EPA-230/2-74-006
DECEMBER 1974
ECONOMIC ANALYSIS
OF EFFLUENT GUIDELINES
STEAM ELECTRIC POWERPLANTS
QUANTITY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D.C. 20460
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ECONOMIC ANALYSIS
OF EFFLUENT GUIDELINES
STEAM ELECTRIC POWERPLANTS
HOWARD W, PIFER MICHAEL L, TENNICAN
T, JAMES GLAUTHIER JOHN W, WEBER
JAMES M, SPEYER MICHELE ZARUBICA
U,S, ENVIRONMENTAL PROTECTION AGENCY
Office of Planning and Evaluation
Washington, D. C. 20460
December 1974
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PREFACE
The attached document is a contractor's study
prepared with the supervision and review of the Office
of Planning and Evaluation of the U.S. Environmental
Protection Agency (EPA). Its purpose is to provide a
basis for evaluating the potential economic impact of
effluent limitations and guidelines and standards of
performance established by EPA pursuant to sections 301,
304(b) and 306 of the Federal Water Pollution Control
Act.
This study supplements the EPA technical
"Development Document" issued in conjunction with the
promulgation of guidelines and standards for point sources
within this industry category. The Development Document
surveys existing control methods and technologies within
this category and presents the investment and operating
costs associated with various control technologies. This
study supplements that analysis by estimating the broader
economic effects (including increases in capital require-
ments, price increases, continued viability of affected
plants, employment, industry growth and foreign trade)
of the required application of certain of these
technologies.
This study has been submitted in fulfillment
of contract No. 68-01-2803 by Temple, Barker & Sloane,
Inc. Work was completed as of December 1974. The study
is an update of an earlier study prepared with the
assistance of Temple, Barker & Sloane, Inc. entitled
"Economic Analysis of Proposed Effluent Guidelines:
Steam Electric Powerplants." The earlier report was
circulated in conjunction with the publication in the
Federal Register of a notice of proposed rulemaking
for the subject point source category. The analysis
contained in the original study has been updated based
upon information received during the period of time
between publication of the notice of proposed rulemaking
and the promulgation of the final regulation.
(i)
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This report represents the conclusions of the
contractor. It has been reviewed by the Office of
Planning and Evaluation and approved for publication.
Approval does not signify that the contents necessarily
reflect the views of the Environmental Protection Agency.
The study has been considered, together with the
Development Document, information received in the form
of public comments on the proposed regulation, and
other materials in the establishment of final effluent
limitations guidelines and standards of performance.
(ii)
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ACKNOWLEDGMENTS
The authors of this study would like to take
this opportunity to thank the many individuals who con-
tributed to this study, especially Walter Barber and
Victor Kimm of the Environmental Protection Agency
(Office of Planning and Evaluation); Robert Uhler of the
Federal Power Commission (Office of Economics,); Valerie
Bennett, Robert Elgin and Richard Rosen of Energy Resources
Company, Inc.; Angela Lancaster and Lewis Perl of National
Economic Research Associates, Inc.; and Lee Gladden and
Elinor Scholl of the TBS professional staff.
In addition, a special thanks to the following
members of the TBS staff who assisted in the preparation
of the final report: Cynthia Kornuta and Pamela Scricco
of the Energy and Environment Group and Arlene Ficcaglia,
Judy Weitzman, Ann Eberhardt, Debby Homer and Lee O'Neil
of the Editing and Production staff.
Responsibility for any errors or omissions
remains with the authors.
Howard W. Pifer III
Director of Energy &
Environment Studies
(iii)
TBS
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TABLE OF CONTENTS
PREFACE i
ACKNOWLEDGMENTS ii:L
LIST OF EXHIBITS AND APPENDICES viii
EXECUTIVE SUMMARY 1
*
TEXT
I, THE CHANGING NATURE OF THE ELECTRIC
UTILITY INDUSTRY (1960-1973)
Introduction : 7
Industry Structure ... 8
The Secure Years (1960-1966) 12
The Turning Point (1966-1969) 20
The Dilemma Years (1969-Present) .... 24
Summary 36
II, BASELINE ELECTRIC UTILITY INDUSTRY
PROJECTIONS (1974-1990)
Introduction 39
Industry Structure 42
Generating Capacity 44
Capital Cost Factors 48
(iv)
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Operating Cost Factors 50
Financial Policy Parameters 51
Economic and Financial Implications ... 56
Summary of Baseline Conditions 59
Historic Growth Assumptions 61
III, ANALYSIS OF THE FINAL EFFLUENT GUIDELINES
Introduction 67
Structure of Assumptions 69
Thermal Capital and Operating
Cost Factors ........ 70
Thermal Capacity Coverage Estimates ... 74
Thermal Installation Schedules 84
Impact of Thermal Guidelines 85
Chemical Capital and Operating
Cost Factors 99
Chemical Capacity Coverage
Estimates 100
Chemical Installation Schedules .... 101
Impact of Chemical Guidelines ..... 102
Total Impact of Final Guidelines .... 105
(v)
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IV, EVALUATION OF OTHER THERMAL OPTIONS
Introduction 115
Thermal Capacity Coverage Estimates . . . 117
Impact of Thermal Options 117
Summary 122
V, EVALUATION OF STATE WATER QUALITY STANDARDS
Introduction 123
Thermal Capacity Coverage Estimates . . . 123
Impact of State Water Quality Standards. . 125
VI, ENVIRONMENTAL IMPACT OF THERMAL GUIDELINES
Introduction 129
Technology of Thermal Pollution 129
Factors that Influence
Environmental Impact 136
Environmental Evaluation of
the Guideline Options 149
VII, ALTERNATIVE ASSUMPTIONS SUBMITTED BY UWAG
Introduction 157
Areas of Difference in Assumptions .... 159
Alternative Thermal Cost Factors 162
(vi)
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Impact of Cost Factors (Thermal) 167
Alternative Chemical Cost Factors 169
Impact of Cost Factors (Chemical) 172
Alternative Baseline Conditions 173
Impact of Growth Assumptions (Thermal) . . . 176
Impact of Interaction Effect (Thermal) . . . 178
Impact of Growth Assumptions (Chemical). . . 180
Impact of Interaction Effect (Chemical). . . 181
Summary 182
EXHIBITS
APPENDIX A PTM RESEARCH METHODOLOGY
APPENDIX B PTM SUMMARY STATISTICS
(vii)
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LIST OF EXHIBITS AND APPENDICES
I, THE CHANGING NATURE OF THE ELECTRIC EXHIBIT
UTILITY INDUSTRY (1960 - 1973)
Growth in Energy Demand and in Peak Load
Relatively Predictable Through Early 1960s 1
Annual Load Factor Remarkably Constant
Through Early 1960s 2
Cost Per Kilowatt of Installed Capacity
at End of 1960s Was About Same Level as
at Start 3
Investment in Electric Plant Per Dollar of
Revenue Quite Constant During Early 1960's 4
Capital Expenditures Grew Very Slowly
in Early 1960s 5
Cost Per Kilowatt-Hour—Both Total and Major
Components—Declined During Early 1960s 6
Growth in Revenues Steady and Consistent
Through Early 1960s 7
Rates Declined Along With Revenues Per
KWH Through the Early 1960s 8
Number of Customers and Average Usage Per
Customer Increased Significantly During
the Early 1960s 9
Financial Results Good Through the Early
1960s 10
Indicators of Investment Climate Improved
Significantly During Early 1960s 11
(viii)
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EXHIBIT
Utility Management Shifted Their
Capitalization Toward Equity During
the Early 1960s 12
Internally Generated Funds Became More
Important During the Early 1960s as
Both New Debt and Equity Tapered Off 13
Industrial Bond Rate Virtually Constant
Until 1965, Then Moved Sharply Upward 14
Requirements for External Financing Has
Grown Dramatically Since Mid-1960s 15
Growth in Energy Consumption and in Peak
Load Accelerated Since the Early 1960s
and Predictability Deteriorated 16
Cost Per KW of Installed Capacity
Increased Dramatically Since the 1960s 17
Capital Expenditures—After a Period of
Relative Constancy in Early 1960s—Have
Grown Rapidly Since That Time 18
Internally Generated Funds Not Growing
as Fast as Need for Funds Since 1965 19
Cost Per Kilowatt-Hour—Both Total and
Major Components—Bottomed Out in Late
1960s, Then Climbed Steadily 20
Fuel Cost Components Bottomed Out in
Mid- to Late-1960s and Increased Since 21
Net Income from Electric Operations Up
Substantially Since Mid-1960s 22
Allowance for Funds During Construction
Becoming an Increasingly Larger Portion
of Total Net Income 23
(ix)
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EXHIBIT
Capital Structures Relatively Unchanged
Over the Years 24
Rate of Growth of Common Equity Up
Substantially in Recent Years; Common
Stock Growth Up Even More 25
Return on Common Equity Deteriorated
in Recent Years 26
Price Earnings Ratio of Common Stock
Deteriorated Badly in Recent Years 27
Ratio of Market Price to Book Value of
Common Stock Deteriorated Steadily and
is Now Less Than One 28
Growth Rate in Earnings Per Share
Deteriorated Sharply Since the Early 1960s 29
Cx)
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II, BASELINE ELECTRIC UTILITY INDUSTRY
PROJECTIONS (1974-1990)
EXHIBIT
Factors Influencing the Electric Utility
Industry's Rate of Growth in Generation
Capacity and Electric Energy Under Moderate
Growth Assumptions, 1973 to 1990 30
Total Electric Utility Industry Generation
Capacity Additions, Retirements, and Totals
by Plant Type and Total Sales to Ultimate
Consumers Under Moderate Growth Assumptions,
1973 to 1990 31
Generating Capacity Cost Growth 32
Schedule of Construction Work in Progress
Cash Payments 33
Operations and Maintenance Cost Growth 34
Economic and Financial Projections of
Baseline Conditions With Moderate Growth
Assumptions, For Selected Years 35
Factors Influencing the Electric Utility
Industry's Rate of Growth in Generation
Capacity and Electric Energy Under Historic
Growth Assumptions, 1973 to 1990 36
Total Electric Utility Industry Generation
Capacity Additions, Retirements, and Totals
by Plant Type and Total Sales to Ultimate
Consumers Under Historic Growth Assumptions,
1973 to 1990 37
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EXHIBIT
Economic and Financial Projections of
Baseline Conditions with Historic
Growth, for Selected Years 38
Economic and Financial Impact of
Reduced Growth - 1977 39
Economic and Financial Impact of
Reduced Growth - 1983 40
Economic and Financial Impact of
Reduced Growth - 1990 41
(xiil
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Ill, ANALYSIS OF THE FINAL EFFLUENT EXHIBIT
GUIDELINES
Capital Cost Growth—Thermal Guidelines 42
Annual Operating Cost Growth—Thermal
Guidelines 43
Non-Nuclear Capacity Coverage by In
Service Year 44
Nuclear Capacity Coverage by In Service
Year 45
Installation Schedule for Retrofitted
Units 46
Economic and Financial Projections With
Thermal Pollution Control Equipment
for Economic Reasons, for Selected
Years 47
Economic and Financial Projections of
Final Thermal Guidelines Before Section
316(a) Exemptions, for Selected Years 48
Economic and Financial Projections of
Final Thermal Guidelines After Section
316(a) Exemptions, for Selected Years 49
Economic and Financial Impact of Thermal
Pollution Control Equipment for Economic
Reasons—1977 50
Economic and Financial Impact of Thermal
Pollution Control Equipment for Economic
Reasons—1983 51
Economic and Financial Impact of Thermal
Pollution Control Equipment for Economic
Reasons—1990 52
fxiii"
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EXHIBIT
Economic and Financial Impact of Final
Thermal Guidelines Before Section 316(a)
Exemptions—1977 53
Economic and Financial Impact of Final
Thermal Guidelines Before Section 316(a)
Exemptions—1983 54
Economic and Financial Impact of Final
Thermal Guidelines Before Section 316(a)
Exemptions—1990 55
Economic and Financial Impact of Final
Thermal Guidelines After Section 316(a)
Exemptions—1977 56
Economic and Financial Impact of Final
Thermal Guidelines After Section 316(a)
Exemptions—1983 57
Economic and Financial Impact of Final
Thermal Guidelines After Section 316(a)
Exemptions—1990 58
Capital Cost Growth—1977 Chemical
Guidelines 59
Capital Cost Growth—1983 Chemical
Guidelines 60
Annual Operating.Cost Growth—1977
Chemical Guidelines 61
Annual Operating Cost Growth--1983
Chemical Guidelines 62
Economic and Financial Projections of
Final Chemical Guidelines, For Selected
Years 63
Economic and Financial Impact of Final
Chemical Guidelines—1977 64
Cxiv")
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EXHIBIT
Economic and Financial Impact of Final
Chemical Guidelines—1983 65
Economic and Financial Impact of Final
Chemical Guidelines—1990 66
Economic and Financial Impact of Final
Regulations—1977 67
Economic and Financial Impact of Final
Regulations—1983 68
Economic and Financial Impact of Final
Regulations—1990 69
(xv)
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IV, EVALUATION OF OTHER THERMAL OPTIONS EXHIBIT
Non-Nuclear Coverage for Existing Units 70
Nuclear Coverage for Existing Units, 71
Economic and Financial Projections of
Option 1 (1979) After Section 316(a)
Exemptions, for Selected Years 72
Economic and Financial Projections of
Option 2 (1974) After Section 316(a)
Exemptions, for Selected Years 73
Economic and Financial Projections of
Option 3 (1972) After Section 316(a)
Exemptions, for Selected Years 74
Economic and Financial Projections of
Option 4 (1961, < 200 MW) After
Section 316(a) Exemptions, for Selected
Years 75
Economic and Financial Projections of
Option 5 (1956, < 25 MW, < 40%) After
Section 316(a) Exemptions, for
Selected Years 76
Economic and Financial Projections of
Proposed Guidelines (March 1974) After
Section 316(a) Exemptions, for
Selected Years 77
(xvi)
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V, EVALUATION OF STATE WATER QUALITY EXHIBIT
STANDARDS
Non-Nuclear Coverage for Existing Units 78
Nuclear Coverage for Existing Units 79
Economic and Financial Projections of
Final Thermal Guidelines After Section
316(a) Exemptions, and After State Water
Quality Standards,for Selected Years 80
Economic and Financial Impact of State
Water Quality Standards—1977 81
Economic and Financial Impact of State
Water Quality Standards—1983 82
Economic and Financial Impact of State
Water Quality Standards—1990 83
fxvii")
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VI, ENVIRONMENTAL IMPACT OF THE THERMAL EXHIBIT
GUIDELINES
Annual Mix of Receiving Water Types—Open
Cycle Steam Electric Capacity 84
Annual Mix of Cooling Method—Steam g5
Electric Capacity
Safezone on Rivers Used for Once Through
Cooling 86
Mix of Capacity by Unit Size 87
Distribution of Projected 1978 Units by
Year Placed in Service 88
Comparison of Capacity Projections Used
for Environmental Versus Economic Analysis 89
Age Composition and Risk Characteristics
of Capacity In-Service by 1983 90
Environmental Risk, Variations on 1970-73
Size Criterion With 1970 Exemption 91
Environmental Risk, Alternative Age
Criteria 92
(xviii)
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VII, ALTERNATIVE ASSUMPTIONS SUBMITTED EXHIBIT
BY UWAG
A Summary of Alternative Economic and
Financial Projections of Final
Thermal Guidelines for the Period
1974-1983 93
A Summary of Alternative Economic and
Financial Projections of Baseline
Chemical Guidelines for the Period
1974-1983 94
A Summary of Alternative Economic and
Financial Projections of Baseline
Conditions for the Period 1974-1983 95
A Summary of Alternative Economic and
Financial Projections of Final Thermal
Guidelines for the Period 1974-1983 96
A Summary of Alternative Economic and
Financial Projections of Final Thermal
Guidelines for the Period 1974-1983 97
A Summary of Alternative Economic and
Financial Projections of Final Chemical
Guidelines for the Period 1974-1983 98
(xix)
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APPENDICES
A, PTM RESEARCH METHODOLOGY FIGURE
Interactions Between the Environment and
the Physical and Financial Characteristics
of the Electric Utility Industry A-l
Determinants of Plant and Equipment in
Service and in Construction for the
Electric Utility Industry A-2
Determinants of Uses of Funds for the
Electric Utility Industry A-3
Determinants and Composition of Total
Sources of Funds for the Electric
Utility Industry A-4
Determinants of Revenues, Expenses, and
Profits for the Electric Utility Industry A-5
B, PTM SUMMARY STATISTICS
Economic and Financial Projections of
Baseline Conditions, for Selected Years B-l
Investor-Owned Electric Utilities
Combined Income Statement, Baseline
Conditions - 1983 B-2
Investor-Owned Electric Utilities
Combined Balance Sheet, Baseline
Conditions - 1983 B-3
Investor-Owned Electric Utilities
Combined Applications and Sources of
Funds, Baseline Conditions - 1983 B-4
Investor-Owned Electric Utilities
Combined Reconciliation of Taxes,
Baseline Conditions - 1983 B-5
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EXECUTIVE SUMMARY
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EXECUTIVE SUMMARY
On 4 March 1974 the Environmental Protection
Agency (EPA) published a notice of proposed rulemaking
announcing its intention to establish limitations on
the discharge of pollutants into waterways by existing
and new point sources within the electric utility in-
dustry. These proposed regulations were promulgated
pursuant to the relevant sections of the Federal Water
Pollution Control Act of 1972 (Act) as amended. With
respect to thermal pollution, the proposed rulemaking
exempted all small units (defined by the Federal Power
Commission as units in plants of 25 megawatts or less
and in systems of 150 megawatts or less in total capa-
city), and all units which were scheduled for retire-
ment prior to 1990.
Interested parties were invited to submit
written comments on the proposed regulations, and
EPA convened public hearings in July to afford those
who had submitted comments to explain the substance
of their position in detail. Based upon these
written comments, public hearings, and subsequent inter-
action among interested parties, the guidelines were
revised.
On 8 October 1974, EPA published in the
Federal Register- (39 FR 36186) final guidelines and
standards for steam electric power generation. The
final thermal guidelines exempt all units placed
into service before 1970, and all but the largest
baseload units (defined as units of 500 megawatts or
greater) placed into service between 1 January 1970
and 1 January 1974. Thus, the final thermal guide-
lines differed from those proposed in March 1974 in
terms of the proportion of existing steam electric
units which were covered by the Act. In addition,
the final chemical guidelines were modified from those
previously proposed.
EPA contracted with Temple, Barker and
Sloane, Inc. (TBS) to evaluate the overall economic
impact of these guidelines.1
Throughout this report, the economic and financial
implications will be attributed to both the Act and the
guidelines. Technically, they represent the impact of the
final guidelines, not the Act itself.
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The purpose of this document is to describe
in some detail the analyses performed and conclusions
reached during the evaluation of the economic and
financial implications of the final guidelines. It
is divided into two major parts. The first is an
executive summary which provides an overview of the
study and its findings. The second part is the
full report which details the economic impact of the
final guidelines, evaluates alternative options
which were considered (including the original
proposal) and summarizes the assessment of environ-
mental risk performed by Energy Resources Company, Inc.
BASELINE CONDITIONS
Prior to the Arab oil embargo, the electric
utility industry was planning to spend more than $205
billion in constant 1974 dollars for capital equip-
ment placed in service during the 1974-83 decade before
any consideration of EPA effluent guidelines. Based
upon the planning assumptions currently being used
by the Technical Advisory Committee on Finance for
the National Power Survey, the most likely level of
capital expenditures prior to the effluent guidelines
would be less than $180 billion (1974 dollars).
This decline of approximately $25 billion in capital
expenditures reflects the decline in the rate of
growth by less than 1 percent to the current pro-
jections of 5.5 percent over the next decade. In
order to provide perspective, EPA has utilized these
most recent industry projections as a baseline from
which to summarize relative changes in economic
impact associated with the effluent guidelines.
ECONOMIC IMPACT OF FINAL GUIDELINES
Based upon the revised guidelines, EPA
estimates that the most likely economic impact in
terms of capital expenditures will be $4.0 billion in
constant 1974 dollars over the next decade. Of
this total, $2.7 billion will be required to meet the
thermal and $1.3 billion to meet the chemical regula-
tions.
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The following brief table summarizes the
timing of these capital expenditures:
CAPITAL EXPENDITURES
(Billions
Baseline Conditions
+Thermal
+Chemical
Total Impact
Percent of Baseline
of 1974
1974-77
$53
$ 0
0
$
1
1
.4
.3
.7
.0
.9%
Dollars)
1978-83
$125
$ 2
0
$
3
2
.6
.4
.6
.0
.4%
1984-90
$219.
$ 1.
0.
$
2.
1.
8
8
5
3
0%
In the short run, the final guidelines would increase
the capital requirements of the industry by less than
2 percent. The impact through the early 1980s increases
to 2.4 percent as a result of conversion to closed-cycle
cooling required by the thermal guidelines. Finally,
the long-run impact is estimated to be approximately
1 percent.
In addition to increasing capital expendi-
tures, the regulations will cause an increase in opera-
tions and maintenance expenses. This increase in
expenses results from the costs associated with oper-
ating closed-cycle cooling systems and chemical cleanup
systems, from costs required to operate additional
capacity needed to offset the reduction in generating
efficiency, and from the costs attendant with generation
capability lost during the installation period. These
annual operations and maintenance expenses are expected
to increase by 1.0 percent during the next decade.
The ultimate economic impact of the guide-
lines is reflected in the average cost of electricity
to the consumer. Increased capital and operating ex-
penditures are expected to increase the cost of elec-
tricity by 0.4 mills per kilowatt-hour by 1983. This
represents less than a 2 percent increase in the future
cost of electricity.
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IMPACT UPON ENERGY DEMAND AND BALANCE OF TRADE
Compliance with the final guidelines will both.
increase fuel consumption within the industry and in-
crease the trade deficit resulting from the importation
of petroleum products. The impact of the regulations
will increase the demand for coal by less than 1.0 per-
cent and for oil by approximately 0.1 percent by 1983.
The added demand for petroleum products under the most
adverse conditions will amount to approximately 18,000
barrels per day which would increase the trade deficit
by a maximum of $80 million in constant 1974 dollars.
ASSESSMENT OF ENVIRONMENTAL RISK
EPA commissioned a separate environmental
survey that concluded that 18 percent of the total gen-
eration capacity operating in 1983 would be potentially
of high risk, where high risk was defined as a plant
whose effluent discharge was of potential danger to
fish or wildlife in nearby waterways.
Compliance with the regulations requires
almost half of these high risk plants be converted to
closed-cycle cooling systems. By 1983, therefore, only
10 percent of the nation's generation capacity will be
considered high risk, and while these remaining high
risk plants will be exempted from compliance with the
guidelines, all may be covered by water quality stan-
dards established by the various states.
CONCLUDING COMMENT
Compliance with the water pollution regula-
tions - while amounting to a large number of dollars -
is small when compared with the total needs of the
industry. The relative impact ranges from 1 to 2 per-
cent depending upon the particular economic measure.
In addition, the magnitude of the economic
impact pales when compared to the reduction in re-
sources projected to be needed by the industry in the
next decade. To illustrate, capital expenditures
attribiitable to the final guidelines are expected to
total $4.0 billion during the next decade; yet the re-
cent decline in industry growth will reduce the capital
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expenditures originally projected by more than $25
billion. If the electric utility industry could
have met the capital requirements projected prior
to last winter, they should experience little
trouble meeting the added requirements to comply
with the final guidelines.
This is not to say that the industry is
without problems - in fact, it is currently in dire
financial straits (see Chapter I). But the plight
of the electric utility industry is not intimately
tied to the environmental movement. Rather, the
problems of the industry evolve from other conditions
within the industry. The decision of EPA to delay
the major expenditures until the 1980s should ease
the short-term capital crunch and provide an adequate
period for the underlying problems to be corrected.
GUIDE TO THE REPORT
The full report consists of seven chapters
and attendant exhibits and appendices.
• Chapter I surveys the environment of
the electric utility industry since
1960 and traces the events which have
led up to its current economic and
financial problems.
• Chapter II details the baseline
operating conditions projected through
1990 without regard for the require-
ments associated with meeting
environmental standards.
• Chapter III provides an evaluation of
the economic impact resulting from the
final guidelines, both thermal and
chemical.
• Chapter IV outlines the economic
analysis of a set of alternatives
representative of the many options
which were evaluated prior to the
selection of the final guidelines -
including the guidelines proposed in
March 1974.
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• Chapter V details the potential
impact that the water quality standards
set by the individual states could have
on those existing generating units not
covered by the final guidelines.
• Chapter VI summarizes the environ-
mental risk associated with the final
guidelines and with some of the other
options considered.
• Chapter VII compares the economic
impact that results from using the
underlying assumptions submitted by
the Utility Water Act Group.
The appendices provide an overview of the
research methodology employed.
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TEXT
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I, THE CHANGING NATURE OF THE
ELECTRIC UTILITY INDUSTRY
(1960 - 1973)
INTRODUCTION
The importance of electrical energy can
hardly be overstated. The use of energy in all its
forms in the United States has been growing at a
compound annual rate of 4.4 percent since 1960. During
the same period, however, the use of electrical energy
has been growing at 7.3 percent and now consumes in
the generating process 23 percent of all forms of energy
used in the country - up from 16 percent in 1960.
The industry that produces this energy - the
electric utility industry - truly has been one of the
great growth industries in the American economy, enjoying
favorable trends in almost every factor affecting its
growth and profitability. Some time in the latter half
of the 1960s, however, significant changes began to
occur in the industry when a multiplicity of events
took place within a relatively short span of years.
These large changes were not the usual downturn in
demand or influx of competition that have signalled a
turn-about in many other growth industries. Demand
continued to grow steadily - even accelerate - while
the competitive situation did not change from the
regulated monopoly status long enjoyed by companies
within the industry. A much different type of change
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-8-
began to affect the industry, and as a result, a dramatic
uncertainty began to envelop the electric utility
industry.
