EPA-230/1-73-006
SEPTEMBER 1973
ECONOMIC ANALYSIS
OF
PROPOSED EFFLUENT GUIDELINES
STEAM ELECTRIC POWERPLANTS
QUANTITY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D.C. 20460
I
55
V
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This report has been reviewed by the Office of Planning and Evaluation,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
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ECONOMIC IMPACT OF PORPOSED EFFLUENT
GUIDELINES - STEAM ELECTRIC POWER PLANTS
MARCH 1974
, or~u>ct;on Agency
U.S. Environmet • «-1 -
Region V. Library
230 South Dearborn S.eet
Chicago, Illinois 60604
James M. Speyer
Office of Planning and Evaluation
Environmental Protection Agency
Washington, B.C. 20460
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PREFACE
The attached document was prepared by the Office of Planning
and Evaluation of the Environmental Protection Agency
("EPA"). The purpose of the study is to analyze the
economic impact which could result from the application
of alternative effluent limitation guidelines and standards
of performance to be established under sections 304(b) and
306 of the Federal Water Pollution Control Act, as amended.
The study supplements the technical study ("EPA Development
Document") supporting the issuance of proposed regulations
under sections 304(b) and 306. The Development Document
surveys existing and potential waste treatment control
methods and technology within particular industrial source
categories and supports promulgation of certain effluent
limitation guidelines and standards of performance based
upon an analysis of the feasibility of these guidelines and
standards in accordance with the requirements of section
304(b) and 306 of the Act. Presented in the Development
Document are the investment and operating costs associated
with various alternative control and treatment technologies.
The attached document supplements this analysis by estimating
the broader economic effects which might result from the
required application of various control methods and technologies,
This study investigates the effect of alternative approaches
in terms of product price increases, effects upon employment
and the continued viability of affected plants, effects upon
foreign trade and other competitive effects.
Several sections of Part II were excerpted from a report
entitled, "Possible Impact of Costs of Selected Pollution
Control Equipment on the Electric Utility Industry and
Certain Power Intensive Industries". The aforementioned
report was prepared for the Council on Environmental Quality
in fulfillment of Contract No. EQC-209 by National Economic
Research Associates, Inc. The work was completed as of
January 1972. The technical appendix to this study (e.g.,
Part III) was submitted in March, 1974 in fulfillment of
Contract No. 68-01-2418 by Temple, Barker, and Sloane, Inc.
It should also be acknowledged that much ofthe analysis in
Parts II and III is based on data supplied -by Edward Pechan,
Office of Planning and Evaluation.
This study is being released and circulated at approximately
the same time as publication in the Federal Register of a
notice of proposed rule making under sections 304(b) and 306
of the Act of the subject point source category. The study
has not been reviewed by EPA and is not an official EPA
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publication. The study will be considered along with the
information contained in the Development Document and any
comments received by EPA on either document before or during
proposed rule making proceedings necessary to establish
final regulations. Prior to final promulgation of regulations,
the accompanying study shall have standing in any EPA
proceeding or court proceeding only to the extent that
it represents the views of the Office of Planning and
Evaluation of EPA and the contractors who studied the
subject industry. It cannot be cited, referenced, or
represented in any respect in any such proceeding as a
statement of EPA's views regarding the subject industry.
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CONTENTS
Page
PART I - EXECUTIVE SUMMARY
I. Introduction
II. Pollution Control Requirements and Costs
A. Effluent Limitation Guidelines
for 1977 and 1983 1-2
B. Water Pollution Abatement Costs 1-3
III. Economic Impact of the Proposed Water Effluent
Guidelines
A. Introduction 1-5
B. Financial Effects 1-6
C. Price Effects 1-7
D. Capacity and Energy Penalty 1-8
E. Production Effects 1-9
F. Employment Effects 1-10
G. Community Effects 1-10
H. Balance of Trade 1-10
IV. Limits to the Analysis
A. Uncertainty of Cost Estimates 1-11
B. Critical Assumptions 1-11
PART II IMPACT ANALYSIS
I. Structure of the Industry
A. Introduction II-l
B. Supply Characteristics II-2
C. Demands Characteristics II-8
IT. Financial Profile
A. Profitability 11-20
B. Capital Formation 11-20
III. Pricing
A. Price Determination 11-26
B. Historical Trends in Prices 11-26
C. Future Trends in the Price of Electricity 11-26
IV. Pollution Control Requirements and Costs
A. Effluent Limitation Guidelines for 1977&83 11-30
B. Current Level of Control 11-30
C. Expected Coverage of the Guidelines 11-31
D. Water Pollution Abatement Costs 11-32
E. Comments on Cost Data 11-32
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V. Economic Impact Analysis Methodology
A. Introduction 11-43
B. Financial Effects 11-44
C. Price Effects 11-45
D. Capacity and Energy Penalties 11-46
E. Production Effects 11-47
F. Employment Effects 11-47
G. Community Effects 11-47
H. Balance of Trade Effects 11-47
VI. Baseline Economic Impact Analysis
A. Introduction 11-48
B. Financial Effects 11-50
C. Price Effects 11-53
D. Capacity and Energy Penalties II-54
E. Production Effects 11-56
F. Employment Effects 11-56
G. Community Effects 11-56
H. Balance of Trade Effects 11-57
VII. Limits to the Analysis
A. Uncertainty of Cost Estimates 11-62
B. Critical Assumptions 11-64
C. Remaining Questions 11-68
PART III TECHNICAL APPENDIX
I. Purpose and Scope III-l
II. Summary and Conclusions III-7
III. Baseline Electric Utility Industry Projections:
EPA Policy Alternative 111-20
IV. Electric Utility Industry Projections: EPA
Policy Alternative 111-44
V. Overview of EPA Policy: Alternatives Before
Exemptions 111-72
VI. Overview of EPA Policy: Alternatives After
Exemptions III-107
VII. Impact of Reduced Industry Growth III-122
VIII. Review of Alternative Technological Assumptions III-129
Appendix A: Research Methodology III-152
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LIST OF TABLES
Table No. Page
1 United States Electric Utility Industry 11-11
2 Projected Growth of Electric Utility 11-12
Generating Capacity, 1970-1990
3 Percent of Electricity Generation by 11-13
Source, By Region, 1969
4 Percent of Electricity Generation by 11-14
Source, 1960-1970
5 Percent of Electricity Generation by 11-15
Type of Fuel, 1970-1990
6 Projected Annual Fuel Requirements, 11-16
Steam Plants, 1970-1990
7 Aggregate Energy Consumption in the 11-17
United States, 1960-1970
8 Average Number of Employees of Investor 11-18
Owned Utilities in the United States,
1960-1970
9 Total Electricity Consumption in the 11-19
United States, 1960-1990
10 Combined Balance Sheets - Year Ended 11-22
Dec. 31, 1971, Investor - Owned
Electric Utilities
11 Revenues - Total Electric Utility 11-23
Industry, 1959-1971
12 Combined Income Statements - Year Ended 11-24
Dec. 31, 1971 - Investor-Owned Electric
Utilities
13 Investment - Total Electric Utility 11-25
Industry, 1961-1971
14 Average Revenues Per Kilowatt-Hour 11-28
Sold - Total Electric Utility Industry,
1951-1971
15 Consumer Price Index - All-City Average, 11-29
1951-1971
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Table No.
16 Residential Electricity and Consumer
Price Index - Total Electric Utility
Industry, 1951-1971
17 Draft Summary of Proposed Water 11-33
Effluent Guidelines For Thermal Discharge:
EPA Recommendation
18 Draft Summary of Proposed Water 11-34
Effluent Guidelines for Chemical Discharges
19 Type of Cooling Systems for Steam 11-35
Electric Plants, 300 mwe and Larger,
Being Constructed or Coming Under
Construction by April 1, 1974
20 Expected Coverage of Thermal Effluent 11-36
Guidelines: EPA Recommendation (Before
Exemptions )
21 Expected Coverage of Thermal Effluent 11-37
Guidelines: EPA Recommendation (After
Exempt ions )
22 Estimates of Capital and Operating 11-38
Costs Per Unit of Generating Capacity -
Thermal Effluent Standards
23 Estimates of Capital and Operating Costs 11-39
Per Unit of Generating Capacity - Chemical
Effluent Standards
24 Incremental Costs of Application of 11-40
Mechanical - Draft Cooling Towers for
Existing Units and New Units
25 Estimates of Capital and Operating Costs 11-41
Per Unit of Generating Capacity That
the Utility Industry Would Have Incurred
in the Absence of Federal Environmental
Regulations
26 Estimates of Incremental Capital and 11-42
Operating Costs Per Unit of Generating
Capacity - Thermal Effluent Standards
27 Summary of the Economic Impact of the 11-58
Effluent Limitation Guidelines
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Table No. Page
28 Summary of the Economic Impact of 11-59
New Source Performance Standards,
1983-1990
29 Selected Electricity Intensive 11-60
Industries in the United States, 1967
30 Impact of the Water Effluent Guidelines 11-61
on the Consumers of Electricity, 1977
and 1983
31 Minimum and Maximum Estimate of Capital 11-69
and Operating Costs Per Unit of
Generating Capacity Associated with
Thermal Effluent Guidelines
32 . Estimates of Capital and Operating 11-32
Costs Per Unit of Generating Capacity
Associated With Chemical Effluent
Guidelines
33 Summary of the Total Cost of the 11-71
Effluent Limitation Guidelines
34 Summary of the Total Cost of New Source 11-72
Performance Standards, 1983-1990
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PART I
EXECUTIVE SUMMARY
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I. INTRODUCTION
The objective of this study is to provide an analysis
of the economic impact of the Environmental Protection Agency's
(EPA's) proposed water effluent guidelines^' on the electric
utility industry. Specifically, the following impacts are
analyzed:
. Financial Effects
. Price Effects
. Capacity and Energy Penalties
. Production Effects
. Employment Effects
. Community Effects
. Balance of Payments Effects
This study estimates the above impacts both before and
after exemptions under Section 316(a) of the Federal Water
Pollution Control Act of 1972 (FWPCA).!/
The following report is divided into three parts. The
first part is a summary of the economic impact of EPA's
proposed effluent guidelines while the second part contains
a more detailed analysis of the projected impact of the guide-
lines. The final part is a technical appendix which discusses
the economic impact of the seven policy alternatives that EPA
considered before publishing the proposed effluent guidelines.
As will be explained in later sections of the report, the
estimates in Parts I and II are based primarily on the analysis
presented in the technical appendix.
s proposed water effluent guidelines for steam electric
plants were published March 4, 1974 in the Federal Register,
pp. 8294-8307.
2,/Section 316(a) of the Federal Water Pollution Control Act of
1972 specifies that whenever the owner or operator of any
source subject to the thermal discharge guidelines can dem-
onstrate that the effluent limitation proposed for the control
of the thermal discharge for that source is more stringent than
necessary to assure the protection and propagation of a balanced,
indigenous population of shellfish, fish, and wildlife in and on
the body of water, the Administrator (or, if appropriate, the
state) may impose an alternative effluent limitation for thermal
discharge, that will assure the protection and propagation of a
balanced indigenous population of shellfish, fish and wildlife.
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II. POLLUTION CONTROL REQUIREMENTS AND COSTSl/
A. Effluent Limitation Guidelines for 1977 and 1983
As shown in Tables 18 and 19 (pp. 11-33-34) the
proposed effluent guidelines specify the level of chemical
and thermal pollution which can be discharged in 1977 and 1983.
While about 83% of the existing capacity and 92% of the planned
capacity will have to comply by 1977 with the chemical guide-
lines for best practicable control technology, there is a
phased schedule for compliance with the thermal guidelines.
Specifically, the utility industry is required to install closed
cycle cooling system according to the following schedule:
Units.!/ Date
- All units installed after Time of initial
July 1, 1977 operation
- Baseload 500 mw and over July 1, 1978
- Baseload 300 mw and over July 1, 1978
- Baseload in plants larger July 1, 1980
than 25 mw and in systems
larger than 25 mw
- All other baseload July 1, 1983
- All cyclic and peaking July 1, 1983
The expected coverage by 1983 of the thermal guide-
lines is summarized below:3_/
I/ This is a summary of Part II, Section IV n TT Tn
21 See Table 17, p. h-33 for definitions of' each category
3/ See Tables 20 and 21, p. 11-33-37 for estimates of the
coverage of the guidelines by each year.
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Cumulative Coverage by 1983 (e.g.
Capacity Placed % of capacity requiring closed
in Service cycle cooling )
Before Exemptions After Exemptions—
Non-Nuclear
- Prior to 1971 51% 10.2%
- 1971-1973 52% 10%
- 1974-1977 89% 40%
- 1978-1990 79% 38%
Nuclear
- Prior to 1971 80% 16%
- 1971-1973 67% 13%
- 1974-1977 100% 46%
- 1978-1983 100% 44%
B. Water Pollution Abatement Costs
The impact analysis in this report is based on cost
estimates contained in a document prepared for EPA by Burns
and Roe, Inc.—' The most important cost parameters are
summarized below:—'
Non-Nuclear Nuclear
Capacity Capacity
($/kilowatt ) ($/kilowatt)
Capital Costs (1970 Prices)
- Cooling Towers on New Plants $7.50 $10
- Cooling Towers on Existing 15.00 18
Plants
Annual Operating Costs (1970 Prices)
- Replacement Power
. 1977 42 42
. 1983 15 12
Capacity Losses
- Power to Operate Cooling 3% 3%
Tower and to Compensate
for Efficiency Losses
!_/ The figures reflect EPA's best estimate of the impact of
appeals under Section 316(a) of the FWPCA of 1972.
2^ EPA, Development Decoument for Proposed Effluent Limitation
Guidelines and New Source Performance Standards for the"
Steam Electric Power Generating Point Source Category,
March, 1974
_3/ See Tables 22 and 23 (pp 11-38 and 39) for a complete summary
of cost estimates for the thermal and chemical guidelines.
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In order to estimate the impact of the guidelines
in current dollars, it was necessary to estimate the rate
of inflation for capital and operating costs. A summary
of these estimates is presented in the technical appendix
(pp. 111-26 and 111-31).
It should be emphasized that in the absence of
federal legislation, the utilities would have installed
alternative cooling systems. The incremental cost of the
thermal guidelines, therefore, is the cost of cooling towers
minus the costs that the utility industry would have spent
for alternative cooling systems (e.g., once through cooling
in most cases and cooling towers in some cases). In order
to quantify the above factors, this report assumed that in
the absence of federal legislation, the mix of cooling systems
in the 1973-1990 period would correspond to the 1970 mix of
cooling systems. It is then possible to deduct the cost
of installing the 1970 mix of cooling system (e.g., Table 23,
p. 11-39 ) from the total cost of complying with the thermal
guidelines (e.g., Table 22, p. 11-38) in order to derive
estimates of the incremental cost of the thermal guidelines
(e.g., Table 24, p. 11-40).
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III. ECONOMIC IMPACT OF THE PROPOSED WATER EFFLUENT
GUIDELINE
A. Introduction
In order to assess the economic impact of the guide-
lines it is necessary to establish baseline projections for
the utility industry. According to the assumptions presented
in the technical appendix the financial projections for the
utility industry in the absence of expenditures for water
pollution control are as follows:^.'
Capitalized Total Yearly Average Consumer
Period Expenditures Revenue at Charges at End
During Period End of Period of Period _
(billions of current dollars) (Mills/Kwh)
1974-1977 93.8 57.0 24.0
1974-1983 364.0 113.6 31.9
1974-1990 968.1 240.9 43.2
The next step is to develop similar projections that
include the expenditures that will be required to comply with
the water effluent guidelines. The difference between the two
sets of projections, represents the total cost of EPA's guide-
lines. Finally, in order to calculate the incremental costs
of the guidelines, it is necessary to deduct the costs that
the utility industry would have incurred for alternative cool-
ing systems (e.g., once through cooling in most cases and cool-
ing towers in a few instances) in the absence of federal
environmental legislation.
In order to evaluate the economic impact of the guide-
lines, the principal focus of the following analysis will be
to compare the estimates of the incremental costs of the
guidelines (e.g., Tables27 and 28i/, PP- H-41-42) to the
baseline projections. Similar estimates of the total costs
of the guidelines are presented in Tables 34 and 35^.' (PP • II-
71-72) and their effect will also be examined.
JY This is a summary of Part II, Section VI p. 11-48
2y A detailed explanation of the baseline projections is
presented in Part III, pp. 111-20-43.
3_/ The estimates in Tables 27 and 28 were derived from the
technical appendix by taking the difference between Policy
Alternatives 7 and 7E (pp 111-98 and 11-116) and Policy
Alternative 0-T (pp-III-70).
4_/ The estimates in Tables 34 and 35 were derived from the
technical appendix by taking the difference between Policy
Alternatives 7 and 7E and Policy Alternative 0 (p. 111-36)
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A complete discussion of the economic impact
methodology is presented in Part II, p. 11-43 and in Part
III, p. III-149.
B. Financial Effects
1. Capital Requirements
Before exemptions the guidelines will increase
the utility industry's capital requirements by an additional
23.2 billion dollars or 6.3% by 1983 and an additional 163
billion dollars or 2.6% between 1983 and 1990. The comparable
figures after exemptions are 9.2 billion or 2.5% by 1983 and
5.2 billion or .8% between 1983 and 1990.-'
If one adds the capital costs that the utilities
would have incurred in the absence of the federal legislation,
the total capital required by the guidelines before exemptions
will be $28.5 billion (or 7.8%) by 1983 and $23.2 billion
(or 3.84) between 1983 and 1990. The comparable figures after
exemptions are $14.5 billion (or 4.5%) by 1983 and $12.1
billion (or 2.0%)between 1983 and 1990.
2. Sources of Financing
The u-tilities will finance the expenditures for
pollution control equipment through internal (e.g., deprecia-
tion, retained earnings, tax deferrals) and external sources
(e.g., long-term debt, preferred stock, common stock).
Based on assumptions incorporated into the PTm model,—' the
utilities could finance 34% of the (1970-1990) capital
expenditures through internal financing while the remainder
would have to come from external sources. There are several
reasons why the utilities should be able to obtain the
required external financing. First the utilities were able to
increase the level of capital investment by 11% per year in
the 1960's even though the industry's interest coverage ratio
fell from 5.11 in 1961 to 3.03 in 1971. Second, the guide-
lines have an insignificant effect on the industry's coverage
ratios in 1977, 1983, and 1990-3/ Finally, if the utilities
are going to be able to finance over 900 billion dollars of
investment for transmission and generation facilities by 1990,
it doesn't appear to be a major problem to finance an additional
14,4 billion dollars for pollution control equipment by 1990. **J
I/ The estimates represent the incremental costs of the water effluent
guidelines.
2/ The PTm (folicy Testing Model) was developed by Dr. Hower Pifer of
~ Temple, Barker, and Sloane, Inc. and Professor Michael L. Tennican
of the Harvard Business School to provide projections for the Technical
Advisory Committee on Finance to the 1973-74 Rational ?ower Survey.
A brief overview of PTm is provided in Part III, p. III-152.
3/ See p. 11-51 for estimates of the coverage ratios with and without
pollution control expenditures.
4_/ Total incremental impact after exemptions of the guidelines by 1990.
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It can be concluded, therefore, that if the utility industry
experiences problems in securing long or short term capital,
it will be the result of the large capital expenditures
required to expand transmission and generation facilities.
C. Price Effects
As shown in the following table, the utilities will
have to increase the price of electricity in order to finance the
operating costs and fixed charges associated with the guide-
lines .
Yearly Cost to the Con- Price Increase at the
sumer at the End of the Period End of the Period
Period Before After Before After
Exemptions Exempt ions Exempt ior s Exemptions
(Billions °f current $) (% Increase)
1974-1983 5.6 3.1 4.7% 2.5%
1984-1990 3.5 1.7 .2% .0%!'
An increase in the price of electricity will also have
an effect on the prices of other goods and services. However,
the average price increase is expected to be small since
purchases of electric power account for only .8% of the total
value of industrial shipments.!' Even if it is assumed that
the increased power costs are completely passed on to the final
consumer, the market price of the most power intensive industry
(e.g., primary production of aluminum) will increase only .3%
(after exemptions) by 1983.17
Based on the above estimates, it can be concluded that
both the direct and secondary price increases associated
with the water effluent guidelines will be very small.
3^7 The increase in the sales of electricity between 1984 and
~~ 1990 is sufficient to generate the 1.7 billion dollars of
additional revenue by 1990 without an additional price
increase.
2_/ National Economic Research Associates, Inc., Possible Impact
of Costs of Selected Pollution Control Equipment on the
Electric Utility Industry and Certain Power Intensive Consumer
Industries. 1972
_3_/ Estimate was calculated by multiplying the percentage of pro-
duction costs accounted for by electricity in the aluminum
industry, namely 11% by the projected price increase after
exemptions, namely 2.5%.
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D. Capacity and Energy Penalty
1. Capacity Penalty
Installation of cooling towers will require the
construction of new capacity to generate power to run the
cooling towers and to compensate for the loss of efficiency
due to the increase in turbine back-pressure.i' The baseline
case assumes that in 1977 the utilities will provide this
increased capacity through the construction of gas-turbine
units. However, by 1983 the utilities will be able to
construct large fossil and nuclear plants to replace the
lost capacity.
Before exemptions the total capacity penalty will
be 1,900 MWe by 1977 and 14,700 MWe by 1983. The comparative
figures after exemptions are 800 MWe by 1977 and 3,300 MWe
by 1983. The composition of the capacity penalty by type of
plant is estimated to be as follows:
Capacity Loss (in MWe)
1977 1983
Type of Plant Before After Before After
Exemptions Exemptions Exemptions Exemptions
1. Peakers (e.g. 1,900 800 1,900 800
gas turbines )
2. Base Loading 12,800 2,500
(Fossil and
Nuclear)
Tota] 1,900 800 14,700 3,300
The projected capacity loss before exemptions will
increase the national demand for generating capacity by only
.4% by 1977 and 2.2% by 1983. The comparable figures after
exemptions are .2% by 1977 and .4% by 1983. In view of the
small increase in the demand for generating capacity it can be
concluded that the utilities should not experience serious
problems in replacing the projected loss in generating capacity.
2. Fuel Penalty
There is a fuel penalty associated with the water
effluent guidelines. This penalty results from the following
factors:
!_/ It is estimated that the total capacity penalty will be
3% of the plants total capacity.
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a. Additional fuel required to operate the
closed cycle cooling system (e.g., 1%).
b. Additional fuel required per kwh of
electricity (e.g., higher heat rate) due
to the increase in turbine back pressure
(e.g., 2%).
The fuel penalty before exemptions will be approximately 4
millions tons equivalent of coal per year by 1977 and 33 mill-
ion tons per year by 1983. The comparable figures after
exemptions are 2 million tons by 1977 and 7 million tons by
1983.I/
In view of the current shortage of energy it is
important to evaluate the effect of the fuel penalty on the
national demand for energy, especially on the demand for oil.
2 /
Based on the Department of the Interior's estimates,—
the fuel penalty after exemptions will increase the national
demand for energy ,05% by 1977 and .2% by 1983. Also, if one
assumes that the fossj.1 fuel penalty will be evenly divided
between coal and oil,i' the guidelines after exemptions would
increase the national demand for oil 4 million barrels per
year or .06% by 1977 and 14 million barrels per year or -2% by
1983. It can be concluded, therefore, that the effluent guide-
lines will have an insignificant effect on both the nation's
ability to satisfy the projected demand for energy and the
country's dependency on foreign sources.
E. Production Effects
Even if the utilities experience delays in obtaining
rate increases to finance expenditures for pollution control
equipment, it is unlikely that an entire power plant will
shut-down because of the higher costs. The one production
effect of the guidelines, however, may be to force certain
utilities to prematurely retire some older units in order
to avoid spending large amounts for pollution control equip-
ment. Such an option will probably be used only after 1977
when it would be possible to replace the retired unit with
new large fossil or nuclear units. Finally, the guidelines
W The fuel penalty was converted to coal equivalency by taking
the total increase in demand for nuclear and fossil fuel
expressed in million BTU, and dividing by the average BTU per
ton -of coal (e.g., 24 million BTU/ton).
2J Dupree, Walter G. and West, James A., United States Energy
Through the Year 2.000. U. S. Department of the Interior,
December, 1972.
_3_/ This is probably a conservative assumption since if the fossil
fuel penalty was distributed according to the projected
utility demand for coal and oil, the eaergy penalty would be
65% coal and 35% oil.
1-9
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won't have a large effect on the growth of the electric
utility industry since the projected increases in the price
of electricity (e.g., 2.5% after exemptions by 1983 is not
expected to have a large impact on the demand for electricity.
F . Employment Effects
Since the price increases associated with the guide-
lines are not expected to have a significant effect on the
growth in demand for electricity, the overall level of employ-
ment in the electric utility industry will increase in order
to meet the projected increase in demand for electricity.
Also as discussed in the previous section, the guidelines are
not expected to cause any plant closures and any employment
effects due to the early retirement of inefficient generating
units will probably be offset by the projected expansion in gen
erating capacity. Furthermore, if the increased demand for
generating capacity due to capacity penalties (e.g., .42 after
exemptions by- 1983), is greater than the reduction due to the
projected price increase, the guidelines will Increase the
level of employment.
G . Community
The water effluent guidelines will impact the community
directly through increased price for electricity and indirectly
through price increases for final goods and services. As shown
in Table 30, p. 11-61), the guidelines after exempt ionsl7 will
increase the average resident's monthly electricity bill $.39
or 1.6% by 1977 and $1.08 (2.5%)by 1983. The indirect price
increases, however, will be so small (e.g., less than. 3%) that
its impact is considered to be insignificant.
H. Balance of Trade
The guidelines will have a small effect on the balance
of trade because part of the increased fuel consumption
associated with closed cycle cooling systems will be met by
increased imports of residual fuel oil. Based on the assumptions
used to estimate the fuel penalty, the guidelines before
exemptions will increase oil imports by 38 million barrels per
year or 1.2% by 1977 and 66 million barrels per year or 1.7% by
1983. The comparable figures after exemptions are 4 million
barrels or .6% by 1977 and 14 million barrels or ,4% by 1983.
It is difficult to estimate the total balance of payments
costs of the guidelines since there is considerable uncertainty
concerning the future price of imported oil. If one assumes
a net out-flow of $7 per barrel of oil, however, the balance
of payments costs before exemptions would be 56 million dollars
per year by 1977 and 462 million dollars per year by 1983.
The comparable figures after exemptions are 28 million dollars
by 1977 and 98 million dollars by 1983. Since the level
of imports in 1973 was approximately 70 billion dollars, it can be
concluded that the guidelines will have an insignificant impact
on the nation's balance of trade.
17 The comparable figures before exemptions are also estimated
in Table 30.
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IV. LIMITS TO THE ANALYSIS!/
A. Uncertainty of Cost Estimates
The analysis indicates that alternative assumptions
about the capital and operating costs of chemical and thermal
pollution control equipment and about the impact of closed
cycle cooling systems on generating efficiencies have a
substantial impact on the projected economic impact of the
guidelines. The effects over the 1974-1984 period of these
technological uncertainties are summarized below.—'
The costs shown are the impact of each assumption
relative to the assumptions incorporated in EPA's proposed
guidelines.
Increase in Capitalized Expendi-
tures After Exemptions —
Chemical Cost Factors
. Maximum
Increase—
+ 200%
$ Increase
(billions current $)
+ 12.9
Thermal Capital Costs
for Retrofits
. Maximum
. Minimum
+ 35%
- 16%
.95
.43
Thermal Operating Costs
and Efficiency Losses
. Maximum
. Minimum
38%
' 7%
1.0
.2
If one assumes the maximum set of assumptions for both
the thermal and chemical guidelines the capital cost of the
guidelines after exemptions by 1983 would increase from 9.2 to
24.1 billion dollars. It can be concluded, therefore, that under
the most conservative set of assumptions, the effluent guidelines
will increase the utility industry's capital requirements by only
6.5% by 1983.
I/
2/
3/
II, Section VII
11-62
This is a summary of Part
See Part II, p. 11-62 and Part III, p. III-129 for a more
detailed discussion of the impact of alternative technological
as sumpt ions.
These estimates assume that the percent variation in impact
for EPA's guidelines after exemptions (e.g., Policy Alternativ
7-E in Part III) is the same as the percent variation for
the technology based guidelines (e.g., Policy Alternative l(a)
in Part III ).
Percent increase over estimates presented in Table 27, p. II-
58 (e.g., 2.7 billion dollars for thermal guidelines and 6.5
billion for the chemical guidelines after exemptions by 1983).
1-11
-------
B. Critical Assumptions
While the preceding sections have analyzed the
impact of the guidelines based on a single set of assumptions
about the growth in demand for electricity, similar calcula-
tions have been made using a low forecast for the growth in
demand.!-' The analysis indicates that under the low demand
case the utility industry's projected expenditures between
1974 and 1983 for transmission and generation facilities is
reduced about 31% from 364 to 250 billion dollars. Since
the projected impact of the guidelines after exemptions is
reduced by only 20%, the incremental impact of the guidelines
will be slightly increased. Specifically, the guidelines
after exemptions will increase the utility industry's
capital requirements 3.0% by 1983 (compared to 2.5% in the
high demand case. It can be concluded, that even under assump-
tions of low demand, the utility industry should be able to
comply with the guidelines without experiencing serious pro-
blems in financing the required expenditures.
Another critical assumption was that in the absence
of federal environmental regulations, the mix of cooling
facilities in the 1973-1983 period would correspond to the
1970 mix of cooling facilities. Therefore, for new power plants
the incremental cost of the thermal guidelines would equal the
cost of cooling towers minus the cost of the basic cooling
facility that the utility would have installed (e.g., once
through cooling in most cases and cooling ponds, combination
systems or cooling towers in the remaining cases). For exist-
ing power plants, however, the incremental cost and the total
cost of the thermal guidelines would both be equal to the
cost of cooling towers.
There are a number of problems concerning this
assumption. First, it is extremely difficult to forecast
what mix of cooling facilities would have been installed
in the absence of federal environmental regulations. Second, a
certain percentage of the new power plants have already incurred
costs for the construction of cooling facilities. Thus, the
incremental costs presented in Table-26 (p. 11-42) which were
calculated based on the assumption that no costs had been
incurred for alternative cooling facilities, actually under-
estimate the impact of the guidelines. Finally, there was a
computational error in the computer run that calculated the
incremental cost of the guidelines after exemptions (e,g,,
policy alternative 7(e) in Part III). Specifically, the costs
See Part III, p. III-122 for a description of the low demand
case.
1-12
-------
that the utility industry would have incurred for cooling systems
in the absence of federal legislation (e.g., Table-25, p.II-4l)
were not included for that fraction of new capacity which will
not be covered under the guidelines. In order to accurately pre-
dict the incremental costs of the guidelines after exemptions,
these costs would have to be added to the estimates which wpre
presented in Tables 27 and 29 (pp. 11-58-59).
It can be concluded, therefore, that the actual incre-
mental costs of the guidelines fall in between the total cost
estimates (Table-22, p. 11-38) and the incremental cost
estimates (Table 26). If one assumes the worst case, namely
that the incremental cost actually equals the total cost, the
capital requirements of the guidelines would increase 5.8
billion dollars by 1983.I/ However, since this would increase
the utility industry's capital requirements only an additional
1.4% by 1983, there is no reason to question the validity of
the analyses' major conclusions.
I/ Similar estimates for other impacts (e.g., price, capacity
~~ and fuel penalty, etc.) are given in Tables 33 and 34, pp. II
71-72.
1-13
-------
PART II
IMPACT ANALYSIS
-------
I. STRUCTURE OF THE INDUSTRY
A. Introduction
The electric utility industry is primarily composed
of the following types of production facilities:
1. Steam Electric (fossil and nuclear)
2. Hydro-electric
3. Internal combustion (e.g., diesel
and gas turbine)
In 1970 steam electric plants generated 83.6% of the nation's
electricity while hydro-electric and internal combustion
plants produced 16.1% and .3% respectively of the nation's
electrical output.—'
Although the proposed water effluent guidelines will
apply almost exclusively to steam electric plants,—there
was not sufficient time to segment the existing financial
data by type of production facility. Therefore, sections
I, II and III will discuss the structure of the entire
electric utility industry. The economic impact analysis
(e.g., sections IV, V, VI, VII) estimates the
costs that steam electric power plants (and where appropriate
internal combustion plants) will incurr in order to comply
with the proposed water effluent guidelines.
!_/ Edison Electric Institute, Statistical Yearbook of the
Electric Utility Industry for 1970, September 1971
2_/ The thermal guidelines will apply exclusively to steam
electric plants (e.g, plants that have a steam cycle). However, the
chemical guidelines will be applicable to internal combustion
generation facilities as well as to steam electric plants.
II-l
-------
B. Supply Characteristics i
1. Types of Firms
The electric utility industry is composed of four
types of entities—investor-owned, publicly owned (non-Federal),
Federally owned and cooperatives. In 1965,.2.' the industry was
composed of 3,550 systems, of which 437 were investor-owned,
2,101 were publicly owned, 971 were rural electric cooperatives
and 41 were Federally owned bodies (see Table -1-). The rela-
tionships among the 3,550 systems are diverse: some either
generate no power or supply only a portion of their own needs,
others have no retail customers but are engaged only in genera-
tion and the wholesaling of power to distributors in the retail
business. As shown in Table -3-, the vast majority of the
investor-owned utilities are engaged in generation, transmission
and distribution, whereas almost two-thirds of the publicly
owned utilities purchase all of their power and only a few coopera-
tives have any generation and transmission facilities. Federally
owned utilities, on the other hand, are almost totally engaged
in generation and transmission.
In 1970, the investor-owned utilities accounted for
about 80 percent of total generating capacity arid over
77 percent of the total production of electricity, thus
constituting the largest segment of the industry. The publicly
owned utilities represented 10 percent of the total generating
capacity and about 12 percent of the total production, while
the cooperatives accounted for only 1 percent of capacity and
percent of total production. Federally owned utilities
represented 11 percent of the generating capacity, and supplied
about 12 percent of total production.
For several reasons, publicly owned and cooperative
systems are able to obtain capital at a lower cost.3-' Federal
projects, other than TVA, obtain capital directly from the
U.S. Treasury. REA cooperatives also obtain capital directly
from the Federal government.
1./ This section was exerpted from a report, entitled Possible
Impact of Costs of Selected Pollution Control Equipment
on the Electric Utility Industry and Selected Power InFensive
Consumer Industries, 1972, which was prepared for the
Council on Environmental Quality.
2./ The most recent year data are available in terms of genera-
tion, transmission and distribution functions.
3./ In the accounting sense of that word.
II-2
-------
2. Regulation^-/
Regulators directly control profits and thus the
general level of utility prices by allowing utilities to earn
no more than a "fair" rate of return on invested capital. In
order to penalize inefficiency and control costs, regulation
requires that only those expenses and investments which are
prudently made can be recovered in rates. Moreover, if elec-
tric utilities have excessive capital costs because of inappro-
priate capital structures, commissions may substitute hypo-
thetical structures and refuse to allow rates higher than would
be needed to cover the lower hypothetical capital costs. Undue
price discrimination is prohibited by providing cost-based tests
for the setting of individual rates.
In order to promote "adequate" reliable service,
commissions control the terms of service extensions and serv-
ice obligations. They also provide a forum for consumers to
voice service complaints. Finally, regulators have resorted
increasingly to withholding rate increases in order to induce
regulated companies to develop satisfactory service quality
standards.
There are six rather well defined specific areas of
regulatory activity which can be distinguished for the elec-
tric utility industry. The first of these is what is generally
thought of when the term "utility-type" regulation is used.
With few exceptions this applies only to investor-owned utili-
ties and is accomplished at the state or local level through a
public service commission or body with some equivalent desig-
nation. Utility-type regulation constitutes the basic means
by which the government comprehensively oversees operation of
the monopoly franchise granted to each investor-owned utility.
All Federal utility operations and, in most cases, municipals
and REA cooperatives are exempt from utility-type regulation.
The Federal Power Commission implements a parallel
type of regulatory activity. It has jurisdiction over the
wholesale rates charged by private utilities, and, in addition,
jurisdiction over the interconnection of utility systems, the
provision of wholesale service, and the general reliability
standards of all utilities. The FPC has also become involved
in joint planning by private and public electric utilities
for meeting regional power loads.
I./ This section was exerpted from a report, entitled "Possible Impact
of Costs of Selected Pollution Control Equipment on the Electric
Utility Industry and Selected Power Intensive Consmer Industries,
1972, which was prepared for the Council on Environmental Quality
II-3
-------
All utilities, whether private or public, are faced
with the second regulatory activity, which is the hydrolicensing
function of the Federal Power Commission. Any hydro project
which involves the construction of a dam on a navigable stream
must obtain a license from the FPC. This license is good for
a specified number of years at the end of which time it must
be renewed subject again to the FPC's approval. The Commission,
moreover, has the right to "recapture" or take over the hydro-
power project in the name of the government at the expiration
of its license.
The third area of regulation is carried on by the
Atomic Energy Commission. This is divided into two subareas,
the first of which is licensing. All nuclear power plants,
whether built by public or private utilities, must first
receive AEC approval of the design, then obtain a license for
construction of the plant, and, finally, a license for its
operation. A second subarea of AEC regulation is general
monitoring to see that health and safety standards are
maintained.
The fourth area of regulation is antitrust. Increas-
ingly in recent years the Justice Department has taken the
position, through both pronouncement and participation in
cases, that the situation of the utility industry in being
subject to regulation does not grant it immunity from anti-
trust consideration. Thus, the Justice Department has challenged certain
mergers between private utilities and has brought pooling arrangements
under its scrutiny. In addition to the Justice Department's direct roles,
the licensing section of the Atomic Energy Act provides that the review
procedure for licensing nuclear plants must include consultation on the
antitrust aspects with the Justice Department. The regulatory responsibilities
of the Securities and Exchange Commission under the Public Utility Holding
Company Act also include consideration of antitrust factors.
