltsi
'	no CWP In rate base)
-COAL PLANT (normalization ol tax credits)
CWIP allowed fc» rale base)
2 -

1990	2O0O	20KI
YEAR

-------
KXIIJniT J J-6
CXffl'AUISON (IF ALTEPNATIVF.
CAPITAL PIXXMERY
(C/kwhf nominal)
25 n
20 -
Return on
Capital
(e/kwh)
15 -
- tevelfzed copltal recovery
(lent terns)
-levefliod capital recovery
(nominal terms)
t997
2007
201/
declining c^iital recovery
(current metliod)
YEAR

-------
EXIIMJT 11-7
Ctl-U'AIUfjdN or RATFS UNDRR Al.'H^NATrVK
CAPITAL iutwihy ml-muous
(1900 C/kwh)
to
-OILPLANT
Electricity
Rates
(1900 «/kwh)
6 -
COAL PLANT	.
(levellied capital recovery In real terms; 15% rate
ol return on wpilly)
COAL PLANT (tevellzed copilot recovery In nominal terms}
- COAL PLANT (current melltotl of capital recovery)
2 -
-K
1990
-4-
2000
H	
2010 YEAR

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EXHIBIT 11-8
1980 present value of the price
OF ONE KLLOWATT-HOUR EACH YEAR
(CENTS)
9
Consumers'	Oil	Coal Plant Scenario*	
F)iscount Rate* Plant	#1	#2	H 3	~|4	#5	#6	#7	#8
8%	236.42 185.71 184.45 185.89 184.63 186.96 189.07 197.94 191.68
10.2%	157.99 130.74 131.47 131.98 132.71 130.27 129.11 131.63 132.36
15%	78.38 70.76 73.17 72.96 75.37 69.28 66.41 67.52 69.94
The discount rates chosen are for illustrative purposes only—8 percent is the assumed rate of
inflation, .10.2 percent is the utility's cost of capital and 15 percent is the rate of return
required by the utility's equity shareholders. There is currently no agreement on the appro-
priate consumer discount rate.
^Scenarios arc described on the following page.

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11-30
2
Description of Scenarios
Scenario	Description
#1	Flow-through of all tax credits; no CWIP in
rate base.
#2	Normalization of all tax credits; no CWIP in
rate base.
#3	Flow-through of all tax credits; all CWIP in
rate base.
#4	Normalization of all tax credits; all CWIP in
rate base.
#5	Flow-through of all tax credits; no CWIP in
rate base; levelized capital recovery in
nominal terms.
#6	Flow-through of all tax credits; no CWIP in
rate base; levelized capital recovery in
real terms.
i *7
7T /
Flow-through of all tax credits; no CWIP in
rate base; levelized capital recovery in
real terms; increase in allowed rate of return
on equity to 15 percent.
£8	Normalization of all tax credits; no CWIP in
rate base; levelized capital recovery in real
terms; increase in allowed rate of return on
equity to 15 percent.

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EXiirniT n-9
FUNDS RF.QUIKbM) FOR CONSTRUCTION
(MILLIONS OF NOMINAL DOLLARS)
Coal Plant Scenario*

¦11
II 2
# 3
#4
#9
810
1980
11.0
10. 2
10. 7
9.9
11.0
10.2
1981
15.9
14.7
14.9
13.6
15.9
14.7
1982
26.7
24. 7
24.2
22. 2
26.7
24.7
1983
52.8
49.7
47.5
43.5
52.7
48.6
1984
140.1
128. 7
128.6
117.2
139.2
127.8
1985
222. 3
204. 7
198. 1
180.6
218.9
201.4
1986
250.8
232.6
208. 2
190.0
244.3
226.1
Total
719.6
664 . 3
632.2
577.0
708.7
653.5
Percentage
di fference
compared
with Scenario #1



ff
(7.7%)
(12.1%)
(19.8%)
(1.5%)
(9.2}
Scenarios as defined on Fxhibit II-8. In addition, Scenario #9 and
Scenario #10 are comparable to Scenarios #1 and #2 except that the
utility is allowed to include pollution control CWIP in the rate base.
Scenarios #5, H6, and #7 in Exhibit II-8 will have the same funds
required for construction as Scenario #1. Scenario #8 will have the
same funds required for construction as Scenario #2.