This uncertainty made itself felt across a
range of factors - from load projections to costs for
new capacity and fuel to financing capabilities. The
list could go on and on, each factor contributing its
weight to the problem of generating a fair return and
financing growth in a way equitable to investors and
consumers alike. The day of predictability and relatively
secure decision-making ended; in its place came days
of uncertainty and genuine concern over the most ap-
propriate way to meet the demands and challenges now
facing the industry.
INDUSTRY STRUCTURE
The electric utility industry is composed of
three basic kinds of companies - investor-owned,
publicly owned, and co-operatives. The publicly owned
utilities could be further categorized into those owned
by state and local governments and those owned by the
federal government. There are slightly in excess of
3500 separate electrical systems in the United States,
almost two-thirds of which are publicly owned. Over
73 percent of the publicly owned and co-operative systems
in the country are engaged in distribution only. By
contrast, most of the approximately 500 investor-owned
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electric utilities are engaged in generation, transmission,
and distribution.
The types of firms in the electric utility in-
dustry differ considerably in generating capacity and
in production of electrical energy. Investor-owned
utilities - the smallest category in terms of number
of systems - have by far the most capacity and generate
the most electricity. The following table illustrates
the generation capacity relationships that existed within
the industry for the year 1973;
GENERATION CAPACITY (1973)
Investor- Publicly
Owned Co-operatives Owned
78% 2% 20%
These generation capacity relationships have not
changed much over the years. There has been a slight
shift toward investor-owned and co-operatives and away
from publicly owned over the past fifteen years, but
this change has been very small. The relationship among
the types of utilities with respect to the production of
electrical energy has followed a pattern nearly identical
to that shown above for generation capacity. That is,
investor-owned utilities generate about 78 percent of all
the electrical power in the United States, while co-
operatives and publicly owned utilities generate about
2 percent and 20 percent respectively.
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Th e generation facilities of the electric
utility industry can be divided into four general
types, depending entirely upon the kind of prime
mover used to drive the generator. These four are as
follows: fossil fuel-steam, hydraulic, nuclear-steam, and
internal combustion. The relationships and the changing
nature of these relationships are shown in the following
brief table:
Year
1960
1973
GENERATION
Fossil-Steam
79%
80%
BY TYPE OF
Hydraulic
19%
14%
PRIME MOVER
Nuclear-
Steam
_
5%
Internal
Cumbustion
2%
1%
This shift towards nuclear and away from hydraulic instal-
lations has been accelerating in recent years, not because
the country's hydro-electric capacity is being reduced,but
because the rate of new hydro-electric additions
is much slower than the rate of growth of nuclear
capacity additions. The trend toward nuclear generating
stations is expected to continue, and some observers
believe that nuclear could account for as much as 20 per-
cent of total generating capacity by the early 1980s.
The relationships in the kind of fuel used in
the generating stations throughout the country have changed
in the past years, although coal still makes up by far
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the largest portion of the fuel used by the industry,
The following brief table illustrates these changing
relationships:
GENERATION BY TYPE OF
Year
1960
1973
Coal
66%
54%
Oil
8%
20%
Gas
26%
21%
FUEL
Nuclear
-
5%
Much of this shift in the fuel mix toward oil has
been brought on by the need to burn low sulfur
fossil fuels and by the increasing shortage of natural
gas. State and local environmental restrictions required
the use of low sulfur fuels, a requirement much more
easily met with oil than with coal. In addition, the
abundance of residual fuel oil refined from low priced
foreign crude oil - particularly on the East Coast -
hastened this trend. With respect to natural gas,
electric utilities have been low priority users and are
suffering severe curtailments as the shortage deepens.
In light of the costs and availability of fossil fuels,
however, it is likely that the beginning trend toward
nuclear fuel will continue and even accelerate, while
oil will decline in importance.
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THE SECURE YEARS - 196Q-1966
Beginning with the time when statistics for
the electric utility industry began to be kept, electrical
energy production never failed to double every nine or
ten years. That kind of growth in the demand for energy,
together with improving technology and receptive capital
markets, made this industry very dynamic. Not only were
the trends favorable, but the predictability of the key
factors affecting the industry was high. Load
characteristics were well understood and variability
from historical trends was small. Capital investment
planning presented few difficulties. The various cost
factors were under control, generally declining, and
predictable. Given the regulatory climate, revenues
were also predictable. Finally, all this added up to
good financial results for the industry - and a good
reception in the capital markets.
DEMAND PREDICTABLE
The demand in very few industries was as
predictable as that in the electric utility industry, and
very few utilities had difficulties with their pro-
jections. Beginning in 1960, and continuing until 1966,
for instance, total consumption of energy in the entire
industry grew at a relatively constant average annual rate
of 6.9 percent. The year-to-year increase ranged only
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between 5.5 percent and 7.7 percent, and the last three
successive years very nearly had identical increases.
At the company level, of course, more variability occurred,
but even there, much of the variation was the result of
factors such as growth in population, growth in households,
industrial activity and the like - things well known to
the individual utilities. Inability to forecast the
growth in energy consumption was not a pressing problem
of the day.
In a similar fashion, forecasting peak demand
posed no more serious a problem. Throughout the early
1960s, the annual non-coincident peak load for the industry
as a whole grew at an average annual rate of 7.0 percent,
and the growth percentage ranged only from 6.0 percent
to 8.5 percent - a relatively narrow range, particularly
when compared to the events of subsequent years. Once
again, individual companies experienced a similar narrow
range of growth in their annual non-coincident peaks.
Exhibit 1 illustrates the relative predictability of
growth in both total energy and peak demand. In 1966,
things began to change and real uncertainty became a
factor.
The annual, non-coincident peak load is the higher of the two
non-coincident peak loads reported by the Edison Electric
Institute ~ summer and December - each, of which is the sum of
the peak loads of all systems during that time period with-
out respect to the particular day it may have occurred in
each system.
IT
B
s|
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Because growth in both consumption of energy
and peak load were so predictable, so too was annual load
factor." Load factor for the industry experienced virtually
no changes through the early 1960s, going from 65.5
percent in 1960 to 65.0 percent in 1965 and never varying
far from that range. Exhibit 2 illustrates the re-
markable stability in load factor experienced by the
industry.
INVESTMENT PLANNING NOT DIFFICULT
Throughout the early part of the 1960s,
capital investment planning presented few difficulties.
This exercise, of course, begins with the forecast of
energy demand and peak load for several years ahead - and
growth in these two key areas was relatively predictable.
So energy and peak load requirements were known with a
high degree of certainty. In addition, the kind of
capacity to add was not much of a mystery in those days.
Utilities were adding large baseload plants to achieve
the economies of scale available to them, retiring their
older, less efficient plants or reducing them to cyclic
or even peaking use. To illustrate, peaking plants made
up only 3 percent of total generation additions in the
early 1960s. More recently, the appropriate mix of new
2. Annual load factor is the ratio of total electric energy output
for a year in kilowatt-hours to the maximum non-coincident peak
load in kilowatts multiplied by 8760 (number of hours in
a year) - 8,784 in leap years.
ITIBIS
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capacity has become more of an issue, and peaking plants
made up 17 percent of total new capacity in the past
seven years. Nuclear decisions were beginning to be
made by the more adventurous utilities, but very little
nuclear capacity was brought on prior to 1969, and the
current technical and environmental problems were not
as sharply defined in those days as they are now.
The investment impact of adding the capacity
necessary to meet the growing demand was quite predictable.
First, the cost of new capacity per kilowatt was stable
or declining slightly throughout the 1960s. Exhibit 3
shows that the cost per kilowatt of installed capacity
was constant during the first four years of the decade,
then declined somewhat for three years, and finally
finished the decade at about the same cost level as it
started. Second, investment in electric plant per
dollar of revenue remained quite constant at around
$4.46. Exhibit 4 illustrates the remarkable consistency
of investment per revenue dollar through 1966. Third,
capital expenditures rose a very small amount in the early
1960s. Exhibit 5 indicates that these expenditures rose
from $3.3 billion in 1960 to $4.0 billion in 1965, an
average annual increase of only 4.0 percent over the
period. Given this stability and the techniques avail-
able to project capital expenditures for new capacity,
industry members were able to forecast capital needs with a
high level of confidence.
COSTS UNDER CONTROL AND PREDICTABLE
Throughout the early years of the 1960s,
the cost of producing and distributing electricity
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declined slowly but surely. Thus, the ability of
utility managements to predict and project their
costs was very good. Exhibit 6 shows that the total
cost per kilowatt-hour (defined as operating revenue
less net income from sales of electricity - thus, the
figure represents all costs associated with the genera-
tion and sale of electricity) declined consistently from
16.3 mills per kilowatt-hour in 1960 to 14.9 mills in
3
1966. Much of the decline resulted from reductions in
the per kilowatt-hour cost of two major cost components:
operations and maintenance, and interest - also shown in
Exhibit 5. The remainder of the decline was due largely
to a reduction in the per kilowatt-hour cost of taxes,
both income and non-income.
The reduction in operations and maintenance
cost was due in large part to the economies of scale
resulting from the newer, larger baseload plants brought
on-stream during this period, and to the continually
increasing electrical usage per customer. The per
kilowatt-hour fuel cost declined during this period due
to the combination of reduction in fuel cost per
4
million BTUs and an improved heat rate. Finally, the
3. The data in this 'exhibit and in all subsequent exhibits
which utilize financial analyses of balance sheet or income
statement items have been adjusted by TBS to reflect electric
operations only.
4. Heat rate, a measure of generating station thermal efficiency,
is the amount of BTUs in the fuel consumed to generate one
kilowatt-hour of electric energy.
iTlBTSJ
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per kilowatt-hour costs of interest went down, this
occurring in spite of a rise in the embedded interest
rate from 3.6 percent to 3.9 percent during this seven
year period. Growth in total energy sales greatly
outdistanced this rise in interest rate, and unit cost
of interest went down.
REVENUES ALSO PREDICTABLE
The task of projecting revenues throughout this
period was not difficult. Growth in electric revenues
was steady and reasonably consistent, moving from $10.1
billion in 1960 to $13.4 billion in 1965, a total
growth over the period of 32 percent. That growth averaged
5.8 percent per year, with year-to-year growth ranging
only from 5.4 percent to 6.8 percent (see Exhibit 7),
This growth in overall revenues occurred in spite of
generally declining electric rates and a significantly
lower revenue per kilowatt-hour (5.9 percent total
decline over the period) due to more and more electric
energy being sold in the lower blocks of the block
5
rate schedules prevalent in the industry. Exhibit 8
illustrates the declines in these two factors.
Revenues increased during this period because
declines in rates and revenues per kilowatt-hour were
more than made up by increases in the numbers of customers
(extensive growth) and by increases in the average
kilowatt-hour usage per customer (intensive growth).
5. In a block vote schedule, a specified charge per kilowatt-hour
is made for all kilowatt-hours falling within a block of
such units, with reduced charges per unit for all or any part
of succeeding blocks of such units.
TBS
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Exhibit 9 indicates that the number of customers grew
11.4 percent from 1960 to 1965, and the kilowatt-hours
sold per customer grew 25.3 percent - by far outweighing
the 5.9 percent decline experienced in revenues per
kilowatt-hour. The result was steady growth in industry
revenues - consistent and reasonably predictable, even
at the company level.
FINANCIAL RESULTS GOOD
The revenue growth and the cost stability
and control experienced through the 1960s led to good
financial results. The electric utility industry per-
formed well in all of the usual measures of financial
performance - net income, earnings per share, return
on equity, and return on total investment - during this
period. This performance is shown in Exhibit 10. The
figures in this exhibit have been adjusted to illustrate
performance on electrical plant and operations only -
all gas and other operations have been taken out of
these industry figures. The results are as follows:
• Net income increasing each year from
$1.7 billion in 1960 to $2.4 billion
in 1965, an overall increase of 42.9
percent.
• Earnings per share increasing each year
from $4.12 in 1960 to $5.92 in 1965, an
average annual growth rate of 8.7 percent.
• Return on equity improving significantly
from 11.7 percent to 12.9 percent.
• Return on total investment also improving
from 6.4 percent to 7.2 percent.
TBS
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This kind of financial performance - together,
of course, with the generally favorable investment
climate - led to good acceptance in the financial
markets for the common stocks of the utility industry.
Price earnings ratios improved from 16.9 in 1960 to
19.8 in 1965. And, together with a constantly increasing
book value per share, the ratio of market price of an
average utility share to its book value improved from
1.69 to 2.22 during the same period. Exhibit 11 illustrates
the year-to-year performance of these two indicators of
investment climate.
The result of this favorable investment climate
was relative latitude on the part of investor-owned utility
management in financing their growth. On the whole,
utility managers took a "conservative" approach, opting
to use debt to finance a constant 60 percent of external
requirements over the years, thereby shifting their
capital structure slightly toward equity and away from
debt as the availability of internally generated funds
increased constantly. Exhibit 12 illustrates this small
but consistent move toward equity and away from debt
during the 1960-1965 period. Exhibit 13 illustrates
the increasing importance of internally generated funds,
along with the fact that, while debt as a portion of
external funds utilized each year remained essentially
constant, even it was trending downward as a portion of
all fund sources as internally generated funds became
m
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more of a factor. Thus, growth financing was a relatively
easy task for utility management throughout this period.
In short, the early part of the 1960 decade
was a very good one for utility management. The problems
that existed were predictable, manageable problems.
Uncertainty was at a minimum and the trends and climate
of those days made dealing with what uncertainty did
exist a very reasonable proposition. Changes in the
situation were in the wind, but the impacts were to be
felt later.
THE TURNING POINT - 1966-1969
Everything that caused the great changes in
the electrical utility industry did not happen all at
once, nor did they all come from the same root factor.
Rather these events occurred during the latter part of
the 1960 decade, and most of the events themselves
were trends that were picking up momentum during this
period. Of the many things that were to have dramatic
impact on this industry, five will be mentioned briefly
here.
CREDIT CRUNCH
While it can be argued that the cost of money
was destined to go up anyway as the economy began to
TIBIS
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overheat in the late 1960s, the credit crunch of 1966
caused a dramatic rise in the cost of money. Picking
Moody's industrial bond rate as an example, this rate
in 1965 had remained virtually constant for seven years.
Then it moved steadily upwards until in 1970, the bond
rate was almost double what it had been five years
earlier (See Exhibit 14). The cost - and ultimately
the availability - of debt has obvious implications to
the electric utility industry. In the late 1960s began
the trend and problems destined to play an enormous
role in the current difficulties facing the industry.
INFLATION
Chronic inflation has been an irritant in the
economy for some time, but by the late 1960s, there was no
question that the rate of cost increases for most com-
panies was outrunning productivity gains. The Vietnam
war fueled the situation, sowing the seeds for a later
rate of inflation that was intolerable. Most important
for electric utilities, inflation was particularly felt
in the capital goods industries, thereby increasing the
cost of building new utility plants - an event destined
to have a profound effect on the utility companies.
EQUIPMENT SHORTAGES
Parts and equipment shortages began to appear
in the second half of the 1960 decade. Much of this was
due to capacity shortages in an overheated economy.
TlBlS
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The result for the electric utility industry was delays
in new plant construction with the attendant higher
ultimate costs that such delays invariably bring - higher
capital costs because the complete project required
longer financing prior to being placed in service, and
higher operating costs because newer, more efficient
plants did not get on-stream when expected and utilities
were forced to rely on more costly older plants or more
expensive purchased power in the meantime.
ENVIRONMENTAL MOVEMENT
The momentum of the environmental movement
really gained steam in the late 1960s. The impact
of this movement on the electric utility industry
was felt in two principal ways. First, it affected
the cost of fuel to utilities as state and local govern-
ments placed increasing importance on environmental
protection. New York City and other cities and states
placed sulfur restrictions on fuels, and these restric-
tions increased the cost of fuel to electric utilities.
Second, environmental protection caused some delays in
the construction programs of many utilities. Siting,
safety, and operating permits were all problems. These
delay difficulties caused higher costs for utilities
in the same manner as the delays from equipment short-
ages mentioned earlier raised ultimate costs of plant
additions.
TIBIS
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FUEL COST INCREASES
The cost of fuel has always been an important
component in the cost of electric power. And until
the latter part of the 1960s the cost pressures were
downward. Productivity improvements in the coal in-
dustry, together with an abundant supply of interruptible
and off-peak gas, kept the prices of fuel down. Then
the cost of all fuels began to rise. The closing of
the Suez Canal in 1967 caused tanker rates to increase,
and at about the same time, the oil exporting countries
began upward revisions in both posted prices and taxes.
The result, of course, was higher priced oil. The
price of coal also began to go up, spurred by the rise
in the price of oil and also by the need for investment
to improve health and safety conditions and by the rise
in foreign demand for metallurgical coal. Finally,
the Federal Power Commission began to permit
increases in the price of interstate natural gas.
This obviously impacted those utilities dependent on
that fuel source, but it also tended to release some-
what the ceiling on alternative fuels, thereby allowing
the price of coal and oil to rise.
Thus, the credit crunch, inflation, equipment
shortages, the environmental movement, and fuel cost
increases - all events that started to be felt in the
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late 1960s - combined to change the electric utility
industry in dramatic ways. The impact of these changes
will be discussed in the following section.
THE DILEMMA YEARS - 1969-PRESENT
The result of the events of the late 1960s
was a significant change in the nature of the electric
utility industry. Gone is the relative certainty in
the key factors affecting the industry. In that place
are uncertainty and a difficult operating environment.
The events of the late 1960s impacted most
severely in two ways - the requirements for external
financing are up dramatically, and the costs experienced
by the industry are up significantly. The following para-
graphs describe the nature and effects of these two
areas in more detail.
EXTERNAL FINANCING UP
By any measure the industry's use of external
financing went up dramatically since the mid-1960s.
Exhibit 15 illustrates that while external funds as a
percent of all funds averaged about 46 percent in the
early 1960s (Exhibit 13 showed that this percentage
was actually trending downward), the ratio is now
averaging 66 percent - and until very recently had been
climbing steadily. This dramatic shift in the nature
IrlBlsl
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of satisfying financing requirements is probably the
single most important thing to happen to the industry in
recent times. There are several reasons why this
occurred.
The first factor underlining the increase
in external financing is an acceleration in the rate of
growth of both energy consumption and peak load. Exhibit 16
indicates that where the growth in kilowatt-hours had
averaged 6.9 percent in the early to mid-1960s, since that
time the average year-to-year growth through 1973
has been 7.5 percent. In a similar fashion, growth
in peak demand was now averaging 8.0 percent on a year-
to-year basis, rather than the 7.0 percent experienced
throughout the early 1960s. Thus, peak load has been
growing faster than total consumption in kilowatt-hours
since more and more of the consumption was occurring
during peak hours. This in turn created a deteriorating
load factor (65.0 in 1965 to 62.0 in 1973) and a
corresponding need for proportionately more capacity
than had been the case. The industry simply was being
required to satisfy a significantly larger and some-
what less level appetite for electrical energy than
it had been in the early part of the 1960 decade.
Providing the additional capacity to meet this
additional requirement for electrical energy obviously
increased the industry's need for funds from some source,
internal or external.
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A second factor affecting the need for increased
external financing was the predictability of growth in
energy consumption and in peak demand - because of
their potential influence on reserve margins. The
primary influences affecting the desire of utility
management for increased reserve margins were the
greater difficulty in handling an outage with ever
larger units coming on line and the unknown probabilities
of nuclear plant outages. But the predictability of
growth in consumption and peak load has been deteriorating
since the mid-1960s, and this deterioration was to
serve as an influence on utility management both to
provide increased peaking capacity, thereby affecting
construction plans, and to plan for an increased level
of reserve margins. Exhibit 16 shows that the standard
f~*
deviations of the year-to-year growth rates for both
energy consumption and peak load have increased signifi-
cantly since that time: the variability of total
consumption increasing over 60 percent and that of peak
load increasing by 100 percent. All these influences
worked to complicate and increase construction plans
and thus financing needs.
A third factor contributing to the great
increase in total financing - and thus ultimately an
increase in external financing - is the dramatic rise
in the cost per kilowatt of newly installed capacity. This
cost had been relatively constant throughout the 1960 decade,
but Exhibit 17 indicates that this cost had increased dra-
matically since that time. The cost per kilowatt of
6, Standard deviation is a measure of variability of items
in a series from the average of that series.
irlBls
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capacity installed in 1974 was averaging about $266 -
almost double the cost of 1970. And this trend toward
ever increasing unit cost of new capacity is expected to
continue. A recently completed survey conducted by the
Technical Advisory Committee on Finance of the current
National Power Survey (TAC-Finance) indicates that new
capacity recently committed to go on stream in 1980 will
ultimately cost an average of $390 per kilowatt for non-
nuclear plants and over $450 for nuclear plants, not in-
cluding pollution control devices.
One impact of this rise in the cost per kilowatt
of newly installed capacity has been an acceleration in the
rate of growth of capital expenditures being made by the
industry. Exhibit 18 indicates that capital expenditures -
relatively constant in the early 1960s - have grown well
over threefold since that time; this growth greatly ex-
ceeds the growth in consumption of energy and in peak demand.
There are several reasons for the great rise
in the unit cost of new capacity. First, general
construction costs have continued their inexorable
rise, and the string seems to have run out on the
economies of scale in building ever larger generating
facilities. Thus, there was no offset to the escalating
construction costs as there had been throughout the
1960s. Second, regulatory and construction delays have
increased the time needed to construct a new plant, and
this lag - exacerbated by the rise in interest rates and
the yearly rise in construction costs - has worked to
increase the final cost of completed capacity. Third,
the shifting capacity mix toward nuclear with its higher
TIBIS
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capital costs (but lower operating costs) was beginning
to make itself felt in the average cost per kilowatt of
installed capacity, and this fact will weigh heavily on
the average unit cost projected for the latter part of
this decade. Finally, investments to meet safety
and pollution control requirements were also contributing
to the rise in unit costs of the new capacity. Thus,
costs were rising, obviously creating a need for funds
proportionately greater than had been experienced in
the early 1960s.
A fourth factor causing external financing
needs to increase substantially in both absolute and
relative terms is the simple fact that since the mid-
1960s, internally generated funds (largely retained
earnings and depreciation) have not been growing as
fast as the requirement for funds. Exhibit 19 in-
dicates that during the early 1960s, internally
generated funds grew at an average annual rate of 6.4
percent while the need for funds grew at a rate of
only 2.5 percent. And in only one of those years
(1962-63) did the year-to-year growth rate of internal
funds fail to exceed the growth rate for the need for
funds. A great contrast has existed since then. The
average annual growth of internally generated funds
since 1965 has increased to 9.5 percent, but the need
for funds has grown almost twice that fast - an 18.1
percent average rate over that same period. And in
the eight years since 1965, the year-to-year growth rate
in need for funds exceeded the growth rate in internal
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funds every year - often substantially - until the
last two years. The difference between financing
requirements and internally generated funds obviously
had to be made up with external financing, and as was
shown earlier in Exhibit 15, this was just exactly the
case.
COSTS UP SIGNIFICANTLY
The second major area impacted severely by
the events of the late 1960s was that of the costs
being experienced by the industry. Costs of producing
and distributing electricity declined during the early
1960s. Then these costs turned around and started
to climb. Exhibit 20 indicates that the total costs
per kilowatt-hour grew from 14.9 mills in 1966 to
17.3 mills in 1973, a 16 percent increase in cost after
years of decline. This increase is accounted for largely
by the rise in operating costs - especially fuel costs -
and in interest costs. As the exhibit shows, other
costs declined a total of 1.0 mills per kilowatt-
hour over the period, due mostly to reduced income taxes
and the increase in allowance for funds used during
construction (to be treated in a later section). Thus,
the increases in operating costs and interest costs are
more significant than might be apparent.
Total operating costs have gone up from 8.1
mills to 10.4 mills per kilowatt-hour since 1966
TIBIS
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(see Exhibit 20), but the great bulk of this increase
is due to a 57 percent increase in the per kilowatt-hour
cost of fuel. There were two reasons for this dramatic
turn-around in the costs of fuel. First, the heat rate
realized by the industry failed to continue its annual
improvement. At best, the heat rate is now static - in
fact, it has not regained the performance experienced in
the late 1960s. Second and more important, fuel cost
per million BTU reversed its slow decline of the early
1960s and has increased significantly since then. Exhibit 21
illustrates the turn-around in annual declines of these
components of unit fuel costs. The result is much
higher fuel costs per kilowatt-hour.
Interest costs per kilowatt-hour - as were
shown in Exhibit 20 - have almost doubled since 1965,
going from 1.1 mills to 2.1 mills in that period of time.
There are two major reasons for this increase. First,
the general cost of borrowing money increased significantly
during this period - the industrial bond rate moved
from 4.8 percent in 1965 to 7.9 percent in 1973. Second,
utilities were borrowing proportionately more money
during this period - Exhibit 15 indicated that the use
of external funds increased from 46 percent to 66
percent - and a significant portion of those funds were
debt. Thus, it was inevitable that the embedded
interest rate would increase (it did - from 3.6 percent
in 1965 to 5.8 percent in 1972). And total interest
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expense attributable to electric operations was up
dramatically - $3.3 billion in 1973 compared to $0.9
billion in 1966 - an average year-to-year rate of in-
crease of over 20 percent per year. Because the growth
of energy consumption grew at an annual rate of 7.5
percent over this period, it was equally inevitable that
interest costs per kilowatt-hour would also increase.
The significant increase in the use of
external financing and the higher cost levels at which
the electric utility industry must now operate are the
primary underlying causes of the current dilemma.
Simply stated, the industry cannot delay the great in-
vestments needed to maintain its service capability, but
the financing of those investments is becoming increasingly
difficult. There are three other factors contributing
to this dilemma - each one somehow the result of the
underlying causes discussed earlier and each more im-
mediate in nature. First, the return on equity in the
industry is down. Second, the market value of the
industry's common shares is less than their book value.
Third, growth in earnings per share is down and prospects
for improvement do not appear bright. Each of these
factors is discussed briefly in the paragraphs that
follow.