The fifth area is the industry's financing activities.
Both the FPC and the SEC have jurisdiction over various aspects
of the issue of securities and notes and short-term bank borrow-
ing.
The final area of regulation is the environmental
area, especially since the Calvert Cliffs decision. The
regulation in this area is not as direct as in the preceding
areas but comes about through the legal necessity, under
Calvert Cliffs, of assuring that the Environmental Protection
Agency s standards and criteria will be met in the construction
and opeation of generating and transmission facilities.
II-4
-------
The Tennessee Valley Authority is a special case:
since 1961 it has been permitted to issue taxable revenue
bonds to finance new construction. As an agency of the
Federal government it borrows at lower interest rates and is
spared the need to raise high-cost equity capital. TVA also
benefits from the fact that charges on its pre-1961 capital
derived from appropriations are equal only to the average
interest rate paid by the U.S. Treasury, and such capital
derived from retained earnings is available without cost to
TVA.
Municipals, like private utilities, must go to the
marketplace to obtain capital, but no Federal income tax is
imposed on the interest received by municipal bondholders.
Municipals thus pay their bondholders only the net rate of
return they demand.
Publicly owned electric utilities are also free
from direct taxation. These systems normally pay no Federal
or state corporate income tax and no property tax (however,
some payments in lieu of local property taxes are often made).
3. Generation of Electricity by Type of Plant
At the present time, fossil fueled plants
represent only 79%of total generating capacity. The remainder
is accounted for by hydro-electric generation both of the
once-through and pumped-storage types, and by direct com-
bustion-generation processes, such as gas turbines and diesel
engine driven generators (see Table ~2-. for percentages).
However, as shown in Table -2- the composition
of generating capacity is expected to change drastically over
the next two decades. Fossil fueled plants will decline from
79% to 44% of total capacity and nuclear plants will increase
from 2% to 40% of total capacity. While conventional hydro-
electric power will decline from 15% to 6% of total capacity,
hydroelectric-pumped storage will increase from 1% to 6% of
total capacity.
II-5
-------
4. Present and Projected Use of Fuels
In 1970, of the 1,529.6 billion kilowatt-hours of
electricity produced by the electric utility industry in
the United States, 709.1 billion kilowatt-hours, or 46.4
percent, was produced by coal. Natural gas represented
the second largest portion of generation, at 24.2 percent.
Electricity generated from hydropower and from oil-fired
boilers was 16.2 per cent and 11.8 percent, respectively,
and nuclear generation represented only 1.4 percent of
total generation.L' As Table -3- shows, the pattern in 1969
varied distinctly from region to region. Gas clearly is the
dominant fuel in the West South Central region, accounting
for 96 percent of fuels used for electricity generation in
that area. Nebraska and California also consume substantial
amounts of gas in the generation of electric energy,. Hydro-
electric production dominates in the Far West (excluding
California) . Coal is, dominant in the East North Central and
the East South Central (including TVA) regions and, to a
slightly lesser degree, in the South Atlantic region. Oil-
fired generation accounts for almost 60 percent of all
generation in New England.
Table -4-shows for the last decade the percentage
contribution of each of the fuels and hydropower to electric-
ity generation in the United States as a whole. As can be
seen from the Table, coal has been losing its relative posi-
tion, while oil and gas are increasing as sources of
electricity and hydropower has remained relatively stable.
As Table -5- indicates, the shift in fuel use
will accelerate in the 1970's and 1980's. In 1980 27.6% of
total electricity generation will be made up by nuclear,
36.5% by coal, 12.4% by natural gas, 12.4% by oil, and 11.4%
by hydro. By 1990, nuclear will amount for 47.3%, coal 26.7%
gas 7.2%, oil 8.0%, and hydro 10.8%. Id
However, even though the relative importance of coal
and oil will decline, the total demand for steam coal and fuel
oil more than double by 1990. Also,as shown in Table -6, there
will be a 1600% increase in the demand for uranium ore.
_!_/ Federal Power Commission, News Release of March 18, 1971,
No. 17372.
2/ The figures in Table-5- will change because of the recent increases in
the price of oil and the Federal government's commitment to achieving
greater energy self-sufficiency. In particular the use of coal will
increase faster than previously projected.
II-6
-------
5. Employment in the Industry
Since the electric utility industry is the most capital-
intensive industry in the United States, it employs relatively few
workers. As Table -^7-> demonstrates, for the year 1970, investor-owned
electric utilities employed a total only 384,900 workers, or only 0.4
percent of the United States labor force. Almost 25 percent of these
were engaged in construction work for the industry. Therefore, there
would be little effect on general employment levels even if the increased
costs associated with water pollution abatement control were to lead to
the laying off of workers.
11-7
-------
C. Demand Characteristics
1. Aggregate Energy
It would be unrealistic to consider the demand
for electricity alone without considering it in the context of
the demand for energy in all of its forms. The economy demands
energy; not necessarily electricity, or natural gas, or any
specific fuel. As we shall later explain, there are various
possibilities for substitution between different energy sources.
During the 1960's the aggregate demand for all
forms of energy (see Table -8-) in the United States increased by
53 per cent (or at a compounded annual growth rate of 4.4 per
cent), primarily as a result of a pronounced acceleration in
energy consumption during the latter half of the 1960s. During
this same period the total demand for electricity (see Table -9-)
increased by 104% or at a compounded annual growth rate of 7.2%.
A recent study by the FPC.L/ indicates that
demand for electricity will increase by 7.5% per year between
1970 and 1980 and by 6.5 % per year between 1980 and 1990,
However, mitigating factors such as large price increases, energy conserva-
tion programs, may substantially reduce the projected demand for electricity,
2. Substitutability Among Primary Fuels and
Electricity & I
In some applications electricity and the primary
fuels are highly substitutable, whereas in others the use of
one particular energy form is dictated by currently prevail-
ing technologies and relative prices. One can identify
several distinct levels of Substitutability. The residential
small appliance and lighting market, for example, is differ-
entiated by the fact that no present or foreseeable potential
substitute product is capable of rendering the services now
provided by electric energy. Similarly, an appreciable element
of the demand by commerical customers is in lighting, which
generally cannot be satisfied by other energy forms. This
does not mean, however, that commerical customers are completely
dependent on electric utilities for their energy. They may
have the option of "total energy;" that is, under certain
special conditions they can install their own generators which
can be fired by either gas or oil. The generator supplies
electricity needs while waste heat from the turbine or engine
supplies heating and cooling needs. The need for a well
l_l Federal Power Commission, Forecasts of Electric Energy and
Demand to the Year 2000, June 1973.
2j This section was exerpted from a report, entitled Possible Impact
of Costs of Selected Pollution Control Equipment on
Utility Industry and Selected Power Intensive Consumer Industries j
1972, which was prepared for the Council on Environmental Quality.
II-8
-------
balanced energy load to make total energy an economical
alternative, however, puts an effective limit on the signi-
ficance of total energy as a competitor of electric utilities.
Clearly, commercial customers who require energy primarily
for lighting generally will not find it feasible to go to
total energy. We can assume, therefore, that residential and
commercial small appliance and lighting markets are serviced
mainly by electric utilities.
In contrast, distinct residential and commercial
large appliance and space heating markets would seem clearly
to be characterized by a high degree of substitutability among
electricity, gas and oil energy inputs. For space heating
and water heating applications, electricity faces, as primary
potential substitutes, oil and gas, and in commercial uses,
possibly coal. Indeed, in these markets, electric energy is
generally the new entrant. There may, of course, be areas in
which neither oil nor natural gas facilities are available
and the electric utility therefore may face only such alter-
natives as bottled liquefied gas for these energy uses.
Similarly, for such applications as cooking, clothes drying
and air conditioning, electricity would be in potential com-
petition only with either natural gas where it is available
or with bottled gas. Where neither is available, the electric
energy supplier would be in a monopolistic position. In
general, however, it would seem a_ priori that the residential
and commerical markets for large appliance and heating appli-
cations may be served by electricity and gas, and to a more
limited extent, oil or coal.
Despite the fact that the nature of industrial
energy demand varies widely with the specific industry, some
general observations can be made. For large customers, the
bulk of the energy demand is likely to be for applications
other than lighting. Where the demand is largely for process
heat, for example, gas, oil and coal may compete effectively
with electricity. Even where the demands are of a nature that
must be met necessarily by electric energy, such as stationary
drive requirements, several substitution possibilities may
exist. The large industrial customer may be able to employ a
total energy installation or may be able to self-generate his
power in a conventional fossil-fuel station. Thus, it would
seem, generally, that the greatest energy product substitution
possibilities are open to industrial customers.
II-9
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3. Elasticity of Demand for Electricity
A crucial variable in discussing and assessing the
effects of pollution control on electric utilities is the
demand responsiveness of the consuming public to changes in
the price of electricity. If, for example, the elasticity
of demand for all electric utility customers were zero, then
any increase in the price of electricity would cause no decrease
in the quantity demanded. In such a situation, all pollution
control costs could be passed on to consumers of electricity
without any change in the demand for that form of energy.
However, if the elasticity of demand for electricity was 1.0,
then an increase in the price of electricity, say of 10 percent,
would cause a decrease in the demand for electricity of 10 percent
A review of several econometric studies which have
attempted to measure the elasticity of electricity demand
indicates that the data on which these studies were based (quite
aside from the appropriateness of the econometric
techniques employed) were too broad, too frag»entarjr or too
ambiguous to give the results much validity. There is, there-
fore, for practical purposes, no measure of the elasticity of
electric demand usable for our purposes.
Probably the only conclusions that can be made are
that the short-run elasticity is likely to be considerably less
than the long-run elasticity and that the elasticity of demand
for small changes in the price of electricity (e.g., about 5-
10%) are likely to be considerably less than the elasticity
for large changes in prices (e.g., greater than 10%).
11-10
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TABLE -1-
UNITED STATES ELECTRIC UTILITY INDUSTRY
Number of Systems!/
Ownership
Investor-Owned
Public (Non-Federal)
Cooperatives
Fedeail
Total
(1)
437
2,101
971
41
TOTAL 3,550
I/ 1965 data.
2j 1970 data, preliminary
_3/ Col. (5) -Col (6) - Burns & Roe, Inc
and Standards of Performance: Steam
Engaged in
Generation
and Trans-
mission
(2)
262
725
72
39
1,098
. , Development
Engaged in
Distribution
Only
(3)
175
1,376
899
2
2,652
Document for
Generating-/ Production3-/
Capacity,
Percent 106 MWH
of Total
(4) (5)
77.2 1,182
10.1 140
1.4 22
11.4 185
4/ 1,528
Effluent Limitation Guidelines
Percent
(6)
77.53
9.1
1.4
12.1
I/
Electric Plants, June 1963
j4/ Percentages do not add to one hundred due to rounding.
-------
TABLE -2-
i
V-
PROJECTED GROWTH OF UTILITY ELECTRIC GENERATING CAPACITY
(Figures in thousands of megawatts)
1970 (actual)
% of
1980
1990
Type of Plant
Fossil Steam
Nuclear Steam
Subtotal Steam
Hydroelectric-
conventional
Hydroelectric-
pumped storage
Gas-Turbine and Diesel
Capacity Total
260
_ 6
266
52
TOTALS
Notes: (1)
(2)
(3)
341
76
_2
78
15
1
6
100
% of
Capacity Total
59
22.
81
68
666
10
4
5
100
% of
Capacity Total
557 44
500 4_0_
1,057 84
82 6
71
51
6
4
1,261
100
These projections are keyed to the electrical energy demand projections made
by Regional Advisory Committee studies carried out in the 1966-1969 period.
The projections are premised on an average gross reserve margin of 20%.
Since different types of plants are operated at different capacity factors,
this capacity breakdown is not directly representative of share of kilowatt-hours
production. For example, since nuclear plants are customarily used in base-load
service and therefore operate at comparatively high capacity factors, nuclear
power's contribution to total electricity production would be higher than its
capacity share.
SOURCE
EPA, Development Document for Proposed Effluent Limitation Guidelines and
New Source Performance Standards for the Steam Electric Power Generating
Point Source Category, Sept. 1973.
-------
TABLE -3-
PER CENT OF ELECTRICITY GENERATION BY SOURCE, BY REGION
1969
Region
Coal
Oil
Gas
Nuclear Hvdi o
(Per Cent)
New England
Middle Atlantic
East North Central
West North Central
(Except Nebraska)
Nebraska
South Atlantic
East South Central
(Except TVA)
Tennessee Vctl-ley AuLhu.tiLy
West South Central
Rocky Mountain
Far West
California
22.1% 59.3% 0.9%
5?. 3 26.1 7.1
92.4 0.6 5.0
47". 7 1.1 36.
28.2 1.2
69.2 14.4 10.4
74.5 0.3
8l. I —
I/ 0.2
33.5 2.1
1.5 I/
10.2
8.5% 9.3%
0.9 13.6
0.4 1.5
36.3
53.8
10.4
19.9
2.3
96.1
28.6
1.8
53.4
14.9
16.8
6.0
r: o
"""" j * -j
16.5
3.8
35.8
3.3 93.4
2.1 34.4
Less than 0.1. per cent.
Source: Edison Electric Institute, Statistical Year Book of
g_lectric Uti3_i_ty__In_d_us try for J^JO , Tables 1 3 S
~
National Coal Association, S t e anv-E 1 ec t r i c _ P 1 an t
, Table 1.
Tenries'soe Valley Authority, Power Annual Report, 1969 ,
p. 23.
11-13
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TABLE- 4-
PER CENT OF ELECTRICITY GENERATION,
BY SOURCE, 1960-1970
Year
Coal
Oil Jf£Ls_ Nuclear
(Per Cent)
Hydro
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
53.6
53.5
53.1
54.2
53.8
54.5
54.1
52.6
52.5
49.0
46.4
6.1
5.9
5.5
5.7
5.8
6.1
6.9
7.4
7.8
9.6
11.8
21.0
21.4
21.6
22.0
22.4
21.0
22.0
21.8
22.9
23.1
24.2
^/
y
V
y
V
y
y
y
y
1.0
1.4
19.3
19.2
19.7
18.1
18.0
18.4
17.0
18.2
16.7
17.3
16.2
I/ 'Small percentage included with coal.
Source: 1960-1968: U. S. Department of Commerce, Statistical
Abstract of the United States, 1964-1970.
lfJ69^r9T(r' Calculated from data in Federal Power
Commission, News Release of March 18, 1971, No. 17372
11-14
-------
T ABLE- 5-
PERCENT OF ELECTRICITY GENRATION BY TYPE OF FUEL
1970-1990
PERCENTAGE
YEAR COAL OIL GAS NUCLEAR HYDRO
197(>i/ 46.4 11.8 24.2 1.4 16.2
36.5 12.4 12.4 27.6 11.1
26.7 8.0 7.2 47.3 10.8
I/ Federal Power Commission, News Release of March 18, 1971,
No, 17372
2/ Estimated from data in National Economic Research Associates,Inc.,
Possible Impact of Cost of Selected Pollution Control Equipment
on the Electric Utility Industry and Certain Power Intensive
Consumer Industries, 1972 and Burns and Roe, Inc., Development
Document for Effluent Limitation Guidelines and Standards
of Performance, June, 1972.
11-15
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TABLE-6-
PROJECTED ANNUAL FUEL REQUIREMENTS STEAM
ELECTRIC POWERPLANTS
1970-1990
FUEL
Coal
Natural Gas
Residual Fuel Oil
Uranium Ore
UNIT
106tons
109cu.f t.
106bbl
tons
1970
322
6,600
331
7,500
1980
500
3,800
640
41,000
1990
700
4,200
800
127,000
(1) Tons of V^Og required to supply feed for difussion plants
without plutonium recycle.
SOURCE: Burns and Roe, Inc., Development Document for Effluent
limitation Guidelines and Standards of Performance;
Steam Electric Plants, Jane 1963
11-16
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TABLE-7-
AGGREGATE ENERGY CONSUMPTION
IN TilE UNITED STATES, 1960-1970
Year
Amount
Per Cent
Change from
Preceding Year
1960
1961
1962
1.963
1964
1965
IS* 6 G
1967
1968
1969
1970 p.
(Trillion Ubii)
44,960
45,573
47,620
49,649
51,515
53,785
56,948
58,868
62,448
65,832
68,810
(Per Cent)
-
+ 1.4
+ 4.5
+ 4.3
+ 3.8
+ 4.4
+ 5.9
+ 3.4
+6.1
+ 5.4
+ 4.5
p. - Preliminary.
Source: 1960-1969: U. S. Department of the Interior,
Minerals Yearbook, Vol. II, 1962-1969.
1970: U. S. Department of the Interior, News
Release of March 9, 1971.
11-17
-------
TABLE -8-
AVKRAGE NUMBER OF EMPLOYEES OF I/
INVESTOR-OWNED ELECTRIC UTILITIES IN THE UNITED STATES ~
1960-1970
Year
Operation
and
Maintenance
Construction
Total
1960
196.1
1962
1963
1964
1965
1966
1967
1968
19G9
1970
*" "*~
274
272
268
268
268
268
271
275
279
282
290
-•_-,-.
.5
.0
.9
.7
.6
.4
.0
.5
.3
.6
.2
- (THbusan
71
71
70
70
72
77
78
81
86
89
94
do}
.4
.0
.9
.8
.9
.0
.1
.9
.0
.9
.7
345.9
343.0
339.8
339.5
341.5
345.4
349.1
357.4
365.3
372.5
384.9
I/
"Includes Alaska and Hawaii.
Source: Edison Electric Institute, Statistical Year
Book of the Electric Utility'Industry , 1970.
11-18
-------
TABLE -9-
TOTAL ELECTRICITY CONSUMPTION IN UNITED STATES
1960-1990
YEAR
1960
1970
1980
1990
KWH
GENERATED (Million)
684, OOO!/
l,396,000l/
5,557,000.?7
PERCENT CHANGE
DURING PERIOD
104%
110%
90%
ANNUAL GROWTH
RATE -'
7%
I/ Edison Electric Institute, Statistical Yearbook of the
Electric Utility Industry for 1971, Oct, 1972.
2/ Federal Power, National Fewer Sur.ey Tech;n,j.ca,l Advisory
Commitee for Itnance. 1973
W Percentages are rounded off.
11-19
-------
II. FINANCIAL PROFILE
A. Profitability—/
1. Total Assets
The electric utility industry is the most
capital intensive industry in the United States. As shown
in Table-10, the total assets of the investor-owned electric
utilities were approximately 100 billion dollars in 1971.
Since, the investor-owned utilities account for about 77%
of total generating capacity, the total assets of the entire
electric utility industry were approximately 125 billion
dollars in 1971.
2. Total Sales
As shown in Table-11-, total sales of electricity
in 1971 were about 25 billion dollar. The investor-owned
utilities accounted for approximately 85% of total sales.
In the period 1960-1971, total sales increased
by 115% which was equivalent to an annual growth rate of about
7.3%.
3. Net Income
As shown in Table-12 , the net income after
taxes in 1971 for the investor owned utilities was about
3.8 billion dollars. Inclusion of the public owned utilities
should not significantly change this figure, since net income
for the public sector (e.g., after allowance for depreciation
and other fixed charges) should theoretically be zero. "LJ
In the period 1964-1971, net income in the
private sector, increased by 74% which was equivalent to
an annual rate of about 8%.
B. Capital Formation
1. Historical Trends in Total Investment
As shown in Table-13-, total investment by
the electric utility industry was 14.8 billion dollars
in 1971. During the period 1961-71, the total cumulative
investment was 88 billion dollars. In the same period
total annual investment grew by 200 % which was equivalent
to an annual rate of approximately 11%.
If While this section includes financial data on the entire Electric
Utility Industry, it should be emphasized that about 9% of the
industry is involved in the distribution and sale of natural gas.
2_/ This assumes that a public utility will charge rates that
will just cover operating expenses plus allowance for
depreciation and other fixed charges.
11 '20
-------
2. Projected Investment for 1973-1990
Recent projections— indicate that in the period
1973-1990 the electric utility industry will have to raise
968 billion dollars just to finance the expansion of generating
transmission and distribution facilities. In this period total
annual investment will grow by 13% per year. In later sections of
this report, estimates will be made of the additional capital requirements
associated with the water effluent guidelines,
3. Sources of Financing
The utilities finance capital expenditures
through internal and external sources. Internal financing is
generated by retained earnings, depreciation (both on fixed
assets and nuclear fuel), and tax deferrals. The sources of
external financing are long-term debt, preferred stocK and
common stock.
The financial model—' used to estimate the
required investment for generation, transmission and destribu-
tion calculated that the utilities would finance 37% of the
1973-90 financial needs through internal financing and
the remainder through external financing. Looking specifically
at the investor-owned utilities, the required investment will
be financed in the following manner:
Financial
Type of Financing Requirements
1973-90
(Billion $)
1. Internal Financing
retained earnings 62
non-cash charges 235
(depreciation and deferrals)
Total Internal Financing 297
2- External Financing
long-term debt 324
pEEferred s^tock 56
common stock 132
Total External Financing 5~i2"
3. Total Financing 809
I/ See Part III, P. 111-20 for detailed estimates of the baseline
projections.
2.7 See Part III, P. III-158-for a description of the model's
financial module.
11-21
-------
TABLE-10-
COMBINED BALANCE SHEETS—YEAR ENDED DEC. 31—INVESTOR-OWNED ELECTRIC UTILITIES!/
INTERCOMPANY TRANSACTIONS ELIMINATED
MILLIONS OF DOLLARS
1071 1070 1000 1068
ASSKTS
I'tilitv Plant
Klcctnc
Accumulated Provision lor Depreciation
and Amortization
Net Electric Utility Plant
Nuclear Fuel*
Accumulated Provision for Amortization
of Nuclear Fuel Assemblies
Net Nuclear Fuel
Net Total Electric Utility Plant
Other .
Accumulated Provision for Depreciation
and Amortization
Net Other Utility Plant .
Total I'tilitv Plant Kvluding Nuclear Fuel
Accumulated Provision for Depreciation
and Amortization Kxcluding Nuclear Fuel
Net Total Utility Plant Excluding
Nuclear Fuel
Total I'tilitv Plant Including Nuclear Fuel
Accumulated Provision for Depreciation
and Amortization Including Nuclear Fuel
Net Total Utility Plant Including
Nuclear Fuel
Other Proper! v and Investment
Total Current and \ccried Assets
Total Deferred Debits
Total Assets
LIAWLITIKS
Capitalization:
Common Capital Stock
Other Paid-in Capital Kxcluding
Karned Surplus** .
Karned Surplus (Retained Income)
Total Common Capital Stock Equity
Preferred Stock
Long-Term Debt :
Mortgage lionds
Other Long-Term Debt
Total Long-Term Debt
Total Capitalization
Total Current and Accrued Liabilities
Total Deferred Credits and Operating
Reserves . .
Contribution in Aid of Construction
Deferred Income Taxes
Other Deferred Items . ...
Total Liabilities
SUM
22
$82
$
$83
0
-
$ 6
11 1
21
$90
1
5
$98
$13
5
II
$20
0
1 1
3
is 17
$86
7
1
•2
$98
033
101
820
842
67
775
604
118
1 10
069
803
320
573
037
821
611
045
135
300
010
817
157
001
1 18
122
096
805
006
55 1
101
33
045
MI3
20
$73
$
$73
8
1
$ 6
•
102
22
$80
5
$87
$11
1
10
$26
7
30
'2
$12
$76
7
•j
$87
824
373
451
174
25
449
900
023
081
639
-
921
382
530
902
25 1
528
220
9S5
382
186
553
40(i
331
833
1 64
183
425
804
487
200
22
220
$81 307
IS 781
$65 613
8 060
1 832
$ 6 237
02 106
20 010
$71 850
-
--
950
4 013
381
$77 794
$1 1 039
3 037
9 278
$23 954
0 300
31 317
2 780
$37 127
$67 441
7 012
832
134
2 051
24
$77 794
$70 702
17 309
$59 393
-
' 7 700
1 715
$ 5 091
84 468
19 084
$65 384
—
—
- —
009
4 293
390
$70 976
$10 830
3 217
8411
$22 464
5 970
31 100
2 485
$33 585
$62 019
5 770
772
392
1 992
25
$70 076
1007
$70 305
16 126
$54 239
—
7 212
1 505
$ 5 647
77 007
17 721
$59 886
—
—
- —
750
4 000
350
$65 085
$10 700
2 844
7 571
$21 181
5 515
28 302
2 147
$30 440
$57 145
4 081
007
358
1 878
50
$65 085
1000
$04
14
$49
0
1
$ 5
71
10
$55
-
4
$60
$10
•2
6
$20
5
25
1
$27
$52
4
1
$60
717
001
843
-
--
-
917
472
445
004
370
288
-
--
027
OK)
334
259
*
502
707
921
130
045
870
943
813
988
482
579
329
822
59
259
1905
$00 385
13 691
$46 691
—
—
-
0 478
1 430
$ 5 048
00 803
15 124
$51 739
--
—
—
010
3 038
320
$56 313
$10,196
2 815
' 6 208
$19 219
4 089
23 752 '
T90I
$25 653
$49 561
4 115
507
200
I 770
04
$56 313
1 004
$50 001
12 777
$44 184
—
—
-
6 070
1 108
$ 4 911
03 040
13 045
$49 095
—
—
—
571
3- 643
318
$53 627
$ 0 904
. 2 721
5 504
$18 249
4 549
22 872
I 050
$24 522
$47 320
3 795
405
204
1 714
09
$53 627
* Prior to 1070 included in "Other Property and Investment "
** Includes Premium on Common and Preferred
I/ Edison Electric Institute,
Stock.
Statistical
Yearbook of the Electric
Utility
Industry
for 1971, Oct. 1972.
11-22
-------
TABLE ~11<-
REVENUES—TOTAL ELECTRIC UTILITY INDUSTRY*
BY YEARS AND CLASSES OF SERVICE
THOUSANDS OF DOLLARS
Year
Total
Revenue
from
Salosf
From Kx-
]>orts to
Canada
and
Mexico
Total
from
Ultimate
Customers
Resi-
dential
Commercial and Industrial Street Other
Small Large and Public
flight and Light and Highway Author-
Power** Power** Lighting ititw
Railroads Inter-
and depart-
Railways mental
1971
$24 734 300p $ 9 141p $24 725 159 $10 483 526 $7 071 971 $6 133 964 $411 534 $512 772 $77 862 $33 530
1(170.
1909
1908
19(57
1906. .
1005
1904 .
1903 .
1902 . .
1901 .
1900 . .
1959.
22 070
•20 1 1-1
. . 18 585
. 17 220
. . 10 1!)'.)
15 102
. 1 t .li:{
. 13 70S
..IK 033
. 12 177
11 523
. . 10 580
885 r
225
308
235
140
538
138
178
1189
388
571
277
11 ()23r
•1 870
5 -18!)
3 515
3 00-4
•1 159
-1 080
10 972
9 015
8 085
7 915
7 025
22 005
20 139
18 579
17 222
10 190
15 158
11 -108
13 097
13 02-1
12 109
11 515
10 572
802
319
879
720
130
379
•158
200
944
303
050
052
9 -115
8 532
7 802
7 183
0 733
0 328
0 010
5 722
5 457
5 115
4 855
4 514
707
729
033
908
714
750
081
544
01-1
799
799
707
0 290 225
5 701 7(i-l
5 315 100
4 935 9 1 1
4 049 084
4 312 859
4 028 198
3 788 310
3 420 013
3 108 055
2 828 180
2 598 452
5
5
4
4
1
3
3
3
3
3
3
3
129 S52
Oil 857
072 211
301 759
134 538
884 7-18
733 309
590 121
591 097
309 749
333 890
009 680
377 791
350 503
327 190
307 272
281 584
202 509
218 225
230 4-18
223 445
205 411
194 043
180 094
453 10-1
117 571
379 435
319 323
321 001
290 892
278 319
275 030
255 8,15
232 319
232 868
209 380
09 109
02 981
01 440
(iO 009
59 132
00 903
61 702
01 749
63 255
02 872
62 640
52 912
30 014
25 884
22 464
20 938
17 083
17 652
17 964
16 998
13 705
15 098
7 624
6 821
t Kxcludes other electric revenues.
* Alaska :ind ll:i\v:ni included since 1900.
** Small Light and Power and Large Light and Power are not wholly comparaltle on a year-to-year basis due to changes from one classification
to another.
p Preliminary. r Revised.
Edison Electric Institute, Statical Yearbook of the Electric
Utility Industry for 1971, Oct. 1972.
11-23
-------
TABLE -12-
COMBINED INCOME STATEMENTS—YEAR ENDED DEC. 31—INVESTOR-OWNED ELECTRIC UTILITIES^
INTERCOMPANY TRANSACTIONS ELIMINATED
MILLIONS OF DOLLARS
1971 1970 1909 I90S
ELECTRIC
Operating Revenues $21 230
( )pcriltlllg KxpellSCV
( Iperation . * S
Maintenance 1
Depreciation and Depletion '-'
Amort i/at ion Charged to ( >peration.
1'ropi'rtv Lo«-cs Chained to Operation
Taxes Othei 'I'liaii Income Taxes '_'
Federal Income Taxes
State Income Taxes
Provision for Deferred or Futuie Income Taxes:
Due to l,ilierali/.e 1 S
III)
:i
• »
382
(.)17
S7
•227
( I7i
'.)(>
256
971
ALL
053
ID!)
088
03 1
5
1
099
015
t)(i
•2-1 (i
1 18)
05
630
423
122
S22
367
117
15:!
'>
IS
C.50
717
57
774
193
2S1
I'.M
000
DEPARTMENT ONLY
$18 830 $17 164 $15
s 7
1
•)
•)
1
$14
S> '1
322
373
mi;
;\
I
130
li:i
si
l i-l
(•Hi)
27
347
•1815
S (i 208
1 1SI
2 005
2
• )
1 901
1 1 19
8(i
1 10
(58)
til
$13 046
$4 118
DEPARTMENTS
$22 276 $20 324
S 0
1
2
2
1
$17
S 1
$ 5
S 2
* 2
$ 3
$ 3
$ 2
2
$
* Includes investment tax credits reported as charges to income I'oi
** Prior to 19*70 shown as a credit to interest charges.
( ) Denotes negative figure
I/ Edison Electric Institute, Statistical
552
520
404
7
3
121
23 I
91
158
(•17)
25
374
902
107
594
603
010
198
(i'2
270
333
333
301
972
022
050
S 8 283
1 322
2 201
5
4
•2 1(17
1 580
9(1
155
(lit))
1)8
$15 827
S -1 497
51
•105
$ 4 053
S 1 021
127
(2)
77
S 1 8215
$ 3 130
$ 3 130
1(07
* 2 82;;
1 880
$ 043
!$ ."i
1
1
1
1
$12
$ 3
$18
$ 7
1
2
1
1
$14
$ 4
$ 4
S 1
* 1
$ 2
$ 2
$ 2
1
$
810
(> 18
Olil
851
1
•J
737
5'2 1 500 S 4
870
1 525 1
1
1
1 315 1
1 31 17 1
01
85
( 10)
54
$ 9 781 $ 9
.S 3 100 * 2
$15 404 $14
S 0 075 S 5
988
1 079 1
(
1511 1
1 501 1
07
91
(41)
02
$11 978 $11
$ 3 42(5 $ 3
28
94
$ 3 548 $ 3
S 953 S
19
20
S 992 8
$ 2 556 $ 2
$ 2 556 $ 2
210
S 2 310 $ '_>
1 520 1
$ 814 $
Industry
211
204
825
431
1
I
272
305
58
87
(28)
49
328
883
624
779
935
577
8
157
498
02
97
(29)
57
446
178
39
80
303
905
10
1
19
911
362
362
209
153
42'2
731
for 1971, Oct. 1972
-------
TABLE -13-
- TOTAL ELECTRIC UTILITY INDUSTRY
(Million of Dollars)
II 2_l
Industry Investment By
Year Total Investment Investor Owned Utilities
1971 14,796 Ll 11,894
1970 12,575 LI 10,145
1969 10,581 LI 8,294
1968 9,140 LI 7,140
1967 7,820 LI 6,119
1966 6,345 1' 4,932
1965 5,254 U 4,027
1964 4,801 1' 3,551
1963 4,357 l! 3,319
1962 4,271 I.' 3,154
1961 4,608 1.1 3,256
^/Electrical world, March 15, 1973, p. 38.
2^/Federal Power Commission, 1970 National Power Survey.
2/Edison Electric Institute, Statistical Yearbook for 1971,
Oct. 1972.
11-25
-------
III. PRICING
A. Price Determination
The price that the utilities can charge is regulated
by local, state, and federal regulatory agencies. While regula-
tory policies vary considerably, most regulatory agencies
allow the utilities to set a price that will insure them an
adequate return on common equity. For the purposes of this
analysis, it was assumed that the utility industry will be
able to set a price that will enable it to earn a 12% return
on total common equity. Since 'pollution control expenditures will
increase the amount of revenues that utilities must generate
in order to maintain a given rate of return, the price
increase for any given year can be expressed as a simple
equation:
n . f • \ -. Increase in total revenues (year i)—'
Price increase (year i) - Total production of electricity (kwh in year i)
B. Historical and Trends in Prices
As shown in Table~14-, the average price of electricity
(e.g., average revenue per kilowatt-hour sold) declined from
17.8 mills/kwh in 1951 to 15.4 mills/kwh in 1969. Between 1969
and 1971 the price of electricity increased to 16.9 mills/kwh -
an increase of about 10%.
It is important to analyze the price of electricity
relative to the prices of other goods and services. As shown
in Table^l5-r, the consumer price index has risen more rapidly
than the electricity price index. Therefore, from the con-
sumer's viewpoint, electricity has become cheaper relative
to other commodities.
C. Future Trends in the Price of Electricity
The results of this analysis.2-/ indicate that even without
expenditures for pollution control equipment the average cost of
electricity will increase from 16.9 mills/kwh in 1971 to 27.6
mill/kwh in 1980 and 43.2 mills/kwh in 1990. The above
I/ See Part III, p. III-162 for an explanation of the methodology
used to calculate the required increase in total revenues.
21 See Part III, p. 111-20 for an explanation of the baseline
projections.
11-26
-------
figures are equivalent to a 5% annual growth rate between
1970-80 and a 4.5% annual growth rate between 1980 and 1990
In view of recent trends in the consumer price index, the
price of electricity relative to other goods and services
should either remain constant or decline slightly.
11-27
-------
TABLE -14-
AVERAGE REVENUES PER KILOWATT-HOUR SOLD—TOTAL ELECTRIC UTILITY INDUSTRYI/
Year
1971
(170
909
908
1)07 .
1)00 .
905 .
904
90H .
902 . . .
!)01 . .
1900
195!)
] !_ . )
:i is
:> 12
:} 05
2 09
2 99
1! 05
:; 01
':! 01
:i 18
:i 08
:i 08
3 05
li 05
U.05
:! 07
;{ 07
:i oo
:! 08
20
1C,
18
.19
21
;ii
:>5
:«;
:<9
41
49
47
49
47
.42
42
.42
;{9
U!)
19
:;9
.:!5
:i:i
.;ii
:ti
:u
:!2
HI
:(i
,'ii
.28
25
.22
.17
.15
.1 1
08
()l
.US 0 99
5!)
51
.55
5(i
51 i
.59
02
05
.OK
.09
09
!<)!)
71
07
04
.07
.77
.77
79
^78
I/ Edison Electric Institute, Statistical Yearbook of the Electric Utility
Inddstry for 1971, Oct. 72.
2J All prices are in current dollars.
11-28
-------
TABLE -15V
CONSUMER PRICE INDEX— /ALL-CITY AVERAGE*
1951-1971
INDEX NUMBERS: 1967=100
Date
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
*Alaska am
Source: U.
1071
070
000 . . .
008
007
000
005
00 1
003
902
1901 . .
900
()5()
058
057
950
055 .
054
953 .
952 .
951 . .
Hawaii included since 1003.
S. Bureau of Labor Statistics.
All
Items
123 1
111) 1
112 0
MX) 1
101 0
98 0
1)5 4
(13 0
1)2 5
1)1 0
80 9
89 3
88 0
80 7
85 2
82 7
80.4
80.1
80.5
80 0
79 3
Klectricity
116 0
100 0
101 2
101 0
100 5
00 2
00 1
00 3
100 0
100 3
100 1
100 0
00 0
07 0
90 3
95 5
95 4
04 7
1)3 1
03 . 0
01 7
Gas and
Klectricity
118 2
110 7
101.8
101 4
100 2
09 4
99 5
90 8
00 0
00 0
90 4
1)0 3
07.0
03 5
90 3
88 0
88 1
80 3
84 7
o'> r
81.8
Total
Housing
126 8
122 0
111 2
107 0
101 5
98 0
95 7
94 3
93 5
92 0
91.3
90 8
89 5
87 0
87 1
84,8
82 0
82.2
81.0
79.0
78.1
Food
120.3
115 3
112 8
105 2
100 9
99 7
1)0 0
02 8
01 5
80 8
88.5
80 3
80.0
87.3
85.4
83 1
80 0
81 3
82 0
83 7
84 0
Apparel
121 8
111) 2
II 1.7
109 0
102.5
08.5
01 8
03 5
03 1
01 1
00 8
00.5
89 4
88.0
88.1
87.5
85.7
85.4
80 1
80 0
88 4
TABLE -16-
RESIDENTIAL ELECTRICITY AND CONSUMER PRICE INDEX-^TOTAL ELECTRIC UTILITY INDUSTRY*
Average
Ueveiiue
per
Residential
Kwhr Used
2 \$t
•2 10
2 1)0
2 12
2 17
2 20
2 25
2.; ;n
2 ,'{7
2 41
2 45
2 47
2.51
2 54
2 50
2 01
2 65
2 70
2 74
2 77
2 81
100 Kwhr
Average
Average
Price per
250 Kwhr
Hate per Kwhr H;
of Typical Bills in
Kwhr for iVIonthh
500 Kwhr
ised on
Cities**
Use of:
750 Kwlii-
U.S. Bureau of Labor Statistics
Index Numbers Based on
KOOO Kwhr
I'.H
Klectricity
(Federal Power Commission)
4 25 «<
4 00
4 05
4 03
4 03
4 00
4.02
4 03
4 00
4 00
4 05
4 04
3 08
3 015
3 80
•A 88
:i 80
•A 82
:i 81
'A 70
i 14?