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EXHIBIT 11-10
SUMMARY OF FINANCIAL POSITIONS
OF SIX NORTHEASTERN UTILITIES
Boston Edison
Connecticut Licjht
& Power
Long Island Lighting
New England Power
Public Service Company
of New Hampshire
United Illuminating
N/A - not available
Future Financing
Requirements
(1980-1984)
2
$948+ million
$890 million
$2.6 billion
$641 million3
4
$850 million
$401 million
Estimated Portion
to be Financed
Externally	
67%
N/A
62%
68%
89%
90%
Interest
Coverage .
Ratio, 1978
2. 59
1.85
1.86
2.91
5
3.17
1.91
AFDC as a
Percentage of
Earnings, 1979
44%
36%
66%
43%
92%
65%
^"Calculated using the SEC formula, taken from "Statistics of Privately-Owned Electric
Utilities in the United States - 1978."
2
Excluding the cost, of anticipated federal requirements mandating conversion of five of the
Company's oi.l-Eired generating units to coal and excluding the cost of constructing the Sea-
brook Nuclear Plant. Connecticut Light & Power is attempting to sell its remaining 4.5%
interest in the Seabrook Plant. The cost of converting five of the Company's oil-fired
units i:> estimated to be between $1.17 and $306 million.
3
These expenditures are for the 1980-1982 period only.
4
Expenditures for 1980-19H5 period.
5
The Company's interest coverage ratio has fallen significantly since 1978 and is currently
below the minimum required by their bond indenture provisions.

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APPENDIX A
DATA AND ASSUMPTIONS
This appendix discusses the data and assumptions
used in the analysis presented in this report. These data
and assumptions include:
•	a projection of future oil and coal prices,
•	a projection of construction costs for a
new coal plant,
•	a projection of future operating and main-
tenance costs,
•	estimates of the marginal capital costs of
the utility, and
•	assumptions regarding effective tax rates.
Each of these projections and estimates is discussed below.
Assumptions regarding the treatment of the capital charges
associated with the oil plant in this analysis are then
reviewed.
FUEL PRICES
The projections of fuel costs are based on the
delivered cost of coal and fuel oil for New England utilities
in 1979^" and inflation factors from the Data Resources, Inc.
Enercy Review, Winter 1980. The 1979 delivered cost of fuel
in New England is:
"Published in Cosz and Qualify of Fuels fcr Electric Utility
Plants - 1579, U.S. Department of Energy, June 19SC.

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A-2
Average Cost of Fuel, Delivered
	(1979 C/mm BTU)	
Coal (2.01% - 3.00% sulfur)	152.7
Fuel Oil (0.51% - 1.00% sulfur) 316.8
These costs are projected to increase in real terms (net of
general inflation) at the following rates:
Percentage Increase
(in Real Terms)

Coal
Fuel Oil
1980 - 1985
5.0%
3.0%
1986 - 1991
2.5%
3.0%
1991 - 1995
1.9%
3.1%
1996 - 2020
1.5%
3.0%
These fuel costs were translated into a cost per
kilowatt-hour of electricity generated based on the following
assumed heat rates:
Heat Rates
(btu/kWh)
Coal Plant	9,832
Oil Plant	9,340
Total fuel costs were calculated by multiplying the
total kilowatt-hours generated by the cost of fuel per kilowatt-
hcur. The total kilowatt-hours generated were based or. an assumed
capacity factor of 50 oercent for both the coal and oil plant.- The
analysis assumed a 410 MW plant (gross capacity) with an effective
2
capacity of 37a MW.
^This is not assumed to be a base unit but rather a mid-range or
cycling unit.
2
This includes the derating of the plant capacity aue to tne rlue
gas desulfurization equipment.

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COAL PLANT CONSTRUCTION COSTS
The following construction costs were assumed:
Construction Cost^"
(1979 S/kw)
Coal Plant	$723
Transmission	100
Pollution Controls	150
These costs are based on examination of recently constructed
coal plants and on information provided by EPA. Inflation in
these capital costs was assumed to be 8 percent each year.
A seven year construction period was assumed between
1980 and 1986. The percentage of 'the total construction costs
assumed to be expended in each year is shown in Exhibit A-l.
The factors shown in this exhibit were based on information
provided in Utility FGD Costs: Reported and Adjusted Costs
For Operating FGD Systems, PEDCo Environmental Inc., September
1978 (PEDCo report).
OPERATING AND MAINTENANCE COSTS
The operating and maintenance costs assumed were
as follows:
Operating & Maintenance Cost
	(1979 C/kWh)	
Oil Pianw	0.35
Coal Plant
Scrubber	0.4 5
Other	0.15
^"Excluding AFDC which is accounted for explicitly in the utili
financial simulation model.