RETURN ON EQUITY DOWN
The total earnings performance of the electric
utility industry has been outstanding. Exhibit 22
TIBIS
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indicates that net income from electric operations was
$4.46 billion in 1973, double what it had been nine
years earlier. Further, in recent years net income
for any given year never failed to increase over the
preceding year. Equally important, earnings growth within
the industry accelerated. Exhibit 22 shows that while
the average growth of net income in the industry had been
8.6 percent during the early 1960s, it has been 10.9
percent ever since. This impressive earnings performance
is somewhat clouded, however, by the increasing role
that the allowance for funds used during construction
(AFDC) plays in the earnings picture.
For some years, the allowance for funds used
during construction - a credit to income for the interest
costs paid on funds tied up in construction work in
progress - has been becoming an increasingly larger portion
of net income (see Exhibit 23). In 1973, AFDC had
reached a high of almost 29 percent of industry net
income. The concept of AFDC heretofore has been well
accepted by utilities, accounting firms and rate com-
missions alike - the problem is that it is a non-cash
credit to net income. Therefore, the cash flow available
to utilities from their earnings streams is only about
71 percent of what they report.
Although industry net income has been up very
nicely in recent years (10.9 percent average annual
growth), the rate of growth of equity capital was even
IrlBlsl
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greater. Exhibit 24 points out that utility management
has not changed its capital structure significantly
in recent years. Thus, equity capital - in the form of
both retained earnings and funds from common stock issues -
has financed its historical share of the increasingly
larger construction programs. Exhibit 25 indicates
that total equity has been growing at an average annual
rate of 12.9 percent since 1966, significantly in
excess of the rate of growth of net income. Thus, as
is shown in Exhibit 26, return on equity declined from
13.1 percent in 1966 to 11.7 percent in 1973. This
reduced return on equity can be attributed to regulatory
lag - the tendency for rate increases granted by the
commissions to lag behind the cost increases that insti-
gated the request for rate relief in the first place.
Thus, rate commissions have not moved quickly enough
to prevent a general decline in the industry's return
on equity.
MARKET VALUE OF COMMON SHARES BELOW BOOK
A much higher rate of return on utility
industry common stock is required by investors than
had been the case some years ago. This increased rate
of return requirement is due to two primary reasons.
First, inflation generally has driven up the rate of return
on riskless securities such as government bonds. Thus,
the rate of return required on common stock would be
IrlBlsl
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driven up correspondingly because the market place
always maintains an appropriate differential between
the return required of riskless securities and that
required of riskier equity securities. Second, the
investment community appears to be assigning a higher
degree of risk to the electric utility industry than
it had in the past. The increase in risk assessment
obviously has its roots in the uncertainty that now
pervades the industry - what will earnings do, what
will regulators allow, will consumers revolt over fuel
cost pass-throughs, and the like? Exhibit 27 indicates
that the price earnings ratio has gone from an average
19.8 in 1965 to an average 9.4 in 1973, and more recently
stood at 6.1 in June 1974. The decline in price
earnings ratio is a definite indication that the rate
of return demanded from the industry's common stock
7
by the financial community has increased .
In the face of a higher demanded rate of
return on the electric utility industry's common stock,
the regulators of the industry have maintained the
allowable rate of return on equity at figures close to
or actually below historical levels (Exhibit 26).
Therefore, the industry's equity securities began to sell
at a discount from previous market levels. Exhibit 28
indicates that this discounting trend continues to this
7. The decline in price earnings ratio is also caused by a
deterioration in future expectations for the industry 's
common stock by potential investors. Concern exists both.
over prospect for continued growth in earnings per share
(discussed in the next section) and over the likelihood of a
stagnant or diminished dividend in light of uncertain earnings
prospects and the great demand for internally generated funds.
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-35-
day, and more importantly that the industry's common stock
now sells at a level below its book value. (In June 1974
the average market price of common stock was very
close to half of book value.) Issuing common stock at a
time when the market value is less than book value
dilutes earnings per share and contributes to driving
the market price per share down even further.
EARNINGS PER SHARE GROWTH DOWN
The growth in earnings per share in the
electric utility industry has taken an abrupt turn
in the last decade. Exhibit 29 indicates that the
earnings per common share have been increasing at an
average annual rate of 2.8 percent since 1966, this
comparing with an annual growth rate of 8.7 percent
during the 1960-65 period. This slowdown in the growth
rate of earnings per share - in spite of an acceleration
in the growth rate of total net income - is due to two
factors. The first is the decline of return on
equity discussed earlier. The second factor is that the
increase in outstanding shares of common stock has
been almost as great as the rate of growth of net
income in the industry. The average annual increase
in the number of outstanding shares of common stock in
the industry has been just over 7.5 percent since 1966.
This compares with an average increase in total industry
net income of 10.9 percent annually (Exhibit 22) during
the same period. Thus, a large portion of the incremental
earnings in any given recent year was needed simply to
assure the maintenance of current earnings per share
ITlBlS
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for the newly issued stock. By contrast, the annual
increase in common shares during the early 1960s was
about 2 percent compared to an annual net income
growth of 8.6 percent - thus, in that period the great
bulk of incremental earnings went to increase overall
earnings per share, not just to cover new common shares.
Prospects for an improved earnings per share
growth picture do not appear bright. Net income for the
industry is highly likely to continue its growth, but
the amount of new equity that must be issued to cover
the capital expenditure programs - at a time when the
common stock sells below book value - will only
serve to dilute the growing net income even further.
A deteriorating earnings per share, rather than a
reduced but positive growth, may characterize the
industry in the years ahead. And 1973 bore that out,
with average earnings per share of $7.55 compared to
$7.73 the year before.
SUMMARY
Thus, utility management presently finds it-
self confronting a painful dilemma. They must make
enormous investments in facilities, and they must raise
large amounts of external funds to finance this invest-
ment. They cannot increase significantly their use of
debt or preferred stock - capital structures must be kept
balanced and earnings coverage requirements must be met.
That leaves no alternative save the issue of common stock.
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Yet if they issue common stock, they do so at a discount
to book value, thereby diluting earnings further. And
the diluted earnings may serve to cause additional deter-
ioration in the investment community's assessment of
future earnings prospects and risk in the utility in-
dustry, thus further reducing the ratio of market
price to book value of common stock. The result is a
snowballing effect. The more common stock that is
issued, the lower its price, and the more shares that
must be issued. And so on it goes.
Looking to the future, even more uncertainty
looms for the electric utility industry. Plant expen-
ditures per kilowatt seem certain to escalate, but
estimates are highly uncertain. Construction delays
for such reasons as inter-regulatory problems, non-
availability of equipment, technical problems, and pol-
lution control problems may well continue, even accelerate
Financing the great requirements of the industry has no
easy solution - particularly when the near-term outlook
for the industry is in the hands of forces external to
utility management.
Of the many forces acting upon the electric
utility industry, three deserve specific mention. The
first is the combination of forces which determine the
prices of energy supply. The industry itself has very
little influence on the prices it must pay for fuel. Yet,
the recent rapid escalation in the prices of fossil fuels,
together with the fuel adjustment clauses which pass
TBS
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these increases on to consumers, has aroused an adverse
public opinion which could result in a significant
movement toward public ownership. A second external
force is the economic climate to which the capital
markets respond. To meet its financing requirements
over the years ahead, the industry requires both a
resurgence of investor confidence and a relaxation in
long-term interest rates. This climate can be affected
only by public policy makers outside the industry. A
third external force affecting the outlook for the
electric utility industry is in the hands of those
who establish regulatory policy. The existing regulatory
climate exhibits no unifying structure, and as evidenced
by inadequate allowed returns and declining actual re-
turns, is detrimental to the continued viability of the
industry in its existing form.
It is within this industry context that the
following analysis of the impact of the Federal Water
Pollution Control Act should be evaluated.
TIBISI
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II, BASELINE ELECTRIC UTILITY INDUSTRY PROJECTIONS
(1974-1990)
INTRODUCTION
In order to discuss the economic and the
financial implications of the Federal Water Pollution
Control Act (Act) and its final guidelines, it is
important to establish a point of reference from
which comparisons can be made. In doing so, the
uncertainties inherent in forecasting conditions
within the electric utility industry which are un-
related to the Act should be segmented from those
associated with the Act. This reference point
requires the establishment of a set of baseline
conditions which exclude any impact associated with
existing state and local environmental standards,
as well as federal standards as specified in the
Act and the Clean Air Act of 1970, as amended. Thus,
the baseline projections represent what utilities
would expend in the absence of environmental regulations
The baseline projections to be described in
this report closely parallel the operating and fin-
ancial assumptions employed by the National Power
1. The following analysis does not consider the economic
impacts associated with the Clean Air Act of 1970 or
any other environmental legislation not directly re-
lated to the Water Act.
-39-
TIBIS
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Survey's Technical Advisory Committee on Finance
(TAC-Finance). In fact, all operating and financial
assumptions not directly related to pollution control
o
equipment were those specified by the TAC-Finance.
The research methodology to be employed
herein is based upon a computerized model of the
electric utility industry which was developed by
Drs. Howard W. Pifer and Michael L. Tennican of
Temple, Barker and Sloane, Inc. (TBS). This model -
entitled a Policy-Testing model (PTm) - is one of
a series of industry models developed by TBS to
project the economic and technical implications of
alternative policy options in the form of industry
structure, rates and method of expansion, financial
strategies, regulatory actions, taxation policy,
economic conditions, etc. PTm (Electric Utilities)
was initially developed to provide industry-wide
projections for the above-mentioned TAC-Finance.
Appendix A provides a non-technical overview of the
logical structure of this computer-based model.
In projecting future operating and financial
conditions within the electric utility industry,
TBS by necessity had to develop its initial esti-
mates in current dollars - that is, expenditures in
1980 were measured in 1980 dollars. Since depreciation,
2. These assumptions correspond to those incorporated into
the TAC-Finance Cases I and IA.
TlBlS
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interest charges, and net income allowed are deter-
mined primarily by historic costs while other
expense items are determined by current cost levels,
all financial transactions within PTm are in current
dollars. Likewise, all operating and financial
assumptions have been reported in current dollars.
However, all economic and financial implications
summarized in this report have been converted to
1974 constant dollars in order to provide a frame
of reference for comparisons. This conversion
from current to constant dollars utilized the overall
5 percent inflation factor proposed by the National
3
Power Survey for planning purposes. In order to
minimize the possible misinterpretations of the
results of this study, all exhibits will be clearly
marked as to the dollars employed, and amounts
reported within the text will be constant 1974
dollars unless otherwise specified. In general,
the following rules of thumb will be employed in
the exhibits:
• operating and financial assumptions
will be projected in current dollars, and
• economic and financial implications will
be reported in constant 1974 dollars.
The initial conditions for the industry were
3.While this long-run inflation factor may appear somewhat low
in comparison with current rates, all cost escalation factors
were developed relative to this rate. Thus, a shift in the
underlying inflation factor would impact all of the other
escalation factors, and would have an insignificant impact
on these data reported in constant 1974 dollars.
TBS
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developed from the most recently published data -
from 1972 Federal Power Commission's Statistics of
Privately-Owned Electric Utilities in the United States. With
these published data as the basis for the investor-
owned sector, the TAC-Finance estimated that the
public sector would be represented as one-fourth of
4
the investor-owned sector.
The remainder of this chapter will specify
the operating and financial assumptions which comprise
the industry baseline conditions, project the
economic and financial implications that follow
from these assumptions, and compare these projections
with those based upon the historic industry growth
rate. The baseline conditions developed in this
chapter will then serve as the basis for an evaluation
of the relative impact of the final guidelines in
later chapters.
INDUSTRY STRUCTURE
The electric utility industry is actually
the aggregation of two principal sectors which, while
providing essentially the same service, differ signif-
icantly in structural characteristics. These sectors
are the investor-owned (i.e., private) firms and
4. This 80-20 mix differs slightly from the actual industry
relationship reported in Chapter I. For this reason,
industry totals reported herein may differ slightly from
actual results prior to 1974.
5. For purposes of projecting industry trends, the TAC-Finance
arbitrarily included co-operative utilities within the public
sector. In addition, the basis for the initial conditions
within the private sector is the Class A and B investor-owned
utilities.
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public agencies (i.e., federal, state and municipal).
In addition, there are fundamental accounting differences
between those investor-owned utilities allowed by
their regulatory commissions to normalize income
tax expenses and those firms required to flow
through the benefits of accelerated depreciation
and other tax deferrals.
In order to develop industry-wide projections,
the TAC-Finance assumed the following industry structure
with respect to the mix of public and private firms,
as well as the proportion of states (weighted by size)
which require investor-owned firms to employ flow
through accounting procedures:
• publicly owned 20 percent
• investor-owned 80 percent
—normalized accounting (48 percent)
—flow through accounting (32 percent)
Given the relative importance of the utilities
in the private sector and the paucity of cogent infor-
mation on the financial characteristics of those
in 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.
[TlBIS
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Electrical energy historically has been
generated primarily by fossil-fueled steam electric
plants - coal, oil and gas - nuclear steam electric,
hydroelectric and peaking units (internal combustion
and gas turbines). Recent trends and future pro-
jections suggest that a major source of future
generation will be nuclear-fueled. For this reason,
the TAC-Finance segmented generation capacity into
c
two categories: nuclear and non-nuclear.
GENERATING CAPACITY
Perhaps the most critical set of assumptions
made by the TAC-Finance relates to the rate of
growth for the electric utility industry in the period
through 1990. Until the recent "energy crisis,"
industry observers assumed that the current rate of
growth - which implied a doubling in size each decade -
would continue through the 1970s with a gradual decline
coming during the 1980s. Events during the winter
of 1973-74 have altered these assumptions so that
most observers now forecast a moderation in the rate
7
of growth. For these reasons, the TAC-Finance lowered
6. This latter category must be further refined in order to
isolate the proportion of non-nuclear (i.e., fossil-fueled
steam electric) capacity which may require pollution control
equipment.
7. Electrical World, which publishes a comprehensive forecast
each year, has substantially lowered its most recent
forecast (15 September 1974).
ITIBISI
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its most-likely estimate of future growth from the
historic rate of growth.
In addition to assuming that the long-run
rate of growth would be moderate, the TAC-Finance
attempted to estimate the short-run implications of
the recent Arab oil embargo and its related impacts.
These short-run aberrations could affect any or all
of the following:
• rate of growth in peak load demand,
• peak load reserve margins,
• rate of retirement for generation capacity,
• mix of nuclear and non-nuclear genera-
tion capacity additions, and
• capacity factors.
The TAC-Finance assumed that the growth in peak load
would be dramatically reduced from the growth rate in
excess of 9 percent that prevailed in the early
1970s. The growth in peak load was assumed to drop
off to 1 percent in 1974 with a gradual improvement
to 4 percent in 1975 and 6.5 percent for the remainder
of the decade. Peak load growth in the 1980s was
assumed to decline to 6 percent in the early 1980s
and 5.5 percent in the latter half of the decade.
With the sudden decline in the peak load
growth rate, reserve margins were expected to increase
from 20 to 26 percent by 1975 because the generation
capacity under construction could not, in the short run,
TlBlSl
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be delayed. Construction would, however, be curtailed
for those units planned to be placed in service in
the late 1970s, thus permitting reserve margins to
gradually return to approximately 20 percent.
Exhibits 30 and 31 provide the detailed factors which
impact the growth of generation capacity and the
resultant capacity additions, retirements and totals.
During the period 1974-77, generation
capacity will increase by nearly 100 million kilowatts -
an annual growth rate of 5.3 percent. Another 200
million kilowatts will be added during the 1978-83
period with an annual growth rate of 5.7 percent.
By 1990 generation capacity will exceed one billion
kilowatts, an increase of 5.6 percent per year and an
increase in generation capacity of nearly^ 340 million
kilowatts during the 1984-90 period.
These net additions to generating capacity
include the retirement of obsolete non-nuclear
generating capacity assumed to retire at the
rate of:
• 1974-75 0.4 percent per year
• 1976-80 0.7 percent per year
• 1981-90 1.2 percent per year
irlBls
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While much publicity has preceded the con-
struction of nuclear-fueled generating plants, a small
percentage of the generating capacity in service in
1973 was nuclear-fueled. Although environmental and
technical issues have delayed the conversion to a
nuclear-based electric utility industry, the TAC-
Finance has assumed that the mix of generating
capacity "will steadily shift to nuclear generation.
Specifically, the TAC-Finance has assumed that the
mix of generating capacity additions will be:
1974-75 30 percent nuclear/
70 percent non-nuclear
1976-80 40 percent nuclear/
60 percent non-nuclear
1981-85 50 percent nuclear/
50 percent non-nuclear
1986-90 60 percent nuclear/
40 percent non-nuclear
The growth in sales of electricity to
ultimate consumers differs from the growth in capacity
due to the assumptions regarding capacity utilization
as measured by the capacity factor. The TAC-Finance
assumed that the demand for electricity will decline
somewhat between 1973 and 1975 due to a decline of
approximately 10 percent in the capacity factor. This
drop in generation efficiency results from the
above-mentioned decline in peak load growth and the
corresponding inability to curtail construction
ITIBIS
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in the short run. The industry's response to the
energy crisis is manifested in the sharp improvement
in the late 1970s and the return to a capacity
factor of nearly 50 percent during the 1980s.
Exhibits 30 and 31 provide the year-by-year capacity
factor assumptions and the resulting growth in
electricity sales to ultimate consumers.
t
CAPITAL COST FACTORS
In an effort to assess the capital cost
escalation facing the electric utility industry,
the TAC-Finance conducted an informal survey of
existing utility construction plans through 1980.
The survey covered 20 utilities which were constructing
a total of 75 generating units during this period.
On the basis of this survey, the TAC-Finance developed
the cost growth factors detailed in Exhibit 32. The
general inflation rate of 5 percent proposed by the
National Power Survey for planning purposes was
then used as the basis for cost growth for trans-
mission and distribution and as the basis for post-
1980 inflation in the costs of generation capacity.
Although the generating capacity, related
transmission and distribution equipment, and nuclear
fuel placed in service in any given year is determined
by the peak load and reserve margin requirements, the
IrlBlsl
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actual 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 work in progress account
historically have constituted a substantial portion
of the capital expenditures by the electric utility
industry in any given year.
In order to approximate the cash progress
payments related to construction requirements, the
TAC-Finance assumed the payment schedules outlined
in Exhibit 33. For example, a $100 million nuclear-fueled
generating unit (with an additional $15 million for
nuclear fuel) placed in service in 1980 would require
cash payments of:
Nuclear Plant Nuclear Fuel
1976 $25 million
1977 $25 million
1978 $25 million
1979 $25 million
1980 - $15 million
Likewise, a $100 million fossil-fueled generating unit
placed in service in 1980 with $100 million in related
transmission and distribution equipment would require
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cash payments of
1977
1978
1979
1980
Fossil Plant
$25 million
$25 million
$25 million
$25 million
Transmission and
Distribution
$50 million
$50 million
OPERATING COST FACTORS
In addition to capital expenditures, a
primary target of cost inflation has been operations
and maintenance expenses which include expenditures
for fossil fuels. Prior to the recent "energy
crisis" the cost growth of operations and maintenance
expenses for non-nuclear generation approximated 10
percent, while operations and maintenance expenses
for nuclear generation (excluding fuel) were relatively
stable. With the rapid increase in the price of
petroleum products resulting from the oil embargo,
the limited supply of natural gas and significant
disparity between inter- and intra-state natural
gas prices, and the steady increase in coal prices,
the TAC-Finance assumed that operations and maintenance
expenses associated with non-nuclear (primarily fossil-
fueled) generation would escalate at 20 percent
during 1974 and 15 percent in 1975 before falling to
8 percent in the late 1970s. At that time, these
expenses were assumed to increase steadily at the
TIBIS
-------
-51-
long-run inflation rate of 5 percent. In addition,
operations and maintenance expenses for nuclear
generation (excluding fuel) also were assumed to
escalate at the 5 percent rate. Exhibit 34 details
these expenses.
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 regu-
latory agencies. These financial parameters are
especially prominent in any projection of the electric
utility industry with its long lead time for construction
of generation plant and its capital intensity.
CAPITALIZATION
In projecting the capital structure of the
industry, the TAC-Finance assumed that the capital
structure will remain relatively stable. The mix of
financing instruments for investor-owned utilities,
therefore, is determined within PTm by the following
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
TIBISI
-------
In addition to projecting the capital structure,
one needs to forecast the future cost of each
financing instrument.
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 1972, the embedded rate for each was approximately
5.5 percent, a rate significantly below the existing
long-term rate of interest. Acknowledging this fact,
the TAC-Finance assumed an 8 percent rate for interest
on long-term debt and dividends on preferred stock for^
its projections. Without a significant change in the
mix of financing instruments, the return on common
equity, the common stock dividend payout ratio, or
some combination of these factors, these conditions
wherein the marginal debt rates exceed the embedded
rates will result over time in lower interest and
8
preferred dividend coverage ratios.
In addition, the TAC-Finance assumed that
average consumer charges per kilowatt-hour will be
set at levels which yield a 14 percent return on
common equity. It should be noted that this assumption
8. For example, the assumptions implicit in these baseline
conditions result in the interest coverage ratio,
defined as Earnings Before Interest Charges and Income
Taxes divided by Interest Charges, declining from 3.9
in 1974 to 3.1 in 1990.
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is consistent either with a target 14 percent return
and no regulatory lag or a target rate in excess of
g
14 percent with time lags in the regulatory process.
In addition, a stable dividend policy which results
in a 70 percent dividend payout ratio was employed.
Regulatory agencies in the past have re-
quired electric utilities to capitalize a portion of
the financing charges associated with the funds
tied to construction work in progress. In 1972,
the allowance for funds used during construction (AFDC)
approximated 6.4 percent of construction work in
progress. The TAC-Finance projected this constant
rate for AFDC.
For the public sector, the TAC-Finance
simply assumed that 65 percent of total financing
requirements will be met from external sources.
ACCOUNTING PRACTICES
Internal cash generation in an industry as
capital intensive as the electric utilities depends
heavily upon the accounting procedures employed.
As previously mentioned, this analysis assumes that
the electric utility industry is segmented into public
9. In recent years the actual return on common equity has been
between 11 and 12 percent. Previous analysis for the TAC -
Finance has shown that varying the required rate of return
on common equity, while perhaps affecting the ease with
which additional financing can be obtainedt has minimal
impact upon the amount of additional financing required.
ITIBIS
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and investor-owned firms with the latter group of
utilities further divided into those which are re-
quired to use normalizing techniques and those which
use flow through accounting procedures. While al-
ternative accounting practices change significantly
both the timing of the cash flows from generating
capacity additions and the revenues required, the
actual liberalized depreciation policies and in-
vestment tax credit policies apply equally to both
groups.
The TAC-Finance assumed straight-line depre-
ciation over 33 years for regulatory and financial
accounting purposes. Tax depreciation figures are
the maximum allowed and make use of the asset depre-
ciation range (ADR) and the double-declining balance
depreciation provisions within the tax code. An
exception to the above is nuclear fuel which is
depreciated on a four year, straight-line basis for
both tax and regulatory purposes. In addition, a 4
percent investment tax credit is permitted on 80
percent of capitalized expenditures.
TAXES
Taxes within PTm have been segmented into
federal and state income taxes as well as additional
taxes other than on income. In developing its projections
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the TAC-Finance specified these tax rates in the
following way:
federal income tax
rate 48.0 percent
state (and local)
income tax rate 4.8 percent
other taxes as a
percent of revenues 10.5 percent
As has been outlined above, the operating,
financial, tax, regulatory, and accounting parameters
and constraints relevant to making economic and finan-
cial projections for the industry are individually
rather simple. However, because of interactions
among the various industry relationships and constraints,
attempts to reduce the number of factors through shortcut
approximations are hazardous. Furthermore, such
10. An example of the reconciliation of taxes within PTm is
provided in Appendix B.
11. To illustrate the point concretely3 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 expenditures in the current and past years; and
the reduced asset lifetimes, the accelerated methods of depre-
ciation, the investment 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 distribu-
tion 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.
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shortcuts - even if based on careful econometric
analyses of historical data - would tend to preclude
an examination of implications of structural and
policy changes.
ECONOMIC AND FINANCIAL IMPLICATIONS
The preceding assumptions regarding genera-
tion capacity, capital and operating cost factors,
and financial parameters define the baseline conditions
for the electric utility industry. Exhibit 35 pro-
vides selected summary data in constant 1974
dollars for specific years. In addition, Appendix B
provides an example of the level of detail captured
by PTm.
CAPITAL EXPENDITURES
Capital expenditures are defined as the
sum of expenditures for plant and equipment placed in
service and the change in construction work in
progress (CWIP) during any given year. For example,
the baseline projections for the next decade (1974-83)
indicate that capital expenditures will be $203.2
billion in constant 1974 dollars. This amount can
be further segmented into $179.0 billion for plant
and equipment placed in service during the period
plus an increase in CWIP of $24.2 billion. These latter
expenditures should be allocated to the future period in
12
which the equipment is placed into service.
12. This adjustment to capital expenditures - while not done in the
summary data exhibits - will be explicitly included in the tables
referenced throughout the text.
ITIBISI
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EXTERNAL FINANCING
External financing requirements are the sum
of long-term debt, preferred stock and common stock
issues in any given year, including the refinancing
13
of maturing long-term debt. These requirements
during the next decade are expected to total $126.3
billion in constant 1974 dollars - approximately
62 percent of total capital expenditures during the
same period. The difference between capital expen-
ditures and external financing requirements in any
given year is the amount of funds generated inter-
nally in the form of retained earnings, depreciation
and tax deferrals less the refundings of long-term
debt.
OPERATING REVENUES
Operating revenues in the investor-owned
sector are those required to yield a 14 percent rate
of return on average common equity. Public sector
revenues are then based on the same revenue per
kilowatt-hour. In 1983, total operating revenues are
projected to be $74.7 billion in constant 1974
dollars.
0/M EXPENSES
Operations and maintenance expenses include
A schedule of long-term debt refundings through 1990 has
been estimated from published sources and in no year exceeds
$1.7 billion. Further, the TAC-Finance assumed that no
new long-term debt issues will mature prior to 1990.