!.0()
2 . 90
2 95
2 05
2 04
2.05
2 07
2 00
2 90
2 08
2 08
2 04
2 02
2 89
2.88
2 87
2 84
2 83
2 70
2.23ff
2 10
2 00
2.07
2 07
2 07
2 . 08
2.12
2 13
2 13
2.13
•2 12
2 10
2 . 00
2 08
2 07
2 00
2 05
2 04
2.02
2.00f>
1 00
1 80
1 80
1 89
1 89
1.01
1 03
1 95
1 92 f!
1 83
1 SO
1 83
1 83
1 .83
1 .80
1 89
113 2
100 '2
IO-2 8
100 9
100 0
99 1
09 1
09.0
100 1
100 1
100 1
00 8
08 5
07 1
95 0
95 5
95 2
94 0
93 0
92 4
91 5
>7 = 100f
Consumer Price
IndexJ
121 3
110 3
109 8
104.2
100.0
97 2
94 . 5
92.9
01 7
00 0
89 G
88 7
87 3
80 0
84 3
81 4
80.2
80 5
80.1
79 5
77 8
Year
1971
1070
1900.
1908
1907
1000
1905
11164
1963
1902
1001
1000
1059
1058
1957
1956
1055
1954
1953
1052
1951
* Alaska and Hawaii included since 1000.
** As determined by the Federal Power Commission in its "Typical Klectnc Bills." The ligures cover rale schedules as of December 31 in all
cities with populations of '2,500 or more.
t "Index numbers" are percentages of the base year 1007. For a description of the components and characteristics of this Index, see the
February, 1953, Mnitllili/ Lnlmr Hevinn of the Bureau of Labor Statistics.
} The ••Consumer Price Index" measures the average change in prices of goods and services purchased by urban wage-earner and clerical-
worker families. Fleetncity is one of these components. The Index does not relied the over-all effect of the increased use of electricity by Hesi-
dential customers -for which see "Average Revenue per Residential Kwhr Used," column 2 of this table; also see Tables 41 K, 45 S and 00 S
ol this publication.
I/ Edison Electric Institute, Statistical Yearbook of the Electric Utility
Industry for 1971. Oct. 1972. 2g
-------
IV. POLLUTION CONTROL REQUIREMENTS AND COSTS
A- Effluent Limitation Guidelines for 1977 and 1983
The economic analysis presented in this report is
based on a preliminary draft of the water effluent limitation
guidelines which are summarized in Tables -17 and 18
As shown in these tables, the two major guidelines are for the
control of chemical and thermal discharges. A third guideline
applies to the construction and design of intake structures. I./
However, the cost of complying with the guidelines for intake
structures has been excluded from the economic impact analysis
for several reasons. First, the installation of closed cycle
cooling systems would probably fulfill all of the requirements
of the intake structure guidelines. Second, even if a power
plant would have to modify its existing intake structures,
it would be difficult to estimate the associated costs because
the guidelines will be applied on a case-to-case basis. Third,
the projected impact of the intake structure guidelines was a
very small percentage of the total cost of the thermal and
chemical guidelines.
B. Current Level of Control
As shown below, about 74% of the generating capacity
in 1970 used once-through cooling systems, while 13% had
cooling towers and 13% had either cooling ponds or combination
systems.
2 /
Types of Cooling System % of 1970 Capacity—7
Once-Through (Fresh Water) 51.0%
Once-Through (Saline) 23.2
Cooling Pond 6.8
Wet Cooling Tower 13.0
Combination 6.0
However, as shown in Table - 19, a much larger percent-
age of the post-1974 capacity is planning to install either
cooling towers or combinations systems. Specifically, 42%
of the fossil plants and 33% of the nuclear plants are already
planning to install cooling towers.
JL_/ EPA proposed regulations for cooling water intake
structures were published in the Federal Register on
December 13, 1973 (p. 34410)
I/ Estimates were derived from an analysts ty Edward Pechan of EPA*s
Office of Planning and Evaluation of data from the Federal Power
Commission's Form 67.
11-30
-------
C. Expected Coverage of the Guidelines
The guidelines that were summarized in section-A
require that a large percentage of both the existing and
planned generating capacity will have to install pollution
control equipment. For example, 83% of existine capacity
and 92% of planned capacity will be covered by the chemical
guidelines. The coverage is also extensive for the thermal
guidelines. Specifically, for the non nuclear capacity, a
maximum of 51% of the pre-1970 capacity, 52% of the 1971-73
capacity, 52% of the 1974-77 capacity, and 73% of the.1978-83
capacity will have to install cooling towers by 1983,—' The
equivalent percentages for the nuclear capacity are 80%, 67%,
67%, and 100%. More detailed estimates of the maximum coverage
of the thermal guidelines are given in Tables 20 and 21.
It should be emphasized that the actual impact of the
thermal guidelines will be considerably less due to the follow-
ing factors:
1. exemptions under Section 316(a)_'
2. exemptions due to lack of land and/or adverse
environmental impact from salt water drift.
3. some power plants will be able to comply with
the guidelines by installing less expensive
closed cycle cooling systems (e.g., cooling
ponds and spray canals)
!_/ These estimates are maximum values because they do not
reflect exemptions under Section 316(a) of the Federal
Water Pollution Control Act of 1972 or the exemptions
due to the lack of land and/or adverse non-water quality
environmental impacts.
2y Section 316(a) of the Federal Water Pollution Control Act
of 1972 specifies that whenever the owner or operator of
any source subject to the thermal discharge guidelines can
demonstrate that the effluent limitation proposed for the
control of the thermal discharge for that source is more
stringent than necessary to assure the protection and
propagation of a balanced, indigenous population of shellfish,
fish, and wildlife in and on the body of water, the
Administrator (or, if appropriate, the state) may impose an
alternative effluent limitation for thermal discharge, that
will assure the protection and propagation of a balanced
indigenous population of shellfish, fish and wildlife.
11-31
-------
At the present time, however, adequate data is only available
to estimate the impact of exemptions under Section 316(a). Thus,
the estimates of the projected coverage of the thermal guidelines
after exemptions (e.g., Table 21) over estimate the actual
impact of the thermal guidelines.
D. Water Pollution Abatement Costs
The impact analysis in this report is based on cost
estimates contained in a document prepared for EPA by Burns
and Roe, Inc.—' The most important cost parameters are
summarized in Tables 22 and 23. As indicated in Table 24,
the installation of cooling towers will increase the average
production costs of existing baseload units by 11 to 22%
and the production costs of new baseload units by 10%.
However, the incremental cost of the guidelines will be con-
siderably less since as shown in Table 25 the utilities, in the
absence of federal legislation would have incurred substantial
costs in order to install the most economical cooling system
(e.g., once through cooling in most cases and cooling towers in some
cases). The incremental cost of the thermal guidelines (see
Table 26), therefore, is the difference between the total cost
of cooling towers (e.g., Table 22)and the cost that the utilities would have
incurred for basic cooling facilities (e.g., Table 25).
F. Comments on Cost Data
In view of the uncertainty concerning many of the cost
parameters, especially the cost of installing cooling towers
on existing plants, a range of cost estimates was included in
the economic impact analysis. As will be documented later in
this report, allowance for variation in the principal cost
parameters has a significant impact on the total cost of
meeting the 1977 and 1983 standards.
_!/ EPA, Development Document for Proposed Effluent Limitation
Guidelines and New Source Performance Standards for the Steam
Electric Power Generating Point Source Category, March, 1973.
11-32
-------
TABLE-17-
DRAFT SUMMARY OF PROPOSED EFFLUENT GUIDELINES FOR THERMAL DISCHARGE:
EPA RECOMMENDATION
ND
NL
= No discharge of heat except that blowdown
may be
» No technology-based limit (e.g., no restrictions
CATEGORY TYPE OF UNIT
M
M
Ui
OJ
I.
II.
III.
IV.
V.
Large Baseloadi/
A. Existing units larger than 500 mw
B. Existing units 300-500 mw
C. Existing units smaller than 300 mw
D. All units on line after July, 1977
Small baseloadr/
Cyclic!/
Peaking*/
Exceptions !/
1977
—
-
-
ND
NL
NL
NL
discharged from cold side (e.g., closed cycle coolir
on type of cooling system)
1978 1979 3,930 1983 NEW SOURCES
ND ,r ND
W r- r* ND
- ND ND ND
ND
ND ND
ND ND
ND ND
I/ The term large baseload unit will include all units with average boiler capacity factors greater than
.60 that won't retire before July, 1983,all nuclear units, and all units for which construction begins
after Oct, 1973.
2/ The term small baseload unit shall mean a unit which is a part with a rated
capacity of les» than 25 megawatts or part of a system of less than 150 megawatts.
3/ Units with capacity factors between .2 and .6 that won't retire before July 1983.
4/ Units with capacity factors less than .2.
5/ Exemptions are the same as in Table 17.
-------
TABLE- 18
DRAFT SUMMARY OF PROPOSED EFFLUENT GUIDELINES FOR CHEMICAL DISCHARGES
Numbers listed are average
ND
I.
II.
III.
IV.
V.
VI.
= No discharge NL
CATEGORY
Waste Water Source
High-Volume
Intermediate-Volume
Low-Volume
Rainfall Runoff
Sanitary Wastes
Radwastes
concentrations of pollutants,
= No technology-based limit
POLLUTANT
Free chlorine residual
Copper
Free chlorine residual
Total residual chlorine
Copper
Chemical additives
Oil and grease
PH
Phosphates (as P)
Total suspended solids
Copper
Iron
Oil and grease
PH
Total suspended solids
Oil and grease
PH
Total suspended solids
Biochemical oxygen demand
except for
MS = Munic
1977
0.2
NL
0.2
NL
NL
NL
10
6-9
ill/
1
1
10
6-9
15
10
6-9
15
MS
NL
pH
ipal standards
1983 NEW SOURCES
0.2
NL
0.2
NL
NL
NL
10
6-9
ill/
ND
ND
NB
-
ND
10
6-9
15
MS
NL
0.2
ND
_
approx. ND
ND
approx. ND
10
6-9
ill/
1
1
10
6-9
15
10
6-9
15
MS
NL
I/ Note: For ash sluicing add "or not to exceed influent pounds/day, whichever is greater"
2_l Note: No discharge for wastewater pollutants from nonrecirculating bottom ash handling
'systems or from fly ash handling systems.
-------
TABLE-19-
TYPE OF COOLING SYSTEMS FOR STEAM-ELECTRIC PLANTS 300 Mw AND LARGER, BEING
CONSTRUCTED OR COMING UNDER CONSTRUCTION BY APRIL 1, 1974, BY EPA REGION,
BY COOLING METHOD
Region 1 •
A. r-ysM -fired
Cco!:-^ Tov.ir2.-HS*
<• v[ ('.nils
?:•! ;'l . Oil ipq-JS«
* of Units
•Vs <••?-: '•roi":h"-K»
•'; oi : Hi ts
To» ?1 - ».
« cf r.-iits
% distrib.-J&f
V B. !-'uc!"ar Plants:
01 C^n — Tov.«r5-K«
~ cf ('nits
S';n"'l . I'rol ir:T-«!vi
•" i'! I'ni ts
JTrre-t >;ro'' jh^-Ms*
B of ! nits
T,.,tr!l - V»
' <•: L:sits
£ . •••<
r of U.-^its
% Jiitrib. -:•.;-
400
1
-
-
3,522
7
3,922
0
4%
513
1
-
.
3,492
4
4,0"; 3
5
4%
913
2
-
-
7,014
11
7 <5?7
13
-> 4%
Real on 21
-
316
1
5,647
10
5,9'.3
U
5%
2,200
2
-
-
8,684
9
10. r 4
11
12%
2,200 •
2
316
1
14,331
19
16 fM7
VHLAtft . »'*VM
22
c;j
Rcnion 3 Region 4 Region 5
13.545
17
2,323
3
2,160
5
is.cro
25
17J{
9.406
10
2, ICO
2
7,132
8
18,713
20
212
23,031
27
4,455 .
5
9,292
13
36.778
li/i
10,576
lo
1,650
2
12.421
19
24.647
37
232
7,031
8
3.195
4
12,715
14
23.741
26
26^
18,407
24
4,045
6
25,136
33.
P. ^ ^ f (A
60
2'!^
9.60C
14
-
-
9.4CI-
I'l
.19.0CI,
2i>
I'M
5,^i
''
2.71U
U
11,131
1?
19,271
T.I
21.;
15,0:2:
21
2.71E:
J;
20,53V
2'i
*V^ *: i r •
lc^
Rcr,on 6
3,295
7
840
2
15,667
23
19.C02
b7
is;;
950
1
-
_
1,995
2
£ — .
, 2.915
3
T'
o/,
4,245
8
C-'iO
2
•17,662
30
22.7-17
••SKC „. ( . —K*
11?S
gct7 1 onr J[*«JJc™
42
3.330
8
_
.
878
2-
4,208
10
4%
330
1
-
_
-
-
330
1
IK
3,660
9
-
-
878
2
•1,530
mr" ^iV"*
2^
4,830
7
735
1
1,408
3
6^973
11
*>%
913
1
-
.
6,660
6
7,573
. 7
• G^
5.743
8
735
1
8.068
9
14.516
•"•"'— it)'™
7Ji
Grand
R!*gI^T TO .Jo'al
700 45,753
1 70
6.901
n
56.334
97-
700 109.076
i na
1% 100%
2,230 30,420
2 34
8.510
10
52,587
C6
2*>*>f\ « OI ^^T
T *.v>vl 7 I T \J«JiJ
2 * ICO
2* ICCtf
2.930 76.1C6
3 10-1
15.502
21
1C3.92)
] 11
•2,9-1 ?r"),(09
1C t/ j
2^\ 10C^
Percent
„ Distributfai
dh«;
23%
3*
20%
54%
15%
5%
26%
46%
30%
0%
,
54%
i
100%
r— -Js
f
1 '
1
JJ
42%
6%
52%
10*
.
333S
9%
50%
100%'
K0=t=
38%
8%.
54%
100%
«—*».
SOURCE:
5/72 FPC Printout of Utility Responses to FPC Order 303-2
-------
u>
TABLE-20-
EXPECTED COVERAGE OF THERMAL EFFLUENT GUIDELINES; EPA RECOMMENDATON (BEFORE EXEMPTIONS)
% Coverage by Required Compliance Date*
Capacity Placed in Service
Non-Nuclear
Prior to 1971
1971-1973
1974-1977
1978-1990
Nuclear
Prior to 1971
1971-1973
1974-1977
1978-1990
1977 1978 1979 1980 1983
25% 10% 5% 11,%
37 4 11
- 37 12 3
— — — — —
80%
67
67
Year of Initial
Operation
-
-
37
73%
-
_
33
100
Total
Cummulative
Coverage
89
73%
80%
67
100
100
* Numbers represent
-------
TABLE-21-
EXEPECTED COVERAGE OF THERMAL EFFLUENT GUIDELINES: EPA RECOMMENDATION (AFTER EXEMPTIONS)
% Coverage by Required Compliance Date**
Capacity Placed in Service
Non-Nuclear
Prior to 1970
1971-1973
1974-1977
1978-1990
1977
1978
5%
7,1
7,1
1979
2%
1,8
2,3
1980
1%
2
.6
1983
22%
Year of Initial
Operation
37%
38%
Total
Cummulative
Coverage
10,2%
10,0%
40.0%
38
Nuclear
Prior to 1970
1971-1973
1974-1977
1978-1990
16
13
13
33
44
16
13
46
44
* After exemptions for Section 316(a) of the Federal Water Pollution Control Act of 1972
** Numbers represent the incremental coverage in the indicated years.
-------
TABLE -22
ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT OF
GENERATING CAPACITY - THERMAL EFFLUENT STANDARDS.*'
Non-Nuclear Capacity Nuclear Capacity
Capital Costs C$/Kilowatt) ($/Kilowatt)
1. Cooling towers on new plants— . $ 7.50 $10
2. Cooling towers on existing plants—' 15 18
3. Replacement capacity
- 1977 (peakers) 90 90
- 1983 (baseload units) 170 260
Annual Operating Expenses —'
1. Replacement power
- 1977 42 42
- 1983 15 12
Capacity Losses
1. Power to operating cooling towers 1% 1%
2. Power to compensate for 2% 2%
efficiency losses
_!/ Cost estimates are specified in 1970 prices and are based on data
in EPA, Development Document for Proposed Effluent Limitation
Standards for the Steam Electric Power Generating Point Source
Category, Sept, 1973.
2j Capital costs include only the cost of constructing and hooking-
up the cooling tower.
3_/ Total annual operating costs for a plant that installs a cooling
tower equals (capacity s£ p,lantX X (annual operating cost/kw) X
C% capacity \®$$ per plant L,,
n-38
-------
TABLE-23-
ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT .
OF GENERATING CAPACITY - CHEMICAL EFFLUENT GUIDELINES-7
1977 Guidelines
Non-Nuclear Capacity—/ Nuclear Capacity—'
($/Kilowatt) ($/Kilowatt)
Capacity Placed in Service;
Prior to 1971
Capital Expenditures $1.95 $0.85
Annual Operating 0.85 0.50
Expenses
1971 - 1977
Capital Expenditures 1.05 0.85
Annual Operating 0.55 0.50
Expenses
1983 Guidelines
9 / 3/
Non-Nuclear Capacity—7 Nuclear Capacity—
($/Kilowatt) ($/Kilowatt)
Capacity Placed in Service;
Prior to 1971
Additional Capital $3.35 $2.75
Expenditures
Annual Operating 0.65 0.35
Expenses
1971-1977
Additional Capital 2.75 2.75
Expenditures
Annual Operating Expenses 0.35 0.35
1978-1983
Capital Expenditures 2.60 2.00
Annual Operating Expenses 0.25 0.20
_!/ Costs estimate are based on data in E-PA, Hevelopment Document for
Proposed Effluent Limitation Guidelines and New Source Performance
Standards for the Steam Electric Power Generating Point SourTT
Category, Sept 1973. All costs are specified at 1970 levels.
_2/ Cost estimates are based on an average plant size of 300 mwe for
the pre-1971 capacity, a 800 mwe plant for the 1971-77 capacity
and a 1,000 mwe plant for the ppst 1977 capacity.
_3/ Cost estimates are based on an average plant size of 1,000 mwe.
II-39
-------
TABLE -24-
INCREMENTAL COSTS OF APPLICATION OF MECHANICAL DRAFT
COOLING TOWERS TO EXISTING UNITS AND NEW UNITS!'
Type of Unit
Price Increase
ixeiuctj.uj.ug ijj-j-c
Fossil
A. Baseload
1. New Units
2. Existing
Units
B. Cycling
1. New Units
2. Existing
Units
C. Peaking
1. New Units
2. Existing
Units
Nuclear (All baseloadl
A. New Units
B. Existing Units
i. CO L. O
36
30-36
24-30
12-18
6-12
0-6
36
30-36
24-30
17-18
6-12
6-12
0-6
36
30-36
24-30
18-24
12-18
7-12
0-6
36
30-36
24-30
18-24
12-18
6-12
0-6
J. 11 11 JL J. K 9 / IX W 11
(1970 $)
.64
.82
.89
1.01
1.20
1.90
.92
1.17
1.25
1.34
1.50
1.67
2.50
3.50
5.00
5.00
5.62
6.25
7.50
12.50
.65
.85
.91
.98
1.04
1.24
1.95
I/ EPA, Development Document for proposed Effluent Limitation
New Source Performance
Source Category, March
standards
, 1974
duction Costs — '
10
13
14
16
19
30
11
14
15
16
18
20
30
28
40
40
45
50
60
100
10
13
14
15
16
19
30
Guidelines and
for the Steam Electric Power Generating roint
2J Estimates are based on production costs (in 1970 prices) for baseload,cycling
and peaking units of 6.34._8.35. and 12.50 mills/kwh.
11-40
-------
TABLE 25
ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT OF GENERATING
CAPACITY THAT THE UTILITY INDUSTRY WOULD HAVE INCURRED IN THE
" ~ AB SINCE OF FEDERAL ENVIRONMENTAL REGULATIONS-*?
Non-Nuclear Capacity Nuclear Capacity
Capital Costsl/ ($/Kilowatt) ($/Kilowatt)
1. Cooling towers on new plants $3.70 $4.50
2. Cooling towers on existing plants
3. Replacement capacity
- 1977 and 1983 (baseload units) 170.00 260.00
Capacity Losses^/
1. Average capacity loss on new plants .7% .7%
2. Incremental capacity loss on existing
plants
_!/ The cost estimates are specified in 1970 prices and are based on the following
assumptions:
a. In the absence of environmental regulations, the mix of cooling
facilities installed between 1970 and 1990 would have been the
same as the 1970 mix of cooling facilities - 74% once through, 7%
cooling ponds, 13% cooling towers and 6% combination systems. The
capacity penalties for cooling towers, combination systems, cooling
ponds, and once through cooling would be 3.0%, 2.5%, 2.0% and 0.0%
respectively.
b. The capital costs for once through cooling are 38% and 42% of the
capital cost of cooling towers for fossil and nuclear units.
c. The capital costs for cooling ponds are 77% and 79% of the cost of
cooling towers for fossil and nuclear units.
d. The capital costs for combinations systems are 88% of the cost of
cooling towers for nuclear and fossil units.
2J Figures are weighted averages based on the projected mix of cooling facilities
and on the estimated capital costs and capacity losses for each type of facility.
11-41
-------
TABLE -26
ESTIMATES OF INCREMENTAL CAPITAL AND OPERATING COSTS PER UNIT OF
GENERATING CAPACITY - THERMAL EFFLUENT STANDARDS^/
Capital Costs
1. Cooling towers on new plants!/
2. Cooling towers on existing plants!/
3. Replacement capacity
- 1977 (peakers)
- 1983 (baseload units)
Non-Nuclear Capacity Nuclear Capacity
($/Kilowatt) ($/Kilowatt)
$ 3.90
15.00
90.00
170.00
$ 5.50
18.00
90.00
260.00
Annual Operating Expenses —'
1. Replacement power
- 1977
- 1983
42.00
15.00
42.00
12.00
Capacity Losses
1. Average capacity loss on new plants
2. Incremental capacity loss on
existing plants
2.3%
3.1
2.3%
3.0%
I/ Cost estimates are specified in 1970 prices and were derived by subtracting
the estimates of the expected costs in the absence of environmental regulations
(e.g., Table 25) from the estimates of the total costs of the thermal
guidelines (e.g., Table 22).
2J Capital costs includes only the cost of constructing and hookingup the cooling
tower.
_3/ Total annual operating costs for a plant that installs a cooling tower equals
(capacity of plant) X (annual operating cost/kw) X (capacity losses/plant).
11-42
-------
V. ECONOMIC IMPACT ANALYSIS METHODOLOGY
A. Introduction
The following economic impact analysis utilizes the
basic industry information developed in Chapters I-IV. The
impacts examined include:
1. Financial Effects
2. Price Effects
3. Capacity and Energy Penalties
4. Production Effects
5. Employment Effects
6. Community Effects
7. Balance of Payments Effects
Each of these impacts will be discussed separately.
The complexity of the calculations required to estimate
the economic implications of the guidelines dictated the develop-
ment and use of a policy testing model (PTM)i' • The computer
model also made feasible range estimates and sensitivity testing
which are valuable in light of the uncertainity inherent in the
available forecasts of the amount of generating capacity to be
fitted with pollution control equipment, the costs of such pollu-
tion control equipment, and the impact of such equipment on
operating costs and the efficiency of generating capacity, etc.
It is important to emphasize several major assumptions
of the economic impact analysis. First, all impacts are
estimated in current dollars. A summary of the rates of infla-
tion that were assumed for capital and operating costs is
presented in Part III, page 111-26 and 111-31, Second for the following
reasons, the cost of closed cycle cooling systems for units
under actual or planned construction were included in the total
cost of the guidelines:
1. A number of utilities probably planned to install
closed cycle cooling systems in anticipation of the
water effluent guidelines.
2. It is impossible to determine whether the utilities
decided to install closed cycle cooling systems for
environmental reasons (e.g., state, local or
I/ The structure of the model is outlined in Part III, page III-152
11-43
-------
federal requirements) or for non-
environmental reasons (e.g., economic and
geographic factors).
Third, the cost estimates emphasized in this report represent
the incremental cost due to the Federal Water Pollution Control
Act of 1972 (FWPCA). Consequently, the costs that the utility
industry would have incurred in the absence of federal legisla-
tion (e.g., see Table 25) Were deducted from the cost estimates
presented in Table 22. Finally, it was assumed that each
utility company could schedule the hook-up of the cooling towers
during off-peak periods and could obtain the replacement power
by either increasing the load factor on other units in their
system or by purchasing power from other utilities.
B. Financial Effects.!/
Under financial effects, this report primarily considered
total capitalized expenditures and their sources of financing.
The capital expenditures associated with the implementation of
the guidelines are of two kinds.—' The first consists of direct
expenditures on pollution control equipment. These expenditures
are a function of:
1. the effluent guidelines for 1977 and 1983,
2. the time schedule for moving toward these goals,
3. the cost per unit of generating capacity of
installing pollution control equipment in new
plants and of retrofitting existing capacity,
4. the changes in these costs over time,
5. the amount of each type of generating capacity,
6. the dat.e of construction of that capacity..
JL/ See Part III, p. III-158 detailed description of the model's financial module.
2_l Another type of capital expenditure that could result would
be for the installation of additional capacity to provide
replacement power while part of the existing generating capacity
is taken off line to allow for the tie-in of the cooling tower.
For the purposes of this analysis, however, it was assumed that
since the replacement power needs were small (e.g., less than 5%
of capacity), the utilities could provide this power from other
operating units in their system. This assumption is further
discussed in Section
11-44
-------
In order to estimate how the utilities would finance
the required investment the following assumptions were made:
1. The regulatory agencies would allow the utilities
raise prices to the extent needed to maintain
an adequate return on common equity—'
2. The capital structure of the investor-owned
utilities would be up to 55% long-term debt, up to 10%
preferred stock, and at least 35% common quality.
3. The publicly owned utilities would finance
35% of capital expenditures through internal
financing and the remainder through external
financing.
While it was assumed that the utilities would be able
to obtain the required external financing, this assumption was
further evaluated by looking at the expected converage ratios
both with and without expenditures for pollution control,—'
C. Price Effects
The water effluent guidelines will effect prices
directly by increasing the price of electricity and indirectly
by increasing the prices of goods and services which utilize
electricity. Specifically, the economic impact analysis
focused on the following direct and indirect price effects:
1. Expected increase in the price of electricity
in mills/kwh
2. Expected increase in the price of electricity as
a percentage of production costs
3. Expected increase in the price of electricity as
a percentage of the cost of power to the final
user,
4. Total increase in the cost of electricity per year
to the consumer,
5, Expected increase in the production costs for the
major power intensive industries.
!_/ For the purposes of this analysis it was assumed that the
utilities would earn an after tax return on common equity of 12%,
2^/ The two coverage ratios covered in this report are:
a. Interest = Income before income taxes and interest payments
Interest payments
b. Non-tax = Income before income taxes and interest payments
adjusted Interest payments plus preferred dividends,
11-45
-------
The expected increase in the price of electricity
is primarily a function of the following factors:
1. Total capital expenditures
2. Sources of financing the capital expenditures
3. Total operating costs
4. Projected demand for electricity
5, Policy of the regulatory agencies
For the purposes of the analysis, it was assumed that the
utilities would obtain rate increase sufficient to maintain
an after tax return on common equity of 12%, The expected
price of electricity, therefore, in any given year can be
calculated by estimating the total costs of the utility
industry and by calculating the price that the utility industry
would have to charge in order to maintain an after tax return
of 12%.I/
D. Capacity and Energy Penalty
Because of the power requirements of closed cycle
cooling systems and the associated decrease in efficiency (e.g.,
higher heat rate), there will be a capacity and energy penalty.
The capacity and energy penalties were calculated based on
the following assumptions:
1. The power requirements of cooling towers would
be 1% of capacity.
2. The efficiency losses would average 2% of capacity,
3. In the absence of federal legislation, the utilities
would have installed cooling system with a total
average energy penalty of 1%.
4. The utilities would replace the lost capacity
with peakers through 1977 and with baseload units
after 1977.
The importance of the resulting capacity and energy penalties
were evaluated by calculating their impact on the projected
increase in generating capacity and on the projected national
demand for energy.
A detailed explanation of the methodology for calculating
the price of electricity is given in Part III, page III-162
11-46
-------
E. Production Effects
Since the electric utility industry is regulated to
insure an adequate return on capital, it was assumed that
there would be no plant closures due to the guidelines.
F. Employment Effects
It was assumed that the guidelines would have a
negligible impact on the general level of employment because:
1. The utility industry employs a very small per-
centage of the total labor force .
2. The expected price increases would not cause
plants to close or reduce their level of production.
G. Community Effects
While the guidelines would certainly have an aesthetic
impact on the community, the only community effect that was
analyzed in this report was the expected increase in the cost
of living due to increases in the price of electricity. Based
on the assumption that the per capita consumption of electricity
would grow by 5%-i.' Pe* year, the report calculated the impact of
the guidelines on the monthly electricity bill for residential
and large industrial customers.
H. Balance of Payments Effects
The guidelines will have a small effect on the balance
of payments because part of the increased fuel consumption
associated with closed cycle cooling systems will be met through
increased impacts of residual fuel oil. In order to estimate
the balance of payments costs, the following assumptions were made;
1. Incremental demand for fossil fuel will be filled
entirely by coal (50 %) and oil (50 %) .
2. 100% of the additional demand for oil will be filled
by impacts
3. The balance of payments cost will be $7 per barrel.
^/ Estimate was derived by assuming a total growth in demand for
electricity of 7% per year and a 2% per year growth in
total customers.
11-47
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VI. BASELINE ECONOMIC IMPACT ANALYSIS
A. Introduction
The impacts considered in this analysis include the
following:
1. Financial Effects
2. Price Effects
3. Capacity and Fuel Penalties
4, Production Effects
5. Employment Effects
6. Community Effects
7. Balance of Payments Effects
The expected coverage of the guidelines was estimated in
Section IV and the methodology used and the critical assumptions
were described in Section V. This section will estimate the
incremental cost that the utility industry will incur both
before and after exemptions under Section 316(a) of the FWPCA
in order to comply with EPA's proposed effluent guidelines for
steam electric powerplants (see Tables 18 and 19 for a summary
of the guidelines). Thus, the costs that the utility industry
would have incurred for thermal cooling systems, primarily for
once through cooling system have been deducted from the total
estimated costs of the thermal guidelines.!'
In view of the fact that there is a considerable
difference in the economic impact before and after exemptions,
it is important to summarize the major assumptions that were
used to estimate the impact of the guidelines after
exemptions :^./
1. 68% of the existing units covered by the guidelines
will receive a total exemption while the remaining
32% will have to install closed cycle cooling systems
on 50% of their capacity. The cooling towers
would only have to be operated during certain
critical periods which would in the aggregate amount
to 30% of the year.
!_/ See Tables 22, 25 and 26 for a comparison of the total and
incremental costs of the thermal guidelines for a. typical
power plant.
2_/ The estimates are based on. a report bv KPA^P Office of Mater
Programs, entitled* "A Preliminary Analysis of Thermal Discharge in
Relation to Water Quality Standards".
11-48
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2. All new units that are planning to install
cooling towers and 17% of all other units
scheduled to come on line after July 1, 1977
will have to install closed cycle cooling
systems on 100% of their capacity. The cooling
towers for both categories of facilities will
have to be operated whenever the unit is
generating electricity.
1149
-------
B. Financial Effects
1. Capital Requirements
As shown in Table 27 the total capitalized
expenditure required to implement the guidelines before
exemptions are 7.7 billion dollars by 1977 and 23.2 billion
dollars by 1983. Based on the estimate of projected utility
expenditures presented in the section on financial profile
(page 11-21), it ran be concluded that the guidelines will
increase the total capital expenditures of the electric
utility industry 8.1% by 1977 and 6.3% by 1983. Approximately
72% of the cost of the guidelines by 1983 can be attributed
to the thermal guidelines.
As indicated in Table 28 , New Source Performance
Standards (NSPS) will increase capital expenditures before
exemptions by 16.3 billion dollars or by an additional 2.6% between
1983 and 1990. Approximately, 86 % of the cost of meeting
NSPS can be attributed to the thermal guidelines.
It is important to emphasize that the actual impact
of the guidelines will be considerably less due to exemptions
under Section 316(a) of the FWPCA. Specifically, as shown
in Table 28, after exemptions the guidelines will increase the
total capital expenditures of, the utility industry 2.1
billion or 2.2% by 1977 and 9.2 billion or 2.5% by 1983.
The thermal guidelines will account for only 30% of the capital
costs by 1983 after exemptions.
Consideration of exemptions has a similar effect
on the cost of NSPS, It is estimated (see Table 28) that
after exemptions the utilities will have to spend an addition
5.2billion dollars in order to comply with NSPS between 1983
and 1990 which will increase the utilities' capital requirements
over this period by about -8%.
2 . Sources of Financing
The utilities will finance the expenditures for
pollution control equipment through internal (e.g. depreciation,
retained earnings, tax deferrals) and external sources (e.g.
long-term debt, preferred etroefc, common stock.!.. Based on
assumptions incorporated into the PTM model, the utilities could
finance 34% of the (1973-1990) capital expenditures through
internal financing while the remainder would have to come
from external sources. If the investor owned utilities were
to maintain the same capital structure (e.g. 55% long-term
debt, 10% preferred stock, and 35% common equity) the external
financing would be obtained in the following way:
11-50
-------
Before Exemptions
13.2
2.9
4.7
21.4
After Exemptions
4.8
.9
2.1
7.8
Type of Financial Requirements for Investor
External Financing Owned Utilities 1973-90 (Billion $)!/
Long-term debt
Preferred Stock
Common Equity
Total
The key assumption of this analysis is that the
utilities will be able to obtain the required external financing.
While it is difficult to conclusively prove that the capital
will be available, there are several compelling arguments. First,
the utilities were able to increase the level of capital
investment by 11% per year in the 1960's even though the industry's
interest coverage ratio fell from 5,11 in 1961 to 3.03 in 1971.
Second, as shown below, the investment required before
exemptions to meet the effluent guidelines will have an insignifi-
cant effect on the industry's coverage ratios in 1977, 1983, and 1990
Coverage Ratios 1977 1983 1990
1) Interest?-/
a. without pollution control
expenditures 3.06 2.93 2.90
b. with pollution control
expenditures 3.00 2.92 2.90
2) Non-Tax Adjusted?-/
a. without pollution control
expenditures 2.60 2.49 2.46
b. with pollution control
expenditures 2.55 2,48 2.47
Finally, if the utilities are going to be able to finance
by 1990 over 900 billion dollars of investment for transmission
and generation facilities, they should not experience major
problems in financing the additional capital (e,s<, 1.4.4 billion after
exemptions by 1990) required for pollution control equipment. It can be
concluded, therefore, that if the utility industry experiences problems
in securing long or short term capital, it will be the result of the large
capital expenditures required to expand transmission and generation facilities.
_!/ Figures were derived by assuming that the composition of external financing
for EPA's proposed guidelines (e.g., policy alternative-7 in Part III) was
the same as in the case of the technological recommendation (e.g., policy
alternative 1 in Part III).
2J See p. 11-47 for a definition ofl the coverage ratios.
11-51
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3. Profitability
As discussed in previous sections, the electric
utility industry has been regulated to insure an adequate
rate of return on its common equity. This analysis assumes
that the regulatory agencies will allow the utilities to
raise the price of electricity in order to recover the increased
operating and fixed charges associated with the effluent guide-
lines. Therefore, the profitability of the electric utility
industry (e.g. rate of return on common equity) should not be
affected by the implementation of the water effluent guidelines.
However, the total after-tax profits of the industry will
increase in order to realize a rate of return on the increased
investment in pollution control equipment.
II- 52
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C. Price Effects
1 • Direct Price Increase
In order to finance the operating costs and the
fixed charges associated with the capital investment, the
utilities will have to raise the price of electricity. Based
on the assumptions presented inthe previous section, the
total cost to the consumers of electricity before exemptions
will increase 1.3 billion dollars or 2.3% by 1977 and 5.6 billion
dollars or 4.7% by 1983. The comparable figures after exemptions
are: .9 billion dollars or 1.6% by 1977 and 3.1 billion dollars
or 2.5% by 1983. The price increase by 1983 needed to generate
the additional revenues will be 1.5 mills/kwh before exemptions
and .8 mills/kwh after exemptions.!.'
As shown in Table 28, between 1983 and 1990, the
price effects New Source Performance Standards (NSPS) will be
negligible. Specifically, before exemptions NSPS will increase
the price of electricity only .1 mills/kwh or .2% by 1990.
After exemptions, however, NSPS will not increase the price of
electricity since the growth in the sales of electricity are
sufficient to generate the required increase in revenues.
2. Secondary Price Increases
To the extent that commercial and industrial users
of electricity pass through to the final consumer increases in
production costs, an increase in the price of electricity will
have an effect on the prices of other goods and services.