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A-4
These estimates sure based on an examination of recent operating
experience at new coal plants and older oil plants and on informa
tion provided in the PEDCo report.^" These costs were assumed to
increase at an annual rate of 8 percent over the time period of
analysis.
CAPITAL COSTS
The following capital costs were assumed for this
analysis:
Capital Costs
Debt	12%
Preferred Stock	13%
Equity
Actual	15%
Allowed by PUC	13.5%
The cost of debt was estimated using the average yield on Baa-
rated public utility bonds over the past 18 months (January 1979
2
through June 1980) . Preferred stock was assumed to yield one
percentage point above the cost of debt. It was also assumed
that the cost of equity capital which the Public Utility Commis-
sion (PUC) allowed the utility to recover in its rates would
be 13.5%; while the actual cost of equity capital would be
approximately 15 percent.
In order to calculate a weighted average cost of
capital the following capital structure was assumed:
^"These data are provided by each utility for each generating unit
on FERC Form 10.
2
As reported in Moody1s Bond Record.

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A-5
Capital Structure
Debt	51.5%
Preferred Stock	12.5%
Equity	36.0%
This capital structure is representative of a typical Northeastern
electric utility. The calculation of the after-tax weighted
average cost of capital is shown in Exhibit A-2. As shown in
this exhibit, the actual after-tax weighted average cost of
capital is 10.2 percent. The after-tax weighted average cost
of capital allowed by the PUC is 9.66 percent. The AFDC rate
used in this analysis is the after-tax weighted average cost of
capital allowed by the PUC of 9.66 percent.
TAX ASSUMPTIONS
The following tax rates were used in this analysis.
Tax Rate
Federal Income Tax	46%
State Income Tax	5%
Investment Tax Credits	10%
Since state income taxes paid are deductible from
federal taxes, the effective marginal income tax rate is:
tf " V* (1 " V =
¦0.46 + 0.05 * (1 - 0.46) = 0.487
where: T? = the federal income tax rate
and Ts = the state incone tax rate
Thus, the effective marginal income tax rats is 48.7 percent

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A-6
The investment tax credit decreases a firm's tax
liability by an amount equal to 10 percent multiplied by the
amount of qualifying investments. Based on a detailed examina-
tion of the construction costs of a coal plant provided in
Capital Cost Addendum: Multi-Unit Coal and Nuclear Stations,
United Engineers and Constructors, Inc., February 1978. It was
assumed that 88 percent of the coal plant investment and 100
percent of the transmission and pollution control investments
would qualify for the investment tax credit. It was also assumed
that the utility would have sufficient income tax liability to
enable it to realize all of its available tax credits.
The last tax assumption pertains to the depreciation
of plant and equipment. In accordance with Internal Revenue
Service (IRS) regulations, the coal plant and transmission
investment was depreciated over 23 years period using the sum-
of-the-years' digits method of accelerated depreciation. The
pollution control investment was depreciated using the straight-
line method over 5 years.
UNDEPRECIATED PORTION OF OIL PLANT
No assumption was made concerning the remaining book
and tax value of the oil plant. It was assumed that the utility
would be allowed to keep the oil plant in its rate base until
it was fully depreciated even if the coal plant was constructed.
Thus, any depreciation expense and capital charges associated
with the oil plant would remain the same whether or not the
coal plant is constructed. Therefore, these costs were disregarded
in this comparative analysis.

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A-7
EXHIBIT A-l
PERCENTAGE OF TOTAL COSTS EXPENDED IN
EACH YEAR OF CONSTRUCTION PERIOD
Coal Plant Transmission Pollution Controls
1980	2%
1981	3
1982	5
1983	9	5%
1984	18	30%	25
1985	28	30	50
1986	35	40	20
1980 to 1986
100%
100%
100%

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A-8
EXHIBIT A-2
CALCULATION OF AFTER-TAX
WEIGHTED AVERAGE COST OF CAPITAL
Portion of After-Tax Cost
Before-Tax	After-Tax Capital * Portion of
Cost	Costl Structure Capital Structure
Debt 12.0%	6.2% .515 3.27
Preferred Stock 13.0	13.0 .125 1.63
Equity
Actual 15.0	15.0; 5.40
Allowed by PUC 13.5	13. 5^ ,:lbU 4.86
)
Weighted Average Cost
of Capital
Actual	10.20%
Allowed by PUC	9.66%
Interest payments on debt are tax deductible. Therefore, the
after-tax cost of debt is 12 percent multiplied by one minus
the corporate marginal tax rate of 48.7 percent. The derivation
o'f this tax rate is explained in this Appendix.