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those items so defined by the Federal Power Commission
in its Statistics of Privately-Otined Electric Utilities in
the United States with the exception of nuclear fuel.
For example, the 1983 operations and maintenance
expenses are estimated to be $38.0 in constant
1974 dollars.
CONSUMER CHARGES
Consumer charges are the average amount per
kilowatt-hour which is being paid in any given year.
The amount of electrical energy consumed is based
upon the growth in peak load demand, the reserve
margin and the capacity factor. For example, the
1983 sale of electrical energy to ultimate consumers
amounts to 3160.8 billion kilowatt-hours and is
obtained from:
• 1973 peak load demand of 351.8
million kilowatts,
• growth in peak load demand between
1973 and 1983 of approximately 5.5
percent per year,
• reserve margin of 20 percent,
• capacity factor of 49.9 percent, and
• 8760 hours per year.
The average consumer charge per kilowatt-hour
is then obtained by dividing operating revenues by
the total electrical energy consumed. The average
cost of electricity in 1983 is projected to be
ITIBIS
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23.6 mills per kilowatt-hour.
SUMMARY OF BASELINE CONDITIONS
The following brief table summarizes the
industry baseline conditions for selected time periods.
14
BASELINE
(1974
Capital Expenditures
in billions
0/M Expenses
in billions
External Financing
in billions
Consumer Charges in
mills/KWH at end
of period
CONDITIONS
Dollars)
1974-77 1974-83
$53.4 $179.0
35.8 126.3
92.0 292.5
24.0 23.6
1984-90
$219.8
146.3
311.2
22.4
Thus, even without the added expenditures required to
meet the Act's effluent guidelines, the industry is
expected on an annual basis to expand as follows:
14. These same time periods will be employed throughout the
subsequent analysis of the Federal Water Pollution Control
Act,
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RATES OF GROWTH IN SELECTED STATISTICS
(1974
Electric Energy
Generation Capacity
Capital Expenditures
External Financing
Operating Revenue
0/M Expenses
Consumer Charges
Dollars)
1974-77
4.3%
5.3
6.5
7.8
7.4
10.5
2.9
1974-83
5.5%
5.7
7.4
8.4
6.6
7.9
1.0
1984-90
5.6%
5.6
4.7
4.1
4.9
3.8
-0.7
The moderation of the growth in electric
energy is somewhat offset by the short-run increase
in reserve margins and decrease in capacity factors.
The growth of both electric energy and generation
capacity in the 1980s are equivalent due to a
return to stable reserve margins and capacity factors
The capital expenditures required by the industry
in the next decade are projected to grow at a rate
in excess of capacity additions since cost escalation
in the construction industry is expected to exceed
the economy's overall rate of inflation. Likewise,
external financing requirements during the next 10
years will continue to rapidly escalate due to the
assumed growth in cost factors and the inability of
the industry to increase its internal cash generation
under existing government policies. As inflation
ITIBIS
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abates and stability returns to the electric
utility industry in the 1980s, the growth rate of
capital expenditures and external financing will
slacken.
Operating revenues are projected in the
short run to increase by approximately 7 percent due
to the rapid, near-term escalation in the price of
fossil fuels and the limited utilization of nuclear
generation. In the 1980s - with the reversal in
these two trends - the growth in operating revenues
will subside to a rate less than that of electric
energy. Thus, the average consumer charges in
constant 1974 dollars per kilowatt-hour will
actually decline during the 1980s after a mild rate
of increase in the next decade.
HISTORIC GROWTH ASSUMPTIONS
All of the above results were based upon
a moderation in the historic rate of growth within
the industry. Prior to this report and the forthcoming
TAC-Finance report, TBS analyses for both the
National Power Survey and EPA were based upon an his-
toric rate of growth. While the TAC-Finance develops
the implications of this rate of growth in its Case 2,
the committee no longer believes that these assumptions
represent the most-likely set of industry projections.
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In order to provide continuity among
reports and to detail the economic and financial
implications of a moderation in industry growth,
TBS analyzed the generation capacity growth assumptions
contained within the TAG-Finance Case 2. It should
be noted, however, that the historic growth assumptions
differ from those previously reported in EPA's
Economic Impact of Proposed Effluent Guidelines - Steam
Electric Power Generating (Maroh, 1974) since they also
reflect the short-run impact of the recent "energy
crisis." In representing the case with historical
industry growth, the TAC-Finance assumed that peak
load would decline to 3 percent in 1974 and 5 per-
cent in 1975 before returning to the historic
rate of doubling every decade (that is, 7.2 percent
per year) for the remainder of the 1970s. Peak
load growth in the first half of the 1980s was
assumed to decline to 6.7 percent with a slight
erosion to 6.6 percent in the second half of the
1980s.
With the near-term decline in peak load
growth, reserve margins were projected to increase to
28 percent by 1975 as generation construction could
not be delayed in the short run. Reserve margins
were expected to steadily decline to 20 percent by
the beginning of the 1980s. Exhibits 36 and 37
provide the detailed factors which impact the growth
of generation capacity and the resultant capacity
additions, retirements and totals. The following
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brief table compares these differences for
selected periods:
NET CAPACITY ADDITIONS
(Millions of Kilowatts)
1974-77 1978-83 1984-90
Historic Growth 125.7
Moderate Growth 97.5
Absolute Difference 28.2
Percent Difference 22.4%
237.4 445.2
203.5 339.0
33.9 106.2
14.3% 23.9%
The overall reduction in capacity additions
between historic and moderate growth range from
20-25 percent in both the short and long run with
a reduced difference in the late 1970s and early 1980s,
Overall, these differences result in approximately a
9 percent reduction in the total generation capacity
of the industry during the next decade and a reduction
of nearly 16 percent by 1990.
With the exception of a slight difference
in the capacity factor during the late 1970s, no other
differences in industry operating and financial con-
ditions were varied between the moderate and historic
growth scenarios.
TIBIS
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Exhibit 38 displays the detailed economic
and financial projections based upon an historic
growth rate for selected years, while Exhibits 39
to 41 summarize the impact of reduced growth for
selected years. While many comparisons could be
made between the alternative growth rate assumptions,
perhaps the most important ones - in terms of
evaluating the impact of the Act's effluent guide-
lines - are the reductions in capital expenditures
and external financing requirements associated with
a moderation in the rate of demand growth as the
following brief tables summarize:
CAPITAL EXPENDITURES
(Billions of
Historic Growth
Moderate Growth
Absolute Difference
Percent Difference
1974 Dollars)
1974-77
$72.9
60.3
$12.6
17.3%
1974-83
$241.2
203.2
$38.0
15 . 8%
1984-90
$314.0
238.2
$ 75.8
, 24.1%
EXTERNAL
(Billions of
Historic Growth
Moderate Growth
Absolute Difference
Percent Difference
FINANCING
1974 Dollars)
1974-77
$45.4
35.8
$ 9.6
21.1%
1974-83
$154.4
126.3
$ 28.1
18 . 2%
1984-90
$201.2
146.3
$ 54.9
27.3%
ITIBIS
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As these tables indicate, the moderation
in demand growth has a significant impact upon the
investment levels required in the next decade - and
an even greater impact in the long run. Given the
changing nature of the electric utility industry
described in the previous chapter, this decline
in the rate of growth should ease the financial
problems facing the electric utility industry.
In addition, this reduction in industry
growth should be compared to the additional require-
ments imposed by the effluent guidelines - to be
detailed in the following chapter - in order to
determine the degree to which these environmental
requirements exacerbate the previously-mentioned
problems now evident within the electric utility
industry.
TBS
-------
Ill, ANALYSIS OF THE FINAL
EFFLUENT GUIDELINES
INTRODUCTION
On 8 October 1974, the Environmental Pro-
tection Agency published in the Federal Register
(39 FR 36186) final effluent guidelines and standards
for steam electric power generation. These final
guidelines differed markedly from the 4 March 1974
announcement of proposed rulemaking in the 'Federal
Register (39 FR 8294).
These modifications to the guidelines were
based, in part, on the following analyses:
• economic analyses performed by
Temple, Barker and Sloane, Inc. (TBS)
and herein contained,
• analyses of environmental risk for
alternative effluent limitations per-
formed by Energy Resources Company, Inc
(ERCO), and
• comments submitted by the Utility Water
Act Group (UWAG).
The next five chapters provide, on a consistent basis,
the different analyses of economic costs and environ-
mental risk which were performed to assist EPA in its
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rulemaking. This report does not reference the inde-
pendent analyses which were performed by EPA personnel
and which formed the basis for the alternative policies
and operating assumptions examined.
This chapter describes the operating and
financial assumptions upon which the final guidelines
were based and provides the resulting economic
analyses both before and after consideration of
exemptions under Section 316(a) of the Act and after
consideration of those utilities who are in the process
of installing closed-cycle cooling facilities for
reasons other than environmental requirements. Chapter
IV briefly describes the major alternatives which were
evaluated in addition to the proposed and final effluent
guidelines. Chapter V discusses the potential economic
and financial impact emanating from environmental
requirements associated with State Water Quality
Standards. These three chapters comprise the bulk of
the analyses which were performed for EPA by TBS.
Chapter VI details both the underlying
methodology and analysis of the potential environmental
risk associated with alternative effluent guidelines.
The contents of this chapter are based upon Development
of Decision Rules for Granting Variances to Thermal Power Plants
on a Specific Site Basis, a report submitted to EPA by
ERCO and herein summarized by TBS.
TBS
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Chapter VII compares and contrasts the major
operating and financial assumptions employed by EPA and
UWAG. This analysis was performed by TBS with assistance
from National Economic Research Associates, Inc. (NERA)
who served as economic advisors to UWAG.
STRUCTURE OF ASSUMPTIONS
In an attempt to estimate the economic and
financial impact of the Act, EPA first specified the
technical standards which were to be required in its
Development Document of Effluent Limitations Guidelines
and New Source Performance Standards for the Steam Eleatrio
Power Generating Point Source Category (forthaoming). Having
specified the technical standards, EPA was then asked
to specify the operating and financial assumptions which
best represented the requirements imposed by the final
effluent guidelines and segmented into thermal and
chemical discharges.
In specifying those assumptions which were
most closely associated with the structure and operating
conditions of the electric utility industry, EPA relied
upon the assumptions of the National Power Survey's
Technical Advisory Committee on Finance (TAC-Finance).
These assumptions were detailed in the previous chapter.
In addition, EPA specified all factors which were
directly related to the effluent guidelines. These
factors included (1) capital and operating costs which
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were based upon technical standards, and (2) capacity
coverage and in service operation dates for pollution
control equipment.
The specifications of these operating and
financial assumptions directly related to the
final effluent guidelines and technical standards
have been divided into thermal and chemical categories
with .each then further segmented into:
• capital and operating cost factors,
• capacity coverage estimates, and
• installation schedules.
THERMAL CAPITAL AND OPERATING COST FACTORS
EPA relied upon the best available engineering
estimates as the basis for the capital and operating
cost factors which are detailed in Exhibits 42 and 43.
These capital cost estimates are based upon
(1) a survey of costs incurred at existing plants, and
(2) the incremental cost of installing mechanical
draft cooling towers instead of open-cycle cooling on
new.units. These final cost estimates reflect the many
comments which were submitted to EPA and which with minor
exception (as described in Chapter VII) were acceptable
to most representatives of the electric utility industry.
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In specifying the capital costs associated
with the installation of closed-cycle cooling processes,
EPA segmented such costs into those required for both
nuclear and fossil (i.e., non-nuclear) steam electric
generating units; and, for each type of generation, the
installation of closed-cycle cooling on:
• existing generating units and/or units
under construction which were designed
for open-cycle cooling - "retrofitted"
units, and
• generating units under construction
which were designed for closed-cycle
cooling and/or are assumed to meet
new source performance standards at
time of in service operation - "new"
units.
The capital costs per kilowatt of generating
capacity are summarized in the following brief table:
CAPITAL COST OF CLOSED-CYCLE COOLING
(Expressed in 1972 Dollars/Kilowatt)
Non-Nuclear Nuclear
For Retrofitted Units $20.43 $24.58
For New Units $ 4.89 $ 3.84
These capital costs expressed in 1972 dollars were then
converted to current dollars utilizing the escalation
factors detailed in Exhibit 42.
TIBIS
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Clearly, the process of installing closed-
cycle cooling on units which currently have open-cycle
cooling and/or which are under construction and were
designed for open-cycle cooling is much more expensive
than the installation cost of closed-cycle on new units.
This results from the need to (1) dismantle and/or
redesign the existing cooling system, and (2) absorb
the total, not incremental, cost of the additional
closed-cycle cooling facilities. The lower incremental
cost for nuclear units being planned reflects their
higher cost for open-cycle cooling - a result of
plant sites located at considerable distance from sources
of cooling water.
The operating costs associated with thermal
guidelines represent the annual operating and main-
tenance expenses for the cooling equipment as well as
associated replacement capacity. In estimating the
operational impacts of closed-cycle cooling, EPA
specified a capacity penalty of 3 percent which re-
flects:
• 2 percent due to increased turbine
back-pressure, and
• 1 percent due to operating require-
ments for the cooling tower.
The fuel costs employed for this analysis of operating
costs were based upon: (1) an average heat rate of
10,000 BTU per kilowatt-hour, (2) a fuel mix of 80
TIBlS
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percent coal and 20 percent oil, and (3) 1974 prices
of $7.00 per barrel for oil and $12.50 per ton for
coal.
The annual operating costs per kilowatt of
replacement generation capacity are summarized in the
following brief table:
ANNUAL OPERATING COST FOR REPLACEMENT CAPACITY
(Expressed in 1972 Dollars/Kilowatt)
Non-Nuclear Nuclear
For Retrofitted Units $39.41 $39.41
For New Units $39.43 $23.12
In determining the type of replacement capacity, EPA
assumed that retrofitted units were replaced by
new fossil baseload units operating at a capacity factor
of 60 percent. New units were replaced by like capacity
nuclear with nuclear, fossil with fossil - operating at
an estimated 70 percent capacity factor.
In addition, EPA assumed that the installation
of closed-cycle cooling on existing units or units
under construction but designed for open-cycle cooling
would require a downtime period of one month in addition
to the normal maintenance period. During this period,
it was assumed that the lost generation capability would
ITIBISI
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be made up by utilization of peaking capacity with an
incremental increase in heat rate of 2,500 BTU/KWH
(12,500 less 10,000) with the same fuel mix and fuel
costs used in computing the total operating costs
for replacement capacity.
These outage cost factors are summarized in
the following brief table:
THERMAL OUTAGE COST FACTORS
(Expressed in 1972 Dollars/Kilowatt)
Non-Nuclear Nuclear
For Retrofitted Units $1.08 $0.89
THERMAL CAPACITY COVERAGE ESTIMATES
An evaluation of the impact of the thermal
guidelines should include not only those expenditures
which are associated with conversion from open- to
closed-cycle on units existing or under construction
and with new source units, but also some proportion of
those units which are under construction and designed
for closed-cycle cooling wherein the cooling system
design was influenced by anticipation of the Act. At
the same time, however, units designed for closed-cycle
cooling for reasons other than environmental (i.e.,
for economic reasons) should not be included in an
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assessment of the economic and financial impact of the
Act. A majority of the units which have installed
closed-cycle cooling for economic reasons have done so
to compensate for an inadequate source of cooling
water.
In specifying the percentage of capacity ,
which will be required to install closed-cycle cooling
to meet the thermal guidelines of the Act, EPA has
segmented generating units into four major categories
by date of in service operation:
• existing units which have open-cycle
cooling (placed in service prior to
1974),
• units under construction which were
designed for open-cycle cooling (placed
in service 1974-78),
• units under construction which were
designed for closed-cycle cooling
(placed in service 1974-78), and
• units assumed to meet new source perfor-
mance standards at the time of in service
operation (placed in service 1979-90).
These categories facilitate a further differ-
entiation of generating units into those which are
required by the thermal guidelines to convert from
This category was specified for analytic purposes and does not
necessarily coincide with the legal definition of flew Source
Performance Standards (NSPS). The legal definition states that
all sources which commence construction after promulgation of
the final guidelines (that is, 4 October 1974) must meet NSPS.
TBS
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open- to closed-cycle cooling (i.e., "retrofitted" units)
and those which are designed for closed-cycle cooling
for reasons related to the Act (i.e., "new" units).
As previously referenced, PTm segments
generating capacity into nuclear and non-nuclear units.
Since the thermal guidelines impact only those units
which are steam electric, EPA estimated the proportion
of non-nuclear units which would be fossil-fueled,
steam electric. The following figure graphically
displays these assumptions:
o%
100
Existing Capacity
(prior to 1974)
Capacity Under
Construction
(1974-1978) .
New Source
Capacity
(1979-1990)
83%
TIBlS
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EXISTING UNITS
The degree to which existing units would be
required to retrofit mechanical draft cooling towers
was a major policy variable in EPA's specification of
alternative guidelines to be evaluated. EPA reviewed
a number of potential criteria for exemptions from
thermal control. Two criteria which were explicitly
recognized in the specification of the final guide-
2
lines were the age and size of existing generating units.
The proposed guidelines published in March
1974 exempted all small units (defined by the Federal
Power Commission as units in plants of 25 megawatts
or less and in systems of 150 megawatts or less in
total capacity) and all units which were scheduled for
retirement prior to 1990. The final guidelines exempt
all units placed into service before 1970 from the require-
ments to meet the limitations on the discharge of heat.
Of the units placed into operation between 1 January
1970 and 1 January 1974, only the largest baseload
units (i.e., those of 500 megawatt capacity or greater)
are subject to effluent control under the Act. In
addition to the age of the unit, the specification of
these exemptions explicitly includes unit size as a
factor.
2. A full list of the criteria considered by EPA can be found
in the Federal Register(39 FR 36288). Alternative guidelines
which were evaluated by TBS are described more fully in
Chapter IV.
ITIBISI
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These exemptions greatly reduce the propor-
tion of existing units which are covered by the thermal
guidelines. Based upon analysis performed by ERCO,
EPA estimated that these final regulations would cover
45.8 percent of existing nuclear capacity and 4.6
percent of existing non-nuclear capacity prior to any
consideration of additional exemptions under Section
316(a) of the Act.
Section 316(a) of the Act specifies that any
unit can be exempted from effluent limitation which 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 into which the discharge is to be
made." EPA commissioned ERCO to conduct a separate
analysis of the afore-mentioned environmental risks
3
associated with existing generating units. Based
upon this analysis, EPA estimated that only 12.9
percent of nuclear and 2.2 percent of non-nuclear
capacity placed into service prior to 1974 (i.e.,
existing units) would be required to convert from
once-through to closed-cycle cooling after the
consideration of Section 316(a) exemptions. These
capacity coverage estimates are graphically presented
in Exhibits 44 and 45.
3. A summary of the ERCO analysis is provided in Chapter VI.
TIBISI
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UNITS UNDER CONSTRUCTION
Simply stated, all steam electric generating
units placed in service on or after 1 January 1974 are
required to install closed-cycle cooling. However,
the impact of the thermal guidelines upon generating
units now under construction must be segmented into
two categories since the cost of retrofitting a
unit designed for once-through cooling is significantly
greater than the cost of installing mechanical draft
cooling towers or an equivalent technology whenever
the unit was designed for such equipment.
In estimating the required coverage for units
under construction (i.e., placed in service 1974-78),
EPA first segmented this capacity into that which had
been designed for (1) open-cycle, once-through, and (2)
closed-cycle cooling.
All steam electric generating units which
were designed for once-through cooling were assumed to
require conversion prior to the Section 316(a) exemption
while only those units which were assessed to impose a
high environmental risk were required to meet the
thermal guidelines after this process. These cover-
age estimates were: 50 percent of nuclear and 31 per-
cent of non-nuclear capacity before Section 316(a)
exemptions, and 27.7 percent of nuclear and 10.6
percent of non-nuclear capacity after Section 316(a)
exemptions.
TIBISI
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In addition to these conversions from open- to
closed-cycle, the remainder of steam electric generating
units now under construction are planning to install
closed-cycle cooling systems. As previously stated, some
proportion of these units may be doing so in anticipation
of the Act's final guidelines - and therefore, should
be included in an assessment of the Act's economic and
financial impact. Likewise, those units which are
installing closed-cycle cooling for economic reasons
should be evaluated but should not be included in
measuring the overall impact of the Act. EPA has
estimated that the remaining 50 percent of nuclear and
49 percent of non-nuclear capacity to be placed in
service 1974-78 are planning to install closed-cycle
cooling. Of these, EPA estimated that one-half
were doing so for environmental reasons and the other
one-half for economic reasons. Since all of these units
are designed for closed-cycle cooling, EPA further assumed
that none would have adequate time or economic justifica-
tion to convert to open-cycle cooling if they were eligible
for Section 316(a) exemptions. Exhibits 44 and 45 graphically
present these capacity coverage estimates.
NEW SOURCE UNITS
Once again, all.steam electric generating
units are required to install mechanical draft cooling
towers or their equivalent - however, new source units,
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defined herein as those units placed in service after
1978, are assumed to install closed-cycle cooling
for operation at the time the units are placed in
service. Of the units to be placed in service after
1978, 100 percent of nuclear and 75 percent of non-
nuclear (i.e., 100 percent of fossil steam electric)
capacity are assumed to be covered before Section 316(a)
exemptions. Coverage after these exemptions is
assumed to be 72.3 percent of nuclear and 56.6 percent
of non-nuclear generating capacity. In addition,
EPA has estimated that 34.5 percent of nuclear and
32.5 percent of non-nuclear capacity would install
closed-cycle cooling for economic reasons during the
period 1979-90. These capacity coverage estimates
are graphically presented in Exhibits 44 and 45.
GENERATION CAPACITY
The total generation capacity which is required
to install mechanical draft cooling towers or an equiva-
lent technology as a result of the final thermal guide-
lines, after consideration of those who do so for eco-
nomic reasons and those who are expected to receive
Section 316(a) exemptions, is summarized in the following
table:
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GENERATION
CAPACITY COVERED
(Millions of KW)
Type of Capacity
Prior to 1974
Retrofitted
1974-78
Retrofitted
Subtotal
1974-78
Planned
1979-90
New Source
Subtotal
Total
1974-83 1984-90
12.3
23.5
35.8
34.4
60.7 124.5
95.1 124.5
130.9 124.5
1974-90
12.3
23.5
35.8
34-4
185.2
219.6
255.4
Thus, 130.9 million kilowatts of generation
capacity will be required by 1983 to install closed-
cycle cooling as a result of the Act - approximately 18
percent of the generation capacity in service at that
time. Of this amount, only 35.8 million kilowatts will
have been retrofitted from open- to closed-cycle. This
amounts to 6.5 percent of the generation capacity in
service at the end of 1978 when new source standards
are assumed to be applied and 5.0 percent of capacity in
service at the end of 1983 when the retrofitting must be
completed. In addition, only those units under construc-
tion which have been designed for closed-cycle cooling
in anticipation of the Act will install these cooling
facilities by 1980 - less than 6 percent of the capacity
in service in 1980.
TIBlS
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The vast majority of the generation capacity
placed into service by 1990 which is covered by the Act
must install closed-cycle cooling at startup. In addi-
tion to the capacity placed in service prior to 1979,
60.7 million kilowatts of the capacity brought on stream
during the period 1979-83 and 124.5 million kilowatts
placed in service during the 1984-90 period will be
covered by new source requirements.
In total, 255.4 million kilowatts of generating
capacity will be covered by the guidelines in 1990,
excluding those who install closed-cycle cooling for
economic reasons and those who are expected to receive
Section 316(a) exemptions. Those covered by the
guidelines will represent 24.0 percent of all generation
capacity by 1990.
The installation of closed-cycle cooling facil-
ities will require the construction of additional
generating capacity to operate the cooling towers and
to compensate for the loss of efficiency resulting from
an increase in turbine back-pressure. This capacity
loss, based upon a 1 percent loss for operation of the
cooling units and an additional 2 percent due to
increased back-pressure, will approximate 4 million
kilowatts by 1983, with an additional 3.7 million
kilowatts by 1990.
T|B|S|
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THERMAL INSTALLATION SCHEDULES
The final effluent guidelines as published in
the Federal Register (39 FR 36186) specify that all units
which require conversion from open- to closed-cycle
cooling must do so prior to 1 July 1981 unless it can
be demonstrated that such conversions would seriously
impact system reliability. If system performance would
be adversely affected, EPA Regional Administrators or
equivalent State Authorities can accept an alternative
schedule of compliance providing that the alternative
schedule requires units representing at least 50 per-
cent of the affected generating capacity meet the com-
pliance date, that units representing at least 80
percent comply by 1 July 1982, and the remaining units
comply by 1 July 1983.
In assessing the economic and financial impact
of the thermal guidelines, EPA specified an installation
schedule which applied the following rules of thumb for
retrofitted units:
• units of 500 megawatts or greater con-
verted for operation of closed-cycle
cooling beginning in 1981,
• units of 300 megawatts but less than 500
megawatts converted for operation in
1982, and
• all other units converted for operation
in 1983.
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Exhibit 46 summarizes the timing implications of
these rules.
New source units and those under construction
designed for closed-cycle cooling were assumed to have
the cooling system operational at the time that the
generating unit was placed in service.
IMPACT OF THERMAL GUIDELINES
In assessing the economic impact of the final
thermal guidelines, TBS first projected separately the
industry conditions which were associated with pollution
control equipment installed:
• for economic reasons only,
• before consideration of Section 316(a)
exemptions, and
• after consideration of Section 316(a)
exemptions.
Having projected these alternatives to the baseline con-
ditions (which excluded any consideration of pollution
control associated with the Act), the implications of
the Act can be determined by computing on a selective
basis the incremental difference between alternatives.
Exhibits 47 to 49 provide summary data for these
three sets of operating conditions for selected years.
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In addition to the summary statistics which were
specified in the previous chapter, Exhibits 47 to 49
provide additional data which:
detail the replacement capacity re-
quired to compensate for the operating
requirements and efficiency losses
associated with the installation of
mechanical draft cooling towers, and
compute the added energy requirements
to operate the cooling towers, to
compensate for the turbine back-pressure
and to operate less-efficient generating
capacity during the period in which
capacity being retrofitted is out of
service.