However, the average price increase is expected to be small
since purchases of electric power account for only about .8%
of the total value of industrial shipments.—' There will be
a larger impact on the price of products which are power
intensive. However, as shown in Table 29 there are only 6
industrial classifications for which electric power costs
amounted to 5 percent or more of the total value of shipments.
Even if we assume that the increased power costs are completely
passed on to the final consumer, the final price of the most
power intensive products, will increase by less than .5%, It
can be concluded, therefore, that the secondary price increases
associated with the guidelines will be very small.
JL/ Total price increase by 1983.
"2j National Economic Research Associates, Inc., Possible Impact
of Costs of Selected Pollution Control Equipment on the
Electric Utility Industry and Certain Power Intensive Consumer
Industries, 1972.
11-53
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D. Capacity and Energy Penalty
1. Capacity Penalty
Installation of cooling towers will require the
construction of new capacity to generate power to run the
cooling towers and to compensate for the loss of efficiency
due to the increase in turbine back-pressure. The baseline
case assumes that in 1977 the utilities will provide this
increased capacity through the construction of gas-turbine
units. However, by 1983 the utilities will be able to
construct large fossil and nuclear plants to replace the lost
capacity.
Before exemptions the total capacity penalty will
be 1,900 MWe by 1977 and 14 , 700 MWe by 1983. The comparative
figures after exemptions are 800 MWe by 1977 and 3 , 300 MWe
by 1983. The composition of the capacity penalty by type of
plant is estimated to be as follows:
Capacity Loss (in MWe)
Type of Plant 1977 1983
Before After Before After
Exemptions Exempt ions Exemptions Exemptions
1. Peakers (e.g. 1,900 800 1,900 800
gas turbines)
2. Base Load --- --- 12,800 2,500
CFossil and
Nuclear )
TOTAL 1,900 800 14,700 3,300
The projected capacity loss before exemptions will increase
the national demand for generating capacity by only ,4% by 1977 and
1.7% by 1983. .V In view of the small increase in the demand for
generating capacity, the utilities should not experience serious
problems in replacing the projected loss in generating capacity.
2. Fuel Penalty
There is a fuel penalty associated with the water
effluent guidelines. This penalty results primarily from
the following factors:
iy The comparable figures after exemptions are .2% by 1977 and .4% by 1983.
II- 54
-------
a. Additional fuel required to operate the
closed cycle cooling systems.
b. Additional fuel required per kwh of electricity
(e.g. higher heat rate) due to the increase
in turbine back pressure.
The fuel penalty before exemptions will be approximately 4
million tons equivalent of coal per year by 1977 and 33 million
tons per year by 1983. The comparable figures after exemptions
are 2 million tons by 1977 and 7 million tons by 1983.i'
In view of the current shortage of energy it is
important to evaluate the effect of the fuel penalty on the
national demand for energy, especially on the demand for oil.
Based on the Department of the Interior's estimates,—'
the fuel penalty after exemptions will increase the national
demand for energy .05% by 1977 and .2% by 1983. Also, if one
assumes that the fossil fuel penalty will be evenly divided
between coal and oil ,3_/ the guidelines after exemptions would
increase the national demand for oil 4 million barrels per
year or ,06%by 1977 and 14 million barrels per year or ,Z£ by
1983. It can be concluded, therefore, that the effluent guide-
lines will have an insignificant effect on both the nation's
ability to satisfy the projected demand for energy and the country's
dependency on foreign sources.
iy The fuel penalty was converted to a coal equivalency by taking
the total increase in demand for nuclear and fossil fuel
expressed in million BTU, and dividing by the average BTU per
ton of coal (e.g. 24 million BTU/ton).
2y Dupree, Walter G. and West, James A., United States Energy
Through the Year 2,000, U.S. Department of the Interior,
December, 1972.
3_/ This is probably a conservative assumption since if the fossil
fuel penalty was distributed according to the projected
utility demand for coal and oil, the energy penalty would be
65% coal and 35% oil.
11-55
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E . Production Effects
Because electric utilities are regulated to insure an
adequate return on their capital base, it is expected that
the utilities will be able to obtain rate increases to cover
the increased costs due to pollution control. Even if there
are delays in obtaining rate increases, it is unlikely that any
power plant will shut-down because of the higher costs associated
with the water effluent guidelines.
The one production effect of the guidelines may be to
force certain utilities to prematurely retire some older units
in order to avoid spending large amounts for pollution control
equipment. Such an option will probably be used only after 1977
when it would be possible to replace the retired unit with new,
large fossil or nuclear units.
However, the guidelines will not significantly affect
the growth of the electric utility industry for several reasons.
First, since the electric utility industry is regulated to insure
an adequate rate of return on its equity, investment in the
industry will not be significantly affected. Second, the expected
increase in the price of electricity is not expected to have a
noticeable impact on the demand for electricity.
F. Employment Effects
Since the price increases associated with the guide-
lines are not expected to have a significant effect on the
growth in demand for electricity, the overall level of employ-
ment in the electric utility industry will increase in order
to meet the projected increase in demand for electricity. Also
as discussed in the previous section, the guidelines are not
expected to cause any plant closures and any employment effects
due to the early retirement of inefficient generating units will
probably be offset by the projected expansion in generating
capacity. Furthermore, if the increased demand for generating
capacity due to capacity penalties (e.g., .4% after exemptions by
1983), is greater than the reduction due to the projected price
increase the guidelines will increase the level of employment.
G. Community rtiffants
The water effluent guidelines will impact the community
directly through increased prices for electricity and indirectly
through price increases for final goods and services-£s shown
in Table 30 the guidelines after exemptions!/ will increase the
average resident'! monthly electricity bill $.39 or 1.6 A by
1977 and $1-08 (2.5%) by 1983. The average monthly bill for
large industrial users would increase $43 (1,6%) by 1977 and
-------
H. Balance of Trade
The guidelines will have a small effect on the balance
of trade because part of the increased fuel consumption
associated with closed cycle cooling systems will be met by
increased imports of residual fuel oil. Based on the assumptions
used to estimate the fuel penalty, the guidelines before
exemptions will increase oil imports by 8 million barrels per
year or 1.2% by 1977 and 66 million barrels per year or 1.5% by
1983. The comparable figures after exemptions are 4 million
barrels or .6% by 1977 and 14 million barrels or ,,4 % by 1983.
It is difficult to estimate the total balance of payments
costs of the guidelines since there is considerable uncertainty
concerning the future price of imported oil. If one assumes
a net out-flow of $7'per barrel of oil, however, the balance
Of payments costs before exemptions would be 256 million dollars
per year by 1977 and 462 million dollars per year by 1983.
The comparable figures after exemptions are 28 million dollars
by 1977 and 98 million dollars by 1983. Since the level
of imports in 1973 was approximately 70 billion dollars, it can he
concluded that the guidelines will have an insignificant impact
on the nation's balance of trade.
11-57
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TABLE 27
SUMMARY OF THE ECONOMIC IMPACT OF TH
EFFLUENT LIMITATION GUIDELINES L
Level I
1977 Standards
Impact
Financial Effects
1. Capital Investment (billion $)
2. % Increase over baseline
Price Effects
1. Increased revenues per year
2. Price increase in mills/kwh
3. Price increase (% cost to final user)
(billions)
Before
Exempt ions
7.7
8,1%
1,3
,5
2,3%
After
ExemDtions
2.1
2.2%
.9
.4
1,63
Level II
1983 Standards!/
Before
ExemDt ions
23.2
6.3%
5.6
1.5
4.7%
After
Exemptions
9.2
2.5%
3.1
.8
2.5%
Oi
00
Capacity Penalty „.
1. Total capacity penalty—
2. % of national capacity
Fuel Penalty
1, Total fuel penalty (million tons
coal equivalent)—'
2. % of national demand for energy
1,900 mwe
.,4%
4
,1%
SOOmwe
.2%
2
,05%
14,700 mwe
1.7%
33
.7%
3,SOOmwe
.4%
7
.2%
I/ Figures represent the incremental cost of the guidelines
"2J Total replacement capacity needed to run the cooling towers and to compensate for
capacity lost due to increased turbine back pressure.
3/ Total increase in demand for nuclear and fossil fuel expressed in million BTU and
~~ divided by the average BTU per ton of .coal (e.g., 24 million BTU)
kj FigureSshown for Level II represent the cumulative effect of 1977 and 1983 standards.
-------
TABLE 28
SUMMARY OF THE ECONOMIC IMPACT OF NEW SOURCE PERFORMANCE
STANDARDS. 3.983-1990
Impact
Financial Effects
1. Capital Investment
2. % increase over baseline
Cost of New Source Performance
Standards - 1983-199Q.3-/
Before
Exemptions
16.3 billion
2,6%
After
Exemptions
5,2 billion
Price Effects
1. Increased revenues per year
2. Price increase
3. Percentage increase in price to
final user
3,5
.1 mills/kwh
.2%
1.7 .,
,0 mills/kwhA'
Capacity Penalty
1. Total capacity penalty!.'
2. % of national capacity
10,400 MWe
.8%
3,100 MWe
.25%
Fuel Penalty
1. Total fuel penalty
(million tons coal equivalent)^/
2. % of national demand of energy
26 million tons
.4%
8 million tons
127
. A ^ fo
I/ Total replacement capacity needed to run the cooling towers
and to compensate for capacity lost due to increased turbine
back pressure.
2y Total increase in demand for nuclear and fossil fuel expressed
in million BTU and divided by the average BTU per ton of coal
(e.g. , 24 million BTU)
3_/ Figures represent the incremental effect of New Source Performance
Standards between 1983 and 1990.
~ between 1984 and 1990 is
*»
°*
11-59
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TABLE 29
SELECTED ELECTRICITY INTENSIVE INDUSTRIES IN THE UNITED STATES
1967
Industry
All Manufacturing
Atomic Energy Commission Plants 2
Primary Production of Aluminum
Electrometallurgical Products
Alkalies and Chlorine
Industrial Gases
Cement, Hydraulic
Six-Industry Total
All Other Industry
2819
33-34
3313
2812
2813
3241
Electric Power
Costs As A
Per Cent of
Value of Shipments^l
(Per Cent)
0.79%
IS.25
11.40
11.01
9.35
9.10
5,94
10 .34
0.69
Total Electric
Poxver .Purchased
Plus Net Generation
(Million Kwh)
505,820.9
29,827.7
53,604.9
11,205.7
12,319.0
7,050.4
8,413.2
122,425.9
383,395.0
OS
O
1 Self-generated power is evaluated for each industry at the same cost per Kwh
as that industry's electric power purchases.
2 These plants constitute only a part of industry 2819 (Industrial Inorganic
Chemicals, N.E.C.). The Census does permit isolating the value of shipments
by these plants. Electric power purchases are based on FPC data.
Source: U.S. Bureau of the Census; Census^ pf Manufactures, 1967 (Washington, D.C.: U.S.
Government Printing Office,~T971); Volume II, Industry Statistics, Part 1,
pp. 28-42; Volume II, Industry Statistics , Part 2, p. 28A-9 and Fuels and Energy
Consumed, Special Series MC (67)"S~4, p. 18-SR4. U.S. Federal Power Commission,
"Electric Energy Purchased, Generated and Used and Maximum Demands at Major
Atomic Energy Commission Installations by Months for 1967" (unpublished table),
July 1968.
-------
TABLE 30
IMPACT OF THE WATER EFFLUENT GUIDELINES ON TflE CONSUMERS
OF ELECTRICITY. 1977 and 1983
YEAR
1977
1983
FINANCIAL DATA
Actual monthly electricity
bill
Projected monthly bill with-
out effluent guidelines
TYPE OF CUSTOMER
RESIDENTIAL LARGE INDUSTRIAL
2/
Projected increase due to the tl
effluent guidelines
- before exemptions
- after exemptions
Percent increase
- before exemptions
- after exemptions
Projected monthly bill
without effluent guidelines
Projected increase due to^/
the effluent guidelines
- before exemptions
- after exemptions
Percent increase
- before exemptions
- after exemptions
$13.33l/
24.20
,56
.39
2.3 %
1.6%
43.25
2.03
1.08
4.7%
2.5%
$l,416l/
2,712
62
43
2.3%
1.6%
4,830
227
120
4.7%
2.5%
I/ Edison Electric Institute, Statistical Yearbook of the Electric
Utility Industry for 1971
2J Temple, Barket & Slone, Economic Impact of Water Effluent Guide-
lines on the Electric Utility Industry. March, 1974.
In addition the following assumptions ivere made.
a. 7% per year growth in demand for electricity and a 2%
per year growth in total customers.
b. The price increase due to the guidelines would be
passed on uniformly to all types of customers.
11-61
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VII. LIMITS TO THE ANALYSIS
A. Uncertainty of Cost Estimates
1. Capital Costs
Section VI estimated the economic impact of the
guidelines based on estimates of the most likely costs of
complying with the effluent guidelines. The data, however,
indicates that there is considerable variability in several
of the cost parameters. For example, estimates of the cost
of installing cooling towers.on existing plants!' vary from
$3.8 per kilowatt of capacity^-' to over ?100 per kilowatt (kw)
of capacity^.'. Since there will be more variability in cost
estimates for individual plants than in estimates for average
national cost,additional computer runs were made with the cost
of retrofitting existing plant varying from $10/kw to $38/kw_L'«
The analysis indicates that the capital requirements reauired
before exemptions to meet the 1983 thermal standards could be reduced
by as mach as 16% or increased as much as 35%.A/ It is in.terest-
ing to note however, that the high estimates for capital
costs would raise the expected price increase in 1983 before
exemptions by only 20% (e.g., from 5 % to 6%).
Similarly, as indicated in Table 32, there is
consideralle uncertainty in the capital cost required to
comply with the chemical guidelines. While it is EPA's judgment
that the actual costs of the chemical guidelines will correspond
to those specified in the development document !/, a separate
computer run was made to determine the impact of the highest
industrial estimate.—' The analysis indicates that the investment
17 Only the capital required to build and hook-up the cooling
tower will be included in the following estimates.
27 Woodson, R.D. "Cooling Towers for Large Steam-Electric
Generating Units," in Eisenbad, M and Gleason, G.,, editors,
New York, 1969, pp. 364-365
3/ Estimated costs for Indian Point Nuclear Station (Consolidated
~ Ed.)
4/ A breakdown of the maximum and minimum capital costs by type
~~ of unit is given in Table 31,
5/ The figures are only estimates since it was assumed that the
~ percent variation in 1983 for the technological option (e.g.
Policy Alternative -0- in Part III would be the same as the percent
variation for EPA's proposed guidelines (e.g. Policy Alternative 7
in Part III).
6/ EPA, Development Document for Proposed Effluent Limitation Guidelines
and New Source Performance Standards for the Steam Electric Power
Generating Point Source Category, March 1973.
1_J Corresponds to Policy Alternatives <-l"(b-) and -l(d) in Part III,
11-62
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required to comply with the 1983 chemical guidel-lnes could increase
from 5,5 billion to 18.4 billion dollars. ¥his would increase ease
the total capital requirements of the utility industry
another 3.5% by 1983.
2. Operating Costs
The principal uncertainties concerning the
estimates of operating costs are the cost of replacing the power
losses associated with closed cycle cooling systems, and the
magnitude of the loss in efficiency due to the increase in turbine
back pressure. In order to determine the importance of varying
these parameters, additional computer runs were made for what
could be considered maximum and minimum values (see Table 31 for
cost estimates). The analysis indicated that the expected price
increase in 1983 before exemptions could be reduced by 2Q% or
increased by 13%.
3. Conclusions
Although a similar analysis was not undertaken to
estimate the effect of cost uncertainties on the impact after
exemptions, it is expected that the variability could be of the
same order of magnitude. Thus, if one assumes the worst set of
assumptions for both the chemical and thermal standards, the guide-
lines after exemptions would require an incremental, investment Q£ 2_4 vl
fcillion dollars by 1983.i'lt can be concluded, therefore, that
even under the most conservative set of assumptions, the
effluent guidelines will not increase the capital requirements
of the electric utility industry more than 6V5£ by 1983.
!_/ Estimate can be broken down as follows:
- cost of guidelines after exemptions 9,2 billion
- adjustment for higher capital 2^0 billion
costs for thermal guidelines
- adjustment for higher capital costs 12.9 billion
for chemical guidelines
11-63
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B. Critical Assumptions
While the previous section analyzed the variability
in the cost estimates, this section will focus on several criti-
cal assumptions that were the basis of the economic impact metho-
dology. The first assumption was that the price increase granted
by the regulatory agencies will be sufficient to maintain an adequ-
ate rate of return on the utility industry's common equity. Speci-
fically, EPA's analysis assumes that the price increases would
enable the utility industry to realize a 12% return on common
equity. Although this is probably a good long-run assumption, in
the short-run some utilities could experience delays in obtaining
the necessary rate increases. To the extent to which delays
occur, the utility's rate of return could fall below the level
assumed in this analysis. A decline in the utility's rate of
return could also affect its ability to finance the required
capital expenditures. However, given the available data there
is no way to predict the exact impact that delays in obtaining
rate increases will have on the overall level of profitability
of the utility industry or on the industry's ability to finance
pollution control expenditures.
The second critical assumption was that the utilities
will be able to finance the incremental expenditures for
pollution control equipment. The principal counter arguments
seem to be as follows:
1. Since the utility industry's ability to finance capital expendi-
tures is already stretched to its upper limit, there will
be considerable problems in obtaining additional capital.
2. Delays in obtaining rate increases could result in
a derating of the utility's bond issues, thus
further reducing the utility's ability to finance
capital expenditures.
While it is not possible to conclusively prove that
the required capital will be available, there are several reasons
why the utilities should be able to obtain financing. First,
since the utility industry is regulated to insure an adequate
rate of return on common equity, it will be able to obtain rate
increases to finance expenditures for pollution control equipment.
Second, the utility industry is already planning to spend about
360 billion dollars between 1973 and 1983 in order to construct
generation and transmission facilities. The guidelines after
exemptions will increase the utilities' capital requirements only 2.5% by
1983. Third, the industry was able to increase investment by 11% per year
in the 1960's despite a rapid decline in the industry's coverage
11-64
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ratios. As noted in previous Section VI, the guidelines will have
an insignificant effect on the industry's coverage ratios. It
can be concluded that any financial problems that the utility
industry will encounter will be caused primarily by the industry's
need to rapidly expand its generation and transmission facilities.
Consequently > a.n effective way for the utility industry to
insure the availability of capital for pollution control equipment
would be to support an extensive energy conservation program.
The third major assumption was that the cooling tower
industry will be able to expand in order to meet the projected
demand for cooling towers. This assumption appears to be
valid for the following reasons:
1. Cooling systems are not generally factory limited.
That is, the bulk of the labor and material is
supplied by construction in the field. The only
components supplied from off-site sources are fans,
spray modules, tower packing and small quantities
of piping and control equipment. None of these
items are sophisticated to manufacture and large
increases in the supply of these materials can be
obtained through subcontractors who specialize in
similar items. The major limitation in increasing
the volume may be in obtaining competent engineering
and design forces to support the increased demand.
However, since most of the increased demand for
cooling towers will occur after 1977, adequate lead
time Is available for the industry to train qualified
personnel.
2. Several types of cooling systems do not require
any type of factory support and can be engineered
and constructed by the utilities or their agents.
This is the case with any cooling pond (spray
pond excluded). The potential of this type of
system for those plants which have surplus
land is significant.
3. There are several recent entrants into the cooling
tower industry and several others are anticipat-
ing entry.
Another critical assumption was that each utility
company could schedule the hook-up of the cooling towers during
off-peak periods and use either the company's or another system's
excess capacity as replacement power. Assuming that it took 3
months to hook-up a cooling tower to an existing power plant
(one month of which was for normal maintenance), and that the
utilities could schedule the outages during 54 of the months
11-65
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between 1978 and 1983, an additional•6% of the nation's
generating capacity would have to be used to supply the
required power.i' Although the incremental capacity
requirements will vary by utility system, the regional
disparities probably could be alleviated by purchasing
power from other systems which were less impacted.
There are several potential problems concerning
the above assumptions. First, if the demand curve for many
utility systems is peaked, there will be considerably less
time in which to schedule outages. Second, if all a utility's
excess capacity during non-peak periods is firmly committed
to either necessary maintenance or to required reserve capacity,
it may be extremely difficult to make available an additional .6%
of tne system's generating capacity. Finally, since all
utility systems are required to comply with the guidelines
at approximately the same time, it also may be difficult to
purchase power from another utility system.
If the above problems prove to be significant the
utilities would have to provide the replacement power by
constructing additional capacity. If it is assumed that ^6%
of generating capacity would have to be replaced, the capacity
expenditures to meet the 1983 guidelines would increase by
approximately 1.1 billion dollars.
Despite the problems just cited, it is the conclusion
of this analysis that since most utilities will not have to begin
to comply with the thermal guidelines until July, 1978, there
is adequate time to schedule the construction and hook-up of
cooling towers without having to construct additional capacity
to supply replacement power.
The fifth critical assumption was that in the absence
of feueral environmental regulations, the mix of cooling facilities
in the 1973-1983 period would correspond to the 1970 mix of
cooling facilities. Therefore, for new power plants the incre-
mental cost of the thermal guideline's would equal the cost of
cooling towers minus the cost of the basic cooling facility
that the utility would have installed (e.g., once through
cooling in most cases and cooling ponds, combination systems
or cooling towers in the remaining cases). For existing power
plants, however, the incremental cost and the total cost of the
thermal guidelines would both be equal to the cost of cooling
towers.
17 Estimate was based on the following consumptions:
- All power plants that were planning to install cooling towers before the
publication of the guidelines have already planned to build additional capacity
to replace the capacity losses associated with cooling towers.
- After exemptions, an additional 88,000 mwe of capacity will have to install
cooling towers by 1983.
- The outages will be scheduled at 3 months intervals over 54 months between
1978 and 1983.
- The total generating capacity in 1983 will be 790,000 mwe.
11-66
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There are a number of problems concerning this
assumption. First, it is extremely difficult to forecast
what mix of cooling facilities would have been installed
in the absence of federal environmental regulation. Second, a
certain percentage of the new power plants have already incurred
costs for the construction of cooling facilities. Thus,the
incremental costs presented in Table-26 which were calculated
based on the assumption that no costs had been incurred for alter-
native cooling facilities, actually under estimate the impact of
the guidelines. Finally, there was a computational error in the
computer run that calculated the incremental cost of the guidelines
after exemptions (e.g., policy alternative 7(e) in Part III).
Specifically, the costs that the utility industry would have
incurred for cooling systems in the absence of federal legislation
(e.g., Table-25) were not included for that fraction of new capacity
which will not be covered under the guidelines. In order to
accurately predict the incremental costs of the guidelines after
exemptions, these costs would have to be added to the estimates
which were presented in Tables 27 and 29.
It can be concluded, therefore, that the actual incre-
mental costs of the guidelines fall in between the total cost
estimates (Table -22 ) and the incremental cost estimates (Table
26). If one assumes the worst case, namely that the incremental
cost actually equals the total cost, the capital requirements of the
guidelines would increase 5.3 billion dollars by 1983-—' Since
this would increase the utility industry's capital requirements only
an additional 1.4% by 1983, there is no reason to question the
validity of the analyses' major conclusions.
The final crucial assumption was that the report analyzed
the impact of the guidelines based on a single set of assumptions
about the growth in demand for electricity. Consequently, another
computer run was made using a low forecast for the growth in demand.
The analysis indicates that the projected expenditures between 1974
and 1983 for generation and transmission facilities is reduced
about 31% — from 364 to 250 billion dollars.!' Since the projected
impact of the guidelines after exemptions is reduced by only about
20%,the percent increase in the utility industry's capital require-
ments by 1983 will increase from 2.5% to about 3%.-' It can be
concluded, that even tfnder assumptions of low demand, the utility
industry should be able to comply with the guidelines without
experiencing serious problems in financing the required expenditures,
I/ Tables 33 and 34 summarize estimates of the total cost of the
guidelines before and after exemptions.
2y See Part III, p. III-122 for a description of the low demand
case.
_3_/ Estimate assumes that the percent variation in Policy Alternative
1-E (low demand) is the same as the percent variation in EPA's
proposed guidelines.
11-67
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C. Remaining Questions
Probably the most important area that hasn't been
discussed is how the economic impact will vary by region and
by utility system. The major determinants of the variation
in economic impact are:
1. Percentage of existing and planned capacity
without closed cycle cooling systems,
2. Percentage of existing capacity that is baseload.
3. Cost of installing cooling towers on existing
and planned capacity.
4. Cost of replacement power.
5. Percentage of existing and planned capacity which
will receive exemptions.
6. Projected demand for electricity.
7. Projected efficiency losses due to increased
tubine track-pressure.
While there was not sufficient time to collect and
analyze data on the above variables, the regional variation
in economic impact should correspond to the results of a pre-
vious study of the economic impact of pollution control
expenditures.L' This study found that the relative impact
would vary as follows:
Region Relative Impact—/
l.New England Average
2.Middle Atlantic Average
3.East North Central High
4.West North Central Average
(except Nebraska)
S.Nebraska Low
6.South Atlantic High
7.East South Central High
except TVA)
S.Tennessee Valley Authority High
9.West South Central Low
10.Rocky Mountain Average
11.Far West Low
12.California Low
iyNational Economic Research Associates, Possible Impact on Costs of
Selected Pollution Control Equipment on the mectric utility industry
and Certain Power Intensive Consumer Industries, Jan. 1972.
^/Impact relative to the averaged national impact.
11-68
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TABLE 31
MINIMUM AND MAXIMUM ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT
OF GENERATING CAPACITY ASSOCIATED WITH THERMAL EFFLUENT GUIDELINES^/
Non-Nuclear Capacity Nuclear Capacity
Minimum Maximum Minimum Maximum
Capital Expenditures ($/kw)
for Back-Fitted Units $10.00 $28.00 $12,00 $38,00
for New Units 7.50 7.50 10.00 10.00
Annual Operating Expena«s
($/kw)l>
for 1977 Guidelines 21.00 84.00 21.00 84,00
for 1983 Guidelines 12.00 18.00 6.00 24.00
Capacity Losses
due to Running Cooling Units 1% 1% 1% 1%
due to Increased Back Pressure 15 15
I/ All costs are specified at 1970 levels.
2J Total annual operating costs for a plant that installs a cooling tower
equals (capacity of plant) X (annual operating costs/kw) X (% capacity
losses per plant)
11-69
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TABLE 32
ESTIMATES OF CAPITAL ANfl OPERATING COSTS PER UNIT OF GENERATING
CAPACITY ASSOCIATED WITH CHEMICAL EFFLUENT GUIDELINES^/
Capacity Placed in Service;
Prior to 1971
Capital Expenditures
Annual Operating Expenses
1971-1977
Capital Expenditures
Annual Operating Expenses
1977 Guidelines
Non-Nuclear Capacity
($/Kilowatt)
Maximum
EPA Industry
Estimate Estimate
$1.95
.85
1.05
.55
$17.00
1.35
11.00
0.90
Nuclear Capacity
$/Kilowatt)
Maximum
EPA Industry
Estimate Estimate
$.85
,50
,.85
.,50
$7.00
1.15
4.50
0.75
Capacity Placed in Service:
1983 Guidelines^
Non-Nuclear Capacity
($/Kilowatt)
Maximum
EPA Industry
Estimate Estimate
Prior to 1971
Additional Capital $3.35 $5.00
Expenditures
Annual Operating Expenses .65 0.25
1971-1977
Additional Capital Expenditures 2,75 3.30
Annual Operating Expenses .35 0.15
1978-1983
Capital Expenditures 2.60 14.30
Annual Operating Expenses .25 1.05
Nuclear Capacity
($ Kilowatt)
Maximum
EPA Industry
Estimate Estimate
$2.75
.35
2,75
,35
2.00
.20
$3,00
0.25
2,00
0,15
6.50
0.90
I/ All costs are specified at 1970 levels.
2J Estimates represent the incremental costs of the 1983 standards.
11-70
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M
M
I
TABLE 33
SUMMARY OF THE TOTAL COST OF THE EFFLUENT LIMITATION GUIDELINES
Level
I
1977 Standards
Impact
Financial Effects
1. Capital investment (billion $)
2. % increase over baseline
Price Effects
1. Increased revenues per year (billions)
2, Price increase in mills/kwh
3. Price increase (% cost to final user)
Capacity Penalty
1. Total capacity penalty i/
2. % o£ national capacity
Fuel Penalty
1. Total fuel penalty (million tons
coal equivalent )?-'
2. % of national demand for energy
Before
Exemptions
9.4
10.0%
1.4
.5
2.4
2,800
.5
6
.15%
After
Exemptions
3.8
4.0%
1.0
.4
1.7%
1,700
,3%
4
,1%
Level
II
1983 Standards!/
Before
Exemptions
28.5
7". 8%
6.2
1.7
5.5%
17,300
2,2%
38
.9%
After
Exemptions
14.5
4.0%
3.7
1.0
3.3%
5,900
.7%
13
.4%
17 Total replacement capacity needed to run the cooling towers and to compensate for
capacity lost due to increased turbine back pressure.
2] Total increase in demand for nuclear and fossil fuel expressed in million BTU and
divided by the average BTU per ton of coal (e.g., 24 million BTU).
3_/ Figures shown for Level II represent the cumulative effect of 1977 and 1983 standards.
-------
TABLE 34
SUMMARY OF THE TOTAL COST OF NEW SOURCE PERFORMANCE
STANDARDS. 1983-1990
Cost of New Source Performance
Standards - 1983-1990
Impact
Financial Effects
1. Capital Investment
2. % increase over baseline
Price Effects
1. Increased revenues per year
2. Price increase
3. Percentage increase in price
Capital Penalty
1. Total capacity penalty—'
2. % of national capacity
Fuel Penalty
1. Total fuel penalty
(million tons coal equivalent)—'
2, % of national demand of energy
Before
Exemptions
23.2 billion
3.8%
4.5 billion
.2 mills/kwh
.5%
13,600 JJWe
1.1%
30 million tons
.5%
After
Exemptions
12.1 billion
2.0%
2.7 billion
.1 mills/kwh
.25%
6,300
.5%
14 million
tons
.2%
_!_/ Total replacement capacity needed to run the cooling towers
and to compensate for capacity lost due to increased turbine
back pressure.
2_l Total increase in demand for nuclear and fossil fuel expressed
in million BTU and divided by the average BTU per ton of coal
(e.g., 24 million BTU).
3_/ Figures represent the incremental effect of New Source Performance
Standards between 1983 and 1990.
11-72
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PART III
TECHNICAL APPENDIX-/
I/ The technical appendix is reproduced in full from a report
entitled, "The Economic Impact of Alternative Water
Effluent Guidelines on the Electric Utility Industry,"
which was submitted to EPA in March, 1974 by Temple,
Barker, and Sloane, Inc. in fulfillment of Contract
No. 68-01-2418.
-------
1, PURPOSE AND SCOPE
This report focuses on the economic and
financial implications of the water effluent guidelines
established pursuant to the Federal Water Pollution Control
Act of 1972 (the Act) for the electric utility industry.
The economic consequences of the Act
include:
• capital expenditures for pollution
control equipment;
• the costs of operating that pollution
control equipment;
• capital expenditures for the added
generating capacity needed to offset
the reduced efficiency of generating
plants resulting from the operation
of cooling equipment; and
• the costs of operating these additional
generating units.
The magnitude of these direct and induced
economic costs is primarily a function of:
• the industry's future demand;
• the industry's future reserve
margins and load factors;
• the mix of nuclear and fossil-fueled
capacity brought into service in
each year;
III - 1 -
-------
• the percentage of each type of
generating capacity affected by
the Act;
• the time phasing of these pollution
control requirements;
• the capital costs associated with the
installation of pollution control
equipment in new plants;
• the capital costs of retro-fitting
existing capacity;
• the direct operating costs of this
equipment; and
• the impact of cooling towers on the
generating efficiencies of the plants
affected by the Act.
The foregoing direct and induced economic
costs will in the long run be borne by the consumers
of electrical energy, but the impact in the shorter
run will largely be absorbed by the capital markets.
The distribution of the financial burden between
consumers and the capital markets as of any particular
time is a function of:
the proportions of operating costs and
capital expenditures associated with
the Act's standards ;
tax and regulatory policies with
respect to the depreciation of the
pollution control equipment ;
the industry's dividend and capital
structure policies; and
capital market conditions.
III-2-
-------
This study projects the economic and
financial consequences of a number of assumptions
supplied by the Environmental Protection Agency
(EPA) concerning the percentage of each type of
generating capacity affected by the Act. These al-
ternative coverage policies include:
• a baseline assumption of no
limitations on chemical and thermal
effluent;
• the coverage implicit in existing federal,
state and local thermal pollution
control regulations;
• the assumption that only the Act's
chemical pollution control standards
are in force;
• the maximum percentages of existing
and new nuclear and fossil-fueled
generating capacity potentially
affected by the Act; and
• the reductions in this maximum
coverage possibly afforded by
exemptions from the Act's standards
that are available in Section 316(a)
of the Act.
This study also projects the impact of the
latter two issues above under various assumptions
with respect to the time phasing of the Act's thermal
pollution control requirements. Considered are a
variety of different time schedules for:
• the completion date for the retro-
fitting of the water cooling equipment
required on existing nuclear and
fossil-fueled plants; and
III-3-
-------
the date after which all plants
coming into service must be fitted
with thermal pollution control
equipment.
To take account of technical uncertainties
concerning the equipment required to control chemical
and thermal water pollution, this study also reviews
the impact of various combinations of maximum, most-
likely, and minimum estimates for:
• the capital costs of the chemical
and thermal pollution control equip-
ment required per unit of generating
capacity;
• the operating costs of such equipment;
and
the impact of the thermal equipment
on generating efficiencies.
Finally, the study examines the implications
of the Act under two different sets of assumptions
concerning rates of growth in the demand for electrical
energy :
• a most-likely projection consistent
with that of the 1973-1974 National
Power Survey; and
• a low-growth projection intended to
reflect the potential impact on de-
mand of energy conservation policies
and escalating costs per kilowatt
hour (kwh) of energy.
III-4-
-------
The impact of the Act is described in terms
of the following financial and physical variables:
• changes in the industry's capital-
ized expenditures, i.e., expenditures
for in-service generating capacity,
for construction work in progress,
and for allowances on funds used
during construction;
• changes in external financing require-
ments;
• changes in yearly operating revenues
and operations and maintenance
expenses;
• average cost per kwh of electricity;
and
• capacity and energy penalties.
These major industry variables are projected
for each of five time periods:
• 1974-1977
• 1978-1983
• 1974-1983
• 1984-1990
• 1974-1990
The scale of the calculations required to
project the magnitude of the economic consequences
of the Act and the distribution of the financial burden
between consumers and the capital markets over time
for a wide variety of technical assumptions and policy
alternatives dictated the use of a computer model
of the electric utility industry. The model used in
this study, PTm, is an extension of a model developed
III-5-
-------
by Dr. Howard W. Pifer of Temple, Barker & Sloane,
Inc., and Professor Michael L. Tennican of Harvard
University, Graduate School of Business Administration,
to provide projections for the Technical Advisory Com-
mittee on Finance (TAC-Finance) to the 1973-1974
National Power Survey. A brief overview of PTm is
provided in the Appendix to this report.
III-6-
-------
2, SUMMARY CONCLUSIONS
2.1 Introduction
Section 2 summarizes the analysis of Sections
3 through 8 by focusing on the two policy options, la-
belled Policy Alternatives 1 and 3, at the ends of the
spectrum considered by the EPA and on the option, Policy
Alternative 7, proposed by the EPA. Each of these policy
alternatives is examined both before and after consid-
eration of the exemptions from required closed-cycle
cooling systems estimated by the EPA to be available
under Section 316(a) of the Act. In addition, Section 2
briefly reviews the economic and financial implications
of the Act under the assumption of reduced rates of
industry demand growth such as may stem from a contin-
uation of recent price and non-price induced energy con-
servation efforts. Finally, this section presents a brief
summary of an earlier report submitted by TBS to the EPA
concerning the effects of technological uncertainties
about the capital costs, operating costs, and generating
plant efficiency losses of pollution control equipment.
A brief overview of the policy alternatives
and alternative technological assumptions is as follows:
• Policy Alternative 0: A base for
reference which assumes no thermal
or chemical effluent controls.
Ill - 7 -
-------
• Policy Alternative 1: An alternative
calling for increasingly strict limi-
tations on chemical effluents by 1977 and
by 1983 and for closed-cycle cooling
systems by 1977 on all but cyclic and
peaking generating capacity built prior
to 1978. These cyclic plants are required
to be fitted with closed-cycle cooling
systems by 1983 while peaking units are
not covered by the guidelines. The chemical
and thermal pollution control aspects of
Policy Alternative 1 are also discussed
separately as Policy Alternatives 1-C and
1-T. The impact on Policy Alternative 1
of the thermal equipment exemptions esti-
mated to be available under Section 316(a)
of the Act is discussed as Policy Alternative 1-E,
• Policy Alternative 3: An alternative which
assumes that generating plants began after
publication of the EPA regulations (estimated
to be those fossil and nuclear plants coming
into service after 1978 and 1981, respec-
tively) have closed-cycle cooling systems
as of their in-service dates and which
assumes that all other capacity is brought
into compliance with the Act's standards
by 1983. Policy Alternative 3's eventual
coverage of generating capacity is iden-
tical to that of Policy Alternative 1;
the two differ only in their time schedules
for the installation of thermal pollution
control equipment. The effect of exemptions
estimated to be available under Section
316(a) of the Act is discussed as Policy
Alternative 3-E.
• Policy Alternative 7: The policy alter-
native being proposed by the EPA. This
policy option assumes that pre-1971 peak-
ing capacity is retro-fitted with closed-
cycle cooling systems by 1983, but otherwise
calls for the same eventual coverage as Policy
Alternatives 1 and 3. The time schedule
for the imposition of these requirements
is an intermediate one, however, calling
for a time phasing that depends, among
other things, on the size of any given
plant. Policy Alternative 7 with Section
316(a) exemptions is labelled Policy Alter-
native 7-E.