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APPENDIX B
FINANCIAL ANALYSIS OF SIX NORTHEASTERN UTILITIES
This appendix presents a brief financial review of
six Northeastern utilities. The utilities reviewed are the
Public Service Company of New Hampshire, United Illuminating,
Long Island Lighting, Connecticut Light and Power, New Eng-
land Power and Boston Edison. Each utility is discussed be-
low.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
The Public Service Company of New Hampshire (PSNH)
is in extremely poor financial position due to the severe
financing problems associated with its share of the Seabrook
Nuclear Facility.1 The New Hampshire State Legislation ruled
that PSNH could not include construction work in progress (CWIP)
in its rate base. As a result of this law, financing has be-
come difficult and PSNH has attempted to reduce its ownership
of this plant from its present 50% to 28%. Even if this is ac-
complished, the utility still faces financing requirements of
over SS50 million between 1980-1985.
The utility's earnings per share have fluctuated in
recent years and AFDC as a percent of earnings reached a stag-
gering 92% in 1979. Thus, 92 percent of the Company's income pro-
vides no funds for capital expenditures (AFDC is non-cash income.)
The Company's entire capacity expansion is dependent on this
plant.

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B-2
The interest coverage ratio for the company has fallen
below the minimum allowed in its bond indentures^ and its pre-
ferred stock coverage ratio has fallen to 1.79 with the sale of
2
1.5 million shares in February of 1980. Thus, the ability of
PSNH to issue additional debt or preferred stock at this time is
extremely limited. It is estimated that of the $850 million re-
quired between 1980-1985, only 11% will be financed internally.
Even if PSNH is able to sell off part of its interest in Seabrook,
the company would have no funds available for any added construc-
tion.
UNITED ILLUMINATING
United Illuminating (UI), located in Connecticut, has
experienced increasing sales (kwh) and a steady cash flow per
share in recent years, but the utility is experiencing serious
financial difficulties. UI's cash flow has been adversely
affected by the two month lag in billing of increased fuel costs
and by the State's 5 percent tax on gross revenues.^
UI faces two immediate problems. First, dividends in
19 7 9 were backed by reported earnings which are over 65% non-
cash AFDC. Secondly, UI is presently prohibited by its inden-
ture provisions from increasing the amount of its unsubor-
4
dir.ated indebtedness. The company does believe that it can
^"Income before taxes must be two times interest charges in order
to issue unsubordinated debt.
2
A second sale of 1.5 million is planned later in 193 0. This
will decrease the coverage ratio to its limit of 1.5.
"As revenues increase due to fuel costs, revenue raxes rise.
These increased taxes are not recovered through the fuel
adjustment clause.
"* Income before Federal taxes must be at least twice annualized
interest charges in order to issue unsubordinated debt.

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B-3
issue at least $25 million of additional preferred stock, pro-
vided that net proceeds from the sale of stock are used to re-
pay short-term debt.^"
Capital outlays are expected to peak during the 1981-
1984 period at which point only 10% of the $305 million of ex-
penditures will be generated from internal solirces. Because
of United Illuminating1s inability to generate funds internally,
and its poor coverage position, the company is attempting to
cut back its construction program. UI is trying to sell half
of its 20% interest in the Seabrook Nuclear Project and the
comDany is seeking exemDtion from a DOE order to convert UI's
2
largest oil-burning generating unit to coal.
LONG ISLAND LIGHTING
Long Island Lighting (LILCo) has one of the highest
proportions (45%) of sales to residential customers of any
•U.S. utility. This, according to the utility, results in a
stable operating environment. From a cash flow standpoint,
the earnings per share have been steady. But in terms of
capital financing, LILCo has encountered recent problems. The
company's capital requirements are estimated to be $448 mil-
lion in 1980 of which over 80% will be financed externally
Although dividends paid have been increasing annually,
an increasing percentage of the earnings on which this is based
is derived from non-cash AFDC. AFDC was 66 percent of earnings
in 1279.
"'"Preferred stock coverage ratio must equal 1.5 ir. order to
increase long-term indebtedness.
2
This conversion could add S37 to $128 million to capital
requirements.