The following discussion of the economic impact
has been segmented into that which is imputed to the ;
installation of closed-cycle cooling for economic reasons
and that which is associated with the Act both before and
after Section 316(a) exemptions.
ECONOMIC REASONS
The economic and financial impact associated
with the installation of closed-cycle cooling for reasons
other than environmental requirements - that is, for
economic reasons - can be imputed by computing the dif-
ference between the projections (1) with thermal equip-
ment for economic reasons, and (2) for industry baseline
conditions. Exhibits 50 to 52 provide detailed informa-
tion on the impact of closed-cycle cooling for economic
reasons for selected years.
TIBIS
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Perhaps the most important impacts are those
associated with capital expenditures and operations
and maintenance expenses, for it is these items which
determine the financing requirements, operating
revenues and, ultimately, consumer charges.
In computing the economic impact as measured
by capital expenditures in a given period, care must be
taken to isolate the impact associated with equipment
placed in service during the period from the impact of
changes in construction work in progress (CWIP). These
latter expenditures - if the impact is an increase in
CWIP - rightfully should be allocated to the future
period in which the equipment is placed into service and,
4
therefore, becomes part of the rate base.
For example, the impact of those who are
installing closed-cycle cooling for economic reasons
upon capital expenditures during the next decade
(1974-83) will be $1.4 billion - that is, an increase
in capital expenditures of $0.5 billion. This latter
quantity represents progress payments for cooling towers
and related replacement capacity which will be installed
in the period 1984-90.
The following brief table summarizes the
economic impact of closed-cycle cooling for reasons
other than environmental as measured by (1) capital
expenditures adjusted for changes in construction work
in progress, and (2) operations and maintenance (0/M)
expenditures:
4. This adjustment to capital expenditures - while not done in the
summary data exhibits - will be explicitly included in the
tables referenced throughout the text.
ITIBISI
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ECONOMIC IMPACT OF PCE FOR ECONOMIC REASONS
(1974 Dollars)
Capital Expenditures
in billions
0/M Expenses
in billions
1974-77
$0.4
0.1
1974-83
$1.4
0.7
1984-90
$2.0
1.7
These capital and operating expenditures led
to the following financial implications:
FINANCIAL IMPLICATIONS OF PCE FOR ECONOMIC REASONS
External Financing
in billions
Consumer Charges in
mills/KWH at end
of period
(1974 Dollars)
1974-77 1974-83
$0.5 $1.5
0.1 0.1
1984-90
$1.4
0.2
These requirements, in terms of both capital market
requirements and added charges to consumers for elec-
tricity, should be considered in relation to the
respective figures for the baseline conditions. For
5. PCE will be used in tables throughout the text as an
abbreviation for Pollution Control Equipment.
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example, the external financing required during the
next decade to finance the closed-cycle cooling being
planned for economic reasons is $1.5 billion - or
stated another way, an increase in industry financing
needs by 1.2 percent. In addition, the increase in
operating expenses and capital charges which are re-
lated to closed-cycle cooling for reasons other than
environmental affect the consumer in the form of higher
average charges per kilowatt-hour. By 1983, the pass-
through of expenses in the form of higher rates will
amount to 0.1 mills per kilowatt-hour, an increase of
less than 0.5 percent.
Thus, the above-mentioned economic and
financial implications can be viewed in relative terms
as follows:
RELATIVE IMPACT
(Percent of
OF PCE
FOR ECONOMIC
REASONS
Baseline Conditions
1974-77
Capital
Expenditures
0/M Expenses
External
Consumer
at end
Financing
Charges
of period
0.7%
0.1
1.4
0.4
1974-83
0.8%
0.2
1.2
0.4
1984-90
0.9%
0.5
1.0
0.9
The overall impact of installing closed-cycle cooling
for economic reasons - while rather significant in
absolute dollars - is relatively small when viewed in
TlBlSl
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the perspective of the total industry levels.
Both capital expenditures and external financing
(as a percent of the baseline projections)
increase slightly. Operating expenses, on the
other hand, steadily increase as more and more cool-
ing towers are added. These increases lead to an
increase in the relative impact upon consumer
charges.
BEFORE 316(A) EXEMPTIONS
In order to evaluate the economic and finan-
cial implications associated with the Act before consid-
eration of exemptions based upon Section 316(a) of
the Act, TBS computed the difference between the pro-
jections which covered (1) all generating units which
required closed-cycle cooling (including those who
were installing such equipment for economic reasons)
before consideration of 316(a) exemptions, and (2) all
generating units which would install closed-cycle cool-
ing for economic reasons. Exhibits 53 to 55 provide
detailed information on the impact of the Act before
316(a) exemptions for selected years.
The following brief table summarizes the
economic impact associated with these conditions:
T|B|S
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ECONOMIC IMPACT OF PCE BEFORE 316(a) EXEMPTIONS
(1974 Dollars)
Capital Expenditures
in billions
0/M Expenses
in billions
1974-77
$0.3
0.1
1974-83
$5.2
1.5
1984-90
$3.2
3.6
Capital expenditures associated with the Act - even
before consideration of possible exemptions - will have
little impact in the near term as expenditures prior to
1978 will amount to only $0.3 billion. These expendi-
tures represent the outlays made by utilities who were
assumed to have planned closed-cycle cooling in anticipa-
tion of the Act and who would not have otherwise installed
closed-cycle facilities for in-service operation during
the period. The major segment of the expenditures in the
next decade will occur after 1980 during the period in
which all modifications from open- to closed-cycle cool-
ing will occur. As more and more cooling towers are in-
stalled, the costs of operating this equipment increases.
Thus, the expenditures for 0/M exceed those for capital
equipment in the post-1983 period. In total, the final
thermal guidelines before 316(a) exemptions will require
capital expenditures of $8.4 billion and increase 0/M
expenses by $5.1 billion by 1990.
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These expenditures are expected to have the
following effect upon external financing requirements
and average consumer charges :
FINANCIAL IMPLICATIONS OF PCE BEFORE 316(a) EXEMPTIONS
(1974 Dollars)
1974-77 1974-83
External Financing
in billions
Consumer Charges in
mills/KWH at end of
period
$1.3
$4.8
0.4
1984-90
$2.0
0.3
The requirement for retrofitting open-cycle systems dur-
ing the early 1980s has an earlier impact in the form of
progress payments for construction work in progress. Thus,
while expenditures for equipment placed in service prior
to 1978 amounted to only $0.3 billion, the additional
financing needs reflected in the build-up in construction
work in progress which amounted to $1.2 billion by the end
of 1977. In the short run, the consumer charges will be
unchanged. In the long run, financing requirements will
total $6.8 billion by 1990 with a 0.3 mill/kilowatt-hour
increase in average consumer charges.
These economic and financial implications can
be placed in terms relative to industry baseline con-
ditions as follows:
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RELATIVE IMPACT OF PCE BEFORE 316 (a) EXEMPTIONS
a
(Percent of Baseline Conditions)
Capital Expenditures
0/M Expenses
External Financing
Consumer Charges at
end of period
1974-77
0.6%
0.1
3.6
-
1974-83
2.9%
0.5
3.8
1.7
1984-90
1.5%
1.2
1.4
1.3
The impact of the Act before consideration of 316(a)
exemptions is expected to result in a long-term increase
in all of the above statistics ranging from 1.2 to 1.5
percent with the most pronounced effect upon capital
expenditures. The most significant impact is that which
occurs in the early 1980s when all of the conversions from
open- to closed-cycle are scheduled. During this period,
capital expenditures are expected to be increased by nearly
3 percent while external financing remains near 4 percent
throughout the next decade. The average consumer charge
per kilowatt-hour should increase by approximately 1.7 per-
cent by 1983.
While these economic impacts are directly
associated with the Act, they should not be considered
the relevant effects since they do not take into consid-
eration the possible exemptions available to utilities
6. Relat^ve comparisons throughout the text will utilize baseline
conditions as the relevant denominator rather than including
pollution control equipment for economic reasons.
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who successfully petition under Section 316(a) of the
Act. The economic impact as summarized above should
serve as a reference point - that is, the upper bound -
of possible economic consequences directly associated
7
with the Act.
AFTER 316(A) EXEMPTIONS
The economic and financial implications associ-
ated with the Act after consideration of those utilities
which are planning to install closed-cycle cooling
systems for economic reasons and those which success-
fully apply for exemptions under Section 316(a) of the
Act can be easily obtained by computing the difference
between the summary in Exhibit 49 (After 316(a) Exemp-
tions) and Exhibit 47 (For Economic Reasons). Exhibits
56 to 58 provide detailed information on the impact of
the Act after 316(a) exemptions for selected years.
The following brief table provides a summary
of the economic impact which is associated with the
coverage after consideration of both economic reasons and
316(a) exemptions. This impact represents the most likely
implications of the thermal guidelines.
ECONOMIC IMPACT OF PCE AFTER 316 (a) EXEMPTIONS
(1974
Capital Expenditures
in billions
0/M Expenses
in billions
Dollars)
1974-77
$0.3
0.1
1974-83
$2.7
0.9
1984-90
$1.8
2.1
7. In addition to these direct impacts, existing generating units
which were initially exempt by the Act could be required to install
closed-cycle cooling to meet State Water Quality Standards. The
magnitude of this indirect effect is computed in Chapter V.
-------
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Thus, the best estimate of the capital expenditures
required by the final thermal guidelines is $2.7 billion
during the next decade with another $1.8 billion re-
quired by 1990. Coverage after 316(a) exemptions in-
cludes only those generating units which were assessed
o
to have high environmental risk. The expenditures
associated with these coverage levels are projected to
be slightly more than one-half of those required prior to
the 316(a) exemption process. The increase in operating
expenses associated with the Act is estimated to be less
than $1 billion during the next decade and to increase to
$3 billion by 1990.
The following brief table assigns the above-
mentioned capital expenditures to the types of capacity
segmented by time in service and cooling equipment origi-
nally installed:
CAPITAL
(Billions
Type of Capacity
Prior to 1974:
Retrofitted
1974-78:
Retrofitted
Sub-total
1974-78:
Planne'd
1979-90:
New Source
Sub-total
Total
EXPENDITURES
of 1974 Dollars)
1974-77 1974-83 1984-90
$ 0.43
0.91
$ 1.34
$ 0.33 $ 0.40
0.94 $ 1.85
$ 0.33 $ 1.34 i^l.85
$ 0.33 $ 2.68 $ 1.85
8. The methodology which produced these environmental risk assess-
ments was made by ERCO and is summarised in Chapter VI.
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This allocation of capital expenditures is important
since it isolates those expenditures which are required
to cover the high risk units as defined by the final
guidelines and which were placed in service prior to
1974. The coverage of existing units is the major
differentiation among the final guidelines, the original
proposed guidelines, and other alternatives considered
by EPA.
Of the $2.7 billion required for capital ex-
penditures during the next decade, one-half is earmarked
for conversion of open-cycle systems to a closed-cycle
technology and one-half is related both to capacity which
is under construction and planning to install closed-
cycle cooling in anticipation of the final guidelines and
to new source capacity scheduled for in service operation
after 1978. In addition, less than one-third of the
capital expenditures needed for retrofitting open-cycle
systems will be spent on existing generating units.
Another important aspect of these capital ex-
penditures is their time schedule. As can be seen in
the above table, only $0.3 billion will be required prior
to 1978 and all of these expenditures are related to
utilities who have planned to install closed-cycle cooling
on units which are now under construction. Thus, the
final thermal guidelines have included a level of cover-
age and an installation schedule which minimizes the
short-term implications of the Act.
ITIBIS
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These expenditures are projected to require
the following external financing and increases in
average consumer charges:
FINANCIAL IMPLICATIONS OF
(1974
External Financing
in billions
Consumer Charges in
mills/KWH at end
of period
PCE AFTER
Dollars)
1974-77
$0.8
-
316(a)
1974-83
$2.5
0.2
EXEMPTIONS
1984-90
$1.2
0.2
The above-mentioned capital expenditures,
combined with the assumed industry operating and regula-
tory policies, require external financing of less than
$1 billion in the near term, and a total of $2.5 billion
during the next decade. The related increase in consumer
charges is projected to be negligible in the short run and
is limited in the long run to 0.2 mill per kilowatt-hour.
The following table summarizes the relative
impact of the final guidelines after 316(a) exemptions:
RELATIVE IMPACT OF
(Percent of
Capital Expenditures
0/M Expenses
External Financing
Consumer Charges at
end of period
PCE AFTER 316 (a) EXEMPTIONS
Baseline
1974-77
0.6%
0.1
2.2
-
Conditions)
1974-83
1.5%
0.3
2.0
0.8
1984-90
0.8%
0.7
0.8
0.9
JTlBlsl
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In the short run, the major need is for external
financing, primarily to finance the construction work
in progress at the end of 1977. These requirements
increase the total financing needs of the industry by
slightly more than 2 percent. All other short-term
impacts are projected to be less than 0.5 percent.
The needs in the early 1980s increase the
capital expenditures during the next decade by 1.5
percent which, when combined with the 0/M expenses,
contribute to an increase in average consumer charges
of less than 1 percent. In the long run, no impact
exceeds 1 percent of the anticipated baseline conditions.
A full evaluation of the Act's economic impact
requires that both the thermal and chemical guidelines
be computed. However, this evaluation of the thermal
guidelines - when placed in the perspective of total
industry needs - appears to place minimal constraints
upon the industry. This preliminary conclusion is
further strengthened when one considers these require-
ments in the context of the moderation in demand growth
detailed in the previous chapter. For example, the final
thermal guidelines require nearly $2.7 billion in capital
expenditures during the next decade. The reduction in
capital expenditures resulting from the moderation in
demand growth is projected to exceed $28 billion (after
adjustment for changes in construction work in progress).
Thus, the final thermal guidelines when combined with
IrlBlsl
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the moderate growth assumptions now anticipated by
most industry spokesmen require capital expenditures,
external financing, etc. which are substantially below
those which were being projected less than one year
ago. Final conclusions should not be made, however,
without a thorough analysis of the chemical guidelines.
CHEMICAL CAPITAL AND OPERATING COST FACTORS
In addition to the above-mentioned thermal
guidelines, the Act specifies chemical effluent limita-
tions which range from pH level, to suspended -solids, to
oil and greases, to metals in waste streams, to chlorine.
These final chemical requirements as stipulated by EPA
differ somewhat in concept from the above-mentioned
specifications of thermal guidelines in that initial
limitations are required by 1977 with additional, more
stringent, requirements by 1983.
The capital and operating cost factors estimated
by EPA to meet both 1977 and 1983 guidelines are detailed
in Exhibits 59 to 62. The expenditures have been seg-
mented by type of capacity (nuclear and non-nuclear),
year in service (prior to 1974, 1974-78, 1979-90), time
of requirements (1977 and 1983 guidelines), and type of
expenditure (capital and operating).
A comparison of expenditure levels would suggest
that thermal guidelines have a much more significant
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impact than the chemical guidelines. For example,
the 1983 capital cost for mechanical draft cooling
towers for non-nuclear capacity ranges from $8.79 to
$36.71 per kilowatt - depending upon the original
design of the cooling system. In addition to this
investment, replacement capacity must be purchased
and operated due to the reduction in efficiency. The
annual operating cost, again for non-nuclear capacity
in 1983, would be $3.19. These impacts per kilowatt
compare to chemical capital expenditures which range
from $2.93 for new source capacity to $4.09 for exist-
ing capacity and annual operating expenditures ranging
from $0.43 to $1.02, respectively. This conclusion,
however, should be tempered by the fact that the 'chemical
guidelines impact significantly more generating capacity
than the thermal guidelines.
CHEMICAL CAPACITY COVERAGE ESTIMATES
EPA has assumed that all steam electric gener-
ating capacity will be required to meet the chemical
standards. In the case of non-nuclear capacity, this
implies coverage levels less than 100 percent - that is,
equal to the proportion of non-nuclear capacity which is
fossil-fueled steam electric. In addition, no basis for
exemptions from these requirements have been formulated.
Thus, the final chemical guidelines will apply
to nearly 650 million kilowatts of generating capacity
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by 1983 and will include an additional 295 million
kilowatts brought on stream between 1984 and 1990.
The coverage levels required by the thermal guide-
lines after 316(a) exemptions are projected to be
130 million kilowatts by 1983 and approximately 255
million kilowatts by 1990. Thus, the levels of cover-
age specified by the chemical guidelines are five
times greater than those associated with the thermal
guidelines over the next decade; and nearly four times
greater in the long run.
CHEMICAL INSTALLATION SCHEDULES
In assessing the economic and financial impact
of the chemical guidelines, EPA specified separate
installation schedules to meet the 1977 and the 1983
effluent limitation requirements. The installation
schedule for the 1977 guidelines was assumed to be
based upon the capacity placed in service prior to 1978.
This schedule is:
• 1974 15 percent of 1977 capacity
• 1975 20 percent of 1977 capacity
• 1976 25 percent of 1977 capacity
• 1977 40 percent of 1977 capacity
Capacity placed into service in 1978 is assumed to meet
these requirements upon placement in service.
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In addition to the above schedule, EPA
specified an installation schedule to meet the 1983
guidelines which required (1) all capacity placed into
service after 1978 to meet the standards at the time
of initial operation, and (2) all earlier generation
capacity to meet the standards according to the follow-
ing time schedule:
• 1979 10 percent of 1978 capacity
• 1980 10 percent of 1978 capacity
• 1981 20 percent of 1978 capacity
• 1982 20 percent of 1978 capacity
• 1983 40 percent of 1978 capacity
IMPACT OF CHEMICAL GUIDELINES
The economic and financial implications of the
chemical guidelines can easily be obtained by computing
the difference between those projections with chemical
pollution control (Exhibit 63) and those which represent
the baseline conditions for the industry. Exhibits 64
to 66 provide detailed information on the impact for
selected years.
The following brief table provides a summary
of the most likely impact of the chemical guidelines:
ECONOMIC IMPACT OF PCE FOR CHEMICAL
(1974 Dollars)
Capital Expenditures
in billions
0/M Expenses
in billions
1974-77
$0.7
0.5
1974-83
$1.3
2.1
,1984-90
$0.5
2.4
TIBISI
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Thus, the best estimate of the capital expenditures
required by the final chemical guidelines is $1.3
billion during the next decade with another $0.5
billion required by 1990. In addition, the chemical
guidelines have a relatively large requirement for
capital expenditures in the short run to meet the 1977
guidelines. In the long run, the operating and mainten-
ance expenses associated with chemical pollution control
far exceed the capital expenditures. By 1990 the 0/M
expenses represent two and one-half times the expendi-
tures for capital equipment ($4.5 vs. $1.8 billion).
These expenditures are projected to require the
following external financing and added consumer charges:
FINANCIAL IMPLICATIONS OF PCE FOR CHEMICAL
(1974 Dollars)
1974-77 1974-83 1984-90
External Financing
in billions $0.9 $1.4 $(0.3)
Consumer Charges in
mills/KWH at end
of period 0.2 0.2 0.1
Once again, the 1977 guidelines impose a relatively high
short-term need for external financing. These needs
peak in 1983 and actually decline in the late 1980s as
the funds internally generated more than compensate for
the new source capital requirements. This results from
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retained earnings, depreciation writeoffs, and tax
deferrals flowing from earlier investments. While
the short-term impact upon the average cost of elec-
tricity is 0.2 mill per kilowatt-hour, this impact
declines to 0.1 mill by 1990.
The following table places these effects in
perspective by comparing them to the baseline conditions:
RELATIVE IMPACT
OF PCE
(Percent of Baseline
Capital Expenditures
0/M Expenses
External Financing
Consumer Charges at
end of period
1974-77
1.3%
0.5
2.5
0.8
FOR CHEMICAL
Conditions)
1974-83
0.7%
0.7
1.1
0.8
1984-90
0.2%
0.8
(0.2)
0.4
In the short run, capital expenditures and related
financing requirements dominate - up 1.3 and 2.5 percent,
respectively. These impacts subside by the 1980s and,
along with this decline, consumer charges fall off as
0/M expenses remain relatively constant as a percent
of total operating and maintenance expenses. Thus, the
chemical guidelines represent a short-term impact which
exceeds that of the thermal guidelines and a relatively
insignificant long-term impact.
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TQTAL IMPACT OF FINAL GUIDELINES
Having separately computed the effect of
thermal and chemical guidelines, one can project the
total impact of the final guidelines by summing each of
the most-likely estimates previously discussed within
this chapter. Exhibits 67 to 69'detail the individual
impacts for selected years. The following summary
discusses each indicator separately - concentrating
upon the total effect, its relative composition, and
the timing of the impact.
CAPITAL EXPENDITURES
The following brief table provides a summary
of the capital expenditures required to comply with
the final guidelines after consideration of exemptions
under Section 316(a) of the Act. These levels of in-
vestment represent the most likely set of circumstances
projected to occur.
CAPITAL
(Billions
Thermal Guidelines
Chemical Guidelines
Total
Baseline Conditions
EXPENDITURES
of 1974 Dollars)
1974-77 1974-83
$0.3
0.7
$1.0
$53.4
$2.7
1.3
$4.0
$179.0
1984-90
$1.8
0.5
$2.3
$219.8
9. This method of obtaining the total impact understates by an insig-
nificant amount the total since it ignores the chemical expenditures
required for the replacement capacity constructed to offset the cap-
acity penalty associated with operating mechanical draft cooling
towers.
TIBISI
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Thus, the electric utility industry is expected to
require $4.0 billion in capital expenditures during the
next decade to meet the standards required by the Federal
Water Pollution Control Act. These expenditures are con-
centrated in the early 1980s as all generating units
requiring conversion from open- to closed-cycle cooling
are being retrofitted and all plants are required to
comply with the 1983 chemical guidelines.
While only one-third of the expenditures re-
quired during the next decade are related to chemical
standards, nearly 70 percent of the short-term require-
ments are linked to the chemical guidelines. The EPA
decision to delay the compliance date for conversion to
closed-cycle cooling eased the short-term capital require-
ments by distributing the investment needs over a longer
period of time. The total impact through 1990 amounts to
$6.3 billion.
In relative terms, these expenditures have a
minor impact on total industry needs as the following
table indicates:
Thermal
Chemical
Total
CAPITAL
(Percent of
Guidelines
Guidelines
EXPENDITURES
Baseline Conditions)
1974-77 1974-83
0.6%
1.3
1 . 9%
1.5%
0.7
2.2%
1984-90
0.8%
0.2
1.0%
TBS
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During the next decade, the final regulations
will require approximately a 2 percent increase in capi-
tal expenditures by the electric utilities. The long-
run impact amounts to only 1 percent.
These requirements, while amounting to a sig-
nificant number of dollars, are relatively small when
compared with the total needs of the industry. In addi-
tion, the magnitude of these expenditures pales when
compared to the possible savings available from energy
conservation. As detailed in the previous chapter, a
moderate reduction in growth from the historic rates
would free up more than $28 billion in investment funds
during the next decade - and a staggering $91 billion by
1990. If the electric industry could have met the capital
requirements projected prior to last winter, they should
not have trouble meeting the added requirements to comply
with the Act.
The above statement is clearly an oversimpli-
fication since the industry is currently in dire financial
straits (see Chapter I). But such a statement highlights
the fact that the plight of the electric utility industry
is not intimately tied to the environmental movement.
Rather, the problems of the industry evolve from other
conditions within the industry which, if corrected,
could provide a sufficiently healthy climate for the
above-mentioned capital requirements to be met. The deci-
sion of EPA to delay the major expenditures until the 1980s
should ease the short-term capital crunch and provide the
industry an adequate period to correct the underlying
problems.
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0/M EXPENSES
The following brief table provides a summary of
the operating and maintenance expenses required to comply
with the Act:
0/M
(Billions
Thermal Guidelines
Chemical Guidelines
Total
Baseline Condition
EXPENSES
of 1974
1974-77
$0.1
0.5
$0.6
$92.0
Dollars)
1974-83
$0
2
$3
$292
.9
.1
.0
.5
1984-90
$2
2
$4
$311
.1
.4
.5
.2
Thus, the electric utility industry is expected
to spend an additional $3.0 billion on operations and
maintenance during the next decade - and a total of $7.5
billion by 1990.
Whereas the thermal guidelines represented approx-
imately two-thirds of the capital requirements during
the next decade, the chemical guidelines represent more
than two-thirds of the O/M expenses during the same period.
Once again, these expenses are relatively small
in terms of industry totals as the following table demon-
strates:
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O/M EXPENSES
(Percent
Thermal Guidelines
Chemical Guidelines
Total10
of Baseline
1974-77
0.1%
0.5
0.7%
Conditions)
1974-83
0.3%
0.7
1.0%
1984-90
0.7%
0.8
1.4%
During the next decade, the final regulations will in-
crease O/M expenses by 1 percent with the long-run impact
gradually increasing to 1.4 percent as a result of the
cumulative effect of adding pollution control equipment.
It should be remembered that O/M expenses related to the
Act should - on a relative basis - gradually increase over
time as the percentage of generating units covered by the
Act increases.
In addition to the economic impact associated
with increased expenditures, the final thermal guidelines
impose an energy impact which can be expressed in terms of
(1) an increase in fuel consumption, and (2) an increase
in the balance of trade to the extent that the additional
fuel requirements are met by importation of petroleum
products.
Based upon the capacity penalty and period of outage
discussed earlier in this chapter, TBS estimates that
the fuel penalty after consideration of 316(a) exemptions
will be equivalent to approximately 9 million tons of coal
by 1983. Assuming the fuel mix of 80 percent coal and
10. Totals may not equal sum of parts due to rounding.
TIBISI
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20 percent oil, the final guidelines would increase the
national demand for coal by less than 1 percent and the
demand for oil by less than 0.1 percent in 1983.
The added demand for petroleum products amounts
to approximately 18,000 barrels per day by 1983. The total
balance of payments cost of the final guidelines will
depend upon the price of oil and the proportion of increased
demand which will be met by importation. If one were.to
take the worst case assumptions - $12 per barrel for oil and
100 percent imported - the annual balance of payments effect
after 316(a) exemptions would be a maximum of $80 million
in constant 1974 dollars by 1983.