-------
Policy Alternatives l(a)-(g): Policy
Alternative 1 for the 1974-1983 period
under different assumptions with respect
to:
the capital and operating costs of
chemical pollution control equipment;
the capital costs of retro-fitting
thermal pollution control equipment;
and
the operating costs and efficiency
losses associated with closed-cycle
cooling systems.
III-9-
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2.2 The Impact of Selected EPA Policy Alternatives
Before Exemptions
Before consideration of the impact of pollution
control requirements, the electric utility industry is
projected to have the capitalized expenditures, operations
and maintenance expenses, and average consumer charges
per kilowatt hour summarized in Table 2.2-1.
Table 2.2-1
BASELINE INDUSTRY PROJECTION, EPA POLICY ALTERNATIVE 0:
SUMMARY DATA
1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
During Period
Operating
Expenses
During Period
(billions of current dollars)
$93.8
$364.0
$968.1
$90.8
$322.3
$832.6
Average Consumer
Charges at End
of Period
(cents per kwh)
2.40?
3.19?
4.32?
Policy Alternative 1, which calls for rapid
compliance with the Act's effluent guidelines, results
in the added capitalized expenditures and operating
expenses shown in Table 2.2-2 below.
111-10-
-------
Table 2.2-2
THE IMPACT OF EPA POLICY ALTERNATIVE
SUMMARY DATA
1974-1977
1974-1983
1974-1990
(billions
Thermal
$11.2
$20.6
$41.5
Capitalized
Expenditures
of current dollars)
Chemical Total
$ 2.2 $ 13.4
$ 6.5 $ 27.1
$ 8.8 $ 50.3
1:
Operating
Expenses
(billions
Thermal
$ 1.4
$ 6.9
$17.6
of current
Chemical
$ 1.0
$ 5.9
$16.8
dollars)
Total
$ 2.4
$12.8
$34.4
The short-run and long-run impacts of Policy Alternative 1
can be highlighted via an inspection of the projections for
the 1974-1977 and 1974-1990 periods. Capitalized expendi-
tures are increased relative to the baseline by 14.3 percent
in the 1974-1977 period, but only by 5.2 percent over the
1974-1990 period. As is discussed further in Sections 3
and 4 of this report, these expenditures for pollution con-
trol equipment are financed in the short run largely via
new issues of debt, preferred stock, and common stock. The
external financing associated with Policy Alternative 1's
pollution control expenditures is $11.0 billion in 1974-1977
and $33.5 billion over the entire 1974-1990 period. As is
shown in Table 2.2-2, operations and maintenance expenses are
2.6 percent and 4.1 percent higher than the baseline in the
1974-1977 and 1974-1990 periods.
Policy Alternative 3 assumes a time schedule
for the installation of closed-cycle cooling systems that
is substantially delayed relative to that of Policy Alterna-
tive 1. As a consequence of inflation and of the greater
technical difficulties inherent in retro-fitting, the capital
costs per unit of capacity rise relative to those in Policy
Alternative 1. On the other hand, the EPA has assumed
III-ll-
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technological improvements over time that result in lower
operating costs for units installed after 1977. Summary
data on capitalized expenditures and operating costs for
Policy Alternative 3 are shown in Table 2.2-3.
Table 2.2-3
THE IMPACT OF EPA
POLICY
ALTERNATIVE 3:
SUMMARY DATA
1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
(billions of current
Thermal Chemical
$ 2.7 $ 2.2
$30.2 $ 6.5
$47.4 $ 8.8
dollars)
Total
$ 4.9
$36.7
$56.2
Operating
Expenses
(billions of current
Thermal Chemical
$ 0.3 $ 1.0
$ 2.3 $ 5.9
$ 9.5 $16.8
dollars)
Total
$ 1.3
$ 8.2
$26.3
Capitalized expenditures for Policy Alternative 3 are
substantially below those of Policy Alternative 1 in
1974-1977, being only 5.2 percent above the baseline in-
dustry projection. On the other hand, despite the major
differences assumed in the timing of thermal pollution
controls, Policy Alternative 3's capitalized expenditures
over the full 1974-1990 period are only $5.9 billion higher
than those of Policy Alternative 1, or 5.8 percent
above the baseline. Operating expenses for Policy Alterna-
tive 3 are lower over all time periods than for Policy
Alternative 1. The 1974-1977 expenses are 1.4 percent
above baseline; the 1974-1990 expenses are 3.2 percent
above baseline.
111-12-
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Policy Alternative 7 stipulates that pre-1971
peaking capacity have closed-cycle cooling for 1983, result-
ing in $0.5 billion of capitalized expenditures for these
peaking plants in the 1978-1983 period and in small amounts
of related operating expenses in subsequent years. However,
as is suggested in Table 2.2-4, Policy Alternative 7 is in
other respects an intermediate position between Policy Al-
ternatives 1 and 3. Policy Alternative 7 results in 1974-
1977 capitalized expenditures for pollution control that
are 10.0 percent above the baseline and in 1974-1990 totals
that are 5.3 percent higher than the baseline. In sum,
Policy Alternative 7, like Policy Alternative 3, entails
much lower capitalized expenditures and external financing
requirements in the 1974-1977 period than does Policy Alternative
1. Furthermore, Policy Alternative 7's thermal pollution
equipment is installed early enough in the 1974-1990
period so as to entail only slightly higher total capitalized
expenditures than Policy Alternative 1. However, this in-
stallation schedule also means that much of the equipment is
installed too early to capture the reduction in operating
costs assumed by the EPA to take place in 1977.
Table 2.2-4
THE IMPACT OF EPA POLICY ALTERNATIVE 7:
SUMMARY DATA
1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
(billions of current
Thermal Chemical
$ 7.2 $ 2.2
$22.0 $ 6.5
$42.9 $ 8.8
Operating
Expenses
dollars)
Total
$ 9.4
$28.5
$51.7
(billions
Thermal
$ 0.4
$ 6.4
$17.4
of current
Chemical
$ 1.0
$ 5.9
$16.8
dollars)
Total
$ 1.4
$12.3
$34.2
111-13-
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2.3 The Impact of Selected EPA
Policy Alternatives After Exemptions
The potential economic and financial impact of
the Act may be reduced dramatically by the exemptions
from thermal control requirements available in Section 316(a)
of the Act. The EPA has estimated that the retro-fitting
of pre-1978 capacity will be reduced to approximately 20
percent of the levels assumed in the preceding discussion
and that capacity coming into service in 1978 or later will
have coverages roughly half that assumed before consideration
of exemptions.
Tables 2.3-1 and 2.3-2 below, which present summary
data on Policy Alternatives 1-E and 3-E, clearly show the
impact of exemptions from the Act's thermal effluent guidelines
Table 2.3-1
THE IMPACT OF EPA POLICY ALTERNATIVE 1-E
SUMMARY DATA
Capitalized
Expenditures
1974-1977
1974-1983
1974-1990
(billions
Thermal
$ 3.2
$ 7.3
$17.1
of current
Chemical
$ 2.2
$ 6.5
$ 8.8
dollars)
Total
$ 5.4
$13.8
$25.9
(billions
Thermal
$ 0.3
$ 1.7
$ 5.1
Operating
Expenses
of current
Chemical
$ 1.0
$ 5.9
$16 . 8
dollars)
Total
$ 1.3
$ 7.6
$21.9
111-14-
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Table 2.3-2
THE IMPACT OF EPA POLICY ALTERNATIVE 3-E
SUMMARY DATA
Capitalized Operating
Expenditures Expenses
(billions
Thermal
1974-1977 $ 1.7
1974-1983 $ 9.8
1974-1990 $18.8
of current dollars) (billions of current dollars)
Chemical Total Thermal Chemical Total
$ 2.2 $ 3.9 - $ 1.0 $ 1.0
$ 6.5 $16.3 $ 0.7 $ 5.9 $ 6.6
$ 8.8 $27.6 $ 3.6 $16.8 $20.4
The sharp reduction in retro-fitting requirements assumed
to occur as a result of 316(a) exemptions means that capital-
ized expenditures for thermal equipment drops sharply in
the 1974-1977 period for Policy Alternative 1-E relative to
Policy Alternative 1; the decline is from $11.2 billion to
$3.2 billion, or 71.4 percent. The impact of the reduced
retro-fitting requirements is, of course, spread out over
longer time periods for the other policy options. The per-
centage declines in the post-1977 period are also reduced
by less dramatic amounts because the EPA has assumed that
exemptions will have less impact on new source coverages
than on the retro-fitting of existing generating capacity.
Policy Alternative 3-E provides an analysis of the
impact of exemptions whenever the installation of closed-
cycle cooling systems is delayed substantially. Once again,
Policy Alternative 7-E yields an intermediate position.
111-15-
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2.4 The Impact of Reduced Industry Growth
A baseline projection for the electric utility
industry assuming approximately a 25 percent reduction in
future rate of demand growth is summarized in Table 2.4-1.
Table 2.4-1
BASELINE INDUSTRY PROJECTION, EPA POLICY ALTERNATIVE 0
(LOW DEMAND): SUMMARY DATA
1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
During Period
Operating
Expenses
During Period
(billions of current dollars)
$63.8
$249.0
$585.1
$ 85.9
$293.3
$708.2
Average Consumer
Charges at End
of Period
(cents per kilowatt hr .)
2.35'?
3.08'?
4 .09'?
The economic and financial consequences of
Policy Alternative 1 under such demand assumptions are
summarized in Table 2.4-2.
Table 2.4-2
THE IMPACT OF EPA POLICY ALTERNATIVE 1
(LOW DEMAND) : SU»UAi1Y DATA
Total
Capitalized
Expenditures
Total
Operating
Expenses
(billions of current dollars) (billions of current dollars)
1974-1977
1974-1983
1974-1990
$11.4
$21.4
$34.3
$ 1.9
$11.4
$30.3
IH-16-
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As is evident in these data, the effect of approxi-
mately a 25 percent reduction in the industry's future demand
growth is to reduce the total dollars of capitalized expendi-
tures and operating expenses substantially relative to those
projected for higher demand growth, from $13.4 billion to
$11.4 billion (14.9 percent) in the 1974-1977 period and
from $50.3 billion to $34.3 billion (31.8 percent) in the
1974-1990 period. Note, however, that the industry's baseline
capitalized expenditures decline even more rapidly, from $93.8
billion to $63.4 billion (32.4 percent) and from $968.1 billion
to $585.1 billion (39.6 percent) in the same periods. Thus,
expenditures for pollution control equipment represent an
increased share of total expenditures, rising to 17.7 percent
for the 1974-1977 period and to 5.9 percent for the 1974-1990
period. These figures contrast with 14.3 percent and 5.2
percent pollution equipment increases relative to the baseline
under the most-likely demand growth forecast.
Unfortunately, these significant reductions in
expenditures are not passed through to the consumer. The
above-mentioned reduction in peak load demand would reduce
1990 consumer charges from 4.32£/kwh to 4.09£/kwh (5.3 percent)
111-17-
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2.5 The Impact of Alternative
Technological Assumptions
Alternative assumptions about the capital and
operating costs of chemical and thermal pollution control
equipment and about the impact on generating efficiencies
of closed-cycle cooling systems may have a substantial
impact on the projected consequences of the Act. In addition
to the "most-likely" estimates used in the analyses sum-
marized above, the EPA has estimated "maximum" capital and
operating costs for chemical equipment, "maximum" and "mini-
mum" capital costs for retro-fitted thermal equipment, and
"maximum" and "minimum" operating costs and efficiency
losses for thermal equipment. The effects over the 1974-
1984 period of these technological uncertainties are sum-
marized in Table 2.5-1. The costs shown are the impact of
each assumption relative to the baseline "most-likely"
assumptions incorporated in Policy Alternative l(a).
Table 2.5-1
THE IMPACT OF POLICY ALTERNATIVES l(b)-l(g) RELATIVE
TO POLICY ALTERNATIVE l(a): SUMMARY DATA
Capitalized Operating
Expenditures Expenses
(billions of current dollars)
Chemical Cost Factors
Maximum
Thermal Retro-Fitting
Capital Costs
Maximum
Minimum
Thermal Operating Costs
and Efficiency Losses
Maximum
Minimum
$12.9
+ $ 6.1
- $ 2.8
+ $ 6.6
- $ 1.3
+ $ 2.9
+ $18.9
- $ 3.1
111-18-
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2.6 Guide to the Remainder of the Report
Further discussions of the policy alternatives
mentioned in this section and of other policy options sub-
mitted by the EPA for analysis by TBS are contained in
Sections 3 through 8. Section 3 projects and discusses
the major economic and financial variables for the electric
utility industry through 1990 under the assumption of no
chemical or thermal effluent controls either at the federal
level or at the state and local level. With this baseline
forecast as background, Section 4 turns to a detailed pro-
jection and analysis of Policy Alternative 1, the option
from which the EPA's final policy proposal evolved. Section
5 describes the economic and financial impact of each of
the EPA's seven primary policy options before consideration
of exemptions. Section 6 then discusses the impact of
exemptions on a selected subset of the seven primary policy
alternatives. Section 7 analyzes the implications of
pollution control requirements under a different set of
assumptions about the industry's future demand growth.
Section 8 concludes the report with a review of the impact
of alternative technological assumptions. Appended to the
report is a brief description of PTm, the computer model
used to generate the economic and financial projections
discussed in this report.
111-19-
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3, BASELINE ELECTRIC UTILITY INDUSTRY PROJECTIONS:
EPA POLICY ALTERNATIVE 0
3.1 Introduction
In order to discuss the economic and the
financial implications of the Act's proposed guidelines,
it is important to establish a point of reference from
which comparisons can be made. In doing so, the un-
certainties inherent in forecasting conditions within
the electric utility industry which are unrelated to
the Act can be segmented from those associated with
the Act. This reference point requires the establish-
ment of a set of baseline conditions, which will be
referred to as Policy Alternative 0 in later sections
wherein comparisons of specific policy alternatives
will be made. These baseline conditions exclude any
impact associated with existing state and local en-
vironmental standards, as well as federal standards
as specified in the Act and the Clean Air Act of 1970.
Thus, Policy Alternative 0 represents what utilities
would expend in the absence of environmental regula-
tions .
In the absence of the Act, existing thermal
and chemical pollution standards would remain in force.
Section 4.5 evaluates the economic impact of these
existing standards. While some might argue that these
federal, state and local standards should be included
III - 20 -
-------
in the baseline conditions, TBS believes that these
standards do not adequately reflect the water quality
standards which would be imposed in the absence of the
Act. Recent concern with environmental integrity sug-
gests that more stringent standards would have been en-
acted in some areas if federal legislation had not been
passed. On the other hand, the more recent "energy
crisis" has perhaps changed the balance between environ-
ment and energy conservation.
This analysis does not deal with the
economic impact and financial implications associated
with the Clean Air Act of 1970 due to a current lack
of detailed engineering and economic assessments. It
is anticipated that future analyses will include these
impacts.
111-21-
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3.2 Policy Alternative 0 Assumptions
Because the electric utility industry com-
prises both investor-owned ("private") and other ("public")
firms and because there are fundamental cash-flow dif-
ferences between those private firms allowed by their
regulatory commissions to normalize income tax expenses
and those private firms required to flow through the
benefits of accelerated depreciation and other tax
shields, PTm in fact arrives at industry estimates via
summation of the estimates for three separate industry
segments:
• publicly-owned 20 percent
• investor-owned, 48 percent
normalized accounting
• investor-owned, flow 32 percent
through accounting
Given t-he relative importance of the two types of
firms in the private sector and the paucity of cogent
information on the financial characteristics of the
public sector, the two segments of the private sector
are modelled in detail and together serve as a basis
for estimating certain characteristics of the public
sector.
"''These assumptions are those used in the preliminary
analysis provided to the TAC-Finance, National Power
Survey.
111-22-
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3.2.1 Growth in Generating Capacity. Perhaps
the most critical set of assumptions relate to the
rate of growth assumed for the electric utility in-
dustry in the period through 1990. Until the recent
"energy crisis." industry spokesmen assumed that the
current rate of growth which implied a doubling in
size each decade would continue through the 1970's
with a gradual decline during the 1980's. These assump-
tions have been incorporated into the baseline conditions
and the policy alternatives defined in Sections 4 and
2
5. Specifically, the growth in peak load demand as
measured in kilowatts is assumed to grow in the follow-
ing way:
• 1971 - 1980 7.2 percent per year
• 1981 - 1985 6.7 percent per year
• 1986 - 1990 6.6 percent per year
In addition to the growth in peak load demand, the
ensuing analyses assume that reserve margins will be
maintained at 20 percent and capacity load factors
at 51.4 percent.
2
The EPA recognized the need to assess the economic and
financial impact implicit in energy conservation;
therefore, Section 7 provides analysis of policy
alternatives in which peak load demand growth has
been limited to:
• 1971 - 1975 6.2 percent per year
• 1976 - 1980 5.7 percent per year
• 1981 - 1985 5.1 percent per year
» 1986 - 1990 4.4 percent per year
IH-23-
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In terms of industry growth, the above load
growth implies that generating capacity in the period
1970 through 1990 will be:
• 1970 324.6 million kilowatts
• 1975 459.6 million kilowatts
• 1980 650.6 million kilowatts
• 1985 899.8 million kilowatts
• 1990 1238.6 million kilowatts
The construction of new generating capacity
implicit in the above growth in peak load demand fore-
casts must also include the retirement of obsolete
fossil gene
the rate of:
3
fossil generating capacity assumed to be retired at
• 1971-1975 0.4 percent per year
• 1976-1980 0.7 percent per year
• 1981-1990 1.2 percent per year
While much publicity has preceded the con-
struction of nuclear-fueled generating plants, less
than 2.2 percent of the generating capacity in service
prior to 1971 was nuclear-fueled. Although environ-
mental and technical issues have delayed the conversion
to a nuclear-based electric utility industry, industry
spokesmen have assumed that the mix of generating
capacity additions will be:
_
Throughout the analysis based upon PTm, "fossil-fueled"
and "non-nuclear" will be used interchangeably to de-
scribe generating capacity which is not "nuclear-fueled,
In this context, hydro-electric generating capacity
would be defined as "fossil-fueled."
111-24-
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1971-1975 30 percent nuclear/70
percent non-nuclear
1976-1980 40 percent nuclear/60
percent non-nuclear
1981-1985 50 percent nuclear/50
percent non-nuclear
1986-1990 60 percent nuclear/40
percent non-nuclear
3.2.2 Growth in Cost Factors. In an effort to assess
the cost escalation facing the electric utility indus-
try, the TAC-Finance conducted an informal, industry-
wide survey of existing utility construction plans
through 1980. On the basis of this survey, the TAC-Finance
4
developed the cost growth factors detailed in Table
3.2-1. The post-1980 inflation rate of 5 percent was
then used as the basis for cost growth in other plant
and equipment, including nuclear fuel, as detailed in
Table 3.2-2.
Although the generating capacity, related
transmission/distribution equipment and nuclear fuel
placed in service in any given year is determined by
the load growth requirements, the construction work
begins several years prior to the in-service date.
Moreover, the cash flow associated with generating
plant additions generally precedes the completion of
construction. Changes in the related construction
4
It should be noted that throughout this report, all
dollar amounts will be specified in current dollars.
111-25-
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TABLE 3.2-1
GENERATING CAPACITY COST GROWTH
(expressed in current dollars)
1970 1975 1980 1985 1990
Nuclear Generating
Capacity
$ per kilowatt $ 150 $ 308 $ 457 $ 584 $ 745
% cost escalation
Inflation - 5.75% 5.65% 5% 5%
Other - 9.20% 2.40%
Non-Nuclear Generating
Capacity
$ per kilowatt $ 120 $ 199 $ 292 $ 372 $ 475
% cost escalation
Inflation - 5.60% 5.50% 5% 5%
Other - 4.70% 2.40%
Gas Turbine Generating
Capacity
$ per kilowatt $ 90 $ 118 $ 154 $ 197 $ 252
% cost escalation
Inflation - 5.60% 5.50% 5% 5%
Other - -
111-26-
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TABLE 3.2-2
OTHER PLANT AND EQUIPMENT COST GROWTH
(expressed in current dollars)
1970 1975
Nuclear Fuel
$ per kilowatt $ 38 $ 48
1980 1985 1990
$ 62 $ 79 $ 101
% cost escalation
Inflation - , \5% 5% 5% £
Other -
Transmission &
Distribution Equipment
$ per kilowatt $ 180 $ 230 $ 293 $ 374 $173
% cost escalation
Inflation - 5% 5% 5% 5%
Other _____
111-27-
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work in progress account historically constituted
a substantial portion of capital expenditures by the
electric utility industry.
In order to approximate the cash progress
payments related to construction requirements, the
TAC-Finance assumed the payment schedules outlined
in Table 3.2-3. For example, a $100 million nuclear-
fueled generating unit (with an additional $15 million
for nuclear fuel) placed in service in 1980 would re-
quire cash payments of:
Nuclear Nuclear
Plant Fuel
1976 $25 million
1977 25 million
1978 25 million
1979 25 million $15 million
1980
Likewise, a $100 million fossil-fueled generating
unit placed in service in 1980 and $100 million in
related transmission/distribution equipment would
require cash payments of:
Transmission/
Fossil Plant Distribution
1977 $ 25 million
1978 25 million
1979 25 million 050 million
1980 25 million 50 million
-------
- 29 -
TABLE 3.2-3
SCHEDULE OF CONSTRUCTION WORK IN PROGRESS CASH PAYMENTS
Capital Expenditures for Nuclear Generating
Capacity (and related pollution control equipment)
placed ir. service during Period T incurred by:
• Period T-l 100 Percent
• Period T-.2 75 Percent
• Period T-3 50 Percent
• Period T-4 25 Percent
Capital Expenditures for Non-Nuclear Generating
Capacity (and related pollution control equipment)
placed in service during Period T incurred by:
• Period T 100 Percent
• Period T-l 75 Percent
• Period T-2 50 Percent
• Period T-3 25 Percent
Capital Expenditures for Nuclear Fuel placed
in service during Period T incurred by:
• Period T-l 100 Percent
Capital Expenditures incurred for Transmission and
Distribution Equipment placed in-service during
Period T incurred by:
• Period T 100 Percent
• Period T-l 50 Percent
111-29-
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Regulatory agencies in the past have required
electric utilities to capitalize a portion of the fi-
nancing charges associated with the funds tied-up in
construction work in progress. In 1970, this allowance
for funds used during construction (AFDC) approximated
5.25 percent of construction work in progress (CWIP).5
In addition to capital expenditures, a pri-
mary target of cost inflation is the operations and
maintenance expenses which include expenditures for
fossil fuels. Prior to the recent "energy crisis,"
the cost growth for fossil fuels approximated 10
percent while operations and maintenance expenditures
for nuclear generation (excluding fuel) were relatively
stable. These patterns were expected to continue
through 1975 at which time cost escalation was assumed
to follow the industry level of 5 percent. Table 3.2-4
details those assumptions.^
3.2.3 Financial Policy Parameters. The instruments
employed to finance the expansion of the electric
utility industry depend largely upon the financial
policies of the electric utilities and the policies
of the governing regulatory agencies.
51972 Federal Power Commission data suggests that the
AFDC should be 7 percent of CWIP.
6Recent events within the oil industry suggest that the
cost of fossil fuels will greatly exceed those assumed
in this analysis.
Hi-30-
-------
TABLE 3.2-4
OPERATIONS AND MAINTENANCE GROWTH
(expressed in current dollars)
1970 1975 1980 1985 1990
Operations and
Maintenance Expenses:
Non-Nuclear Generating
Capacity
$ per kilowatt hour .70? 1.13? 1.44? 1.84? 2.34?
% cost escalation
Inflation - 10% 5% 5% 5%
Other - - -
Operations and
Maintenance Expenses:
Nuclear Generating
Capacity (excluding
fuel)
? per kilowatt hour .38? .38? .48? .61? .78?
% cost escalation
Inflation - - 5% 5% 5%
Other - - _
Hl-31-
-------
Throughout this analysis TBS has assumed
that the past policies of agencies which regulate the
electric utility industry will remain in force — specifi-
cally, the overall structure of the industry with respect
to the mix of public and private firms as well as the
proportion of states which require private firms to
employ flow through accounting procedures.
In addition, it is assumed that average
consumer charges per kilowatt hour will be set at
•7
levels which yield a 12 percent return on common equity.
Likewise, the future capital structure of
electric utilities has been assumed to remain relatively
stable. The mix of financing instruments for investor-
owned utilities is determined within PTm by the follow-
ing constraints upon their capital structure:
• long-term debt no more than 55 percent
• preferred stock no more than 10 percent
• common equity at least 35 percent
7It should be noted that this assumption is consistent
either with a target 12 percent return and no regula-
tory lag or a target rate in excess of 12 percent with
time lags in the regulatory process. In recent years
the actual return on common equity has been between
11 and 12 percent. Previous analysis by Drs. Pifer
and Tennican for the TAC-Finance has shown that vary-
ing the required rate of return on common equity, while
perhaps affecting the ease with which additional fi-
nancing can be obtained, has minimal impact upon the
amount of additional financing required.
111-32-
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In addition, a dividend policy which results in a
70 percent dividend payout ratio has been employed.
Historically, the average rate of interest
on long-term debt and the dividend rate on preferred
stock have been approximately the same. At the end
of 1970,the embedded rate for each was approximately
4.8 percent, a rate significantly below the existing
long-term rate of interest. Acknowledging this fact,
TBS has assumed a 7.5 percent interest rate and dividend
rate for preferred stock. Without a significant change
in the mix of financing instruments, the return on
common equity and/or the common stock dividend payout
ratio, these conditions wherein the marginal debts
rates exceed the embedded rates will result in lower
interest and preferred dividend coverage ratios.^
For the public sector, it is simply assumed
that 65 percent of total financing requirements will
be met from external sources.
3.2.4 Tax and Accounting Relationships. Internal
cash generation in an industry as capital intensive
as the electric utilities depends heavily upon the
accounting procedures employed. As previously men-
tioned, this analysis assumes that the electric
utility industry is segmented into public and investor-
8'For example, the assumptions implicit in Policy Al-
ternative 0 result in the interest coverage ratio,
defined as Earnings Before Interest Charges and In-
come Taxes divided by Interest Charges, declining from
3.335 in 1973 to 2.902 in 1990. The marginal impact
of the Act's effluent guidelines are insignificant.
111-33-
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owned firms with the latter group of utilities further
segmented into those which are required to use normal-
izing techniques and those which use flow through account-
ing procedures. While these alternative accounting practices
change significantly both the timing of cash flows resulting
from generating capacity additions and the revenues required,
the actual liberalized depreciation policies and investment
tax credits need not differ.
PTtn assumes straight-line depreciation
over 30 years for regulatory and financial accounting
purposes. Tax depreciation figures are the maximum
allowed and make use of the asset depreciation range
(ADR) and the double-declining balance depreciation
provisions within the tax code. An exception to the
above is nuclear fuel which is depreciation on a 3-
year, straight-line basis for both tax and regulatory
purposes. In addition, a 4 percent investment tax
credit is permitted on 80 percent of capital expenditures.
Taxes within PTm have been segmented into
federal (48 percent) and state (4 percent) income
taxes as well as additional taxes other than on in-
come which are assumed to approximate 11 percent of
revenue.9
An example of the reconciliation of taxes within
PTm is provided in Table 3.3-5.
111-34-
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3.3 Economic and Financial Consequences
of Policy Alternative 0
The assumptions detailed in Section 3.2
define the baseline conditions for the electric utility
industry and are not varied in Policy Alternatives 1
through 7 which also incorporate different sets of
proposed thermal and chemical effluent guidelines.
Table 3.3-1 provides selected summary
data obtained from the Policy Alternative 0 baseline
assumptions. Detailed PTm results for these same
baseline conditions can be found in Appendix A of
Economic and Financial Implications of the Federal Water
Pollution Control Act of 1972 for the Electric Utility
Industry, a TBS report submitted to the EPA on Sep-
tember 7, 1973 in fulfillment of Contract # 61-01-1582.
Tables 3.3-2 through 3.3-5 provide an example
of the level of detail within the investor-owned
sector which is captured by PTm.
Table 3.3-1 displays the detail which will
be presented for each policy alternative. In order
to better understand the specific definitions used,
a brief discussion of each variable follows:
• Capitalized Expenditures are the
sum of capital expenditures (in-
cluding the change in construction
work in progress ( A CWIP) and the
allowance for funds used during con-
struction (AFDC) in any given year.
For example, the 1977 capitalized
expenditures of $28.2 billion can be
segmented into:
• Private Sector $23.0 billion
-Capital Expenditures
for in-service plant $17.1
- A CWIP 4.2
-AFDC 1.7
111-35-
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Table 3,3-1
POLICY ALTERNATIVE 0
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1973
1977
1983
1990
Capitalized Expenditures:
Total for the Year
Total since 1973
$15.4
$28.2
93.8
$ 58.4
364.0
$121.1
968.1
H External Financing:
I
Total for the Year
Total since 1973
$9. 5
$19.1
64.1
$ 38.3
244.4
$ 76.5
624.8
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
$34.4
$16.0
$57.0
$26.6
$113.6
$48.6
$240.9
$95.4
Consumer Charges:
(cents/kwh)
Average for the Year
1. 91
2.40
3.19
4.32
*Excludes nuclear fuel expense
-------
TABLE 3.3-2
POLICY ALTERNATIVE 0
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED INCOME STATEMENT
(billions of current dollars)
Operating Revenue $ 90.9
-Operating and Maintenance Expenses $38.9
(excluding nuclear fuel)
-Taxes other than Income 10.0
-Depreciation (including nuclear fuel) 11.1
^Allowance for Interest on Construction
Work in Progress 3.7 56.3
Earnings Before Interest and Income Taxes $ 34.6
-Interest Charges 11.8
Earnings Before Income Taxes $ 22.8
-Income Taxes (State and Federal) $ 9.4
+Investment Tax Credits 0.8 8.6
Net Income 14.2
-Dividends on Preferred Stock $ 2.1
-Dividends on Common Stock 8.5 10.6
Retained Earnings $ 3.6
111-37-
-------
TABLE 3.3-3
POLICY ALTERNATIVE 0
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED BALANCE SHEET
BASELINE CONDITIONS - 1983
(billions of current dollars)
Asset Accounts
Gross Plant in Service $ 328.5
-Accumulated Depreciation 80.7
Net Plant in Service $247.8
Net Nuclear Fuel 4.0
Construction Work in Progress 71.0
Net Electric Plant $ 322.9
Net Working Capital (assumed to be constant) (0.5)
Total Assets $ 322.4
Liability and Equity Accounts
Deferred Tax Items $ 17.7
Long-Term Debt-outstanding prior to 1971 $ 27.0
-issued after 1970 140.6
Long-Term Debt - Total $ 167.6
Preferred Stock -outstanding prior to 1971 $ 6.9
-issued after 1970 23.6
Preferred Stock - Total $ 30.5
Owners' Equity -outstanding prior to 1971 $ 24.7
-cash issues after 1970 56.7
-retained earnings after
1970 25.2
'Owners' Equity - Total $ 106.6
Total Liabilities and Owners' Equity $ 322.4
111-38-
-------
TABLE 3.3-4
POLICY ALTERNATIVE 0
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED APPLICATIONS AND
SOURCES OF FUNDS
BASELINE CONDITIONS - 1983
(billions of current dollars)
Applications of Funds
Capitalized Expenditures
Non-Nuclear Generating Plant $7.6
Nuclear Generating Plant 11.9
Nuclear Fuel 1.6
Transmission and Distribution Equipment 15.3
Pollution Control Equipment 0.0
Increase in Construction Work in Progress 7.6
Total 44.0
Capitalization of Allowance for
Interest on Construction Work
in Progress during 1982 3.3
Refundings of Long-Term Debt 0.8
Total Applications $ 48.1
Sources of Funds
Internal Cash Generation ,
Retained Earnings $ 3.6
Depreciation (including
nuclear fuel) 11.1
Deferred Tax Items 2.1
Total $ 16.8
External Financing
Long-Term Debt $19.6
Preferred Stock Issues 3.4
Common Stock Issues 8.3
Total $ 31.3
Total Sources $ 48.1
111-39-
-------
TABLE 3,3-5
POLICY ALTERNATIVE 0
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED RECONCILIATION OF TAXES
BASELINE CONDITIONS - 1983
(billions of current dollars)
Earnings Before Income Taxes: Reported
-Accelerated Depreciation
-Allowance for Interest on Construction
Work in Progress
Earnings Before Income Taxes: Tax Base
Income Taxes: Paid
-Investment Tax Credits (Actual)
+Deferred Tax Items
+Investment Tax Credits (Amortized)
Income Taxes: Reported
$ 4.6
3.7
$ 22.8
8.3
0.4
2.1
0.1
$14.5
$ 7.6
1.8
$ 9.4
-------
Public Sector
-Capital Expenditures
for in-service plant
- £ CWIP
$ 5.2 billion
$ 4.3
0.9
External Financing Requirements are the
sum of long-term debt, preferred stock
and common equity stock issues in any
given year, including the refinancing
of maturing long-term debt.10 pOr ex-
ample, the 1977 external financing
requirements of $19.1 billion can be
segmented into:
Private Sector
-New Long-Term
Debt $9.1
-Maturing Long-
Term Debt 1.0
-Preferred Stock
Issues 1.6
-Common Stock
Issues 4.0
Public Sector
$15.7 billion
$ 3.4 billion
The difference between capitalized
expenditures and external financing
requirements in any given year is
the amount of funds generated in-
ternally in the form of retained
earnings, depreciation and tax
deferrals.
Operating Revenues are those required
to yield a 12 percent rate of return
on common equity. For example, the
1977 operating revenues are estimated
to be $57.0 billion.
10
A schedule of long-term debt refundings through 1990
has been estimated from published sources and in no
year exceeds $1.7 billion. Further, PTm assumes
that no new long-term debt issues will mature prior
to 1990.
111-41-
-------
Operations and Maintenance Expenses
include those items so defined by the
Federal Power Commission in its
Statistics of Pr-jvately Owned Eleotr-i-o
Utilities in the United States with the
exception of nuclear fuel. For example,
the 1977 operations and maintenance
expenses are estimated to be $26.6
billion.
Consumer Charges are the average amount
per kilowatt hour which is being paid
in any given year. The amount of elec-
trical energy consumed is based upon
the growth in peak load demand,, the re-
serve margin and the capacity load factor
For example, the 1977 electrical energy
amount of 2378.0 billion kilowatt hours
is obtained from
• 1970 peak load demand of
270.5 million kilowatts;
• Growth in peak load demand
1970-1977 of 7.2 percent per
year;
• Reserve margin of 20 percent;
• Capacity load factor of 51.4
percent; and
• 8760 hours per year.
The actual numerical calculation is (270.5
million kw)* (1.072)7 * (1.20) * (0.514) *
(8,760 h) = 2378 billion kwh.
The average consumer charge per kilowatt
hour is obtained by dividing operating
revenues by the total electrical energy
consumed. For example, the average con-
sumer charge for 1977 is estimated to be:
$57.0 billion = 2.40?/kwh
2378 billion kwh Y/
111-42-
-------
The summary data for Policy Alternative 0
indicate the magnitude of growth which the electrical
utility industry will undergo during the period 1974-
1990. Even without the added expenditures required
to meet the Act's effluent guidelines, the industry
is expected on an annual basis to expand:
• Capitalized Expenditures 13 percent
• External Financing Re-
quirements 13 percent
• Operating Revenues 12 percent
• Operations and Maintenance
Expenditures 11 percent
• Consumer Charges 5 percent
The rapid growth in both capitalized expen-
ditures and external financing requirements reflects the
effects of the assumed growth in peak load and cost
factors. The slightly lower rate of growth in opera-
ting revenues results from the time lag between capital
outlays and the associated cost burden passed on to the
consumer. The industry's conversion to nuclear-based
generation is the primary factor in holding down the
rate of growth in operations and maintenance expendi-
tures to 11 percent. Finally, the relatively small
increase in the average consumer charge per kilowatt
hour closely parallels the underlying long-run rate
of inflation.
111-43-
-------
4, ELECTRIC UTILITY INDUSTRY PROJECTIONS:
EPA POLICY ALTERNATIVE 1
4.1 Introduction
Section 3 of this report specified a set
of baseline conditions which do not include the costs
associated with the Act's effluent guidelines; the remaining
analyses deal with alternative sets of proposed effluent
guidelines. Section 4 concentrates upon Policy Alternative
1, a set of conditions which were referenced in a previous
TBS report to the EPA as combining:
"...the "most-likely" estimates of the
capital and operating costs for both
thermal and chemical pollution control
equipment and their impact upon opera-
ting efficiencies with the "maximum"
coverage levels anticipated to repre-
sent the "most-likely" set of circum-
stances with environmental-related
costs."1
Eoonomic and Financial Implications of the Federal Water Pollution
Control Aat of 1972 for the Eleetrie Utility Industry (September 1973);
page4-2, Policy Alternative 1 is identical to Case X in
the previous report and differs from Case I only by in-
cluding the addition of new source pollution control
equipment during the 1984-1990 period. TBS has described
Policy Alternative 1 in greater detail than other policy
alternatives in order to provide continuity between re-
ports. This extensive coverage, therefore, should not
imply that Policy Alternative 1 is the preferred option.
Ill - 44 -
-------
4.2 Policy Alternative 1 Assumptions
To estimate the operational impacts of com-
pliance with the Act, the EPA has specified water effluent
guidelines for both thermal and chemical pollutants. In
order to provide a basis from which to properly eval-
uate the alternative policies proposed for effluent
guidelines, TBS has divided Policy Alternative 1 into
its two components:
• Policy Alternative 1-T which
provides the economic and financial
implications for only the thermal
standards; and
• Policy Alternative 1-C which sum-
marizes the consequences for only
the chemical standards.