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B-4
LILCo has fallen below its interest coverage limit of
2.0 and its preferred stock coverage ratio of 1.58 is nearing
the limit of 1.50. For future capital financing the utility
will have to rely on sales of common stock and mortgage bonds.
For the years 1980-1984 the capital requirements are estimated
at $2.6 billion and it is estimated that external financing of
$1.6 billion will be needed.
The majority of the capital expenditures by LILCo
will be for nuclear facilities, including the Shoreham Nuclear
Plant which is projected to start operating in 1982 and the
Nine Mile Point #2 Plant which is scheduled to be completed in
1986. Because of these major construction expenditures, and
the company's poor internal financing position, it is doubtful
that LILCo could absorb any substantial increases in capital
costs.
CONNECTICUT LIGHT AND POWER COMPANY
The Connecticut Light & Power Company (CLP) is a
wholly-owned subsidiary of Northeast Utilities. The financial
position of CLP has and will continue to be strained because
of its investment in new nuclear facilities. To ease the
strain, the company has sold part of its interest in the Sea-
brook Plant for $46.9 million.^" Excluding the Seabrook Plant,
CLP still requires $481 million from 1980-1984 to finance the
Millstone #3 Nuclear Facility. Total planned construction ex-
penditures amount to $370 million over the 1980-1984 period.
"Decreased from its initial share of 12% of 4.5% with an
ultimate coal of selling all its interest:.

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B-5
In addition to the construction expenditures, the
company's financing requirements during the period of 1980-
1984 also include $160 million to meet long-term debt and
preferred stock sinking fund and debt maturity requirements.
Of this amount, $123.5 million will be due in 1982.
Northeast Utilities has been a major supplier of
capital to CLP and it is anticipated that NU will contribute
$40 million to CLP during 1980. The continued supply of these
funds is unsure though, because of the poor financial position
of the parent company. NU had only a 9.1% return on common
equity in 1979 and there is no assurance that NU can continue
to sell its common shares in amounts necessary to be able to
provide capital to CLP, and thus will force CLP to use more
external financing.
CLP, without capital from NU, will find it difficult
to finance its current construction program. The interest
coverage ratio has been- near the limit for the last three years
while the preferred stock coverage dropped below its limit (1.50)
to 1.4 5 in 1979. The company has already stated that it would
be incapable of financing any DOE requirements for converting
oil-fired unics to coal.^" The cost of these conversions would
add between $137 to $306 million to the construction expenditures
depending upon whether flue gas desulfurization equipment is
required for each of the units.
NEW ENGLAND POWER*
The New England Power Company (NEr) is a wholly-ovr.ec.
subsidiary of the New England Electric System (NEES) and
1The company is presently congesting existing effor-s by DOE zc
¦ require such conversions.

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B-6
accounts for nearly 70% of the parent company's revenues. NEP
received nearly $70 million from its parent company during the
1978-79 period and is taking part in NEES's 15-year program
(NEESPLAN) which is aimed at reducing peak demand growth from
3.1% to 1.9% and reducing the amount of new capacity needed.^"
The company has also planned to convert six oil burners to coal
so that by 1982 coal will dominate the fuel mix at 42% with oil
dropping to 37%. These conversions are part of a construction
budget which calls for $205 million to be spent in 1980, $248
million in 1981 and $188 million in 1982.
All of the construction expenditures were met with
internal funds and with capital contributions from the parent
company in 1979 and 1980. Most of 1981 and 1982 requirements
will be met by the sale of common shares through the dividend
reinvestment and employee stock ownership plans and $90 million
of pollution control bonds.
NEES has filed for rate	increases and the company is
attempting to persuade regulators	that companies that stress
conservation should be allowed to	reward investors with a
higher return.
Although AFDC represented 4 3 percent of earnings in
1979, New England Power has been in strong financial condition
during the past two years. The interest coverage ratio of 2.9 05
(in 1978) was one of the highest for New England utilities.
Overall, the company's estimated capital expenditures appear to
be within its ability to finance them.
^"Only 700 MW is planned—500 >1W of nuclear power and 200 MW of
renewable sources (wood, trash, etc.).

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B-7
BOSTON EDISON
Boston Edison is in a good financial position relative
to the majority of other utilities operating in New England.
The percent of capital funds that Boston Edison has generated
internally has risen from 36% in 1974 to over 80% in 1979.
This trend is in sharp contrast to most utilities.^"
AFDC represented 44 percent of earnings in 1979. The
interest coverage ratio of Boston Edison has remained over 2.5
in both 1978 and 1979, despite the increases in interest rates.
Because of the company's internal financing ability
and since the market value of the company's stock is more than
25% below book value, the company1s 1980 capital expenditures
of approximately $145 million will be financed with only $50
million of external financing. Capital outlays in the next
four years (1981-1984) will average more than $200 million a
year. These expenditures are based on a construction permit
being granted for the Pilcram #2 Nuclear Plant in 1981. This
steppea-u? construction program will require $140 to $150
million of external financing each year.
"National average of funds generated internally was 36% in 1979.

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