EXTERNAL FINANCING
The following brief table summarizes the exter-
nal financing requirements of the industry which are asso-
ciated with the Act:
EXTERNAL FINANCING
(Billions of 1974 Dollars)
1974-77 1974-83
Thermal Guidelines
Chemical Guidelines
Total
Baseline Conditions
$0.
0.
$1.
$35.
8
9
7
8
$2
1
$3
$126
.5
.4
.9
.3
1984-90
$1.
(0.
$0.
$146.
2
3)
9
3
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The incremental increase in external financing needs during
the next decade nearly equals the capital expenditures
level of $4.0 billion. External financing requirements in
the short run exceed the capital expenditures (adjusted
for changes in construction work in progress) - reflecting
the financing needs for the added construction work in
progress. The long-run needs fall off as the incremental
sources of internal funds begin to compensate for the added
pollution control requirements.
On a relative basis the most significant effect
in the short run and extending throughout the next decade
is a relative need for external financing.
EXTERNAL FINANCING
(Percentage of Baseline)
1974-77 1974-83 1984-90
Thermal Guidelines 2.2%
Chemical Guidelines 2.5
Total 4.7%
2.0% 0 . 8%
1.1 (0.2)
3.1% 0 . 6%
The above table indicates that the short-term addition
to external financing by the electric utility industry is
nearly 5 percent, moderating to 3 percent by 1983 and
dropping off to less than 1 percent by 1990.
While these requirements may increase the finan-
cing burden of the industry, they represent less than 20
percent of the capital freed up as a direct result of energy
conservation.
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CQNSUMER CHARGES
The ultimate impact of the guidelines is re-
flected in the average cost of electricity to the con-
sumer. As the following table shows, the overall impact
of the final guidelines on the average cost per kilowatt-
hour is less than 0.5 mill throughout the period under
consideration :
CONSUMER CHARGES
(Mills/KWH in 1974 Dollars)
Thermal Guidelines
Chemical Guidelines
Total
Baseline Conditions
1977
0.2
0.2
24.0
1983
0.2
0.2
0.4
23.6
1990
0.2
0.1
0.3
22.4
When these increases are placed in the context of the
baseline conditions, the overall impact on the cost of
electricity peaks at a 1.7 percent increase in 1983.
CONSUMER CHARGES
(Percent of Baseline Conditions)
Thermal Guidelines
Chemical Guidelines
Total11
1977
0.;
O.i
1983
0.8%
0.8
1.7%
1990
0.9%
0.4
1.3%
11. Totals may not equal sum of parts due to rounding.
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Although the percentage impact of the final guide-
lines doubles from 1977 to 1983, the absolute level of con-
sumer charges (in constant 1974 dollars) declines from
24.2 to 24.0 mills per kilowatt-hour as the growth in the use
of electricity exceeds the growth in required revenues.
This decline in the cost of electricity continues through
the 1980s and reaches a level of 22.7 mills per kilowatt-
hour by 1990.
Thus, while the cost of electricity is expected
to increase as a direct result of the Act, the relative
price of electricity will - after peaking in the mid-1970s -
begin a gradual decline as the industry returns to a moder-
ate rate of growth after a period of rapid escalation in
construction costs and fuel prices during the early 1970s.
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IV, EVALUATION OF OTHER THERMAL OPTIONS
INTRODUCTION
A number of alternative thermal guidelines
were evaluated between 4 March 1974 when the original
guidelines were proposed and 8 October 1974 when the
final guidelines were published. The options for the
thermal guidelines ranged from covering almost all
plants placed into service since 1950 at one extreme,
to covering only those coming on-line after 1978 at
the other.
The options displayed a hierarchy of three
primary criteria which were considered in achieving
a balance between economic impact and environmental
risk:
age of units was the most significant
criterion and affected both economic and
environmental results the most;
size of unit was added to age as a cri-
terion to strike a finer balance between
two age cutoffs;
capacity factor was considered in some
options as a tertiary factor to
supplement both age and unit size.
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The selected option, of course, does employ the first two
criteria, but does not include capacity factor.
The five options presented in this chapter
provide a good perspective of the range of economic im-
pacts which were under review. The environmental im-
pacts for a similar range of options are presented in
Chapter VI. These were not necessarily those options
given the most serious consideration, but they best
display the variations possible in economic impact.
The five, in terms of capacity exempted, are:
Option 1 - exempt all units placed, into
service before 1979;
Option 2 - exempt all units placed
into service before 1974;
Option 3 - exempt all units placed into
service before 1972;
•)
Option 4 - exempt all units placed into
service before 1961, and all units of
less than 200 megawatt capacity; and
Option 5 - exempt all units placed into
service before 1956, and all units of
less than 25 megawatt capacity or in
systems of less than 150 megawatts,
and all units operating at less than
40 percent capacity factor.
In addition, the guidelines proposed in March 1974 -
which exempted all small units in plants of 25 megawatts
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or less and in systems of 150 megawatts or less,
and units scheduled for retirement prior to 1990 -
were re-evaluated.
THERMAL CAPACITY COVERAGE ESTIMATES
The above-mentioned options differ only
in their coverage of capacity which is either existing
or under construction. Option 1 exempts all units in
these two categories; whereas, the other options limit
exemptions to some portion of existing capacity.
Capacity coverage estimates are graphically
presented in Exhibits 70 and 71 for the final guidelines,
the guidelines proposed in March 1974, and the five
options.
IMPACT OF THERMAL OPTIONS
Economic and financial projections are pre-
sented in Exhibits 72 to 76 for each of the options after
consideration of Section 316(a) exemptions. Exhibit 77
provides comparable data for the proposed guidelines.
The comparative impacts of the options are
summarized, item by item, in the following sections.
In order to simplify the following analysis, the only
time period discussed will be the next decade, 1974-83.
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Since all existing capacity required to convert from
open- to closed-cycle has been scheduled to do so
between 1981 and 1983, this time period captures all
of the differences among the options.
While the primary differences among the
options result from the variation in coverage levels
assumed for existing coverage, the difference between
Options 1 and 2 is solely the result of covering units
which are being constructed and were designed for open-
cycle cooling.
CAPITAL EXPENDITURES
Under the baseline conditions, capital expendi-
tures for plant and equipment placed into service during
the next decade are projected to be $179.0 billion in con-
stant 1974 dollars. The five options, after 316(a) ex-
emptions, would increase that amount from $1.4 to $4.3
billion as summarized in the following table:
CAPITAL EXPENDITURES (1974-83)
(Billions
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
Baseline Conditions
of 1974 Dollars)
Capital
Expenditures
$2.7
$1.4
2.3
2.7
3.9
4.3
$5.2
$179.0
Percent
of
Baseline
1.5%
0.8%
1.3
1.5
2.2
2.4
2 . 9%
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These expenditures compare to $2.7 billion
for the final guidelines and $5.2 billion for those
proposed in March 1974 - with the final guidelines
falling within the mid-range of the five options:
0/M EXPENSES
The following brief table summarizes the
operations and maintenance expenses represented by the
five thermal options during the next decade:
0/M EXPENSES (1974-83)
(Billions
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
Baseline Conditions
of 1974
0/M
Expenses
$0.9
$0.7
0.8
0.9
1.1
1.1
$1.3
$292.5
Dollars)
Percent
of
Baseline
0.3%
0.2%
0.3
0.3
0.4
0.4
0.4%
-
The 0/M expenses range from $0.7 to $1.1 billion
in constant 1974 dollars and in all cases amount to
less than 0.5 percent of the baseline.
EXTERNAL FINANCING
The financing requirements during the next
decade cover the plant and equipment placed in service
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during the next period plus the construction work in
progress at the end of the period for in-service
operation after 1983. Thus, external financing for
the next ten years can be, and generally is, higher
than capital expenditures after the latter has been
adjusted for the change in construction work in pro-
gress. In general, external financing represents
slightly more than 60 percent of all financial re-
quirements - with the remainder being internally
generated funds.
The table that follows summarizes the ex-
ternal financing for the five options as well as both
the final and proposed guidelines:
EXTERNAL FINANCING (1974-83)
(Billions of 1974 Dollars)
External
Financing
Final Guidelines $2.5
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
Baseline Conditions
$1,5
2.2
2.5
4.0
4.6
$5.9
$126.3
Percent
of
Baseline
2.0%
1.2%
1.7
2.0
3.2
3.6
4.7%
-
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CONSUMER CHARGES
The impact on the consumer of these alterna-
tive levels for thermal coverage will be the following
increase in the average cost of a kilowatt-hour of
electricity in 1983:
CONSUMER CHARGES (1983)
(Mills/KWH;
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
Baseline Conditions
1974 Dollars)
Consumer
Charges
0.2
0.1
0.2
0.2
0.3
0,3
0.4
23.6
Percent
of
Baseline
0.8%
0.4%
0.8
0.8
1.3
1.3
1.7%
-
The options range from an increase of 0.1 mill
to 0.4 mill per kilowatt-hour and in no option do
these increases in consumer charges exceed 2 percent
of the projected baseline level of 23.6 mills per
kilowatt-hour. The final guidelines are anticipated
to increase the cost of electricity to the consumer by
0.2 mills.
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SUMMARY
As the preceding discussion has indicated,
the total economic impact of the final guidelines falls
within the mid-range of those for the five options.
In general, the impact of Option 5 is approximately
three times as large as the comparable effect of
Option 1 during the next decade. The final guidelines'
impact is approximately one-half of the impact of the
originally proposed guidelines which were published in
March 1974.
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V, EVALUATION OF STATE WATER
QUALITY STANDARDS
INTRODUCTION
The alternatives to the final guidelines
which were evaluated in the previous chapter differ
only in the assumed coverage levels for existing
steam electric generating capacity. In specifying
these alternatives, EPA explicitly recognized that
existing units which were not covered by the Act still
would be required to meet State Water Quality Standards.
These units, therefore, could be required to convert
from open- to closed-cycle cooling systems in order to
meet the state standards. The following analysis -
based upon the final guidelines - attempts to estimate
the potential impact of State Water Quality Standards.
The impact of these standards upon any other option then
can be directly estimated by comparison of the coverage
levels for existing units.
THERMAL CAPACITY COVERAGE ESTIMATES
The final guidelines exempt all units placed
into service before 1970 and all units of less than 500
megawatt capacity placed into operation between 1 January
1970 and 1 January 1974. As a result, the final
1. Option 1 also excludes units currently under construction - that
is, units to be placed into service 1974-78.
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guidelines' coverage of existing units is limited to
only the largest baseload units placed into service
after 1 January 1970. EPA estimated that the final
regulation covered 45.8 percent of existing nuclear and
4.6 percent of existing non-nuclear capacity prior to
any consideration of additional exemptions under
Section 316(a) of the Act. The coverage of existing
units was reduced to 12.9 percent of nuclear and 2.2
percent of non-nuclear after 316(a) exemptions. Thus,
the final guidelines do not in any way cover 54.2
percent of existing nuclear and 95.4 percent of existing
2
non-nuclear capacity. Some proportion of these
units may not - and probably do not - meet State
Water Quality Standards.
In assessing what proportion of existing
units would not meet the state standards, EPA relied
upon the concept of environmental risk developed by
Energy Resources Company, Inc. (ERCO) and summarized in
Chapter VI. That is_, all existing units which were not
covered by the Act and which were assessed to pose high
environmental risks were assumed to be required to
convert from open- to closed-cycle under State Water
Quality Standards. This definition of State Water
Quality Standards implies that all high risk plants -
even those which are not directly covered by the Act -
2. It should be noted that 17, percent of the non-nuclear1
capacity is not fossil-fueled steam electric.
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will be required to install closed-cycle cooling
systems as a result of either the Act (those covered
by the Act) or State Water Quality Standards (those
existing units not covered by the Act).
EPA estimated that the coverage by state
standards under the final guidelines after consider-
ation of Section 316(a) exemptions would be 1.1
percent for existing nuclear and 20.5 percent for
existing non-nuclear capacity. In total, this level
of coverage means that 14.0 (that is, 12.9 + 1.1)
percent of existing nuclear and 22.7 (that is, 2.2 +
20.5) percent of existing non-nuclear has been as-
sessed as high environmental risk. Exhibits 78 and
79 graphically present these for both the final thermal
guidelines and the alternative options outlined in
the previous chapter.
IMPACT OF STATE WATER QUALITY STANDARDS
The economic analysis thus far has
differentiated the impact of the thermal guidelines
from those expenditures for closed-cycle cooling
which were installed for economic - not environmental
- reasons. In addition to this impact, there
exists a potential for additional expenditures to
meet the requirements associated with state water
standards. This latter category can best be evaluated
by comparing the projections (1) after consideration
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of Section 316(a) exemptions, and (2) after consider-
ation of 316(a) exemptions and State Water Quality
Standards. Exhibit 80 provides summary data for the
combination of after 316(a) exemptions and after
state standards. In addition, Exhibits 81 to 83 pro-
vide detailed information on the impact of State
Water Quality Standards for selected years.
The following brief table summarizes the
economic impact associated with these conditions:
ECONOMIC IMPACT OF STATE WATER QUALITY STANDARDS
(1974
Capital Expenditures
in billions
0/M Expenses
in billions
Dollars)
1974-77 1974-83
$0.0 $2.6
$0.0 $0.4
1984-90
.$0.0
$1.1
The potential capital expenditures required
to retrofit all existing high environmental risk
capacity which is not covered by the Act amount to
$2.6 billion - nearly equal to the impact of the Act
itself. In addition, all of this effect occurs in the
early 1980s. The operating and maintenance expenses
are less than $0.5 billion in 1983 and continue at a
reduced level - accumulating to $1.1 billion by 1990.
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These expenditures are projected to require
the following external financing and increases in the
cost of electricity:
FINANCIAL
STATE WATER
(1974
External Financing
in billions
Consumer Charges in
mills/KWH at end
of period
I Iff LI CAT IONS OF
QUALITY STANDARDS
Dollars)
1974-77 1974-83
$0.0 $3.4
0.0 0.2
1984-90
$(1.6)
0.1
Thus, State Water Quality Standards are
projected to increase the need for external financing
by $1.8 billion - all in the early 1980s. These
funds are needed to finance the capital requirements
and the short-term increase in construction work in
progress. The impact upon consumer charges is 0.2
mill in 1983 with a decline to 0.1 mill by 1990.
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VI, ENVIRONMENTAL IMPACT OF THE
THERMAL GUIDELINES
INTRODUCTION
The evaluation of environmental impacts upon
water bodies has been integral to the process of estab-
lishing appropriate thermal effluent guidelines for the
steam electric utility industry. This chapter presents
in three sections: (1) the technology of thermal pollu-
tion; including the alternative techniques of alleviating
it; (2) the factors that influence environmental impact,
especially the utility plant characteristics which bear on
the degree of that impact; and (3) the environmental evalua-
tion of the guideline options considered by EPA.
TECHNOLOGY OF THERMAL POLLUTION
Any power plant that generates power from heat
(either from burning fossil fuel or fissioning uranium)
must have a place to reject heat. According to the second
law of thermodynamics it is impossible to change all the
heat into electricity with no waste. In the case of gas
turbines, the combustion products are exhausted directly
into the atmosphere at about 1,000°F.
In the case of steam turbines, the cost of
boiler water and the low pressure of steam at ambient
temperature make it impractical and inefficient to ex-
haust the steam directly into the atmosphere. The steam
1. The material in this chapter summarizes the results of re-
search performed for EPA by Energy Resources Co., Inc.(ERCO).
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cooling water cannot be recycled through towers
or ponds indefinitely because chemicals collect by
leaching and from additives while nearly pure water
is slowly lost by evaporation. Some of the water is
bled off and replaced by fresh water to avoid overcon-
centration: the water that is bled off is called blow-
down. If the water is bled off after passing through
the tower or pond, it is called cold-side blowdown,
as opposed to hot-side blowdown, where the water goes
directly from the powerplant condensers into the river.
Available technologies for thermal abatement
include the operation of:
• Cooling ponds and lagoons
• Spray systems and spray ponds
• Natural draft wet towers
• Mechanical draft wet towers
• Natural and mechanical draft dry towers
• Diffusers
The first four systems cool water primarily by
evaporation, while the fifth - dry towers - cools only by
exchanging heat between two fluids, hot water and cooler
air. The sixth system distributes the waste heat
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directionally, so that the ecological effects can be
minimized by either reducing or increasing mixing as
a function of the nature of particular ecosystems.
Each of these systems requires different amounts
of energy and water to effect the same amount of cooling.
Furthermore, the operation of each of these systems
affects the environment differently. This section pro-
vides a description of the alternative technologies
employed to achieve cooling.
COOLING PONDS AND LAGOONS
Given sufficient land, cooling ponds and
lagoons are the cheapest and, environmentally, the most
satisfactory method to achieve reductions in thermal
loads. The heat is rejected from the pond surface by the
natural effects of conduction, convection, radiation, and
evaporation. Cooling ponds can be classified as completely
mixed, stratified and flow-through ponds. In a completely
mixed pond the flow between the inlet and outlet locations
of the pond combined with wind mixing tend to keep the
pond at a nearly uniform temperature. Stratified ponds
are warm on the surface near the outfall and
cooler on the bottom near the intake. In a flow-
through pond the temperatures decrease continually,
along the pond. The pond effluent can either be
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returned to the plant intake (closed cycle) or
discharged to a natural receiving body (open cycle).
Flow-through and stratified ponds are more common and
more effective than completely mixed ponds.
SPRAY SYSTEMS AND SPRAY PONDS
Spray ponds are available in two different
configurations: conventional spray ponds and powered
spray systems. In conventional spray ponds, warm
water is pumped out of spray nozzles to increase the
exposure of surfaces to the atmosphere for cooling.
Powered spray systems consist of multiple nozzle
assemblies and motors, or a thermal rotor module
with numerous disks spinning on a common shaft,
and driven by a single motor. Spray systems rely
on expanded surface contact to increase evaporation.
Spray ponds require little maintenance, but are subject
to poor operation due to climatic conditions.
NATURAL DRAFT WET TOWERS
Natural draft wet towers are basically large
chimneys which provide a draft to pull air over a
large surface of water. Among the advantages of
natural draft wet towers are long-term maintenance-
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free operation, smaller amounts of ground space
required for multiple towers, reduced piping costs
when towers can be located adjacent to plant, no
electricity required for operating fans, fewer elec-
trical controls and less mechanical equipment. On
the other hand, it is not possible to control outlet
temperatures as well as with mechanical draft towers.
Also, because they are usually 500 feet high, nat-
ural draft towers tend to dominate the landscape.
MECHANICAL DRAFT WET TOWERS
Mechanical draft evaporative (wet)towers are
divided into two categories, forced air flow and
induced air flow. Induced draft towers are further
subdivided into counterflow and crossflow towers.
Crossflow induced draft towers can usually attain
better thermal performance than counterflow towers.
Mechanical draft towers are much smaller than nat-
ural draft, and may be as low as 50 feet in height.
NATURAL AND MECHANICAL DRAFT DRY TOWERS
In natural and mechanical draft dry tower
heat rejection systems, the circulating water never
comes into direct contact with the cooling air.
There are indirect and direct air-cooled condensing
systems. The first uses a condenser at the turbine
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to condense the exhaust steam. The second uses cooling
coils in the tower without the use of a condenser or
circulating water. The large steam piping required
appears to make the direct system infeasible for large
power plants.
DIFFUSERS
Outfalls can be designed to distribute the
flow of waste heat in streams to achieve desirable
ecological goals. In rivers, heated water may be
concentrated on the surface to maximize atmospheric
cooling and minimize downstream effects, or concen-
trated in midstream to minimize effects on shore-line
biota, or diffused across the width of the river to
minimize the temperature effects anywhere in the
river. In salinity-stratified estuaries, it may
be possible to both withdraw and return the water from
middle levels, minimizing effects on both surface and
bottom species.
The closed-cycle cooling methods with signif-
icant present use are natural and mechanical draft wet
towers, ponds, and spray ponds. Many closed-cycle cooling
systems have been, and will continue to be, installed
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by utilities for economic reasons whether or not required
to by EPA for environmental reasons. The projections
of impact of the EPA regulations throughout this report
take that factor into account and state impacts in terms
of incremental systems only.
The guidelines provide that both Best Prac-
^
ticable Control Technology (BPCT) and Best Available
4
Technology Economically Achievable (BATEA) to control
thermal pollution can be met by one suitable tech-
nology: evaporative external cooling to achieve essen-
tially no discharge of heat into waterways except for
cold-side blowdown, in a closed, recirculating cooling
system.
The mechanical draft evaporative cooling tower
has been used as the basis for all analysis of costs and
environmental impacts.
3. Currently available for 197?j in assessing BPCT a balancing
test between total aost and effluent reduction benefits is
made. In some instances, this test may eliminate the applica-
tion of technology which is high in cost in comparison to the
minimal reduction in pollution which might be achieved.
4. The highest degree of technology that has been demonstrated
as capable of being designed for plant operation; costs for
this treatment may be much higher than for treatment by "best
practicable" technology.
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FACTORS THAT INFLUENCE ENVIRONMENTAL IMPACT
The factors that directly influence the en-
vironmental impact of the heated water discharges are:
(1) location; (2) amount; (3) temperature; and (4)
frequency. The powerplant characteristics which directly
affect these parameters are:
• receiving water type (river, lake
estuary, ocean)
• cooling method (open cycle, "helper"
system, closed cycle)
• safezone
• efficiency
• heat rate
• unit size
• capacity factor
• age
SAMPLE PQWERPLANTS STUDIED
In order to gather extensive data which was not
publicly available, regarding utility plant characteristics,
a random sample of 180 plants or units was selected from the
publication Steam Electric Plant Factors (National Coal Association^
January 1974). Those 180 plants represent approximately 14
percent of the 1,273 plants listed, and account for 396
steam-electric utility generating units operating in
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1974. The sample data was supplemented by a telephone
and telegram survey, by a literature search, and by
data from FPC Form ft? computer tapes issued monthly by
the Federal Power Commission.
Individual assessments were also made of
environmental hazards due to thermal effluent for each
of the 180 plants in the sample. Analysis of the plant
characteristics and environmental assessments identified
the patterns described below. (The sample data has been
adjusted to correctly reflect figures such as mix of
fossil and nuclear units.) Those patterns eventually
formed the basis for the environmental evaluation of
each of the options.
RECEIVING WATER TYPE
The damage from thermal pollution depends
on the method by which heat enters and leaves a re-
ceiving water body:
• On a river, most of the heat is removed
downstream by the river flow.
• On a lake, most of the heat is dissipated
into the air by conduction and evaporation
• On an estuary the heat is removed in
alternating directions by tidal flows,
• In the open ocean, the heat is removed by
natural currents or convection.
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About 10 percent of the plants utilize municipal
or industrial sewage water, aqueducts, or other combined
techniques in which most of the heat is dissipated
before entering a navigable waterway. As such,
those plants are exempt on the grounds of not using
waterways.
The damage from heat clearly depends on
the type of receiving water body and on its size. If
the water body is large, many animals can avoid the
hottest areas and those which are harmed will be
rapidly replenished by others nearby. If the body is
small enough so that an entire habitat is strongly
heated (for example, an entire lake surface or river
cross-section), then a few days' damage may take years to
reverse.
Approximately 60 percent of steam electric produc-
tion capacity has been located on rivers over the last 20
years. Approximately another 20 percent has been on
lakes. Of the remaining 20 percent, half is located
on estuaries, and half utilizes wells, city water, sewage
water or other sources for cooling. Ocean water is used
by less than 3 percent of all plants.
Most significant in terms of environmental impact
are the receiving water types for plants using once-
through cooling, as shown in Exhibit 84, since all
closed-cycle cooling systems present no environmental
hazard.
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The current mix of such plants is approximately
50 percent on rivers, 30 percent on lakes, and 15 per-
cent on estuaries. Only 5 percent use water from other
sources. Some trends are evident: estuary sites are
growing slowly; lake sites are growing rapidly; and river
sites are decreasing rapidly. Much of this trend is
probably due to the large size of new plants. The
Great Lakes and the ocean are large compared to the
water needs of any powerplants now contemplated, whereas
only the Mississippi and Columbia River basins have
much larger flows all year than the largest plants
require for plant draft.
COOLING METHOD
Heat may be rejected from the cooling water
at three different stages:
• with once-through cooling, the heated
water is returned directly to the re-
ceiving water body;
• with "helper" systems, all or part of the
heated water is partially cooled all
or part of the time by a tower, pond
or ditch before returning to the receiving
water body;
• with true closed-cycle cooling, nearly all
the water is cooled by a tower or pond
and then recycled through the condenser.
The first method may cause mortality to both
organisms drawn through the plant and those near the
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outfall, while the second greatly reduces damage
near the outfall, but may considerably Increase damage
to those drawn through the plant, and the third generally
eliminates thermal damage to the water body; all organisms
drawn through the plant are killed but their number
is small since the make-up water needs are only a few
percent of the water used by either of the other methods.
An indirect but sometimes very important
effect on rivers from switching to closed-cycle
systems is an increase in the quantity of water
consumed by cooling. The effect varies considerably in
the different climatic regions but generally in open-
cycle systems about half of the. heat discharged to
a river, or well dispersed in a large lake, results
in evaporative heat transfer while the other half
transfers to the atmosphere by conduction and convec-
tion.
With closed-cycle systems of cooling towers
and ponds about three-fourths of the heat transfer
results in evaporation, an increase of up to 50 per-
cent over open-cycle. Further, a man-made cooling pond
can result in additional water requirements due to
enhanced natural evaporation of the impounded water.
However, the ability of a pond to store surplus runoff
from, the wet season for use in the dry season can often
completely compensate for added evaporation. Overall,
it appears that no more than a 30 percent increase in
evaporation water loss could result from a massive in-
crease in closed'rcycle cooling.
ITIBIS
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The industry is rapidly increasing its usage
of closed-cycle cooling. In 1970 approximately 78
percent of all steam electric plants relied upon once-
through cooling. By 1977, that percentage is expected
to decline to 60 percent.