4.2.1 Thermal Assumptions. The thermal requirements
specified by the EPA stipulate that:
• All fossil or nuclear-fueled base-
load generating plants (defined as
those plants with a capacity load
factor in excess of 60 percent)
which will not be retired prior to
July 1983 , must have closed-cycle
cooling systems installed by July
1977.
• All fossil or nuclear-fueled
cyclic generating plants (defined
as those plants with a capacity
load factor between 20 and 60 per-
cent ) which will not be retired
prior to July 1989 , must have closed-
cycle cooling systems by July 1983 •
111-45-
-------
• All fossil or nuclear-fueled
generating plants placed in
service after July 1977 must
have closed cycle cooling systems.
The standards applicable to generating units
placed in service prior to 1971 have been estimated by
the EPA to require 40 percent of the fossil capacity and
80 percent of the nuclear capacity to be retro-fitted
with pollution control equipment by 1977. These existing
source standards also require that 52 percent of the
fossil capacity and 67 percent of the nuclear capacity
brought in service during the 1971-1973 period will be
retro-fitted by 1977. The installation schedule for this
retro-fitted equipment is:
• 1974 15 percent
• 1975 20 percent
• 1976 25 percent
• 1977 40 percent
The EPA has further estimated that an additional
9 percent of total pre-1971 fossil capacity is cyclic and
will need to be retro-fitted by 1983. The installation
schedule for the pollution control equipment required on
these existing cyclic plants is:
• 1978 10 percent
• 1979 10 percent
• 1980 20 percent
111-46-
-------
• 1981 20 percent
• 1982 20 percent
• 1983 20 percent
Of fossil and nuclear plants brought in
service during the 1974-1977 period, 89 and 100 per-
cent, respectively, are required to be fitted with
closed-cycle cooling systems. In the case of fossil
plants, 52 percent of capacity will be retro-fitted
by 1977 in accordance with the installation schedule
described above for existing base-load plants; the
other 37 percent will be incorporated in new plants
during their construction at lower costs and will in-
volve cash outlays on the same time schedule. In the
case of nuclear plants, 67 percent of those brought
in service for the 1974-1977 period will be retro-
fitted, and 33 percent will have pollution control
equipment incorporated during the plant construction
process.
Standards applicable to plants brought in
service after 1977 are assumed by the EPA to affect
73 percent of fossil capacity and 100 percent of nuclear
capacity. All required pollution control equipment
will be incorporated during the plant construction
process.
The coverage and time phasing of pollution
controls assumed in Policy Alternative 1 are repro-
duced in Table 4.2-1.
111-47-
-------
Table 4.2-1
POLICY ALTERNATIVE 1
COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Generating Capacity
In-S'*rvioe Date
Pollution Control Equipment
In-Service Date
________ .__
PCE Incorporated
in New Plants
__ _________
PCE Retro-Fitted
in Existing Plants
_______ ___
PCE Incorporated
in New Plants
___ __ ___
PCE KctroFitted
in Existing Plants
Before 1P7I
Hy 1377*
Hv 10(13**
40%
9%
80%
1971-1973
1974-1977
Hy 1977*
liv 1SI77*
37%
52%
52%
33%
67%
67%
oo
1973-UH>0
1078-1990***
73%
1007.
•T e in-t.iH.itton srhrdulr for equipment ri-quirod by 1977 is: 1974 - 15%: 1975 - 20%; 1976 - 25%; and 1977 - 40%.
•••'• o in-tJH.itu.r-. scli-dulo for equipment required by 1983 Is: 1978 - 10%; 1979 - 10%; 1980 - 20%; 1981 - 20%; 1982 - 20%; and 1983 - 20%.
*M' >!luiiop control equipment to he functioning a.s of the plant's in service date; cash outlays for this pollution control equipment follow the
s.irie schedule as those for the cener.itin.F rapacity. See Section 3 for details.
-------
These guidelines will impact more than one
billion kilowatts of generating capacity during 1974-
1990. The 1977 guidelines will affect 235 million
kilowatts of fossil-fueled and 70 million kilowatts
of nuclear-fueled generation. Thus, nearly 58 per-
cent of the generating capacity placed into service
by 1977 will require cooling facilities.
By 1983, an additional 145 million kilowatts
of fossil-fueled and 132 million kilowatts of nuclear-
fueled generating capacity will require cooling facil-
ities, increasing the level of coverage to nearly 74
percent. The remainder of the capacity impacted is
that brought in service during 1984-1990 and brings
the overall coverage to more than 80 percent.
The installation of cooling facilities
will require the construction of additional capacity
to generate power to operate the cooling towers and to
make up for the loss of efficiency due to the increase
in turbine back-pressure. This capacity loss, based
upon a 1 percent loss for running the cooling units
and an additional 2 percent due to increased back-
pressure, will approximate 9.1 million kilowatts
by 1977, an additional 8.4 million kilowatts by 1983.
and an additional 13.2 million kilowatts by 1990. To
meet these added generating requirements, the EPA
has assumed that the 1977 guidelines will be met
through the construction of gas-turbine peaking units
111-49-
-------
at a 1970 cost of $90 per kilowatt. The EPA further
assumes that the electric utilities should be able to
construct base-load generating plants to replace addi-
tional capacity losses by 1978.
In order to meet the thermal standards in-
cluded in Policy Alternative 1, the EPA has estimated
that nearly 1,614 trillions of Btu's will be expended
to operate the cooling facilities. This estimate is
based upon the following assumptions:
2
• 60 percent average load factor;
• 8,760 hours per year; and
• 10,000 Btu's burn per hour of
operation•
In addition to the above-mentioned levels
of thermal coverage, the EPA has provided detailed cost
estimates for construction and operation of the cooling
facilities. These estimates, summarized in Table 4.2-2,
specify different capital expenditures for new source
and back-fitted units as well as varying operating ex-
penses between the 1977 and 1983 guidelines.
The thermal effluent guidelines outlined
herein do not include the additional capital expen-
ditures which might be required to maintain adequate
capacity reserve margins while generating capacity is
removed from service for installation of cooling units.
2The 60 percent load factor was used in place of the EPA
assumptions of a 30 percent load factor for retro-fitted
capacity, and a 60 percent load factor for fossil-fueled
and a 70 percent load factor for nuclear-fueled capacity
additions which are required to have a closed-cycle
cooling system.
111-50-
-------
Table 4.2-2
CAPITAL AND OPERATING COSTS
THERMAL GUIDELINES
Capital Expenditures ($/kw)
for Back-Fitted Units
for New Units
Annual Operating Expenses ($/kw)
installed by 1978
installed by 1978-1990
Non-Nuclear
Capacity
15.00s
7.50
42.00
15.00
Nuclear
Capacity
18.00
10.00
42.00
12.00
Capacity Losses
due to Running Cooling Units
due to Increased Back Pressure
1%
2
1%
2
*A11 costs are specified at 1970 levels. Cost escalation occurs at the inflation rates
projected for each type of generating capacity in Table 3. 2-1.
**Annual operating expenses associated with the Act will be incurred only by tnose
plants required to install cooling facilities and only in amounts to offset operating
inefficiencies.
-------
Assuming that historical capacity reserve margins can-
not be reduced, the ability of the industry to absorb
these capacity losses without the purchase of additional
generating equipment depends upon, among other things,
the seasonal patterns of demand. Under the best of
circumstances, highly seasonal patterns of demand, per-
haps no additional capacity would be required. Because
information not available to TBS would be required to
assess the economic impact of these downtime periods,
estimates of outage have been excluded from this report
and are an area of possible further analysis.
4.2-2 Economic and Financial Consequences of
Thermal Assumptions. The economic impact of
these coverage levels and the costs associated with
the thermal guidelines can be obtained from Table
4.2-3. This exhibit captures the level of detail
which will be presented for each policy alternative
that includes thermal pollution standards. In addition
to the summary data detailed in Section 3.3, operating
inefficiencies are provided in the form of energy and
capacity losses.
The actual consequences of the previously
specified assumptions can be directly obtained by com-
paring Tables 3.3-1 and 4.2-3 and recording the dif-
ferences. For example, the capitalized expenditures
between 1974-1990 increased by $41.5 billion ($1,009.6
minus $968.1) as a direct result of the addition of
cooling facilities as prescribed in Policy Alternative
1. These added expenditures will be partly financed
111-52.
-------
Table 4.2-3
POLICY ALTERNATIVE 1-T
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Expenditures;
External Financing:
Operating Revenues;
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$ 31.4
105.0
$21.7
73.4
$58.9
$27.3
$ 60.6
384.6
$ 39.7
259.9
$117.3
$49.8
$ 125.4
1.009.6
$ 79.3
652.9
$248.2
$97.4
Consumer Charges:
(cents /kwh)
Average for the Year
2.48
3.30
4.45
Energy Losses:
(trillions of Btu's)
Total for the Year
478.3
919.8
1.613.6
Capacity Losses:
(millions of kw )
Total since 1973
9. 1
17.5
30.7
*Excludes nuclear fuel expense
-------
by $28.1 billion in external financing with the
remainder generated internally. The additional require-
ments will increase operating revenues by $7.3 billion
and operations and maintenance expenses by $2.0 billion in
1990. Finally, the consumer will be required to share
the burden in the form of higher charges for the use of
electricity:
• in 1977 0.08£/kwh (3.3 percent)
• in 1983 0.11£/kwh (3.4 percent)
• in 1990 0.13£/kwh (3.0 percent)
While the relative increase is only 3 percent in 1990,
these incremental charges result in an increase in
revenues required by the previously mentioned $7.3
billion in 1990.
4.2-3 Chemical Assumptions. The Act specifies stan-
dards for both chemical and thermal water pollution; how-
ever, the EPA has requested that TBS place primary focus
upon the thermal guidelines. The following set of
assumptions for chemical effluent standards have been
utilized in each policy alternative analyzed in Section
5. Limited analysis of alternative capital and operating
cost assumptions for chemical effluent standards is pro-
vided in Section 8.
The chemical requirements as stipulated
by the EPA differ somewhat in concept from the pre-
vious specification of thermal guidelines. The 1977
guidelines require compliance by 1977 and cover:
111-54-
-------
• 81.5 percent of pre-1971 fossil-
fueled capacity;
• 88.8 percent of fossil-fueled
additions placed in service during
1971-1977; and
• 100 percent of nuclear-fueled
generating capacity placed in
service by 1977.
The capital and operating costs associated with these
chemical guidelines are summarized in Table 4.2-4.
By 1983, more stringent chemical pollution
control has been stipulated. For example, nuclear
capacity operating by 1977 will require $.85 in capital
expenditures and $.50 per year in operating costs
per kilowatt to meet the 1977 guidelines. By 1983
additional controls will require that another $2.75 per
kilowatt be expended in capital expenditures while
annual operating expenses are increased to $.85 per
kilowatt. All of the above chemical capital and
operating cost estimates are specified at 1970 levels
and must be inflated at the relevant rates provided
in Section 3.2. The coverage levels remain the same
for pre-1978 capacity and closed-cycle requirements
are imposed upon 73.3 percent of fossil-fueled addi-
tions and all nuclear units placed in service after
1977.
4.2-4. Economic and Financial Consequences of
Chemical Assumptions. The economic impact
associated solely with the chemical guidelines stip-
ulated by the EPA can be obtained from Table 4.2-5.
111-55-
-------
Table 4. 2-4
CAPITAL AND OPERATING COSTS
CHEMICAL GUIDELINES
1977 Guidelines
H
H
H
I
I
Capacity Placed in Service:
Prior to 1971
Capital Expenditures
Annual Operating Expenses
1971-1977
Capital Expenditures
Annual Operating Expenses
Non-Nuclear
Capacity
1.95*
0.85
1.05
0.55
Nuclear
Capacity
($/kw)
0.85
0.50
0.85
0.50
(continued)
-------
Table 4 .2-4 (continued)
1983 Guidelines
M
M
H
I
Oi
Capacity Placed in Service:
Prior to 1971
Additional Capital Expenditures
Additional Annual Operating Expenses
1971-1977
Additional Capital Expenditures
Additional Annual Operating Expenses
1978-1983
Capital Expenditures
Annual Operating Expenses
Non-Nuclear
Capacity
<$/kw)
3.35
0.65
2.75
0.35
2.60
0.25
Nuclear
Capacity
<$/kw)
2.75
0.35
2.75
0.35
2.00
0.20
*A11 costs are specified at 1970 levels. Cost escalation occurs at the inflation rates projected
for each type of generating capacity in Table 3. 2-1.
-------
Table 4. 2-5
POLICY ALTERNATIVE 1-C
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Ln
03
Capitalized Expenditures:
F-xtorru'l Financing:
Total for the Year
Total since 1973
Total for the Year
Total since 1973
$28.9
96.0
$19.7
65.8
$ 59.3
370.5
$ 38.8
249.0
$121.7
976.9
$ 76.7
630.2
Operating He-venues:
Total for the Year
$57.6
$115.8
$244.1
Operations & Maintenance Expenses:*
Total for the Year
$27.1
$49.8
$97.3
Consumer Charges:
(cents/kwh)
Average for the Year
2.42
3.25
4.38
*Fxcludes nuclear fuel expense
-------
A comparison of Tables 3.3-1 a.nd 4.2-5 shows that the cap-
italized expenditures between 1974-1990 will increase by
$8.8 billion as a direct result of the chemical guidelines.
These expenditures will be financed by $5.4 billion in ex-
ternal financing and an incremental $3.4 billion generated
internally. These additional internal funds result in part from
an increase in retained earnings, in part from increased
depreciation and tax deferrals. The net effect of these
chemical guidelines on the consumer results in the
following increases in average charges for electricity:
• in 1977 0.02£/kwh (0.8 percent)
• in 1983 0.06£/kwh (1.9 percent)
• in 1990 0.06£/kwh (1.4 percent)
111-59-
-------
4.3 Economic and Financial Consequences
of Policy Alternative 1
Table 4.3-1 provides selected summary data
obtained from an evaluation of Policy Alternative 1
and combines the economic consequences of both thermal
and chemical effluent guidelines implicit in Tables
4. 2-3 and 4.2-5 .
The short-term impact of the Act's thermal
and chemical water pollution control requirements
through 1977 is a 14 percent increase in capitalized
expenditures and requires a more than proportionate
increase of 17 percent in external financing require-
ments. In the long run, the overall impact for both
of these measures ranges from 5 to 5i percent. Through-
out the period 1974-1990 operating revenues, operations
and maintenance expenses and consumer charges increase
at approximately 4 to 44 percent with a peak in the
early 1980's of 5 to 54 percent. This intermediate
peak in the burden passed on to the consumer results
from the rapid increase in capitalized expenditures
and external financing required to meet the 1977
guidelines.
Tables 4.3-2 through 4.3-4 summarize for
1977, 1983 and 1990 the relative impact due to thermal
and chemical standards. During the 1974-1990 period,
more than 80 percent of the related capitalized ex-
penditures ($41.5 billion out of $50.3) and external
financing requirements ($28.1 billion out of $33.5)
can be attributed to cooling equipment. On the other
hand, chemical standards account for nearly 50 percent
111-60-
-------
Table 4.3-1
POLICY ALTERNATIVE 1
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1033
3900
M
M
M
I
M
.R lie venues:
>!,.••: & ?.i.'iintenr>ncc Expenses:
Total for the Year
Total since 1973
Total for the Year
Total since 1073
Total for the Year
Total for the Year
$ 32. 1
107.2
$22. 3
73. 1
$59.5
$27.8
$ 61.5
391. 1
$ 40.2
2G4. 5
$119.5
$51.0
$ 126.0
1, 01S.4
$ 70. 5
638. 3
$251.4
$99. 3
r Charges:
Average for the Year
2.50
3.36
4.51
i ! ! u>n:, <>l lit u's)
Total for the Year
478.3
919.8
1,613.6
i:on.'-: of k\v
Total since 1973
9.1
17.5
30. 7
KxH-i''"<- nuclear fuel c:-:pcnR
-------
Table 4. 3-2
POLICY ALTERNATIVES 0 AND 1
ECONOMIC AND FINANCIAL CONSEQUENCES: 1977 SUMMARY
(dollar figures in billions of current dollars)
Capitalized Expenditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses;*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
Policy
Alternative
0
$28.2
93.8
$19.1
64.1
$57.0
$26.6
Added
Thermal
Requirements
+3.2
+ 11.2
+2.6
+9.3
+1.9
+0.7
Added
Chemical
Requirements
+0.7
+2.2
+0.6
+1.7
+0.6
+0.5
Policy
Alternative
1
$ 32.1
107.2
$22.3
75.1
$59.5
$27.8
Consumer Charges:
(cents /kwh)
Average for the Year 2.40
+0.08
+0.02
2.50
Energy Losses:
(trillions of Btu's)
Total for the Year
+478.3
478.3
Capacity Losses:
(millions of kw )
Total since 1973
+ 9.1
9.1
*Excludes nuclear fuel expense
-------
Table 4.3-3
POLICY ALTERNATIVES 0 AND 1
ECONOMIC AND FINANCIAL CONSEQUENCES: 1983 SUMMARY
(dollar figures in billions of current dollars)
U>
I
('amtn Ii7.«'d Kxpcnditurcs :
Ext-.-rr.nl Financing:
Operating
Opi-r.itinns & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
Policy
Alternative
0
$ 58.4
364.0
$ 38.3
244.4
$113.6
$48.6
Added
Thermal
Requirements
+2.2
+20.6
+ 1.4
+ 15.5
+3. 7
+ 1.2
Added
Chemical
Requirements
10.9
+6.5
+0.5
+4.6
+2.2
+ 1.2
Policy
Alternative
1
$ 61.5
391. 1
$ 40.2
264.5
$119.5
$51.0
Consumer Charge's:
(cr-nt-i/kwh)
Average for the Year 3. 19
+0.11
+0.06
3.36
Knerpy Losses:
I c i-1 1 I t • > n s "I Utu's)
Total for the Year
+919.8
919.8
Capacity l.onsi'S:
(millions of kw )
Total since 1973
+ 17.5
17.5
S nuclear fuel expense
-------
Table 4. 3-4
POLICY ALTERNATIVES 0 AND 1
ECONOMIC AND FINANCIAL CONSEQUENCES: 1990 SUMMARY
(dollar figures in billions of current dollars)
Policy
Alternative
0
Added
Thermal
Requirements
Added
Chemical
Requirements
Policy
Alternative
1
M
l-l
M
I
Kxpcnditures:
1 External Financing:
Total for the Year $121.1
Total since 1973 968.1
Total for the Year $ 76. 5
Total since 1973 624. 8
+4.3
+41.5
+2.8
+28.1
+0.6
+8.8
+0.2
+5.4
$ 126.0
1.018.4
$ 79.5
658.3
Oppr.-iting Revenues:
Total for the Year
$240.9
+7.3
+3.2
$251.4
Op«'rations A Maintenance Expenses:
Total for the Year
$95.4
+2.0
+1.9
$99.3
Cnns'imor Charges;
(centrf/kwh) .
Average for the Year 4. 32
+0. 13
+0.06
4.51
Energy Losses:
( l r i ! 1 11 n'.s o i [it u s)
Total for the Year
+1.613.6
1.613,6
Cap.'icitv Losses:
(millions of kw )
Total since 1973
+30.7
30.7
Kxr!u:i<>< nuclear fuel expense
-------
of the increase in operations and maintenance expenses
($1.9 billion out of $3.9 billion). About 30 percent of the
incremental charges passed on to the consumer (.06£/kwh
out of .19£/kwh) are directly related to chemical pollu-
tion control. These chemical guidelines will remain
unchanged throughout Policy Alternatives 1 through 7.
111-65-
-------
4.4 Financing Implications of Policy
Alternative 1
Policy Alternative 1 assumptions imply that
the electric utility industry will spend $84.7 billion
during the period 1974-1990 to comply with the chemical
and thermal effluent guidelines of the Act. Of this
amount, 69.8 percent ($59.1 billion) corresponds to
the thermal guidelines; the remainder ($25.6 billion)
represents costs associated with the chemical guide-
lines. During the period 1974-1990, 59.4 percent of
the expenditures ($50.3 billion) have been capitalized;
the remainder ($34.4 billion) is the operating expenses
incurred during the 1974-1990 period.
The financial burdens associated with
meeting the proposed effluent guidelines are shared
among the following:
• capital markets in the form of
increased external financing require-
ments — long-term debt, preferred
stock, and common stock issues;
• consumers in the form of increased
charges for electrical power; and
• government in the form of reduced
tax receipts because of reductions
in taxable income.
Of the total capitalized expenditures
of $50.3 billion, $41.2 billion (81.9 percent) are
attributable to the investor-owned utilities and $9.1
billion to the public sector. Of the investor-owned
expenditures;
UI-66-
-------
• $16.9 billion (41.0 percent) will
be financed by long-term debt,
• $3.1 billion (7.5 percent) by
preferred stock issues;
• $7.3 billion (17.7 percent) by
common stock issues,
• $3.3 billion (8.0 percent) by
retained earnings; and
• $10.6 billion (25.7 percent) by
non-cash charges against income.
Of the publicly owned financing requirements, 35
percent are assumed to be generated internally ($3.1
billion) with the remainder obtained from external
sources ($6.2 billion).
111-67-
-------
4.5 Pol icy Alternative 0-T
The analysis of the economic impact and
financial implications resulting from the thermal and
chemical pollution control assumptions contained in
Policy Alternative 1 ignores the effect of existing
standards. If one desired to measure the incremental
impact due solely to the Water Pollution Control Act
of 1972, one would need to reduce the impacts detailed
for Policy Alternative 1 by the amounts that would be
spent on pollution control equipment to meet existing
federal, state and local standards.
In order to assess the impact of these
existing standards, the EPA has requested the analysis
of Policy Alternative 0-T which corresponds to Policy
Alternative 0 with the addition of existing thermal
standards. Therein, the EPA has assumed that the coverage
levels associated with existing pollution control
standards would be:
• prior to 1974 no coverage
• 1974 to 1977 89 percent (fossil)
100 percent (nuclear)
• 1978 to 1990 73 percent (fossil)
100 percent (nuclear)
These post-1973 coverage levels correspond to those
assumed to be effective with the Act.
While the coverage levels may be identical, the
capital costs and generating inefficiencies required to
comply with existing legislation are significantly lower
than those associated with the Act.
Hl-68-
-------
The capital expenditures required for fossil-
fueled equipment would have been $3.90 per kilowatt and
$5.50 per kilowatt for nuclear-fueled generating capacity.
These expenditures compare with $7.50 and $10.00 per
kilowatt required by the Art for fossil and nuclear-
fueled additions, respectively. In addition, no retro-
fitting of generating capacity installed prior to 1974
would be required.
The inefficiencies associated with operating
the cooling equipment specified by the Act was esti-
mated to lower generating capacity by 3 percent. The
capacity losses associated with the existing standards
have been estimated by the EPA to reduce operating efficiency
by 0.7 percent. The cost of operating these cooling
facilities is the same as the cost of the new units installed
as a response to the Act's guidelines.
Table 4.5-1 provides the selected summary
data obtained from an evaluation of existing thermal
pollution control requirements. These requirements
when compared to Policy Alternative 1 provide an es-
timate of the incremental impact of the Act's standards.
Table 4.5-2 provides a 1990 summary of the relative
impacts due to thermal and chemical standards when
Policy Alternative 0-T replaces Policy Alternative 0
as the baseline.
111-69-
-------
Table 4.5-1
POLICY ALTERNATIVE 0-T
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Kxpcnditures:
Total for the Year
Total since 1973
$28.8
95.5
$ 59.3
369.3
$122.6
980.3
O
External Financing:
Operating Revenues:
Operations &. Maintenance Expenses:*
Consumer Charges:
(cents/kwh)
Total for the Year $19.4
Total since 1973 65.3
Total for the Year $57.1
Total for the Year $26.6
Average for the Year 2.40
$ 38.8
248.4
$114.3
$48.8
3.21
$ 77.5
633.7
$242.5
$95.6
4.35
Kncrgy Losses:
( I ri 11 ions ol Btu's )
Total for the Year
47.3
136.7
304.9
Capacity Losses:
(millions of kw /
Total since 1973
0.9
2.6
5.8
''KxrhxU'S nuclear fuel expense
-------
Table 4. 5-2
POLICY ALTERNATIVES 0-T AND 1
ECONOMIC AND FINANCIAL CONSEQUENCES: 1990 SUMMARY
(dollar figures in billions of current dollars)
C 'a nit.nl 17 rd !• xpenditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
Consumer Charges:
(ccnts/kwh)
Knercv Losses:
(trill nm.s of IH u 's>
Cnpnoitv Losses:
(millions of kw )
Policy
Alternative
0-T
Total for the Year $122.6
Total since 1973 980. 3
Total for the Year $ 77. 5
Total since 1973 633.7
Total for the Year $242. 5
Total for the Year $95. 6
Average for the Year 4. 35
Total for the Year 304. 9
Total since 1973 5.8
Added
Thermal
Requirements
+2.8
+29.3
+ 1.8
+19.2
+5.7
+1.8
+0.10
+ 1.308.7
+24.9
Added
Chemical
Requirements
+0.6
+8.8
+0,2
+ 5.4
+3.2
+ 1.9
+0.06
Policy
Alternative
1
$ 126.0
1.018.4
$ 79.5
658.3
$251.4
$99.3
4.51
1.613.6
30.7
*K>
nuclear fuel expense
-------
5, OVERVIEW OF EPA POLICY ALTERNATIVES
BEFORE EXEMPTIONS
5.1 Introduction
Analyses paralleling that of Policy Alter-
native 1, which was described in detail in Section 4,
were performed for a total of seven major policy al-
ternatives. Section 5 is an overview of the results
of these analyses. As in Section 4, each policy alter-
native is examined in terms of its potential impact
before consideration of exemptions possibly available
under Section 316(a) of the Act. The effects of ex-
emptions are discussed in Section 6 of this report.
The primary policy alternatives differ from
one another only in the coverage and time phasing of
thermal pollution control requirements; all seven pol-
icy options presume the same chemical pollution stan-
dards and costs. Section 5, therefore, focuses on the
different thermal effluent guidelines assumed in each
of the seven primary policy options and on the overall
economic and financial implications for each of the
policy alternatives. The chemical pollution control
requirements assumed in each alternative are those
that were discussed in detail for Policy Alternative 1,
It should be emphasized that, because the
purchase cost per kilowatt of cooling equipment is
assumed to increase over time, delays in the imple-
mentation of any given level of coverage increase the
III- 72 -
-------
total capital expenditures associated with the coverage
policy. Moreover, because there are differences between
the costs of new and retro-fitted equipment, whether a
particular unit of capacity is required to meet standards
as of its in-service date or as of a later date affects the
eventual total amount of capital expenditures for cooling
equipment.
Policy Alternative 1 can be viewed as the
base from which emerged all the other policy alterna-
tives submitted by the EPA for economic and financial anal-
ysis by TBS. Each of these alternative policies for
controlling thermal water pollution differs somewhat in:
• the time schedule for retro-fitting
cooling equipment on existing source
generating units;
• the first year (or years, if fossil
and nuclear are treated differently)
that plants newly coming into service
are required to have closed-cycle
cooling systems; and
• the requirement that all peaking units
brought into service prior to 1971 have
closed-cycle cooling systems.
The date at which new source standards are in
effect imposed is one key difference between the various
policy alternatives. The Act states that plants on
which construction is begun after the publication of EPA
regulations must have closed-cycle cooling systems in operation
as of their in-service dates. These new source standards
are assumed in all policy options to be applicable to
fossil capacity coming into service in 1979 or later and
to nuclear plants coming into service in 1982 or later.
In addition, Policy Alternative 1 requires closed-cycle
cooling equipment on all generating capacity placed in
service in 1978 or later.
Hl-73-
-------
Some other policy alternatives assume that the
installation of the thermal pollution control equipment
on capacity other than that defined as new source by the
Act, i.e., that capacity on which construction is begun
after the publication of regulations, is delayed until
1983.
The pre-1974 plants which are currently oper-
ating without closed-cycle cooling systems and the
plants which will come into service in 1974 or later
without such systems are also treated in significantly
different ways in the seven primary policy options.
Policy Alternative 1 specifies that the vast majority of
these plants be fitted with pollution control equipment
by 1977. Most of the other policy alternatives delay
the bulk of the retro-fitting until 1983. Some policy
alternatives assume that plants coming into service in the
1974-1977 period which have been designed to incorporate
closed-cycle cooling systems will have such systems completed
by 1977.
111-74-
-------
5.2 Policy Alternative 1
Briefly to recapitulate the thermal require-
ments discussed in Section 4, Policy Alternative 1
stipulates that :
All fossil or nuclear-fueled base gener-
ating plants (defined as those plants
with a capacity load factor in excess
of 60 percent), which will not be retired
prior to July 1983, must have closed-cycle
cooling systems installed by July 1977.
All fossil or nuclear-fueled cyclic gener-
ating plants (defined as those plants with
a capacity load factor between 20 and 60
percent), which will not be retired prior
to July 1989, must have closed-cycle
cooling systems by July 1983.
All fossil or nuclear-fueled generating
plants coming into service in 1978 or
later must have closed-cycle cooling
systems.
The coverage and time phasing of pollution
controls assumed in Policy Alternative 1 are reproduced
below as Table 5.2-1.
A summary of the economic and financial con-
sequences of Policy Alternative 1 is set out below in
Table 5.2-2. As discussed in Section 4, except for the
energy and capacity loss figures, the data in Table 5.2-2
are the industry's total capitalized expenditures, exter-
nal financing, etc. The level of each of these figures
relative to the baseline assumption of no water pollution
control requirements, Policy Alternative 0, is summar-
ized for Policy Alternatives 1 through 7 in Section 5.9.
IH-75-
-------
Table 5.2-1
POLICY ALTERNATIVE 1
COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
___F_9_5_5.i_i_c_nj3a^jitjy ?i.4_^.L? a.JL
•ti-i: Capacity Pollution Control Equipment PCElncorporated PCE~Rctro-Kitted PCE Incorporated" 1'CK ""Retro-Kitted
, .-...(, ,. D.I'..' In-Servlce D:ite in New Plants in Existing Plants in New Plants in Existing Plants
Ily 1D77* - 40% - 80T»
]ty 1HB3** 0%
1?T1-1?73 I3v 1977* - 52% - 67%
:>n • < hcdulr for fT«-nt ti> br fimriltir.inK :>H of tin- plant's In service date; cash outlays for this pollution control equipment follow the
,..,c «,',,..! ]'.,. as tf'.nsr fi>r '.lie RI-U'ratine capacity. See Section 3 for details.
-------
Table 5.2-2
POLICY ALTERNATIVE 1
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Fxpenditures:
Total for the Year
Total since 1973
$ 32.1
107.2
$ 61.5
391. 1
$ 126.0
1.018.4
External Financing:
Total for the Year
Total since 1973
$22.3
75. 1
$ 40.2
264.5
$ 79.5
658.3
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
$59.5
$27.8
$119.5
$51.0
$251.4
$99.3
Consumer Charges:
(cents /kwh)
Average for the Year
2.50
3.36
4.51
Losses:
( t r i 1 ! ions of Btu 's)
Total for the Year
478.3
919.8
1,613.6
Capacity Losses:
(millions of kw )
Total since 1973
9.1
17.5
30.7
' K'xfhidrs nuclear fuel expense
-------
5.3 Policy Alternative 2
Policy Alternative 2 is identical to Policy
Alternative 1 with the exception of the added require-
ment that all peaking units brought into service prior
to 1971 have closed-cycle cooling systems by 1983. As
shown in Table 5.3-1, the EPA has estimated that the effect
of this requirement is to boost the retro-fitting of
pre-1971 fossil capacity by 1983 from 9 percent to 11
percent.
The economic and financial consequences of
Policy Alternative 2 are summarized in Table 5.3-2.
As mentioned earlier, a comparison of the con-
sequences of Policy Alternative 2 with those of the
other policy options is presented in Section 5.9.
"1-78-
-------
Tuble 5. 3-1
POLICY ALTERNATIVE 2
COVEaAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Generating Capacity
In -Service Date
Pollution Control Equipment
_ In-Service Date
________ fossil S:J!J?J?.£.iLy. __ ____
PCE Incorporated ~ PCE Retro-Kitted
in New Plants in Existing Plants
_____ N_UILL?-? r—
PCE Incorporated ~
in New Plants
______
PCE~Retro-Fitted
in Existing Plants
Be/ore 1971
By 1977*
By 1983**
40%
11%
80%
1971-1973
1974-1977
By 1977*
By 1977*
37%
52%
52%
33%
67*
67%
1978-1990
1978-1990***
73%
100%
VO
I
*The installation schedule for equipment required by 1977 is: 1374 - IS'li; 1975 - 20%; 1976 - 25%; and 1977 - 40%.
**The installation schedule for equipment required by 1983 is: 1978 - 10%; 1979 - 107.; 1980 - 20%; U>81 - 20",,; l'J82 - 20°',,; and 1983 - 20%.
"**Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. St;e Section 3 for details.
-------
Table 5. 3-2
POLICY ALTERNATIVE 2
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
oo
o
I
('npita 1 i?c'd Kxpenditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$ 32. 1
107.2
$22.4
75.2
$59. 5
$27.8
$ 61.5
391.6
$ 40.3
264.7
$119.5
$51.0
$ 126.0
1.018.9
$ 79.5
658.4
$251.4
$99.3
Consumer Charges:
(ccnts/kwh)
Average for the Year
2.50
3.36
4.51
Energy Losses:
(t ri1 I ions o( Btu's)
Total for the Year
478.3
925.1
1.624.1
Cnpacity Losses:
(millions of kvr >
Total since 1973
9.1
17.6
30.9
< Kxrludes nuclear fuel expense
-------
5• 4 Pollcy A1 te ma t i v e 3
Policy Alternative 3 calls for the same generating.
capacity coverage levels as Policy Alternative 1, but assumes
substantial delays in the time phasing of the portion
of these coverage requirements to be met by retro-fitting.
New source standards are assumed to apply to fossil plants
coming into service after 1978 and to nuclear plants coming
into service after 1981. As in Policy Alternatives 1
and 2, the equipment required by the new source standards
is installed during the construction of the generating
plants and comes into service simultaneously with the
plants.
The installation of closed-cycle cooling systems
on capacity that is not new source (i.e., that capacity
on which construction started before publication of EPA
regulations) is in Policy Alternative 3 assumed to be
delayed until 1983. As in Policy Alternatives 1 and 2,
it is assumed that some plants currently under construc-
tion have already been designed to include closed-cycle
cooling systems. Specifically, the EPA has assumed in Policy
Alternative 3, as in Policy Alternatives 1 and 2, that
37 percent of the fossil capacity brought into service in
the 1974-1977 period and 33 percent of the nuclear capacity
brought into service in the 1974-1981 period will have
been designed to include pollution control equipment. In
Policy Alternative 3, it is assumed that these units will
be completed by 1983. These units are assumed to come
in at the new unit costs, appropriate to their installa-
tion dates. The remaining 52 percent fossil and 67 per-
cent nuclear coverages are to be met by retro-fitting
by 1983. Policy Alternative 3 also assumes that 31
percent of the fossil plant brought into service in 1978
will have been designed to incorporate pollution control
111-81-
-------
equipment and will be fitted by 1983 at new unit costs;
the remaining 42 percent coverage requirement will be
retro-fitted by 1983.
The pollution control equipment required by
1983 is assumed to be installed in accordance with the
following schedule:
• 1981 10 percent
• 1982 40 percent
• 1983 50 percent
The coverage and time phasing assumptions of
Policy 3 are presented in Table 5.4-1; the projected
economic and financial implications of these assump-
tions are presented in Table 5.4-2.
111-82-
-------
Tatle 5.4.-1
POLICY ALTERNATIVE 3
COVERAGE AND TIME PHASING OP THERMAL POLLUTION CONTROLS
_ ____ _.---- ____ ___ ________ .--____ _______
Generating Capacity Pollution Control Equipment PCE~inco"rporat<7f PCE Retrofitted PCfcfincorporaFed ~ PCE~Retro-Fitted
In-Service Date _ In-Service Date _ in Now Plants in Existing Plants in New Plants in Existing Plants
Before 1971
1971-1973
By 1983>
By 1983*
49%
52%
80%
67%
1974-1977
Bv 1983*
37%
33%
67%
H
M
I
oo
00
1978
1979-1981
By 1983*
1979-1981**
By 1983-1'
31%
73%
42%
33%
33%
67%
67%
1982-1990
1982-1990-**
100%
'The installation schedule for equipment required by 1983 is: 1981 - 10''«; 1982 - 40%; and 1983 - 50%.
**Pollutlon control i'qmpm<• functioning as of the plant's m-scrvicc date; cj.-.h outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. Sec Section 3 for details.
-------
Table 5. 4-2
POLICY ALTERNATIVE 3
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
H
I
00
Capitalized !• xpcnditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses;*
Consumer Charges:
(conts/kwh)
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
Average for the Year
$30.2
98.7
$20.8
68.1
$57.9
$27.3
2.43
$ 66. 1
400.7
$ 44.1
274.3
$119.8
$50.4
3.36
$ 126.0
1.024.3
$123.4
663.2
$251.6
$98.6
4.51
Energy Losses:
( i n 1 1 KIMS (iI Btu's)
Total for the Year
78.8
919.8
1.613.6
Capacity Losses:
(millions of kw )
Total since 1973
1.5
17.5
30.7
Kxcluclos nuclear fuel expense
-------
5.5 Policy Alternative 4
The fourth policy alternative specified by the
EPA calls in effect for the imposition of new source
standards as of 1977. That is, it is assumed that all
capacity coming into service after 1976 must have closed-
cycle cooling, irrespective of the date on which con-
struction of any particular plant began. Policy Alter-
native 4 secondly calls for a delay until 1983 in retro-
fitting the pre-1977 capacity that has not been designed
to have closed-cycle cooling systems. Policy Alternative
4 thirdly assumes that the capacity coming into service
in the 1974-1976 period that has been designed to have
such systems will have them completed by 1977.
The coverage of Policy Alternative 3's
retro-fitting requirements is the same as in Policy Al-
ternatives 1 and 3. The installation schedules for
the pollution control equipment retrp-fitted by 1983
are the same as that in Policy Alternative 3. The
schedule for the equipment already planned in 1974-1977
capacity additions is the same as that of Policy Alternatives
1 and 2. The coverage and time phasing of Policy Alter-
native 4's requirements are set out in Table 5.5-1.
The economic and financial impact of these
assumptions is summarized in Table 5.5-2
111-85-
-------
Tab c 5. 5-1
POLICY ALTERNATIVE 4
COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Fo£8i l_jC_a_p_a_c_H£ .. —
Generating Capacity Pollution Control Equipment PCE~l7icorpbraFc:i PCK Metro-Fitted PC E Incorporated ~" PCE Retro-Fitted
In-Servlee Date In-Service Pate in New Plants in Existing Plants in New Plants in Existing Plants
Before 1971 By 1983** - 49% - 80%
1971-1973 By 1983** - 527. - 67%
1974-1976 By 1977* 37% - 33%
By 1983** - 52% - 67%
M
H 19?7 1977*** 37% - 33%
I Ry 1977* - 52% - 67%
00
O\
I
1978-1990 l'J7B-10»0*** 73% - 100%
control equipment follow the
-------
Table 5. 5-2
POLICY ALTERNATIVE 4
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
oo
Kxpenditures:
Kxtcrnal Financing:
Operating Hevonuos:
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$30.5
99.8
$20.9
68.9
$58.0
$27.3
$ 65.5
397.6
$ 43.6
271.3
$119.3
$50.4
$ 126.0
1.022.3
$ 79.3
661.6
$251.3
$98.4
Gons'.irnfr Charges:
(cents/kwh)
Average for the Year
2.44
3.35
4.50
Knorgy Losses:
(trill mns o I Btu ' s)
Total for the Year
105.1
904.0
1.613.6
Capacity Losses:
(millions of kw )
Total since 1973
2.0
17.2
30.7
Kxfl'id-"-' nuclear fuel expense
-------
5.6 Policy Alternative 5
Policy Alternative 5 differs from Policy Alter-
native 4 only in assuming that all existing source plants
requiring retro-fitting and having a capacity of 500 megawatts
or above will have such retro-fitting completed by 1977,
instead of by 1983. The "by 1977" timetable is the same
15-20-25-40 schedule used in other policy options. The EPA's
estimate of the coverage and time phasing implied by
Policy Alternative 5 is shown in Table 5.6-1.
The projected economic and financial consequences
of this policy option are shown in Table 5.6-2.
111-88-
-------
Table 5.6-1
POLICY ALTERNATIVE 5
COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Generating Capacity
In -Service Date
Pollution Control Equipment
In-Service Date
________ ..
PCE Incorporated
in New Plants
.. _________
PCK Retro-Kitted
in Existing Plants
________ __
PCE Incorporated
in New Plants
_ _____ _
PCE Retrofitted
In Existing Planta
Before 1971
By 1977*
By 1983**
25%
24%
80%
1971-1973
By 1977*
By 1983**
37%
15%
67%
00
1974-1976
1977
By 1977*
By 1983**
1977-;.**
By 1977*
37%
37%
37%
15%
52%
33%
33%
67%
67%
1978-1990
1978-1990***
73%
100%
*The installation schedule for equipment required by 1977 is: 1974 - 15%; 1975 - 2('%; 1976 - 25%; and 1977 - 40%.
**Thr installation schedule for equipment required hv 1!1R3 is; 19B1 - 10%; 1082 - 1('%: rind 19H3 - 50%.
***Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. Sec Section 3 for details.
-------
Table 5.6-2
POLICY ALTERNATIVE 5
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
H
\O
O
Capitalized Kxpcnditures:
Kxtornal Financing:
Operating Revenues;
Operations & Maintenance Expenses;*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$ 31.9
106.2
$22.0
74.0
$58.6
$27.1
$ 62.1
393.3
$ 40.7
266.4
$119.4
$50.8
$ 126.0
1.020.3
$ 79.5
659.8
$251.3
$99.0
C.'onsurnor Charges:
(cents/kwh)
Average for the Year
2.47
3.35
4.51
Kncrgy Losses:
(trill ions ol Btu's)
Total for the Year
410.0
977.6
1.613.6
Caparity Losses:
(millions of kw)
Total since 1973
7.8
18.6
30.7
'; Kxc-luclos nuclear fuel expense
-------
5.7 Policy Alternative 6
Policy Alternative 6 is identical to Policy
Alternative 5 except in assuming that all existing source
plants having a capacity of 300 megawatts or above will
be retro-fitted by 1977, instead of partly by 1977 (plants
having a capacity of 500 megawatts or above) and partly
by 1983 (plants having a capacity of under 500 megawatts)
as is assumed in Policy Alternative 5. The coverages and
time phasing estimated by the EPA for Policy Alternative 6
are shown in Table 5.7-1.
The economic and financial projections made
by TBS for Policy Alternative 6 are summarized in Table
5.7-2.
111-91-
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Taole 5.7-1
POLICY ALTERNATIVE 6
COVERAGE AND TIME PHASING OK THERMAL POLLUTION CONTROLS
Generating Capacity
In -Service Date
Pollution Control Equipment
_ In-Service Date _
__ ___ .__
PCtTlncorporated
in Now Plants
_________
PCE Retrofitted
in Existing Plants
PCE Incorporated
in New Plants
.
PCE Retroitted
in Existing Plants
Before 1971
By 1977*
By 1983**
35%
14%
80%
1971-1973
By 1977*
By 1983**
41%
11%
67%
1974-1976
liy 1977*
By 1983**
377
49%
3%
33%
67%
NJ
1977
1977***
By 1977*
37%
33%
52%
67%
1978-1990
1978-1990***
73%
100%
*The installation schedule for equipment required by 1977 is: 1974 - 15%; 1975 - 20%; 1976 - 25%; and 1977 - 40%.
**The installation schedule for equipment required by 1083 is: 1981 - lOTo, 1982 - 40%; and 1983 - 50%.
***Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. See Section 3 for details.
-------
Table 5. 7-2
POLICY ALTERNATIVE 6
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Kxpenditures:
Total for the Year
Total since 1973
$ 32.0
106.5
$ 61.7
391.5
$ 126.0
1.018.7
External Financing:
Total for the Year
Total since 1973
$22. 1
74.3
$ 40.4
264.7
$ 79.5
658.4
I
vo
Operating Revenues;
Total for the Year
$59.4
$119.5
$251.4
Operations & Maintenance Expenses:*
Total for the Year
$27.8
$50.9
$99.1
Consumer Charges:
(conts/kwh)
Average for the Year
2.50
3.36
4.51
Energy Losses:
(trill ions <>t Btu's)
Total for the Year
441.5
914.5
1.613.6
Capacity Losses:
(millions of kw)
Total since 1973
8.4
17.4
30.7
*KxrIut|ps nuclear fuel expense
-------
5.8 Policy Alternative 7
Policy Alternative 7 is similar to Policy
Alternatives 5 and 6. It differs in requiring that
pre-1971 .peaking capacity be retro-fitted by 1983, a
requirement which adds 2 percent to the pre-1971 fossil
coverages assumed in the two related policy options.
Policy Alternative 7 also differs slightly in the as-
sumed time schedule for the retro-fitting of existing sources,
As shown in Table 5.8-1, capacity brought into
service prior to 1971 is retro-fitted by dates that de-
pend on the type and size of the generating plants.
Nuclear plants are retro-fitted by 1978 in accordance
with the time schedule:
15 percent of total retro-fitting
completed as of 1975;
• another 20 percent completed as of 1976;
• another 25 percent as of 1977 ; and
• the remaining 40 percent as of 1978.
Fossil capacity brought into service prior to 1971 is
retro-fitted as follows:
• plants of 500 megawatts and above in 1978 ;
• plants of 300 megawatts to 500 megawatts
in 1979 ;
other base capacity in 1980 I and
111-94-
-------
Table 5.8-1
POLICY ALTERNATIVE 7
COVERAGE AND TIMK PHASING OK THERMAL POLLUTION CONTROLS
Generating Capacity
In-Service Date
Pollution Control Equipment
In-Service Date
____ __ ____ _
PCE Incorporated
in New Plants
.._ __ _____
PCE Retro-Fitted
in Existing Plants
________ _____
PCElncorporated
in New Plants
___ __ _ __
PCE Retrofitted
in Existing Plants
Before 1971
By 1978*
1978
1979
1980
By 1983**
25%
10%
5%
80%
1971-1973
H
H
I
VO
Ui
1974-1976
By 1977***
By 1978*
1978
1979
1980
By 1978*
1978
1979
1UDO
37?
33%
37%
4%
11%
37%
12",
3%
67%
67%
1977
1977****
By 1978*
37%
52%
33%
67%
1978-1990
1978-1990****
73"
100%
*The installation schedule for equipment required by 1978 is: 1975 - 15%; 1976 - 20%; 1977 - 25%; and 1978 - 40%.
**The installation schedule for equipment required by 1983 is: 1981 - 10%; 1982 - -10%; and 1983 - 507..
***The installation schedule for equipment required by 1977 is: 1974 - 15%; 1975 - ->0%; 1976 - 25%; and 1977 - 40%.
****Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. See Section 3 for details.
-------
the remaining coverage, including cyclic
and peaking capacity, by 1983.
The capacity to be retro-fitted by 1983 is done in accor-
dance with the same 10-40-50 installation schedule used
in Policy Alternatives 3 through 6.
Capacity brought into service in the 1971-1973
period is phased according to a schedule similar to that
for the pre-1971 capacity, specifically:
• nuclear capacity by 1978;
• fossil capacity of 500 megawatts and
above in 1978;
• fossil capacity of 300 megawatts to 500
megawatts in 1979; and
• the remaining fossil coverage in 1980.
Policy Alternative 7 further assumes that 37
percent of the fossil capacity and 33 percent of the
nuclear capacity brought into service in the 1974-1976
period has been designed to incorporate closed-cycle
cooling systems and is fitted by 1977 with such equipment,
as was also assumed in Policy Alternatives 4, 5, and 6.
Policy Alternative 7 assumes that the retro-fitting of the
other 1974-1976 capacity additions is spread as follows:
• nuclear capacity by 1978;
• fossil capacity of 500 megawatts and
above in 1978;
Hl-96-
-------
• fossil capacity of 300 megawatts to 500
megawatts in 1979; and
• the remaining coverage in 1980.
Capacity brought into service in 1977 and sub-
sequent years is treated the same in Policy Alternative
7 as in the two related options.
The coverage and time phasing requirements
assumed in Policy Alternative 7 are shown in Table 5.8-1,
The economic and financial implications of
Policy Alternative 7 are shown in Table 5.8-2.
111-97-
-------
Table 5. 8-2
POLICY ALTERNATIVE 7
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Kxpendi tares;
Total for the Year
Total since 1973
$ 31.2
103.2
$ 61.6
392.5
$ 126.0
1,019.8
I
vo
oo
I
Kxterrml Finnnrin":
Operating Revenues:
Total for the Year
Total since 1973
Total for the Year
$21.5
71.9
$58.4
$ 40.4
265.7
$119.8
$ 79.4
659.1
$251.6
Operations & Maintenance Expenses:*
Total for the Year
$27.4
$50.9
$99.3
Consumer Charges:
(ccnts/kwh)
Average for the Year
2.45
3.36
4.51
Kr.orgy Losses:
(trill ions ol Btu's)
Total for the Year
147.2
909.3
1.624.1
Capacity Losses:
(millions of kw>
Total since 1973
2.8
17.3
30.9
*Kxcluiles nuclear fuel expense
-------
5.9 Summary Comparisons of Policy
Alternatives 1 Through 7
Selected summary data on the total economic and
financial impacts of Policy Alternatives 1 through 7 and
on their impacts relative to the baseline industry fore-
cast are presented in Tables 5.9-1 through 5.9-4. These
tables focus on:
• capitalized expenditures;
• external financing;
• operations and maintenance expenses; and
• average consumer charges per kilowatt hour.
Two central results are clearly evident in the
data on capitalized expenditures in Table 5.9-1. First,
as is perhaps most easily seen in the figures for each of
the policy options relative to the baseline, delays in
the implementation of thermal pollution control require-
ments result in significant increases in the total amount
of capitalized expenditures over the 1974-1990 period.
Consider the data for Policy Alternatives 1, 3, 4, 5 and
6. All of these policy options call for the same eventual
coverage of each type of capacity brought into service as
of any particular date, but vary in the dates by which
compliance is mandatory. Policy Alternative 1, which
assumes the most rapid installation schedule, results in
capitalized expenditures for pollution control equipment
of $50.3 billion in the 1974-1990 period. Policy Alternative
3, which assumes the latest compliance, is estimated to
require pollution control expenditures of $56.2 billion.
Policy Alternatives 4, 5, and 6, which assume compliance
schedules in between those of Policy Alternatives 1 and 3,
result in the intermediate amounts displayed in Table 5.9-1.
111-99-
-------
Table 5.9-1
IMPACT OF EPA POLICY ALTERNATIVES
ON CAPITALIZED EXPENDITURES:
SELECTED SUMMARY DATA
Capitalized Expenditures
(Ml I Ion H of <• urn-lit il o I I a r -i )
Capitalized Expenditures Relative to Baseline
iH of current dollaru)
H
H
1— 1
O
O
Policy Alternative
0
1
2
3
4
5
6
7
1974-1977
93.8
107.2
107.2
98.7
99.8
106.2
106.5
103.2
1978-1983
270.2
283.9
284.4
302.0
297.8
287. 1
285.0
289.3
1974 -1983
364.0
391.1
391.6
400.7
397.6
393.3
391." 5
392.5
1984-1990
604. 1
627.3
627.3
623.6
624.7
627.0
627.2
627.3
1974-1990
£'68. 1
1.C18.4
1,018.9
1,024.3
1.C22.3
1,020.3
1,018.7
1,019.8
1974-1977
-
13.4
13.4
4.9
6.0
12.4
12.7
9.4
1978-1983
-
13.7
14.2
31.8
27.6
16.9
14.8
19. 1
1974-1983
.
27.1
27.6
36.7
33.6
29.3
27.5
28.5
1984-1990
.
23.2
23.2
19.5
20.6
22.9
23.1
23.2
1974-1990
50.3
50.8
56.2
54.2
52.2
50.6
51.7
-------
Table 5. 9-2
IMPACT OF EPA POLICY ALTERNATIVES
ON EXTERNAL FINANCING:
SELECTED SUMMARY DATA
Kxternal Financing
(billions of current dollars)
External Financing Relative to Baseline
(billions of current dollars )
P.'I:
H
t— 1
H
1
r-1
O
1
:ov Alternative
0
1
*>
3
4
5
6
7
I!'74-l
-------
Tab e 5. U-3
IMPACT OF EPA POLICY ALTERNATIVES
ON OPERATIONS AND MA INT liNANCi'J EXPENSES:
SELECTED SUMMARY DATA
Operations and Maintenance Expense 3
(billions of current dollars)
Operations and Maintenance Expenses Relative to Baseline
(billions of current dollars)
H
H
H
I
Policy Alternative
0
1
2
3
4
5
6
7
1977
26.6
27.8
27.8
27.3
27.3
27.3
27.8
27.4
1983
48.6
51.0
51.0
50.4
50.6
50.8
50.9
50.9
1990
95.4
99.3
99.3
98.6
98.8
99.0
99.1
99.3
1977
1.2
1.2
0.7
0.7
0.7
1.2
0.8
1983
2.4
2.4
1.8
2.0
2.2
2.3
2.3
1990
-
3.9
3.9
3.2
3.4
3.6
3.7
3.7
-------
Table 5.9-4
IMPACT OF HPA I'OMCY AI.TKUNATIVKS
ON AVKJIACJK C'ON.Sl'MKK CIIAKUKS 1'Klt MV1I
SELECTED Sl'MMAKY DATA
Avernge Consumor Charges por
(current cents)
Average Consumer Charges per kwh Relative to Baseline
(current cents)
M
H
i_j
i^^
O
1
Policy Alternative
0
1
2
3
4
5
6
7
1977
2.
2.
2.
2.
2.
2.
2.
2.
40
50
50
43
44
47
50
45
1983
3.
3.
3.
3.
3.
3.
3.
3.
19
36
36
36
36
35
36
36
1990
4.
4.
4.
4.
4.
4.
4.
4.
32
51
51
51
51
51
51
51
1977
-
0. 10
0. 10
0.03
0.04
0.07
0. 10
0.05
1983
0.
0.
0.
0.
0.
0.
0.
-
17
17
17
17
16
17
17
1990
-
0. 19
0. 19
0. 19
0.19
0.19
0. 19
0. 19
-------
Consider next the figures for Policy Alternatives
2 and 7. Policy Alternative 2 differs from Policy
Alternative 1 only in its coverage by 1983 of pre-1971
peaking capacity, adding $0.5 billion to capitalized expen-
ditures in the 1978-1983 period. Policy Alternative 7, in
contrast, calls for some lags in compliance relative to
Policy Alternative 2 that increase capitalized expenditures
by $0.9 billion, to $51.7 billion relative to the baseline,
over the 1974-1990 period.
The second major conclusion that emerges clearly
from the summary table is that the EPA's various policy alter-
natives result in widely disparate patterns of capitalized
expenditures over time. Capitalized expenditures attrib-
utable to pollution control equipment over the
1974-1977 period, range from a maximum of $13.4 billion
for Policy Alternatives 1 and 2 to a minimum of $4.9
billion for Policy Alternative 3. These relationships
are sharply reversed in the subsequent sub-period. To
cite figures for two policy options having the same eventual
coverages, Policy Alternative 1 results in capitalized
expenditures of $13.7 billion from 1978-1983; Policy
Alternative 3 results in pollution control expenditures of
$31.8 billion. Policy Alternative 7's capitalized expendi-
tures are $9.4 billion and $19.1 billion in the respective
1974-1977 and 1978-1983 sub-periods.
The costs of any capital expenditures by the
electric utility industry are passed on to consumers over
the life of the equipment and are reflected only gradually
in depreciation tax shields, but the relationships between
Policy Alternatives 1 through 7 manifest in the
capitalized expenditure data are evident also in the
external financing figures summarized in Table 5.9-2,
especially.in the data for the earlier sub-periods. The
Hl-lOA-
-------
1974-1977 external financing requirements for Policy
Alternative 1 comprise $11.0 billion for pollution con-
trol equipment; for Policy Alternative 3, the industry's
total external financing includes $4.0 billion for
pollution control. For Policy Alternative 7, the incre-
mental financing is $7.8 billion.
The 1974-1977 relationships for external financ-
ing reverse sharply in the 1978-1983 period, as was true
of capitalized expenditures. Policy Alternative 1 results
in external financing requirements during the period of
$9.1 billion. Policy Alternative 3 requirements, in contrast,
are projected at $25.9 billion. Policy Alternative 7's
1978-1983 requirements are $13.5 billion.
The magnitude of the external financing require-
ments associated with pollution control equipment should
also be viewed relative to the industry's total external
financing activities. The 1974-1977 pollution control
requirements increase the industry's baseline external
financings of $64.1 by a minimum of 6.2 percent for Policy
Alternative 3 to 17.2 percent for Policy Alternative 1 and
to a maximum of 17.3 percent for Policy Alternative 2.
The 1978-1983 pollution control requirements increase external
financing relative to a baseline of $180.3 billion by a
minimum of 5.0 percent for Policy Alternative 1 to a maximum
of 14.4 percent for Policy Alternative 3.
The relative impacts of Policy Alternatives 1
through 7 on operating expenses is somewhat different from
their impacts on capitalized expenditures and external
financing. As shown in Table 4.2-2, annual operating expenses
for thermal equipment installed after 1977 are assumed by
the EPA to be much lower than for equipment installed in
1977 or earlier. Thus, as is evident in Table 5.9-3,
Policy Alternative 1 results in higher operations and
III-105-
-------
maintenance expenses, both in 1977 and in later years, than
Policy Alternative 3. As before, the policy options having
pollution control equipment installation schedules in
between those of Policy Alternatives 1 and 3 have operating
costs that are also in between those of Policy Alternatives
1 and 3. To cite some illustrative numbers, the 1977
operations and maintenance expenses are $1.2 billion,
$0.8 billion and $0.7 billion for Policy Alternatives 1,
7, and 3, respectively. The 1990 figures are $3.9 billion,
$3.7 billion and $3.2 billion for Policy Alternatives 1,
7, and 3.
Table 5,9-4 displays the combined impact of the
capital and operating factors associated with each policy
option on average consumer charges per kilowatt hour. The
various policy options result in incremental charges in
1977 ranging from 0.10 cents per kilowatt hour for Policy
Alternatives 1, 2 and 6 to 0.03 per kilowatt hour for the
chemical equipment requirements of Policy Alternative 3.
However, what is striking in Table 5.9-4 is how little the
various policy alternatives differ from one another in the
long run. In 1990, for example, all seven primary policy
options result in a projected increase of 0.19 cents per
kilowatt hour, or 4.4 percent, relative to a baseline charge
of 4.32 cents.
In summary, the different thermal phasing assump-
tions in Policy Alternatives 1 through 7 result in sub-
stantially different time profiles and somewhat different
total amounts of capitalized expenditures and external
financing. However, the lower operating expenses per unit
assumed by the EPA to apply to thermal equipment installed after
1977 by coincidence almost exactly offset the interest,
dividends, and other expenses associated with the higher total
capital expenditures of the alternatives having relatively
slow installation schedules for thermal equipment.
III-106-
-------
6, OVERVIEW OF EPA POLICY ALTERNATIVES
AFTER EXEMPTIONS
6.1 Introduction
Section 6 of this Report discusses the
implications of the EPA assumptions with respect to
exemptions potentially available under Section 316(a)
of the Act. Such exemptions have the effect of reducing
the coverages assumed in the primary policy alternatives
by substantial amounts. The coverages of pre-1978
capacity assumed in Policy Alternatives 1 through 7 to be
retro-fitted are reduced by approximately 80 percent.
Only the 1974-1977 capacity designed to be fitted with
closed-cycle cooling systems is assumed not to be affected
by assumptions. Capacity coming into service in 1978 or
later is assumed to have coverages reduced by roughly a
half, specifically to 38 percent for non-nuclear capacity
and 44 percent for nuclear capacity.
Because the impact of exemptions is similar
across the seven policy alternatives considered in
Section 5, Section 6 focuses on their impact on only
three of the EPA options, namely, Policy Alternatives 1,
3, and 7.
Ill - 107 -
-------
6.2 Policy Alternative 1-E.
Policy Alternative 1-E incorporates the EPA's
estimate of the potential impact of exemptions on the
coverages assumed in Policy Alternative 1. The resultant
coverages and time phasings are shown in Table 6.2-1.
The economic and financial consequences of
Policy Alternative 1-E are summarized in Table 6.2-2.
III-108-
-------
Table 6.2-1
POLICY A I/I KKNATIVK 1-K
COVKItAGE AND TIMING PHASING OK TIIEHMAI POLLUTION CONTROLS
\\ITI1 KXKMl'llONS
Generating Capacity
In-Service Date
Pollution Control Equipment
In-Service Date _
________ ._
PCE Incorporated
in New Plants
_^ _________
PCE Retro-Fitted
in Existing Plants
PCE Incorporated
in New Plants
--- _______
PCE Retro-Fitted
in Existing Plants
Before 1971
By 1977*
By 1983**
8% .
1.8%
16%
1971-1973
By 1977*
10%
13°;
M
M
I
M
O
VO
I
1974-1977
1978-1990
By 1977*
1978-1990***
37%
38%
10 To
33%
44%
1?%
•The installation schedule for equipment required by 1077 is: 1074 - 15%; 1975 - 20%: 1976 - 25%; and 1977 - 40%.
**The installation schedule for equipment required by 1983 is: 1978 - 10%; 1979 - 10%; 1980 - 20%; 1981 - 20%; 1982 - 20%; and 1983 - 20%.
***Pollution control equipment to be functioning as of the plant's in-service date; catth outlays for this pollution control equipment follow the
same schedule as those for the generating capacity. Sec Section 3 for details.
-------
Table 6.2-2
POLICY ALTERNATIVE 1-E
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
o
Capitalized Expenditures;
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$29.9
99.2.
$20.5
68.6
$58. 1
$27.3
$ 60.2
377.8
$ 39.4
255.0
$117.0
$50.0
$123.7
994.0
$ 78.1
642.5
$246.9
$97.4
Consumer Charges:
(cents/kwh)
Average for the Year
2.44
3.29
4.43
Energy Losses:
(trillions of Btu's)
Total for the Year
157.7
352.2
683.3
Capacity Losses:
(millions of kw )
Total since 1973
3.0
6.7
13.0
lr.i nuclear fuel expense
-------
6.3 Policy Alternative 3-E
The EPA's estimated impact of exemptions on Policy
Alternative 3 is incorporated in Policy Alternative
3-E. The coverage and time phasing assumptions are
summarized in Table 6.3-1. The economic and financial
consequences of Policy Alternative 3-E are displayed in
Table 6.3-2.
III-lll-
-------
Table 6. 3-1
I'OI.ICY AI.TI.HNATIVK 3-K
COVERAGE AND TIME 1'IIASING OF THERMAL POLLUTION CONTROLS
"WT1II EXEMPTIONS
Generating Capacity
In-Service Date
Pollution Control Equipment
In-Service Date
________ .
PCE Incorporated
in New Plants
_________
PCE Retro-Fitted
in Existing Plants
__ ___ .
PCE Incorporated
in New Plants
-- ____ _
PCE ReTro-Fitted
in Existing Plants
Before 1971
By 1983'-
9. 8%
1971-1973
Bv 1983-
10™
13".
1974-1977
By 1983
10"-
KJ
I
1978
1979-1981
1982-1990
1978**
By 1983*
1979-1981**
By 1983*
1982-1990**
31%
38%
387o
33%
33%
44%
11%
11%
The installation schedule for equipment required by 1983 is: 1981 - 10%; 1982 - 4
-------
Table 6.3-2
POLICY ALTERNATIVE 3-E
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars/
1977
1983
1990
to
I
Capitalized Expenditures;
External Financing;
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$29.4
97.7
$20.1
67.2
$57.8
$27.1
$ 61.3
380.3
$ 40.2
256.8
$117'.0
$50.0
$123.7
995.7
$ 78.0
643.5
$247.0
$97.9
Consumer Charges;
(cents /kwh)
Average for the Year
2.43
3.29
4.43
Energy Losses:
(trillions of Btu's)
Total for the Year
78.8
357.4
683.3
Capacity Losses:
(millions of kw )
Total since 1973
1.5
6.8
13.0
*Excludes nuclear fuel expense
-------
6.4 Policy Alternative 7-E
Policy Alternative 7-E incorporates the EPA's
estimate of the impact of exemptions on the coverages
assumed in Policy Alternative 7. The coverages and
time phasings assumed in Policy Alternative 7-E are
displayed in Table 6.4-1.
The economic and financial consequences
of Policy Alternative 7-E are presented in Table
6.4-2.
III-114-
-------
Table 6.4-1
POLICY ALTERNATIVE 7-E
COVERAGE AND TIME PHASING Of THERMAL POLLUTION CONTROLS
WITH EXEMPTIONS
F_o_sfc_il_Caj?J(.£_itjy Nuclear Capacity
Generating Capacity Pollution Control Equipment PCE Incorporated~PCE~Retrc)~Pitted PCE~lncorporated PCE Retro^Fitted
' In-Service Date In-Service Date in New Plants ' in Existing Plants in New Plants in Existing Plants
Before 1971
By 1978*
1978
1979
11)80
1983*»
5%
2!'.
1%
2.2%
M
I
Ul
1971-1973
By 1978*
1978
107'J
IftflO
7.1%
0.8%
2. 1%
13%
1974-1976
Hy 1977***
By 1978*
1978
1079
1980
37%
7. 1%
2.3%
0.6%
33%
13%
1977
1077****
By 1978
37%
33%
13%
1978-1990
1978-1990****
44%
*The installation schedule for equipment required by 1978 is: 1975 - 15%; 1976 - 20%; 1977 - 25%; and 1978 - 40%.
**The installation schedule for equipment required by 1983 is: 1981 - 10%; 1982 - 49%; and 1983 - 50%.
***The installation schedule for equipment required by 1977 is: 1974 - 15%; 1975 - 20%; 1976 - 25%; and 1977 - 40%.
****Pollution control equipment to be functioning as of the plant's in-servire date; cash outlays for this pollution control equipment follow the
same schedule as those for the gonrrntinjj capacity. Spr Section 3 for clrtnil.s.
-------
Table 6.4-2
POLICY ALTERNATIVE 7-E
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1900
Capitalized Expenditures;
Total for the Year
Total since 1973
$ 29.4
97.6
$ 60. 3
378. 5
123.8
994.7
External Financing:
Total for the Year
Total since 1973
20.1
67.3
39.5
255.6
78. 1
642.9
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
58.0
27. 2
117'. 3
50.0
247.3
97. 7
Consumer Charges:
(cents/kwh)
Average for the Year
2. 44
3.29
4.43
Energy Losses:
(trillions Btu's)
Total for the Year
98.4
310.1
641.?
Capacity Losses;
(millions of kw)
Total since 1973
1.7
5.9
12.?
* Excludes nuclear fuel expense
-------
6.5 Summary Comments on the Impact of Exemptions
Selected summary data on the total economic and
financial impact of Policy Alternatives 1-E, 3-E, and 7-E
are shown in Tables 6.5-1 through 6.5-4. As is evident
in all these tables, the impact of each of the policy
options before exemptions is substantially reduced by
316(a) exemptions.
As shown in Tables 6.5-1 and 6.5-2, the effects
of exemptions on capitalized expenditures and external
financing requirements in any given period depends on
the proportion of retro-fitted versus new equipment in
the total capitalized expenditure figure. Thus, the large
amount of 1978-1983 retro-fitting assumed in Policy
Alternative 3 is substantially reduced in Policy Alternative
3-E, from $31.8 billion to $11.9 billion.
As is evident in Tables 6.5-3 and 6.5-4, the
effect of exemptions in the long run depends more on the
reduced requirements applicable to new sources than on the
reductions in retro-fitting requirements. Thus, by 1990,
average consumer charges relative to the baseline are 0.11
cents per kilowatt hour, a decline of about 40 percent from
the 0.19 cents per kilowatt hour associated with the EPA
policy alternatives before exemptions.
III-117-
-------
Table 6.5-1
IMPACT OF EPA POLICY ALTERNATIVES WITH EXEMPTIONS
ON CAPITALIZED EXPENDITURES:
SELECTED SUMMARY DATA
Capitalized Expenditures Capitalized Expenditures Relative to Baseline
(l)illions of rnrrcnt dollars) (billions of current dollars)
1974-1977 1978-1983 1974-1083 1984-1990 1974-19SC
5.4 8.4 13.8 12.1 25.9
3.9 11.9 15.8 11.4 27.2
3.8 10.7 14.5 12.1 26.6
PMicv Altorn.itive
0
l-K
3-E
7-E
H
H
H
M
CD
1974-1977 1978-1983 1974-19113 1984-1990 1974-1990
93.8 270.2 364.0 604.1 968.1
99.2 278.6 377.8 616.2 994.0
97.7 282.1 379.8 615.5 995.3
P7.6 280.9 378.5 616.2 994.7
-------
I
I-1
VO
I
Table 6.5-2
IMPACT OP EPA POLICY ALTERNATIVES WITH EXEMPTIONS
ON EXTERNAL FINANCING:
SELECTED SUMMARY DATA
External Financing External Financing Relative to Baseline
(billions of current dollars) (billions of current dollars)
Po'icv .Mtornntive
0
1-E
3-K
7-K
1974-1977
64.1
68.6
67.2
67.3
1978-1983
180.3
186.4
109.6
188.3
1974-1983
244.4
255. 0
256.8
255.8
1984-1990
380.4
387.5
306.7
387.3
1974-1990
624.8
642.5
643.5
642.9
1973-1977
-
4.5
3.1
3.2
1978-1983
-
6.1
9.3
8.0
1974-1983
-
10.6
12.4
11.2
1984-1990
-
7.1
6.3
6.9
1974-1990
-
17.7
18.7
18.1
-------
Table 6. 5-3
IMPACT OF EPA POLICY ALTERNATIVES WITH EXEMPTIONS
ON OPERATIONS AND MAINTENANCE EXPENSES:
SELECTED SUMMARY DATA
Operations and Maintenance Expenses
(billions of mi-rent dollars)
Operations and Maintenance Expenses Relative to Baseline
(billionH of current dollars)
IVHcv
• Alternative
0
1-K
3-K
7-E
1977
26.6
27.3
27.1
27.2
1083
48.6
50.0
50.0
50.0
1990
95. 4
97.4
97.9
97.7
1977
-
0.7
0.5
0.6
1983
-
1.4
1.4
1.4
1990
-
2.0
2.5
2.3
-------
M
I
to
M
Table 6. 5-4
IMPACT OF KPA POLICY ALTERNATIVES WITH EXEMPTIONS
ON AVERAGE CONSUMER CHARGES PER KWH
SELECTED SUMMARY DATA
Average Consumer Charges per kwh
(current cents)
Poliev Alternative
1
3
7
0
-E
-K
-E
1977
2.40
2.44
2.43
2.44
1983
3.19
3.29
3.29
3.29
1990
4.32
4.43
4.43
4.43
Average Consumer Charges per kwh Relative to Baseline
(current cents)
1977
0.04
0.03
0.04
1983
0.10
0.10
0.10
1990
0.11
0.11
0.11
-------
7, IMPACT OF REDUCED INDUSTRY GROWTH
7.1 Introduction
The preceding analyses all employed the most-
likely projection of peak load demand growth which implied
that the doubling in size of the electric utility industry
each decade would continue through the 1970's with a
gradual decline during the 1980's. While many conserva-
tionists have long preached the need for energy conserva-
tions, the recent Arab oil embargo has demonstrated not
only the need for conservation, but also the economic
realities associated with a rapid curtailment in the in-
dustry's growth.
In an effort to assess the economic and financial
impacts implicit with a gradual shift to conservation of
electrical energy, the EPA requested a comparison of Policy
Alternatives 0, 1 and 1-E with a projection of relatively
low growth in peak load demand. It should be noted that
these assumptions are also consistent with a slackening
of demand due to escalating electrical energy costs.
Ill- 122 -
-------
7.2 Low Demand Assumptions
The low demand growth assumptions are consistent
with the minimum growth scenarios employed by the TAC-
Finance. Specifically, peak load growth in kilowatts has
been limited to:
• 1971-1975 6.2 percent per year
• 1976-1980 5.7 percent per year
• 1981-1985 5.1 percent per year
• 1986-1990 4.4 percent per year.
In terms of industry growth, the above load
growth implies that generating capacity in the period
1970 through 1990 will be:
• 1970 324.6 million kilowatts
• 1975 438.5 million kilowatts
• 1980 578.6 million kilowatts
• 1985 741.9 million kilowatts
« 1990 920.2 million kilowatts
These projections of industry growth during the 1970's
and 1980's represent more than a 25 percent decrease in
generating capacity and a decline in the average growth
rate from 6.9 to 5.3 percent.
III-123-
-------
7.3 Economic Consequences of Low Demand
The assumptions outlined in Section 7.2 define
the low demand growth conditions for the electric utility
industry and were the only modifications to Policy
Alternatives 0, 1, and 1-E. Tables 7.3-1 through 7.3-3
provide selected summary data for these three alternatives.
7.3.1 Prior to Exemptions. A comparison of Tables 7.3-1
and 3.3-1 yields the overall impact of low demand growth
upon the baseline conditions within the electric utility
industry. In general, the 1970-1990 reduction in peak load
demand of 25 percent results in an overall reduction in
1974-1990 capitalized expenditures by 40 percent and exter-
nal financing requirements by 45 percent. Unfortunately,
these significant reductions in construction and financing
are not passed through to the consumer. The above-mentioned
reduction in peak load demand would reduce consumer charges
by only 5 percent. These observations are consistent with
the rate adjustments being requested and the generating addi-
tions being delayed by those electric utilities undergoing
significant conservation during the current "energy crisis."
In terms of the Act's impact, the results
are the same for Policy Alternative 1 although the mag-
nitude of the benefits are reduced. For example, the pre-
viously determined $50.3 billion increase in capitalized
expenditures would be reduced by 32 percent to $34.3 billion.
The reduction in external financing requirements would
be 38 percent ($33.5 to $20.9 billion). In addition, the
differential impact in consumer charges of 0.19£/kwh would not
III-124-
-------
Table 7.3-1
POLICY ALTERNATIVE 0 (LOW DEMAND)
• ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions "o/'current dollars)
1977
1983
1990
Ni
-------
be changed at all. Thus, the overall impact of reduced
industry growth yields:
• a more than proportionate reduction
in construction requirements and
their related financing requirements;
• a slight decrease in the charges borne
by the consumer; and
• an increasing share of total expen-
ditures being related to pollution
control equipment.
7.3.2 After Exemptions. The foregoing conclusions
continue to hold after consideration of exemptions poten-
tially available under Section 316(a) of the Act. Under
the industry growth assumptions employed in Sections 3-6,
Policy Alternative 1 requires $50.3 billion in capitalized
expenditures without exemptions and $25.9 billion after
exemptions — a reduction in the Act's impact by nearly
50 percent. With low demand growth assumptions, the
required capitalized expenditures is reduced to $34.3
billion without exemptions and $17.7 with exemptions. Once
again, the percentage reduction is nearly 50 percent.