Exhibit 85 is surprising in its indication
of the method by which the increase in closed-cycle
cooling is being accomplished. Cooling ponds represent
approximately 4 percent of the industry; spray ponds
and semi-closed systems are much smaller. EPA's initial
choice for BATEA (mechanical draft cooling towers) has
also been nearly constant at just over 10 percent of the
industry for 20 years. Practically all the net increase
in closed-cycle cooling is due to the rapid growth in
natural draft cooling towers during the 1970s. Probably
the decreased energy penalty, land use, fogging, drift,
and noise compensate for the larger capital cost of
natural draft compared to mechanical draft towers.
SAFEZONES ON RIVERS
A very significant factor in terms of environ-
mental risk is the percentage of a river's total flow which
is not affected by a plant's thermal discharge. As a
result of consultation with numerous biological scientists
employed by universities, by private research organ-
izations, and by government agencies the following
designations were developed:
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• high risk - less than 30 percent of
river flow unaffected
• low risk - over 70 percent of river
flow unaffected
• moderate risk or undetermined -
30-70 percent unaffected
The last category, between 30 percent and 70 percent of
river flow not affected, it was agreed, constituted a
risk which could not be ascertained without a detailed
biological demonstration such as that contemplated
under Section 316(a).
Exhibit 86 shows that no pronounced change
in safezones has been exhibited over the last fifteen
years, mainly because relatively few once-through river
plants are being built (up only 25 percent in the final
decade). Placing larger new units at an old site
necessarily reduces the safezone but this is counter-
balanced by the increased attention given to locating
on sufficiently large rivers and both economic and
environmental constraints forcing the largest plants to
use closed-cycle cooling.
EFFICIENCY
Until 1960, the efficiency of electrical pro-
duction had been increasing rapidly over time. Between
1920 and 1960 technologically feasible pressures
increased ten-fold to 3,400 psi. temperatures doubled
to over 1,000° F, and the average efficiency nearly
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tripled to 32 percent. Although electrical consumption
doubled each decade in this period, the environmental impact
was greatly mitigated by the improvements in efficiency.
While the average plant in 1920 rejected 2
units of energy into the air and 6 units into water for
each unit converted into electricity, the 1960 rejection
rate was 1-1/2 units of energy into water for each unit
converted into electricity. As a result, the nearly 16-
fold increase in electrical production increased the heat
rejected into waterways only about 4-fold; while this
heat increase is large, it amounts to less than 2 percent
annual growth per capita and is similar to the growth of
the whole economy during the period.
Since 1960, however, the improvement in
efficiency has been negligible. One unit was built with
a maximum pressure of 5,000 psi, temperatures up to 1,200°F,
and double reheating providing an efficiency of 40 percent;
but reliability was a problem. Most other new fossil units
have shown efficiencies of about 36percent. The common
nuclear units have an efficiency of 32 percent and since
there are no stack losses,2 units of energy must be
rejected into the cooling water for each unit turned into
electricity. Few higher efficiency nuclear units are
expected until at least the mid-1980s. Since nuclear units
will soon be providing over one-half of the capacity
additions, the demand for cooling water will grow about
6 percent per capita, which is faster than the growth of
electrical demand.
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Return to a pattern of increasing efficiency
which can compensate for increased demand is not likely
for at least several decades, although combined gas
turbine and steam electric systems might approach
45 percent efficiency within ten years. High tempera-
ture gas reactors are near 40 percent; breeder reactors,
magnetohydrodynamic and electrogasdynamic generators,
and fusion reactors are at least decades from becoming a
major source of energy. Geothermal generation and solar
energy create more waste heat than present generators;
their great advantage lies in fossil fuel savings. Fuel
cells promise major reductions in waste heat and may be
useful for temporary storage, but appear impractical with
natural fuels. Nevertheless, all the above are expected
to account for less than 5 percent of the new generation
added in the next ten years.
HEAT RATE
Heat rate measures the amount of fuel
that must be burned to produce one unit of electricity.
It is commonly given as British Thermal Units per kilowatt-
hour. It has been suggested that units with large heat
rates should be exempted from regulation because those
units require so much cooling water that they cannot
afford to raise their electric rates enough to pay for
the cost of cooling towers. However, this argument
can easily be turned around. Closing down high heat
rate units will give a large reduction in. thermal
pollution and fuel use with only a small reduction in
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generating capacity. This criterion has now been
bypassed since practically all high heat rate units
will be exempted on the basis of age. Nearly all
units built since 1960 have heat rates within a 20
percent range, with nuclear units at the top of the
range. The heat rates for new plants are conjectural
but the major trend is still evident - the heat
rate decreased rapidly through the late 1950s and
has nearly stablized since then.
UNIT SIZE
As prospective savings from improved efficiency
have declined, the utilities have utilized a break-
through in boiler technology in the 1950s to reap
economies of scale. Maximum boiler and generator
unit sizes increased 6-fold between 1955 and 1972 to
1,150 megawatts with only a doubling of employees
per unit. Although many plants containing several of
these large units are now planned, the technology is
not without environmental costs since very few streams,
lakes, or bays in the United States are large enough
to cool these plants without undergoing large temperature
rises.
The only direct effect of unit size on thermal
pollution is during periods of breakdown and maintenance.
When a single-unit plant is shut down for maintenance,
all of its thermal effluent ceases. The temperature
near the cooling water outfall may drop rapidly by
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10°to20°F. The resulting "cold shopk" may be fatal
to organisms that have acclimated to the outfall
temperatures. If many smaller units are used the temp-
erature changes on shutdown of a single unit are much
less. ,
A number of indirect effects of unit size may
be important. The small units tend to be older, more
lightly loaded, and less efficient. The administrative
costs of monitoring them are much higher and the con-
version costs moderately higher for a given reduction
in environmental risk. The age exemption has now
eliminated practically all units previously being con-
sidered for a size exemption.
Exhibit 87 shows the size of the largest
units has grown erratically because each large increase
required new technological breakthroughs for safe
reliable operation. The average unit size has, none-
theless, grown continuously. Therefore, the total
number of steam electric units seems likely to remain
between 2,000 and 3,000 for the entire second half of
the twentieth century.
CAPACITY FACTOR
Environmental risk depends mainly on net
generation and heat rate. The capacity factor is the
ratio of net generation to generating capacity, so it
obviously correlates with the cost/benefit ratio. But
TlBIS
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capacity factor, size space, and heat rate all cor-
relate well with age.
The main difference in capacity factors
is between fossil and nuclear plants. The higher heat
rate of nuclear plants, however, cancels out their
advantage in high capacity factor.
Capacity factor would cause more problems
than almost any other measure as a criterion for exemption
Exemption for all time on the basis of capacity factor
in an arbitrary base year in the past would lead to
continual challenges from plants that had fallen be-
low the cutoff after the base year. On the other hand,
establishing the base year in the future would subject
the exemptions to the uncertainties of the future and
make exemptions to some degree a matter of management
policy for each utility system. Basing exemptions on
current production would raise problems of planning
multi-year construction on the basis of exemptions
which fluctuate yearly.
AGE
Age is a suitable surrogate for many other
unit characteristics which affect environmental
risk. It correlates very well with efficiency, heat
rate, size, and capacity factor. Because efficiency
and heat rates have not kept pace with the trend in
size, the newer units pose a higher environmental
hazard.
TlBISl
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Furthermore, the fact that newer units have
high capacity factors (as a logical result of their
cost/benefit performance) indicates that those units
operate a high percentage of the time and thus pose a
more prolonged hazard than units used only periodically.
The age distribution projected for all units
in operation January 1, 1978, is presented in Exhibit
88. Approximately 52 percent of 1978 capacity is
expected to have been placed into service between 1970
and 1977. The 1970 to 1977 units will provide approx-
imately 57 percent of net generation in 1978. The
oldest units, placed in service in 1961 or before will
account for only 28 percent of capacity and 23 percent
of net generation.
Some costs depend directly on age since the
old equipment is too fragile to undergo major modifica-
tions. Moreover, when future plants are included in
the analysis, age surpasses even capacity factor as a
measure of cost/benefit, because the cost of retro-
fitting an old plant is about three times as large as
the cost of installing closed-cycle cooling on a plant
as original equipment.
ENVIRONMENTAL EVALUATION OF THE GUIDELINE OPTIONS
Each of the options considered by EPA was
evaluated in terms of the environmental impact which
would still exist under the guideline from exempted units,
ITIBISI
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Much attention was given to determining guidelines which
would achieve the environmental objectives of the Act
with the lowest economic cost.
THE MEASURES OF ENVIRONMENTAL IMPACT
The environmental "cost" associated with each
option has been measured in terms of the percentage of
high risk net generation which it would exempt. The guide-
lines proposed in March 1974 would have covered all but 3
percent of the high risk net generation by 1978, and all
but 1 percent by 1983. However, the economic cost of
those guidelines was significantly greater than that of
the final guidelines which will exempt 44 percent of high
risk net generation by 1983.
For purposes of this analysis all steam
electric generating units were categorized as:
High risk - open-cycle units in which
current or projected thermal effluent
clearly poses an environmental hazard
to the receiving body of water. Such
units are: (a) those in plants on rivers
with safezones less than 30 percent; (b)
half of those units in plants on rivers
with safezones between 30 percent and 70
percent; and (c) half of those units on
estuaries and lakes.
5. The projections of generating capacity used for the environmental
assessment differ slightly from the final projections presented
in the earlier chapters. Exhibit 89 compares the two and shows
those used for the environmental analysis are 4.3 percent lower
in 1974 and 1.4 percent lower in 1983.
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low risk - open-cycle units in which
current or projected thermal effluent
does not appear to pose an environmental
hazard to the receiving body of water.
Such units are: (a) those in plants
on rivers with safezones of over 70
percent; (b) half of those in plants
on rivers with safezones between 30
and 70 percent; (c) half of those on
estuaries and lakes; and (d) all
employing water from municipal, sew-
age, ocean, and well sources.
closed-cycle - units which are or will
be operating closed-cycle cooling for
economic reasons or in anticipation of
the Act and which, therefore, pose no
environmental hazard.
RISK PROFILE OF THE INDUSTRY
In the absence of environmental guidelines
from EPA, 21.5 percent of the steam electric capacity
in operation by 1983 will consist of high risk units.
The risk characteristics of these units vary signif-
icantly as a function of age, as shown by Exhibit 90.
Of the older, pre-1970 capacity which will still be in
service by 1983 as much as 30 percent is high risk.
In contrast, only 16 percent of the capacity coming into
service between 1970 and 1983 will be high risk.
Underlying that trend is a significant shift to
a higher share of closed-cycle cooling systems for economic
TIBlS
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reasons. Of the pre-1970 capacity which will still be
in service by 1983, only 14 percent utilizes closed-cycle
cooling. That figure jumped to 59 percent of all new
units placed in service between 1970 and 1973, and will
be up to 66 percent for those placed in service between
1974 and 1982.
By 1983, 58 percent of the capacity in operation
will consist of post-1973 units or 1970-73 units larger
than 500 megawatts, all of which will be covered by the
final guidelines.
As a basis for estimating environmental risk,
figures on net electric generation have been used in
addition to capacity. For the economic analysis,
capacity provides the best basis for estimating capital
costs, but the environmental hazard is also directly
related to utilization. The 21.5 percent high risk
share of 1983 capacity is equivalent to a slightly
lower percentage of 1983 net electric generation (19.4
percent), reflecting reduced utilization of the oldest,
highest risk units.
The projected high risk share of 1983 capacity
and net electric generation in the absence of guidelines
is shown on the following page.
TIBISI
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Risk Characteristics of Units in Service by
1983 in Absence of the Final Guidelines
Capacity
Net Generation
In 1970, 30 percent of net electric generation
was from high risk units. By 1983, as a result of retire-
ments and lower risk additions, that would decline to
19 percent even without federal guidelines.
Each of the guideline options was evaluated in
terms of the percentage of 1983 high risk capacity and
net generation which would be exempt. That which was
covered would be shifted to closed-cycle cooling systems
as a result of the guidelines. The sections below
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summarize the environmental risk evaluation for the
major options considered.
THE FINAL OPTION
The final guidelines adopted by EPA will
exempt all units in service prior to 1970 and those less
than 500 megawatts in service between 1970 and 1973.
Those units are the oldest and smallest units. As such,
they have the lowest cost/benefit ratios and year-by-year
will decline in utilization and be the first units to be
retired. Therefore, cooling towers retrofitted to those
units would have very high costs per kilowatt of capacity
and would have unusually short lives.
The final guidelines will not cover 56 per-
cent of the 1983 high risk capacity and 44 percent of
the high risk net generation. That uncovered capacity
accounts for 12 percent of total fossil and nuclear
capacity and 10 percent of all capacity in that year.
EPA has assumed that all high risk units which are not
covered by the guidelines will not be exempt from State
Water Quality Standards and, therefore, may be required
to convert to closed-cycle cooling systems at some future
time. The potential economic impact of State Water Quality
Standards was analyzed in the preceding chapter.
TBS
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THE MARCH 1974 PROPOSED OPTION
The proposed guidelines published March 4, 1974would
have exempted only units in service prior to 1950 and those
in plants of less than 25 megawatt capacity or in systems
of less than 150 megawatts. That standard would have "ex-
empted only 4 percent of high risk capacity and 1 percent
of high risk net electric generation by 1983, or less than
1 percent of the total fossil and nuclear levels that year.
VARIATIONS ON THE FINAL OPTION
Changes from the 500 megawatt size criterion
to be applied to 1970-73 units would have relatively
small effects upon environmental risk unless increased to
the point where even 700 to 1300 megawatt units would be
exempt. Decreases in the criterion, as shown in Exhibit
91, would not substantially reduce the environmental risk.
At the extreme, with no 1970-73 units exempt, 53 percent of
the high risk capacity (11 percent of total fossil and
nuclear capacity) would have been exempt. At a cutoff of 700
megawatts the exemptions increase only up to 59 percent.
However, increasing the cutoff up to 1300
megawatts, which would exempt all 1970-73 units, would
increase the environmental risk to 66 percent.
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ALTERNATIVE OPTIONS ON AGE
»
The environmental risk of the guidelines is
most sensitive to variations in the age criterion in the
guideline. Unfortunately, the economic impact is also
most sensitive to this criterion as a result of the high
cost of retrofitting cooling towers on existing plants.
The range of environmental risk as a function
of this criterion is from 4 percent with a 1950 service
year cutoff to 79 percent with a 1978 cutoff, as shown in
Exhibit 92. A 1961 cutoff would yield 24 percent risk,
while a 1970 limit doubles the percentage of high risk
net generation exempted (52 percent).
OTHER OPTIONS CONSIDERED
In addition to these major options, consid-
eration was given to a substantial number of others.
Most were simply variations on unit size and age of
those presented above.
Some, however, were examined which included
capacity factor as a criterion. That was not incor-
porated into the final regulation in part, at least,
because it would present very difficult enforcement prob-
lems. The capacity factor of a unit fluctuates both daily
and annually, and in response to system demands, manage-
ment policy, and maintenance schedules.
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Age serves almost the same function which
*
capacity factor would, because age and utilization are
highly correlated, without the same administrative ambig-
uities. Furthermore, the use of age as the primary cri-
terion has enabled EPA to reduce the cost of the guide-
lines to the industry by a significant amount while still
insuring that almost all new units which will be in ser-
vice through the end of the century will be covered.
TIBIS
-------
VII, ALTERNATIVE ASSUMPTIONS
SUBMITTED BY UWAG
INTRODUCTION
On 4 March 1974, the Environmental Protection
Agency (EPA) published a notice of proposed rulemaking
in the Federal Register (39 FR 8294) announcing its intention
to establish limitations on the discharge of pollutants
by existing and new point sources within the steam
electric generating category.
The regulation as proposed was supported by
two documents which were made available to the public
and circulated to interested persons at approximately
the time of the publication of the proposed rulemaking.
Prior to 4 March 1974 remarks on an initial draft of
the Development Document were distributed and comments were
solicited. The majority of comments received and EPA's
response were described in the notice of proposed
rulemaking.
1. Development Doawnent for Proposed Effluent Limitations Guidelines
and New Source Performance Standards for the Steam Electric Power
Generating Point Source Category (March 1974); and Economic
Analysis of Proposed Effluent Guidelines: Steam Electric Power-
plants (March 1974). This latter document contained TBS analysis
of the proposed guidelines.
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Interested parties were again invited to
participate in the rulemaking by submitting written
comments within 90 days of the publication date of
the proposed regulation. In response to requests
for additional time the period for public comment
was extended for 23 more days.
Thereafter, EPA convened a public hearing
on 11 and 12 July 1974 in order to afford an oppor-
tunity for those who had submitted comments to ex-
plain the substance of their position in detail and
to determine EPA's interpretation of and basis for
its proposals.
On 26 June 1974, the Utility Water Act
Group (UWAG) - in conjunction with the Edison
Electric Institute, the American Public Power
Association, and the National Rural Electric Co-
operative Association <- submitted perhaps the
most detailed comments to EPA on the proposed ther-
mal and chemical guidelines.2 On the basis of these
2. Comments on EPA 's Proposed Section 304 Guidelines and
Seat^on 306 Standards of Performance for Steam Electvlo
Powerplants (S Volumes); and Comments on EPA fs Proposed
Section 316(a) Regulations and Draft Guidanoe Manual.
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written comments, public hearings and subsequent
interaction between EPA and UWAG representatives,
general agreement was reached on the basic method-
ology to be utilized in evaluating the economic
impact of the final guidelines.
Minor differences in assumptions still
remain — and the purpose of the following analysis
is both to specify these differences and to evaluate
their economic impact.
AREAS OF DIFFERENCE IN ASSUMPTIONS3
The differences in operating and financial
assumptions which remain fall into two general cate-
gories. First, UWAG does not agree with some of
the basic industry assumptions developed by the
National Power Survey's Technical Advisory Com-
mittee on Finance (TAG-Finance). The specific
assumptions on which disagreement exists deal with
the most likely rate of future industry growth and
the rates required by the capital market for is-
suance of long-term debt and preferred stock.
3. The bases for the UWAG assumptions are documents submitted
to EPA by National Economic Research Associates, Inc.
(NERA)f UWAG's economic advisers.
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Second, UWAG does not accept the capital
and operating cost factors assumed for both the
thermal and chemical guidelines. The differences
that remain include capital costs for closed-cycle
cooling and chemical discharge cleanup, the opera-
ting costs for both thermal and chemical effluent
reduction, and the cost of outage during which
open-cycle cooling facilities would be converted
to closed-cycle.
The economic impact of these differences in
assumptions is analyzed in the following sections
which focus on:
• the "cost" effect of assuming UWAG
capital and operating cost factors with
the baseline industry operating assump-
tions specified by the TAC-Finance;
• the "growth" effect of assuming the
EPA capital and operating cost factors
with the industry operating assumptions
specified by UWAG; and
• the "interaction" effect of simulta-
neously using UWAG cost factors and
UWAG industry operating assumptions,4
4.The "interaction" effect is the impact of these assumptions
less (1) the impact of the final guidelines with EPA
assumptions, and (2) the "cost" effect, and (Z) the "growth"
effect.
TIBIS
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These different effects are graphically depicted
below:
Industry
Operating
Assumptions
TAC-Finance
UWAG
Cost Factors
EPA
UWAG
Relevant
Baseline
Conditions
Interaction
Effect
TAC-Finance
UWAG
The "cost" effect of varying the cost factors
will be analyzed first and will be segmented by type
of guidelines - thermal and then chemical. Next, the base-
line conditions will be adjusted to reflect the UWAG
industry operating assumptions, and this new baseline will
then become the basis for analyzing both the "growth" and
"interaction" effects. In order to highlight the dif-
ferences between EPA and UWAG assumptions, the economic
and financial implications will be limited to those
after consideration of Section 316(a) exemptions for
the period 1974-83.
TIBISI
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It should be noted that the capacity
coverage levels used throughout this analysis were
those estimated by EPA. While UWAG accepted the
coverage levels assumed prior to 316(a) exemptions,
they did not necessarily accept the levels estimated
after 316(a), nor after 316(a) and State Water Quality
Standards.
ALTERNATIVE THERMAL COST FACTORS
While general agreement exists on the
methodology to be used in evaluating the economic
impact of the thermal guidelines, EPA and UWAG differ
in their estimates of the cost of constructing and
operating closed-cycle cooling systems as required by
the final guidelines.
CAPITAL COST FACTORS
The following table summarizes the differ-
ences in capital cost factors which remain:.
ITIBISI
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THERMAL CAPITAL COST FACTORS
(expressed in 1972 Dollars/Kilowatt)
For Retrofitted Units
Non-Nuclear
Nuclear
For New Units
Non-Nuclear
Nuclear
EPA
Estimate
$20.43
24.58
$4.89
3.84
UWAG
Estimate
$22.44
27.01
$6.40
4.27
These estimates of capital costs are significantly
closer than those which prevailed after the publication
of the proposed guidelines. The remaining differences
can be attributed to:
differences in the base period and
inflation rates used to convert
the estimates to a consistent basis
for comparison, and
differences in the mix of cooling
equipment assumed to be installed.
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EPA has assumed that the capital cost associated with
the Act should be based upon mechanical draft cooling
towers; whereas, UWAG assumed a mix of mechanical and
the more expensive natural draft towers which they
believe approximated the existing distribution of cool-
ing towers.
OPERATING COST FACTORS
UWAG assumptions for the cost of installing,
operating, and maintaining closed-cycle cooling systems
differ from those of EPA in two ways. First, UWAG has
assumed that the annual operating cost for replacement
capacity differs from EPA estimates as follows:
. THERMAL ANNUAL OPERATING COST
FACTORS FOR REPLACEMENT CAPACITY
(Expressed in 1972 Dollars/Kilowatt)
For Retrofitted Units
Non-Nuclear
Nuclear
For New Units
Non-Nuclear
Nuclear
EPA
Estimates
$ 39.41
39.41
$ 39.43
23.12
UWAG
Estimates
$130.09
130.09
$ 84.56
23.12
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Th is variability in estimates results from a difference
in the assumptions underlying the computations, not in
the methodology employed to determine these costs.
Specifically,EPA assumed that new capacity would
be utilized v/ith the operating costs based upon: (1) an
average heat rate of 10,000 BTU per kilowatt hour, (2) a
fuel mix of 80 percent coal and 20 percent oil, and (3)
fuel prices of $7.00 per barrel for oil and $12.50 per
ton for coal. Since replacement capacity need not be
placed in service before 1981, adequate time exists for
installation of new capacity.
UWAG, on the other hand, assumed that the appro-
priate basis for computing the annual operating costs for
new plants would be: (1) an average heat rate of 10,000
BTU, (2) a fuel mix of 50 percent coal and 50 percent oil,
and (3) fuel prices of $12 per barrel for oil and $25 per
ton for coal. For existing plants, UWAG based its analysis
upon equal usage of residual oil, coal, and distillate with
corresponding heat rates of 12,500, 12,500 and 15,000 BTU.
Second, UWAG and EPA differ on the computational
procedure to be employed in estimating the costs asso-
ciated with operating less efficient generating equipment
during the period in which capacity being converted from
open to closed-cycle cooling is out of service.
TBS
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EPA assumed that the installation of closed-
cycle cooling on existing units or units under con-
struction but designed for open-cycle cooling would
require a downtime period of one month in addition
to the normal maintenance period. During this period,
it was assumed that the lost generation capability
would be made up by utilization of peaking capacity
with an incremental increase in heat rate of 2,500
BTU/KWH (12,500 less 10,000) with the same fuel mix
and fuel costs used in computing the total operating
costs for replacement capacity,
UWAG's computations reflect alternative sets
of conditions prevailing at the time of installation.
First, replacement capacity - if available during the
period of outage - would be relatively inefficient
cycling or peaking equipment. Second, for systems
with insufficient capacity to handle these outages,
the next option would be purchased power from other
utilities. Third, for those utility systems which would
be unable to purchase additional power from surrounding
systems, outages would require the purchase of peaking
units. In this last case, both the additional fuel cost
and the capital cost must be reflected.
5. The final regulation specifies that up to a two-year delay in
installation schedule can ~be granted where such conversions
would seriously impact system reliability.
ITIBIS
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These differences in underlying assump-
tions are summarized in the following table.
THERMAL OUTAGE COST FACTORS
(Expressed in 1972 Dollars/Kilowatt)
For Retrofitted Units
Non-nuclear
Nuclear
EPA
Estimates
$1.08
.89
UWAG
Estimates
$4.46
7.81
IMPACT OF COST FACTORS (THERMAL)
In order to estimate the economic impact of
the alternative cost factors developed by UWAG, two
additional cases were evaluated:
• UWAG Case #1 - Projections which corres-
pond to those previously associated with
the installation of closed-cycle cooling
for economic reasons, except that the
thermal cost factors - both capital and
annual operating - are those assumed by
UWAG; and
• UWAG Case #2 - Projections which corres-
pond to those previously analyzed after
consideration of 316(a) exemptions, except
that the thermal cost factors are those
assumed by UWAG.
These cases, along with the previously cited baseline
conditions, economic reasons, and after 316(a) exemptions
are provided in Exhibit 93 for the period 1974-83.
ITIBIS
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Prior to evaluating the effect of altering
the cost factors upon the economic impact of the Act, one
must first determine the increased impact of installing
closed-cycle cooling for reasons other than environmental.
Having computed the difference attributed to installa-
tion of closed-cycle cooling for economic reasons, the
following table summarizes the impact of the thermal
guidelines after considering the exemptions available
under Section 316(a) of the Act.
COST
UWAG Cost Factors
EPA Cost Factors
Difference
EFFECT OF UWAG ASSUMPTIONS
THERMAL (1974-1983)
(1974 Dollars)
Capital o/M
Expenditures Expenses
(in billions) (in billions)
$ 2.9 $ 2.2
2.7 0.9
$ 0.2 $ 1.3
1983
Consumer
Charges
(mills/KWH3
0.3
0.2
0.1
Thus, the cost effect of utilizing the UWAG
assumptions for thermal cost factors is an increase in
capital expenditures of $200 million in the next
decade, a $1.3 billion increase in operating costs dur-
ing the same period, and a 0.1 mill increase in the
1983 average cost per kilowatt-hour. The relatively
large increase in operations and maintenance expenses
primarily reflects the assumed significant increase in
fuel prices.