Similar relative changes in external financing requirements
and consumer charges result from consideration of
exemptions under the conditions of most-likely and low
demand growth.
III-126-
-------
Table 7.3-2
POLICY ALTERNATIVE 1 (LOW DEMAND)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars'
1977
1983
1990
Capitalized Expenditures;
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$24.3
75.2
$16.1
49.0
$54.3
$26.0
$ 40.3
270.4
$ 24.6
171.5
$98.1
$44.4
$ 65.7
619.4
$ 37.6
368.2
$177.5
$77.4
Consumer Charges:
(cents/kwh)
Average for the Year
2.46
3.24
4.28
Energy Losses:
(trillions ol Btu's)
Total for the Year
431.0
762. 1
1.166.8
Capacity Losses;
(millions of k\v j
Total since 1973
8.2
14.5
22.2
-'•Excludes nuclear fuel expense
-------
Table 7. 3-3
POLICY ALTERNATIVE 1-E (LOW DEMAND)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(dollar figures in billions of current dollars)
1977
1983
1990
Capitalized Expenditures;
Total for the Year
Total since 1973
$22.4
68.3
$ 39.5
260.0
$ 64.6
602.8
oo
I
External Financing:
Total for the Year
Total since 1973
$14.5
43.3
$ 24.1
164.1
$ 37.0
358.2
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
$53.0
$25.6
.0
$43.8
$174.1
$76.1
Consumer Charges:
(cents /kwh)
Average for the Year
2.40
3.17
4.20
Energy Losses:
(trillions of Btu's)
Total for the Year
131.4
273.3
467.8
Capacity Losses:
(millions of lew )
Total since 1973
2.5
5.2
8.9
"•Excludes nuclear fuel expense
-------
8, REVIEW OF ALTERNATIVE TECHNOLOGICAL
ASSUMPTIONS
8.1 Introduction
Section 8 reviews the economic and financial
consequences of alternative assumptions about;
• the capital costs per kilowatt
of generating capacity of thermal
and chemical pollution control equip-
ment;
• the operating costs of such pollution
control equipment, and
• the impact of closed-cycle cooling
systems on operating efficiency of the
generating capacity on which such equip-
ment is installed.
Section 8 thus considers the effect of
uncertainties in the "most-likely" capital costs and
operating characteristics discussed in Section 4 and
assumed in the economic and financial projections
presented in the other sections of this report. As
mentioned earlier, Section 8 is based on a report sub-
mitted to the EPA by TBS on September 7, 1973.
Economic and Financial Implications of the Federal Water
Pollution Control Act of 1972 for the Electric Utility
Industry.
Ill - 129 -
-------
- 130 -
The coverage and time phasing of pollution
control requirements assumed in Section 8 are the same
as those in Policy Alternative 1. However, because TBS's
earlier report focused only on the 1974-1983 period, the post-
1983 requirements of Policy Alternative 1 are excluded
from consideration in the analysis reviewed in Section
8. As a consequence, this section's figures for capital-
ized expenditures, external financing, etc. in the years
preceding 1983 do not reflect any cash outlays for the
construction of polluti6n control equipment that is
assumed in either sections of this report to come into
2
service in 1984 and subsequent years.
The alternative technological assumptions
proposed by the EPA for analysis by TBS differ only in
their assumed costs and in their assumed impact on gen-
erating efficiencies. Section 8 therefore focuses on
these different assumptions and on their economic and
financial consequences. The percentages of each type
of capacity affected by the Act's pollution control
requirements and the timing of installation of pollution
control equipment are those that were discussed in
detail for Policy Alternative 1 in Section 4. An
overview of the alternative technological assumptions
considered by TBS is perhaps best conveyed graphically.
Such an overview is presented in Figure 8.1-1.
magnitude of construction work in progress for
post-1983 pollution control equipment can be seen by
comparing capitalized expenditures through 1983 for
Policy Alternatives 1 and l(a).
III-130-
-------
1 ; ' : i i
. . . , i. : J... 4-j- J4-
' < ' i 1 !
; ' ' j r r i i
1 '• ! ' ; :
; • ' ; ; OVERVIEW OF
- » . . - r —r- '- ' • t - ; ( •' I" ~
.... . . ... , - . — t ,_ , - r- - r - - - { - . - , -
i ' ' i ! i
f . . , ,
,. . 4 ,-. (.. | .,--;--
CHEMICAL GUIDELINES TH
-Hj-
- -[ -
i
1
1 i 1 ' ; ' '' '
, L, 1_— -L J_L_^.) 4.^4-1-. ,-.-: .;
1 1 ! i ,
I i 1 ' • i
. i 1 j liii, i » — ••
U-j-.__j_4__L_. . |_ ... j ^ j . ( _ |
Fiture 8. 1-1 ' ; • ' !...-„
;r-t~r- ~n r" T ' i ' 1 j "P'Tr m_L: ..
ALTBRN
— j- T- -
1
ERMAL
Capital and Operating Capital Costs of Retro-Fitted j
Cost Estimates Cooling Systems
...:.. i •.:;.; i | ....
most likely ,
f : ' i
• / ', ' ' maximum !
most likely ^/ ' , ' . ; j ]
/ ' \ ' '• ' ' ' !
• • \ - - minimum ; t -
...... ^ - ; .
i i
- —
- - t - - -
..L _
4-1-
AT'lVE TECHNOLOGICAL ASSUMPTIONS . 1 _ .'
1 ' ' ' ' ' '
- — j i i | - f •» - r *" ' » | ; ] •
- - \ — r-r ' r- }- T- r T ~ T" • T
i 1 . [ ' i i ...:.. i .- .-. ,- ..-.-.__ ..
: t " i ! ! , i « , T
"] 1 { a [ t 1 ] _|__L i ! • . ' ;
, GUIDELINES POLICY ALTERNATIVE
j i Operating Costd and [ ^ ;
i ! Efficiency Losses < <
---\\--r : - ; ; • - ! :.:---.---;
i most likely i !
1 4. ' ' 1 • . 1 i : i .
i ' ! i ! r 1 : 1 • ; ' ;
! most likely \ ','<•, 1/K4
/ ' • ; : . :
j jv^ maximum i ' ! i i '
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_ j. ..4. J *. . L ^ , , ... ,| .,_*._ _,-. . -
Jl J , ! > , • : : i •
| T most likely j ; ; ' ! ; _ 1W)-- - -
, , , , . , i\ni
jS \ • . • ' ! : . : ;..... . .
. -,-.-- . ^- - -j. -,_, -p-.r T- - - T T -T- • — - • - -
— i- -r - |- Xj i- -t - j- i -t ! i - -' r ; " " ; '•- ", — ' ' " "
i >sv ! ! minimum , , ; j , , , l/_^v
\ T 1
1 j , t f i
f i i t ' i i
most likely 1 ! ' i 1 most likely ! ' ! . ! ,/fl
,
i ; i
maximum
i
i
;
: i '
.
' i
,. |... .;_
i ' ! t ' . i , •
i ! ' • ! ; ' ' '
i ' maximum ' t ' • •
i • |
t i t ., ^ i , . ^ _,,_.-. t ._,..--.--
i i ' | i •
-------
8.2 Alternative Technological Assumptions
The cost assumptions considered in various
combinations in this section can be presented in five
tables. Table 8.2-1, which displays the so-called
"most-likely" costs associated with the chemical effluent
guidelines, is simply a reproduction of Table 4.2-4,
which was discussed in Section 4. As shown in Figure
8.1-1, these chemical costs are employed in all but
Policy Alternatives l(f) and (g) below. These two
cases consider the impact of some "maximum" estimates
of chemical pollution control costs. The maximum cost
figures specified by the EPA are set out in Table 8.2-2.
Tables 8.2-3 through 8.2-5 present the
alternative assumptions with respect to thermal pollution
control equipment. Table 8.2-3 is a reproduction of the
"most-likely" cost assumptions discussed in Section 4.
Tables 8.2-4 and 8.2-5 present the EPA's "maximum" and
"minimum" estimates for the same cost and operating
variables.
HI-132-
-------
Table 8:2-1
MOST-LIKELY CAPITAL AND OPERATING COSTS
CHEMICAL GUIDELINES
1977 Guidelines
M
to
I
Capacity Placed in Service;
Prior to 1971
Capital Expenditures
Annual Operating Expenses
1971-1977
Capital Expenditures
Annual Operating Expenses
Non-Nuclear
Capacity
($/kw)
1.95*
0.85
1.05
0.55
Nuclear
Capacity
($/kw)
0.85
0.50
0.85
0.50
(continued)
-------
Table 8.2-1 (Cont.)
1983 Guidelines
Capacity Placed in Service;
Prior to 1971
Additional Capital Expenditures
Additional Annual Operating Expenses
1971-1977
Additional Capital Expenditures
Additional Annual Operating Expenses
1978-1983
Capital Expenditures
Annual Operating Expenses
Non-Nuclear
Capacity
($/kw)
3.35
0.65
2. 75
0.35
2.60
0.25
. Nuclear
Capacity
($/kw)
2.75
0.35
2. 75
0.35
2.00
0.20
*All costs are specified at 1970 levels. Cost escalation occurs at the inflation rates projected
for each type of generating capacity in Table 3. 2-1.
-------
Table 8.2-2
MAXIMUM CAPITAL AND OPERATING COSTS
CHEMICAL GUIDELINES
1977 Guidelines
Capacity Placed in Service:
- - -
Prior to 1971
Non-Nuclear Nuclear
Capacity Capacity
($/kw) ($/kw)
Capital Expenditures 17.00* 7.00
V Annual Operating Expenses 1.35 1. 15
1971-1977
Capital Expenditures 11.00 4.50
Annual Operating Expenses 0. 90 0. 75
(continued)
-------
Table 8.2-2 (continued)
1983 Guidelines
Capacity Placed in Service:
Prior to 1971
Additional Capital Expenditures
Additional Annual Operating Expenses
1971-1977
Additional Capital Expenditures
Additional Annual Operating Expenses
1978-1983
Capital Expenditures
Annual Operating Expenses
Non-Nuclear
Capacity
($/kw)
5.00
0.25
3. 30
0. 15
14.30
1.05
Nuclear
Capacity
($/kw)
3.00
2. 00
0. 15
6. 50
0.90
*A11 costs are specified at 1970 levels.
-------
Table 8.2-3
CAPITAL AND OPERATING COSTS -
THERMAL GUIDELINES
M
M
I
Capital Expenditures ($/kw)
for Back-Fitted Units
for New Units
Annual Operating Expenses ($/kw)
installed by 1978
installed by 1978-1990
Non-Nuclear
Capacity
15.00*
7.50
**
42.00
15.00
Nuclear
Capacity
18.00
10.00
42.00
12.00
Capacity Losses
due to Running Cooling Units
due to Increased Back Pressure
1%
2
1%
2
*A11 costs are specified at 1970 levels. Cost escalation occurs at the inflation rates
projected for each type of generating capacity in Table 3. 2-1.
**Annual operating expenses associated with the Act will be incurred only by tnose
plants required to install cooling facilities and only in amounts to offset operating
inefficiencies.
-------
oo
I
Table 8.2-4
MAXIMUM CAPITAL AND OPERATING COSTS
THERMAL GUIDELINES
Capital Expenditures ($/kw)
Non-Nuclear Nuclear
Capacity Capacity
for Back-Fitted Units 28.00* 38.00
for New Units 7.50 10.00
Annual Operating Expenses ($/kw)
for 1977 Guidelines 84.00 84.00
for 1983 Guidelines 18.00 24.00
Capacity Losses
due to Running Cooling Units 1% 1%
due to Increased Back Pressure 5 5
*A11 costs are specified at 1970 levels .
-------
Table 8.2-5
MINIMUM CAPITAL AND OPERATING COSTS
THERMAL GUIDELINES
Non-Nuclear Nuclear
Capacity Capacity
Capital Expenditures ($/kw)
for Back-Fitted Units 10.00* 12.00
for New Units 7.50 10.00
Annual Operating Expenses ($/kw)
for 1977 Guidelines 21.00 21.00
for 1983 Guidelines 12.00 6.00
Capacity Losses
due to Running Cooling Units 1% 1%
due to Increased Back Pressure 1 1
*A11 costs are specified at 1970 levels.
-------
8.3 Policy Alternative 1 (a)
As mentioned above, Policy Alternative l(a)
presumes the EPA's most-likely estimates of capital and
operating costs for both chemical and thermal pollution
control equipment and of the impact of closed-cycle
cooling systems on generating efficiencies. A brief
summary of the projected economic and financial im-
plications of Policy Alternative l(a) is presented in
Table 8.3-1.3
As shown in Table 8.3-1, the assumptions
behind Policy Alternative l(a) imply that the electric
utility industry will spend $35.5 billion dollars dur-
ing the period 1974-1983 to comply with the chemical
and thermal effluent guidelines of the Act. Of this
amount, 68.2 percent ($24.2 billion) corresponds to
the thermal guidelines; the remainder ($11.4 billion)
represents costs associated with the chemical guide-
lines. During the period 1974-1983, 64.2 percent of the
expenditures ($22.8 billion) have been capitalized;
the remainder ($12.7 billion) are the operating ex-
penses incurred during the 1974-1983 period.
Table 8.3-1 also shows how Policy Alternative
l(a)'s capitalized expenditures and operating costs vary
over the 1974-1977 and 1978-1983 periods. Operations
See Economic and Financial Implications . . . , Case I for
further detail.
III-140-
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TABLE 8,3-1
POLICY ALTERNATIVE KA)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
Capitalized Operating
Expenditures Expenses Total
Relative to Relative to Relative to
Baseline Baseline Baseline
1974-1983
Chemical Guidelines 5,5 $ 5.9 $ 11.4
Thermal Guidelines 17.4 6.8 24.2
Total Impact* $ 22.8 $12.7 $ 35.5
1974-1977
Chemical Guidelines $ 2.1 $ 1.0
Thermal Guidelines 10.9 1.4
Total Impact* $ 13.0 $ 2.3
1978-1983
Chemical Guidelines $3.4 $4.9 $8.3
Thermal Guidelines 6.5 5.4 11.9
Total Impact* $ 9.8 $10.3 $ 20.1
*Totals may not equal the sum of components due to rounding.
III-141-
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and maintenance expenses for both chemical and
thermal pollution control increase substantialy
from the 1974-1977 period to the 1978-1983 period
as the amount of equipment in service increases. The
time schedule for installing chemical equipment is
such that capitalized expenditures in this category
take place at roughly equal average yearly rates
during the two periods. Capitalized expenditures
for cooling equipment are, however, much higher in
the early period. This latter relationship would
of course be modified substantially under the thermal
equipment time phasing assumptions used in other of
the major policy alternatives.
Policy Alternative l(a)'s external financing
requirements and 1983 average consumer charges per kilo-
watt are presented in the summary tables in Section 8.10
III-142-
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8.4 Policy Alternative l (b)
Policy Alternative l(b) differs from Policy
Alternative l(a) only in using the EPA's estimated maximum
capital costs for the retro-fitting of closed-cycle
cooling systems. The impact of Policy Alternative l(b)'s
assumptions is described in part in Table 8.4-1. Further
4
summary data are presented in Section 8.10.
TABLE 8,4-1
POLICY ALTERNATIVE 1 (B)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
1974-1983
Chemical Guidelines
Thermal Guidelines
Total
Capitalized
Expenditures
Relative to
Baseline
$5.5
23.4
Operating
Expenses
Relative to
Baseline
$ 5.9
6.8
$28.9
$12.7
Total
Relative too
Baseline
$ 11.4
30.2
$41.6
NOTE: Totals may not equal the sum of components due to rounding. .
See also Economic and Financial Implications . . . , Case V,
for further detail.
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8.5 Policy Alternative 1 (c)
Policy Alternative l(c) adds maximum thermal
operating costs and efficiency losses to the maximum
thermal retro-fitting costs assumed in Policy Alter-
native l(b). Policy Alternative l(c)'s capitalized
expenditures and operations and maintenance expenses
are shown in Table 8.5-1.5
TABLE 8.5-1
POLICY ALTERNATIVE 1 (c)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
Capitalized Operating
Expenditures Expenses
Relative to Relative to
Baseline Baseline
Total
Relative to
Baseline
1974-1983
Chemical Guidelines
Thermal Guidelines
Total Impact
$5.5
30.1
$35.5
$5.9
25.7
$31.6
$11.4
55.8
$67.1
NOTE: Totals may not equal the sum of components due to
rounding.
See also Economic and Financial Implications
for further detail.
Case III,
III-144-
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8.6 Policy Alternative 1 (d)
Policy Alternative l(d) assumes most-likely
thermal operating costs and efficiency losses, as in
Policy Alternatives l(a) and l(b), and minimum thermal
retro-fitting costs. As holds for all Policy Alterna-
tives l(a) through l(e), chemical costs are assumed
to be the EPA's most-likely estimate. The consequent
capitalized expenditures and operating expenses are
shown in Table 8.6-1.6
TABLE 8.6-1
POLICY ALTERNATIVE 1 (D)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
Capitalized Operating
Expenditures Expenses Total
Relative to Relative to Relative to>
Baseline Baseline Baseline -
1974-1983
Chemical Guidelines $5.5 $5.9 $11.4
Thermal Guidelines 14.5 6.8 21.3
Total Impact $20.0 $12.7 $ 32.7
NOTE: Totals may not equal che sum of components due to
rounding.
c
See also Economic and Financial Implications . . . , Case IV,
for further detail.
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8.7 Policy Alternative 1 (e)
Policy Alternative l(e) incorporates the EPA's
minimum estimates both for thermal retro-fitting costs
and for thermal operating costs and efficiency losses.
Policy Alternative l(e)'s projected capitalized expen-
ditures and operations and maintenance expenses are
shown in Table 8.7-1.7
TABLE 8.7-1
POLICY ALTERNATIVE 1 (E)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
Capitalized Operating
Expenditures Expenses Total
Relative to Relative to Relative to
Baseline Baseline Baseline
1974-1983
Chemical Guidelines $5.5 $5.9 $11.4
Thermal Guidelines 13.3 3.7 17.6
Total Impact $18.7 $ 9.6 $ 28.3
NOTE: Totals may not equal the sum of components due to rounding.
7
See also Economic and Financial Implications . . . , Case II,
for further detail.
"1-146-
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8.8 Policy Alternative I(f)
Policy Alternative l(f) assumes that all
thermal costs are at the EPA's most-likely levels, as
Policy Alternative l(a), but that chemical costs
are at the estimated maximum levels shown in Table
8.2-2. The implications of these assumptions for
capitalized expenditures and operating costs are
shown in Table 8.8-1.8
TABLE 8,8-1
POLICY ALTERNATIVE 1 (F)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
Capitalized Operating
Expenditures Expenses Total
Relative to Relative to Relative to
Baseline Baseline Baseline
1974-1983
Chemical Guidelines $28.4 $8.8 $27.2
Thermal Guidelines 17.4 6.8 24.2
Total Impact $ 35.7 $15.6 $ 51.3
MOTE: Totals may not equal the sum of components due to rounding.
o
See also Economic and Financial Implications . . . , Case VII,
for further detail.
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8.9 Policy Alternative 1 (g)
Policy Alternative l(g) incorporates the
maximum assumptions both for chemical and for thermal
costs and efficiency losses. The capitalized expen-
ditures and operating costs associated with this
g
"worst case" alternative are shown in Table 8.9-1.
TABLE 8,9-1
POLICY ALTERNATIVE 1 (G)
ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
(billions of current dollars)
1974-1983
Chemical Guidelines
Thermal Guidelines
Total Impact
Capitalized Operating
Expenditures Expenses
Relative to Relative to
Baseline Baseline
$ 18.4
30.1
Total
Relative to
Baseline
$ 27.2
55.8
$48.5
$34.5
$83.0
NOTE: Totals may not equal the sum of components due to rounding.
9
See also Economic and Financial Implications
for further detail.
.., Case IX,
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8.10 Summary Conclusions About the Alternative
cy_
5T
Technological Assumptions
Table 8.10-1 summarizes the total impact
of the chemical and thermal assumptions on capitalized
expenditures and operating expenses during the 1974-
1983 period for Policy Alternative l(a) through Policy
Alternative l(g). It also presents projected external
financing requirements during the 1974-1983 period rel-
ative to the baseline Policy Alternative 0. Table
8.10-1 also includes 1983 coverage consumer charges
per kilowatt hour relative to a baseline price of 3.19
cents per kilowatt hour.
The consequences of the range of the un-
certainties associated with technological factors can
be seen by comparing the summary data for Policy
Alternatives l(a), l(e), and l(g). Capitalized expen-
ditures for pollution control equipment under most-
likely assumptions are $22.8 billion during the 1974-
1983 period, but range from $18.7 billion to $48.5
billion. Operating expenses attributable to pollution
control during the period are $12.7 billion under
most-likely assumptions, but range from $9.6 billion
to $34.5 billion. Incremental external financing
requirements are $16.4 billion during the period
under most-likely assumptions, but range from $13.6
billion to $49.7 billion. The increased average
consumer charges per kilowatt hour in 1983 due to
pollution control equipment are 0.16 cents under
most-likely assumptions, but range from 0.13 cents
to 0.54 cents.
HI-149-
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TABLE 8,10-1
IMPACT OF ALTERNATIVE TECHNOLOGICAL ASSUMPTIONS:
SELECTED SUMMARY DATA1
Capitalized Expenditures
External Financing
Operations and
Maintenance Expenses
Average Consumer
Charges Per Kilowatt Hour
Policy
Alternative
1974-1983
Relative to Baseline
(billions of dollars)
M
M
I
M
Ui
O
0
1
1
1
1
1
1
1
(a)
(b)
(c)
(d)
(e)
(f)
(g)
-
22.
28.
35.
20.
18.
35.
48.
8
9
5
0
7
7
5
1974-1983
Relative to Baseline
(billions of dollars)
-
16.
21.
24.
15.
13.
25.
49.
4
0
4
0
6
3
7
1974-1983
Relative to Baseline
(billions of dollars)
-
12.
12.
31.
12.
9,
15.
34.
7
7
6
7
6
6
5
1983
Relative to Baseline
(cents)
0.
0.
0.
0.
0.
0.
0.
-
16
19
21
16
13
23
54
Expressed in current dollars.
-------
The impact of changing individual elements
in the sets of assumptions can also readily be seen
in Table 8.10-1. As is evident from Figure 8.10-1,
the impact of most-likely versus maximum versus minimum
assumptions for thermal retro-fitting costs can be seen
by comparing Policy Alternatives l(a), l(b) and l(d).
The impact of most-likely versus maximum thermal
operating costs and efficiency losses can be seen
by comparing Policy Alternatives l(b) and l(c); the
most-likely versus minimum comparisons can be seen in
Policy Alternatives l(d) and l(e). Finally, the
impact of most-likely versus maximum chemical cost
assumptions can be seen by comparing Policy Alternatives
l(a) and l(f). A commentary on such comparisons is
presented in the September 7, 1973 TBS report to the EPA
and thus is not reproduced in detail here.
III-151-
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APPENDIX: RESEARCH METHODOLOGY
A.I Introduction
This appendix on research methodology
consists of a non-technical overview of the logical
structure of the computer model used to derive the
projections discussed and analyzed in the text of this
report. The model, called PTm, is an extension of a
model developed by Dr. Howard W. Pifer of Temple, Barker &
Sloane and Professor Michael L. Tennican of Harvard University ,
Graduate School of Business Administration, to pro-
vide projections for the Technical Advisory Committee
on Finance to the 1973-1974 National Power Survey.
In broad terms, PTm has three main logical
components, which may conveniently be labeled the en-
vironmental, physical, and financial modules. As
shown in Figure A.1-1, it is assumed that general eco-
nomic conditions and other factors outside the model
determine the demand for electricity. Consumers' peak
and average demand, the industry's policy with respect
to reserve margins, and the equipment, power drain, and
generating efficiency implications of pollution control
requirements combine to determine the industry's physical
plant, equipment, fuel, and labor requirements. These
Drs. Pifer and Tennican gratefully acknowledge the
counsel and assistance of a number of individuals
from industry, the Federal Power Commission, and
various financial institutions — especially Messrs.
John Childs, Gordon Corey, Fred Eggerstedt, Robert
Fortune, Rene Males, John O'Connor, and Robert Uhler.
III-152-
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KNVIUUNMK.NTAL
H
H
it
3
3
It
a
z
H
W
n
a!
IS
K M
S M
H! s
•< z
D
>
-------
physical requirements and the relevant factor costs,
which are also influenced by economic considerations
external to PTm, combine to determine the consequences
of building and operating the capacity needed to meet
consumer demand.
These capital asset and operating cash require-
ments are met in part by revenues collected from the users
of electrical energy and in part by external financing.
The amount of cash provided by operations at any given
point in time is influenced by regulatory policy (in
effect via the allowed revenue per kilowatt hour), by
tax policy (via the effective rate of taxation after con-
sideration of depreciation tax shields, investment tax
credits, etc.), and by the cost of capital raised in prior
periods. Any shortfall between cash needs and the cash
provided by operations is met by recourse to the capital
markets.
Figure A.1-1 omits a number of interactions
and feedbacks, two of which might be noted explicitly.
First, if external financing is to be available,
regulatory policy must be such as to allow revenues
per kilowatt hour sufficient to yield returns to
capital that are adequate in light of prevailing capital
market conditions, tax policy, and pollution control
requirements, all of which may have an impact on the cost
of electrical power and hence on demand. As a second
illustration, because the financial characteristics of
the electric utility industry and of individual utilities
may be considerations in the drafting and administration of
pollution control legislation, pollution control policy in
part determines and in part is determined by the industry's
financial profile.
III-154-
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A.2 PTm's Environmental Module
The model's environmental module has as its
primary function the inputting of assumptions concern-
ing future growth in the demand for power, current and
future pollution control requirements, equipment and
operating costs, etc. The implications of these policy,
economic, and technical assumptions are then determined
in the physical and financial modules of PTm. PTm is
programmed so as to be able to test a wide variety of
policy alternatives via changes in input data. In
testing alternative policies with respect to the coverage
and time phasing of water pollution control requirements,
however, modifications to the logical structure of the
model itself were required, so that a series of slightly
different models were actually used to make the projec-
tions set out in the body of the report. Nonetheless,
for simplicity we shall in the following speak of PTm as a
single model rather than a set of related models.
A.3 PTm's Physical Plant and Equipment Module
The primary relationships determining the
industry's physical plant and equipment requirements
are shown in Figure A.3-1. Consistent with the assump-
tion that demand will be met, the industry's gross gen-
erating capacity in service as of any point in time is
determined by the level of demand, the industry's policy
with respect to capacity reserves, and the efficiency
III-155-
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KiRiiro A.:t-l
DETERMINANTS OK PI.AI.T AND EQUIPMENT IN SERVICE
ANU IN CONSTRUCTION KOR THE ELECTRIC UTILITY INDUSTRY
Impact of Kuturr Pollution
Equipment on Generating
Plant Efficiency
K-"
in
I
Impact of Current Pollution
Equipment on Generating
Plant Efficiency
Current Required
Gross Capacity
Future Retirements
Construction for
Future Requirements
Additions to Plant and
Equipment in Service and
in Construction
Pollution Control Equipment
Requirements
Construction for
Current Requirements
Current 1cvircments
-------
impact and operating power drain of pollution control
equipment. These current capacity requirements and the
rate of retirement of old generating units together
determine the amount of generating capacity additions
necessary for meeting current demand. With the inclu-
sion of the pollution control equipment required for
generating capacity currently in service, the additions
to in-service plant and related equipment are fully
specified in physical terms.
Given the long time lags involved in con-
structing new generating capacity, the industry's
plant and equipment construction as of any point in
time typically includes significant amounts of work in
progress so as to meet future demand as it materializes.
As is shown in Figure A.3-1, future demand, future reserve
factors, future pollution control requirements, and future
retirements — together with the lags in construction —
determine the plant and equipment additions that are
related to future demand, i.e., construction in progress.
It should be noted that because the time span between
ordering and placing generating capacity in service
is radically different for peaking units, fossil-fueled
base load plants, and nuclear units, PTm computes con-
struction work in progress for nuclear and for non-nuclear
plants via two different time schedules. Thus, average
construction lags are themselves a function of the
assumed future mix of these various types of generating
plants. It might also be noted that PTm is designed to
accept assumptions with respect to the relative propor-
tions of nuclear and fossil additions that change over
time.
HI-IS?-
-------
A.4 PTm's Financial Module
For expositional purposes it is convenient
to divide PTm's financial module into three segments,
dealing with :
• uses of funds;
• sources of funds; and
• revenues, expenses, and profits.
A.4.1 Uses of Funds. The industry's uses of
funds, depicted in Figure A.4-1, are determined pri-
marily by the physical plant and equipment required
to meet current and future demand and by the cost
per unit of this equipment. A second use is the
allowance on funds tied up in plant and equipment in
the process of construction. For simplicity, PTm
assumes that the industry's net working capital remains
constant, so that changes in working capital appear
neither as a use nor as a source of funds. Given the
miniscule size of such working capital changes relative
to the industry's major sources and uses of funds,
such a simplifying assumption is unlikely to introduce
appreciable error absent fundamental structural changes
in the industry's current assets and payables accounts
or in its usage of short-term debt.
As may be clear from Figure A.4-1, once the
total physical amounts of plant and equipment required
to meet current and future demand and the proportions
of those amounts accounted for by nuclear and fossil-fueled
plants are determined, the crucial input assumptions
required to convert these physical quantities into
III-158-
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Figure A.4-1
DETERMINANTS OF USES OF FUNDS
FOR THE ELECTRIC UTILITY INDUSTRY
Cost Per Unit of Plant
and Equipment
.Plant & Equipment
Construction for Current
Requirements
Plant & Equipment
Construction for
Future Requirements
Capitalized Expenditures !
t M/ !
>
>
Expenditures for In-
Service Plant and Equipment
Allowance for ' Funds
Used for Construction
in Progress
T
Expenditures for Increasing
Plant and Equipment
in Construction
>
f
Total Uses of Funds
/
\
t
Cost Per Unit of Plant
and Equipment
III-159-
-------
financial terras are the cost per unit of each type of
asset and the schedule of payments required by con-
tractors while such plant and equipment are under con-
struction.
A.4.2 Sources of Funds. In the case of the private
sector of the electric utility industry, sources of
funds consist of two major elements, namely:
• funds provided by operations and
• external financing.
Funds provided by operations in turn are the sum
of three internal sources, namely:
• depreciation;
• tax deferrals; and
• retained earnings.
For the public sector, it is simply assumed that 35
percent of total funds uses are met for internal
sources. As is shown in Figure A.4-2(a), any short-
fall between total uses and internal sources is met
via external financing.
Figure A.4-2(b) shows these same relation-
ships in a format that is slightly different and that
shows how the private sector's total required external
financing and capital structure and dividend policies
combine to determine:
• cash issues of preferred stock'
• gross cash offerings of debt; and
• cash issues of common stock.
III-160-
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Figures A.4-2
DETERMINANTS AND COMPOSITION
OF TOTAL SOURCES OF FUNDS FOR THE ELECTRIC UTILITY INDUSTRY
U>
Total
V
^
External
*
Fund* Provided
TOTAL SOURCES OP FUNDS
H
H
H
Depreciation
Initial
Capital Structure
Total Uses of Funds
TOTAL SOUIICES OF FUNDS
Additions to Capital
Ending
Capital Structure
3 Cash Issues of Preferred
Caah laaura of Debt
Cash Isauea of Common
Debt Retirements
Retained Earnings
Profit Available for
Common Stock
-------
A.4.3 Revenues and Related Variables. The third
segment of the financial module determines total in-
dustry revenues, expenses, profits, and related sta-
tistics such as price per kilowatt hour and interest
coverage ratios. The output variables of this revenue
segment serve in many instances as inputs to other
segments (e.g., the depreciation expense figure com-
puted in the revenue segment is an input to the sources
of funds segment.) Conversely, certain of the input
variables to the revenue segment are based on the
output from the sources and uses segment of the fi-
nancial module (e.g., plant and equipment expenditures
provide the base for computing depreciation expense).
The structure of the revenue segment and the inter-
actions between this segment and other parts of the
total model are depicted in Figure A.4-3.
As shown at the top of Figure A.4-3, profits
available for common stockholders are assumed to be
determined completely by the amounts of the industry's
common equity capital and by a rate of return on equity
set by regulatory policy.2 As a consequence of this
assumption, revenues and prices per kilowatt hour of
electricity are determined by required profits, other
capital charges, and operating expenses.
It should be noted that "policy" is a term intended
to comprise the effect of both the target rates of
return set by individual regulatory bodies and the
administrative lags involved in adjusting prices per
kilowatt hour so as to achieve such target returns.
III-162-
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Figure A.4-3
DETERMINANTS OF REVENUES, EXPENSES, AND PROFITS FOR THE
ELECTRIC UTILITY INDUSTRY
H
M
OJ
I
Depreciation &
Amortization of
Plant and Equipment
-------
Earnings before interest and taxes (EDIT)
is simply the sum of EBT and interest expense and is com-
puted by the same general process used for preferred
dividends. The resultant EBIT figure constitutes one
of the five main determinants of revenues.
The second determinant of revenues, deprecia-
tion and amortization of plant and equipment, is a vari-
able related to the amount of plant and equipment in
service. Presuming taxes other than on income consist
primarily of property taxes, a third determinant of
revenue, namely other taxes, is also related to the
amount of plant and equipment in service. Plant and
equipment requirements are in turn determined by both
current demand and pollution control policy.
Current consumer demand and the power drains
and operating efficiency losses associated with pollution
control equipment combine to determine the level of
operating and maintenance expenses. This latter expense
figure is the fourth determinant of revenues.
Future consumer demand and pollution control
requirements also determine future in-service plant and
equipment requirements and hence determine the amount
of construction currently in progress. The amount of
construction in progress in turn determines the allow-
ance for funds used during construction, which is another
non-cash item, but which also affects — this time
diminishes -- the level of revenues required to achieve
a given level of profit as determined by regulatory
accounting procedures. This allowance on construction
funds variable is the fifth and last major determinant
of revenues.
III-164-
-------
Net profit is simply the sum of profits
available for common stock and preferred dividends.
The amounts of preferred dividends are determined
by the amounts of preferred equity capital and the
average dividend rate on the industry's outstanding
preferred stock. The dividend yield on new pre-
ferred stock issues -- and hence the average yield—
is in turn determined over time by the reaction of
the capital market to the industry's offerings.
Earnings before income taxes (EBT) are then
set at a level such that EBT minus taxes will be equal
to the required net profit figure. The tax expense
figures (or equivalently, the effective tax rate) is
itself a function of the EBT figure, which is computed
in accordance with regulatory accounting procedures,
and several other factors. The calculations are some-
what complicated first of all because various special
features of the tax code (e.g., provisions allowing
investment tax credits and accelerated depreciation) and
of regulatory accounting (e.g., the creation of allow-
ances for funds used during construction as non-cash
credits to income) must be taken into account. As a
consequence of these differing provisions, taxable EBT
and regulatory EBT may — and typically do -- differ.
Secondly, as mentioned earlier, there exist two sub-
stantially different regulatory methods for determin-
ing the tax expense figure to be associated with EBT.
Normalizing accounting gives rise to deferred taxes,
which is a non-cash charge against income, but which
nonetheless constitutes an accounting expense to be
covered by revenues if accounting profits to stock-
holders are to reach prescribed levels.
III-165-
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A.5 A Concluding Comment
As has been outlined above, the operating,
financial, tax, regulatory, and accounting relationships
and constraints relevant to making economic and financial
projections for the industry are individually rather
simple. However, the number of these relationships and
constraints are so great as to dictate the use of a com-
puter model such as PTm. Moreover, because of inter-
actions between the various industry relationships and
constraints, attempts to reduce the number of factors
through shortcut approximations are hazardous.'1 Further-
more, such shortcuts, even if based on careful econo-
metric analyses of historical data, would tend to pre-
clude an examination of the implications of structural
and policy changes.
3
To illustrate the point concretely, consider the industry's
effective tax rate as it appears in regulatory and shareholder
financial reports. This rate is, in fact, a complex function
of (among other things): the actual federal, state, and local
income tax rates; the industry's plant and equipment expendi-
tures in the current and past years; and, the reduced asset
lifetimes, the accelerated methods of depreciation, the invest-
ment credits, and the other income statement items allowed for
tax purposes, but not for regulatory purposes. These current
and past expenditures are themselves a function of: demand
growth; the mix of nuclear and non-nuclear capacity built to
meet this demand; and the costs per unit of such generating
capacity and the related transmission and distribution equipment
Clearly, to assess the industry's future effective tax rate
directly is a formidable task; even more clearly, simply to
assume the future rate will be the same as the current rate or
some average of recent rates is unlikely to be an adequate
approximation of the outcome of the detailed calculations or
actual events.
III-166-
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PTm was designed not only to compute rapidly
the implications of any given set of assumptions about
the future, but also to facilitate the examination of
structural and policy changes. Thus, the model is
able conveniently to accept input assumptions for over
100 variables, such as the current level of and future
changes in: the industry's peak demand; reserve margins;
the mix of nuclear and non-nuclear capacity additions;
unit costs of generating plants, transmission and distri-
bution capacity, thermal and chemical pollution equip-
ment; etc. As is discussed briefly in Section 4, PTm then
generates projections for a variety of physical and fi-
nancial variables, including: capacity figures for each
of the major segments of the industry; energy losses
resulting from thermal water pollution control standards;
income statements, balance sheets, funds flows, and re-
conciliations of regulatory and Internal Revenue Service
income tax expense figures; and summary statistics such
as interest coverage figures.
III-167-
U. S. GOVERNMENT PRINTING OFFICE : 1974 732-430/428
------- |