TlBlSl
-------
-169-
ALTERNATIVE CHEMICAL COST FACTORS
Perhaps the most diverse estimates are
those associated with the capital and operating cost
factors required to meet the final chemical guidelines.
EPA and UWAG were unable to resolve all of the differ-
ent assumptions - and the cost factors discussed below
reflect these differences.
CAPITAL COST FACTORS
The following tables summarize the differ-
ences in capital cost factors:
CHEMICAL CAPITAL COST FACTORS: NON-NUCLEAR
(Expressed in 1972 Dollars/Kilowatt)
Capacity prior to 1974
1977 Guidelines6
1983 Guidelines
Capacity 1974-78
1977 Guidelines
1983 Guidelines
Capacity 1979-90
1983 Guidelines
6
EPA
Estimate
$ 1.70
0.58
$1.29
0.52
$ 1.63
UWAG
Estimate
$5.78
$ 4.58
$ 3.18
6~. These capital expenditures are in addition to those required,to
meet the 197? guidelines.
TIBISI
-------
-170-
CHEMICAL.CAPITAL.COST FACTORS: NUCLEAR
(Expressed in 1972 Dollars/Kilowatt)
Capacity Prior to 1974
1977 Guidelines
1983 Guidelines7
Capacity 1974-78
1977 Guidelines
1983 Guidelines7
Capacity 1979-90
1983 Guidelines
EPA
Estimate
$0.58
$0.58
$ 0.48
UWAG
Estimate
$ 0.53
$ 0.53
$ 0.51
The variation in capital costs for non-nuclear
generating capacity is significant and should have a
significant effect upon the capital expenditures required
to meet the chemical guidelines. The differences for
nuclear capacity are not significant.
OPERATING COST FACTORS
The following tables summarize the differences
in annual operating cost factors:
'.These capital expenditures are in addition to those required to
meet the 1977 guidelines.
ITlBlS
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-171-
CHEMICAL ANNUAL OPERATING COST FACTORS: NON-NUCLEAR
(Expressed in 1972 Dollars/Kilowatt)
Capacity prior to 1974
1977 Guidelines
1983 Guidelines8
Capacity 1974-78
1977 Guidelines
1983 Guidelines8
Capacity 1979-90
1983 Guidelines
EPA
Estimate
$0.54
0.06
$0.25
0.02
$0.25
UWAG
Estimate
$0.61
$0.48
$0.50
CHEMICAL ANNUAL OPERATING COST FACTORS: NUCLEAR
(Expressed in 1972 Dollars/Kilowatt)
EPA
Estimate
Capacity prior to 1974
1977 Guidelines $0.20
1983 Guidelines8
Capacity 1974-78
1977 Guidelines $0 20
1983 Guidelines8
UWAG
Estimate
$0.004
$0.004
Capacity 1979-90
1983 Guidelines
$0.20
$0.006
.These annual operating expenditures are in addition to those require!
to meet the 1977 guidelines.
TBS
-------
-172-
These differences are rather insignificant
when compared with the absolute differences in capital
costs for non-nuclear capacity.
IMPACT OF COST FACTORS (CHEMICAL)
In order to estimate the economic impact
of the alternative chemical cost factors developed by
UWAG, an additional case was evaulated:
UWAG Case #3: Projections which cor-
respond to those previously associated
with the chemical guidelines, except
that the chemical cost factors are
those assumed by UWAG.
This case along with the previously cited baseline con-
ditions and chemical guidelines are provided in Exhibit
94 for the period 1974-83.
The cost effect of the UWAG assumptions
for chemical cost factors is summarized in the fol-
lowing table:
COST EFFECT OF UWAG ASSUMPTIONS
CHEMICAL (1974-83)
(1974 Dollars)
UWAG Cost Factors
EPA Cost Factors
Difference
Capital
Expenditures
(in billions)
$3.1
1.3
$1.8
O/M
Expenses
(in billions)
$2.0
2.1
($0.1)
Consumer
Charges
(mills/KWH)
0.2
0.2
0.0
-------
-173-
Thus, the differences in chemical cost
factors more than double the required capital ex-
penditures - by $1,8 billion. This impact far exceeds
the differential impact, for thermal cost factors.
The impact of utilizing UWAG assumptions has an insig-
nificant effect upon chemical 0/M expenses and the
average cost of electrical energy in 1983.
ALTERNATIVE BASELINE CONDITIONS
While UWAG accepted the vast majority of
TAC-Finance assumptions for future operating conditions
which were incorporated into the baseline projections
detailed in Chapter II, two areas of disagreement
remain.
First, UWAG does not accept the TAC-Finance
position that the most likely rate of industry growth
will be moderate after the short-run adjustments to
reflect the recent energy crisis (TAC-Finance Cases I
and IA). Instead, UWAG has proposed that the appropriate
baseline projections should incorporate the alternative
historical growth rate assumptions described in Chapter II
of this report (TAC-Finance Case II).
Second, UWAG does not believe that current
rates for interest on long-term debt and dividends on
preferred stock will stabilize at 8 percent. UWAG has
proposed that the long-run rate for these financing
instruments will approximate 10 percent.
TlBlSl
-------
-174-
ECONOMIC IMPACT
The alternative set of baseline conditions
proposed by UWAG required the evaluation of an
additional case:
UWAG Case #4 - Projections which
correspond to the previously mentioned
baseline conditions, except that the
rate of industry growth is the historic
rate and the capital market rates are
those assumed by UWAG.
This case, along with previously cited baseline and
historic conditions, is provided in Exhibit 95 for the
period 1974-83.
The following tables separately summarize the
economic impact upon baseline conditions of alternative
rates ,of industry growth and alternative capital market
assumptions:
BASELINE CONDITIONS WITH
ALTERNATIVE GROWTH RATES (1974-83)
(1974 Dollars)
Capital
Expenditures
(in billions)
Historic Growth $211.7
Moderate Growth 179.0
Difference $ 32.7
1983
O/M Consumer
Expenses Charges
(in billions) (mills/KWHT
$306.6
292.5
$14.1
23.9
23.6
0.3
TlBlS
-------
-175-
BASELINE CONDITIONS WITH HISTORIC GROWTH AND
ALTERNATIVE CAPITAL
MARKET RATES (
(1974 Dollars)
Capital 0/M
Expenditures Expenditures
(in billions) (in billions
UWAG Interest and
Preferred
Dividend Rates $211.7 $306.6
NPS Interest and
Preferred
Dividend Rates 211.7 306.6
Difference $ 0.0
$ 0.0
1974-83)
1983 Con-
sumer Charges
) (mills/ KWH
24.6
23.9
0.7
Thus, one can easily conclude that the baseline level of
expenditures is greatly influenced by the assumed rate of
growth and that the impact of these differences is sig-
nificantly greater than the above-mentioned differences
in cost factors. In addition, the capital market assumption
for future rates of interest on long-term debt and dividends
on preferred stock have a significant impact upon the
1983 cost of electricity but no effect on expenditure
levels.
The amount of generating capacity which is
covered under the guidelines of the Act increases with
the change in the growth rate of the electric utility
industry from moderate to historic. This increase in
capacity required to install closed-cycle cooling -
when coupled with the cost factors assumed by EPA - impacts
-------
-176-
the economic costs associated with the Act. These
growth effects have been separated from the direct cost
effects of utilizing UWAG cost factors since they are
the result of higher industry growth and capital market
conditions - and not higher cost factors.
In addition to these indirect growth effects,
the interaction effects of simultaneously considering
the higher growth assumptions and the higher cost factors
proposed by UWAG must be evaluated separately.
IMPACT OF GROWTH ASSUMPTIONS (THERMAL)
The indirect effect of UWAG growth and capital
market assumptions upon the economic impact of the final
thermal guidelines after consideration of 316(a) can be
evaluated after specification of two additional cases:
UWAG Case #5 - Projections which corres-
pond to those previously associated with
the installation of closed-cycle cooling
for economic reasons, except that the
industry growth and capital market assump-
tions are those assumed by UWAG; and
UWAG Case #6 - Projections which corres-
pond to those previously analyzed after
consideration of 316(a) exemptions, ex-
cept that the industry growth and capital
market assumptions are those assumed by
UWAG.
ITIBISI
-------
-177-
These projections, along with the revised UWAG base-
line conditions (UWAG Case #4) are provided in
Exhibit 96 for the period 1974-83.
The following table summarizes the growth
effect associated with closed-cycle cooling after con-
sideration of 316(a) exemptions.
GROWTH EFFECT OF UWAG ASSUMPTIONS -
THERMAL (1974-83')
(1974 Dollars)
UWAG Baseline
NFS Baseline
Difference
Capital .
Expenditures
in^ billions)
$3.1
2.7
$0.4
0/M
Expenses
(in billions)
$1.1
0.9
$0.2
1983 Con-
sumer Charges
(mills/KWH
0.2
0.2
0.0
Thus, the indirect growth effect of utilizing
the UWAG baseline conditions with the EPA cost factors
is small - after deducting those units with closed-cycle
cooling for economic reasons and after exempting those
units eligible for 316(a) exemptions. The UWAG growth
assumptions would increase capital expenditures by $400
million during the next decade and 0/M expenses by $200
million.
T
B|SI
-------
-178-
IMPACT OF INTERACTION EFFECT (THERMAL)
In addition to the direct cost and indirect
growth effects of UWAG assumptions upon the economic
impact of the thermal guidelines, the interaction of
higher growth and higher cost factors combined
result in an increase in the overall impact. This
interaction effect requires the specification of
two additional cases:
UWAG Case #1 - Projections which
correspond to those previously
associated with the installation
of closed-cycle cooling for
economic reasons, except that
the baseline conditions and cost
factors are those assumed by UWAG;
and
UWAG Case #8 - Projections which
correspond to those previously
analyzed after consideration of
316(a) exemptions, except that
the baseline conditions and cost
factors are those assumed by UWAG.
These cases along with the revised baseline conditions
(UWAG Case #4), are provided in Exhibit 97 for the
period 1974-83.
|T|B|S
-------
-179-
The following table summarizes the inter-
action effects of alternative baseline and thermal cost
factor assumptions associated with closed-cycle cooling
after consideration of 316(a) exemptions.
INTERACTION EFFECT OF UWAG ASSUMPTIONS
THERMAL (1973-83)
(1974 Dollars)
Capital
Expenditures
(in billions)
UWAG Cost Factors
All Other Effects9
Difference
$3.4
3.3
$0.1
0/M
.Expenses
(in billions)
$2.7
2.4
$0.3
1983 Con-
sumer Charges
(mills/KWH
0.4
0.3
0.1
Thus, the interaction effect of alternative base-
line conditions and cost factors combine to increase the
economic impact of the thermal guidelines during the next
decade by $200 million for capital expenditures, $300 million
for operating expenses, and 0.1 mill for the average con-
sumer charge per kilowatt-hour.
9 . Includes economic impact of final guidelines plus
cost effect plus growth effect.
TIBISI
-------
-180-
IMPACT OF GROWTH ASSUMPTIONS (CHEMICAL)
The indirect growth of UWAG growth and
capital market assumptions can be evaluated by
specifying an additional case:
• UWAG Case #9 - Projections which
correspond to those previously
associated with the final chemical
guidelines except that the industry
growth and capital market assumptions
are those assumed by UWAG.
These projections, along with the revised UWAG base-
line conditions (UWAG Case #4), are provided in
Exhibit 98 for the period 1974-83.
The following table summarizes the indirect
growth effect of the thermal guidelines:
GROWTH EFFECT OF UWAG ASSUMPTIONS
CHEMICAL (1974-831
(1974 Dollars)
Capital
Expenditures
(in billions)
0/M
Expenses
(in billions)
1983
Consumer
Charges
(mills/KWH)
UWAG Baseline $ 1.5
EPA Baseline 1.3
Difference $ 0.2
$ 2.1
2.1
$ 0.0
0.2
0.2
0.0
ITIBIS
-------
-181-
Thus, the indirect growth effect of utilizine-
the UWAG baseline conditions with the EPA cost factors
is small - amounting to an increase in capital expenditures
of $200 million.
IMPACT OF INTERACTION EFFECT (CHEMICAL)
The interaction of UWAG baseline conditions
and UWAG chemical cost factors combined can be evaluated
by specifying an additional case:
• UWAG Case #10 - Projections which cor-
respond to those previously associated
with the final chemical guidelines,
except that the baseline conditions and
cost factors are those assumed by UWAG.
These projections are included in Exhibit 98.
The following table summarizes the inter-
action effect of alternative baseline and chemical cost
factor assumptions:
INTERACTION EFFECT OF UWAG ASSUMPTIONS
CHEMICAL (1974-83)
(1974 Dollars)
UWAG Cost Factors
All Other Effects
Difference
Capital
Expenditures
(in billions)
$3.3
10 3.3
$0.0
0/M
Expenses
(in billions)
$2.1
2.0
$0.1
1983
Consumer
Charges
(mills/KWH)
0.3
0.2
0.1
10-Includes economic impact of final guidelines plus cost effect
plus growth effect.
TBS
-------
-182-
Thus, the interaction effect has a slight
impact upon O/M expenses ($100 million) over the next
decade and increases consumer charges by 0.1 mill
per kilowatt-hour by 1983. These differences are
primarily a result of rounding errors.
SUMMARY
In order to appropriately assess the economic
impacts of alternative assumptions proposed by UWAG,
TBS segmented the impact into the direct cost effect
of higher capital and operating cost factors, the in-
direct growth effect of historic baseline conditions,
and the interaction effect of simultaneously considering
both of the above.
Furthermore, it is the opinion of TBS that
only the direct cost effect is the appropriate measure
of the differences that remain between EPA and UWAG.
The other effects are associated with the growth
assumptions wherein the EPA assumptions correspond
quite closely to the recent revised forecasts published
in Electrical World.
THERMAL GUIDELINES
The total impact of the UWAG assumptions upon
the thermal guidelines after consideration of 316(a)
exemptions is summarized in the following table:
ITIBIS
-------
-183-
ECONOMIC IMPACT OF UWAG ASSUMPTIONS
UPON THERMAL GUIDELINES (1974-83)
(1974 Dollars)
1983
Capital 0/M Consumer
Expenditures Expenses Charges
(in billions) (in billions) (mills/KWH)
Cost Effect $0.2 $ 1.3 0.1'
Growth Effect 0.4 0.2 0.0
Interaction Effect 0.1 0.3 0.1
Difference $0.7 $ 1.8 0.2
Thus, the total impact of the UWAG assumptions
is to increase the capital expenditures required during the
next decade to meet the thermal guidelines from $2.7
to $3.4 billion. In addition, 0/M expenses - primarily
a result of a near doubling in the cost of fossil fuel -
increase from $0.9 to $2.7 billion during the next decade.
The total of these increases is projected to increase the
average cost of a kilowatt-hour of electricity by 0.2 mill
by 1983.
CHEMICAL 6UIDFI IMPS
The total impact of the UWAG assumptions
upon the chemical guidelines is summarized in the
following table :
IrlBlsl
-------
-184-
ECONOMIC IMPACT OF UWAG ASSUMPTIONS
UPON CHEMICAL GUIDELINES (1974-83)
(1974 Dollars)
1983
Capital 0/M Consumer
Expenditures Expenses Charges
(in billions) (in billions) (mills/KWH)
Cost Effect $1.8
Growth Effect 0.2
Interaction Effect 0.0
Difference $2.0
$(0.1)
0.0
0.1
$ 0.0
0.0
0.0
0.1
0.1
Thus, the total impact of the UWAG assumptions
is to increase the capital expenditures required during
the next decade to meet the chemical guidelines from
$1.3 to $3.3 billion - primarily as a result of widely
different capital cost assumptions for non-nuclear
capacity. This increase in capital expenditures is
nearly three times the increase resulting from dif-
ferences in thermal cost factors.
In addition, 0/M expenses are not expected
to increase as a result of different assumptions - once
again a marked contrast with the conclusion for the
thermal guidelines. These increases should result in
a 0.1 mill increase in the average cost of a kilowatt-
hour by 1983.
iTlBlSJ
-------
EXHIBITS
-------
Exhibit 1
GROWTH IN ENERGY DEMAND AND IN PEAK LOAD
RELATIVELY PREDICTABLE THROUGH EARLY 1960s
Growth
Period
1960-1961
1961-1962
1962-1963
1963-1964
1964-1965
Growth in
Energy Demand
Average
' 5%
^^^^^1
i^$$^$^m
S 7.1%
E$$^^^$^3
7.7%
7.1%
6.9%
Standard
Deviation
Growth in
Peak Load
Standard
Deviation
Average
0%
7.3%
6%
.5%
7.
Sources: EEI, Electrical World
-------
Exhibit 2
ANNUAL LOAD FACTOR REMARKABLY
CONSTANT THROUGH EARLY 1960s
Year
1960
1961
1962
1963
1964
1965
Load Factor
65.5%
64.8%
64.9%
65.2%
64.2%
65.0%
Source: EEI
TlBlSI
-------
Exhibit 3
COST PER KILOWATT OF INSTALLED CAPACITY AT END OF 1960s
WAS ABOUT SAME LEVEL AS AT START
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
Average Cost of All New
Units Placed In Service During Year
$135
$1°6
$139
$144
$116
$109
$85
$111
$128
h^^^^S^^ $149
$141
Source: FPC
ITIBISI
-------
Exhibit 4
INVESTMENT IN ELECTRIC PLANT PER DOLLAR OF
REVENUE QUITE CONSTANT DURING EARLY 1960s
Year
1960
1961
1962
1963
1964
1965
1966
Investment Per
Dollar of Electric Revenue
$4.49
4.51
4.45
4.45
4.44
4.46
4.46
Source: FPC
IrlBlsl
-------
Exhibit 5
CAPITAL EXPENDITURES GREW VERY SLOWLY IN EARLY 1960s
Year
1960
1961
1962
1963
1964
1965
Annual Capital Expenditures
(billions)
$3.3
$3.3
$3.2
$3.3
$3.6
$4.0
TBS
-------
Exhibit 6
COST PER KILOWATT-HOUR - BOTH TOTAL AND MAJOR
COMPONENTS -DECLINED DURING EARLY 1960s
Operations & Maintenance Costs
Per kWh
Total Cost
Year
1960
1961
1962
1963
1964
1965
1966
i
Excluding
Per kWh
16.
16.
16.
15.
15.
15.
14.
3 mills
3
0
7
4
1
9
5
5
5
5
5
5
5
Fuel
.8 mills
.7
.6
.5
.4
.4
.3
Fuel Only
2
2
2
2
2
2
2
.9 mills
.9 •
.9
.8
.8
.7
.8
\
Total
8
8
8
8
8
8
8
.7 mills
.6
.5
.3
.2
.1
.1
Interest Cost
Per kWh
1
1
1
1
1
1
1
2 mills
2
2
2
1
1
1
All Other Costs
Per kWh
6.4 mills
6.5
6.3
6.2
6.1
5.9
5.7
H
fi
(A
Sources: FPC, EEI, TBS Estimates
-------
Exhibit 7
GROWTH IN REVENUES STEADY AND
CONSISTENT THROUGH EARLY 1960s
Growth
Period
1960-1961
1961-1962
1962-1963
1963-1964
1964-1965
Growth in
Operating Revenues
Aver a .TG
5.4%
5.5%
5.5%
5.7%
5.;
Standard Deviation
6.8%
0.6%
Source: FPC
TIBISI
-------
Exhibit 8
RATES DECLINED ALONG WITH REVENUES PER
KWH THROUGH THE EARLY 1960s
Average Bill for
Residential Service
Year
1960
1961
1962
1963
1964
1965
Total Change
1960-1965
500 kWh
$10.62
10.64
10.66
10.64
10.61
10.41
-2.0%
250
$7.
7.
7.
7.
7.
7.
-0
kWh
44
45
48
48
43
38
.8%
Revenue Per kWh
All Customers
1.
1.
1.
1.
1.
1.
-5
69
-------
Exhibit 9
NUMBER OF CUSTOMERS AND AVERAGE USAGE PER CUSTOMER
INCREASED SIGNIFICANTLY DURING THE EARLY 1960s
Period
1960
1961
1962
1963
1964
1965
Total Change
Total Customers
58
60
61
62
64
65
,870
,130
,324
,857
,148
,558
+11.
,000
,000
,000
,000
,000
,000
4%
kWh Per
11,
11,
12,
13,
13,
14,
+ 25
Customer
605
986
656
218
880
543
.3%
Sources: EEI
TlBlSl
-------
Exhibit 10
FINANCIAL RESULTS GOOD THROUGH THE EARLY 1960s
Year
1960
1961
1962
1963
1964,
1965
Overall
Increase
Average
Annual
Increase
Net
Income
(in millions)
$1,666
1,741
1,954
2,100
2,185
2,381
42.9%
8.6%
Earnings Return on
Per Share Common Equity
$ 4
4
4
4
5
5
43
8
.12 11 . 7%
.33 11.6
.73 12.4
.99 12.7
.41 12.5
.92 12.9
.7%
.7%
Return on
Total Investment
6.4%
6.4
6.8
7.0
6.9
7.2
Sources: FPC, TBS estimates
TBS
-------
Exhibit 11
INDICATORS OF INVESTMENT CLIMATE IMPROVED
SIGNIFICANTLY DURING EARLY 1960s
Year
1960
1961
1962
1963
1964
1965
Price Earnings Ratio
16.9
20.9
19.3
20.6
20.1
19.8
Year
1960
1961
1962
1963
1964
1965
Ratio of Market Price
to Book Value
1.69
Js 2.11
N 2.04
2.15
2,15
2.22
Source: Moody's Public Utilities Manual
PTlBlsl
-------
Exhibit 12
UTILITY MANAGEMENT SHIFTED THEIR CAPITALIZATION
TOWARD EQUITY DURING THE EARLY 1960s
Year
1960
1961
1962
1963
1964
1965
Cajpi/tal.iz;a.ti_ori Radios
Long-Term Debt Common Equity
52.8% 36.5%
52.8 36.8
52.4 37.3
52.1 37.9
51.8 38.6
51.5 39.0
Source: Moody's Public Utilities Manual
TlBISl
-------
Exhibit 13
INTERNALLY GENERATED FUNDS BECAME MORE IMPORTANT
DURING THE EARLY 1960s AS BOTH NEW DEBT AND EQUITY TAPERED OFF
External Funds
Total Sources
Year of Funds
1960
1961
1962
1963
1964
1965
Totals
1960-1962
Percent
1963-1965
Percent
(in millions)
$3,660
3,359
3,359
3,336
3,832
4,078
$21,624
100%
100%
Debt
$1,226
996
764
829
1,008
1,261
$6,084
29%
28%
New Equity
$704
633
610
747
704
521
$3,919
19%
17%
Internal
Funds
$1,729
1,729
1,984
1,759
2,119
2,294
$11,614
52%
55%
Source: FPC
TBS
-------
Exhibit 14
INDUSTRIAL BOND RATE VIRTUALLY CONSTANT UNTIL 1965,
THEN MOVED SHARPLY UPWARD
Year
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
Industrial Bond Rate
4-67%
4.70%
4.53%
4.42%
4.51%
4.80%
5.52%
5.79%
6.64%
^$$^^^^^^^
^^^m^$^^
8.86%
TBS
-------
Exhibit 15
REQUIREMENTS FOR EXTERNAL FINANCING HAVE
GROWN DRAMATICALLY SINCE MID-1960S
Total
Year
1965
1960-1965 Total
1966
1967
1968
1969
1970
1971
1972
1973
1966-1973
Average
Sources
of Funds
$ 4
21
5
6
7
7
11
12
14
14
79
,078
,624
,551
,160
,101
,983
,043
,520
,142
,902
,402
External
Funds
$ 1
10
3
3
4
4
7
8
9
10
52
,784
,010
,039
,618
,260
,817
,778
,930
,736
,214
,392
Percent
External
43
46
54
58
60
60
70
71
68
68
66
7%
.3
7
7
0
3
4
3
8
5
0
Source: FPC
TBS
-------
Exhibit 16
GROWTH IN ENERGY CONSUMPTION AND IN PEAK LOAD
ACCELERATED SINCE THE EARLY 1960s AND
PREDICTABILITY DETERIORATED
Growth
Period
1960-1965
Growth in
Energy Consumption
Average
6.!
Growth in
Peak Load
Average
Standard
Deviation
1965-1966
1966-1967
1967-1968
1968-1969
1969-1970
1970-1971
1971-1972
1972-1973
7.5%
Standard
Deviation
Standard
Deviation
1^-1.
Average
0%
^$^^P
8.3%
4%
7.
1.3% Standard -> |
Deviation
Source: EEI, Electrical World
TIBISI
-------
Exhibit 17
COST PER KW OF INSTALLED CAPACITY
INCREASED DRAMATICALLY SINCE THE 1960s
Years
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
Average Cost of All New
Units On-stream During Year
$135
$144
1970
1971
1972
1973
1974
Sources: FPC, Power Engineering, TBS estimates
TBS
-------
Exhibit 18
CAPITAL EXPENDITURES - AFTER A PERIOD OF RELATIVE CONSTANCY IN
EARLY 1960s - HAVE GROWN RAPIDLY SINCE THAT TIME
Annual Capital Expenditures
(billions)
$3.3
$3.3
$3.2
$3.3
$4.0
Average Annual Growth Rate
4.2%
1960-1965 1966-1973
1969
$7.1
$10.1
$11.9
$13.4
$14.9
-------
Exhibit 19
INTERNALLY GENERATED FUNDS NOT GROWING
AS FAST AS NEED FOR FUNDS SINCE 1965
Year-to-Year
Year
1960-1961
1961-1962
1962-1963
1963-1964
1964-1965
1965-1966
1966-1967
1967-1968
1968-1969
1969-1970
1970-1971
1971-1972
1972-1973
1960-1965
Average Rate
1965-1973
Average Rate
Internal Funds
0
14
-11
20
8
9
1
11
11
3
10
22
6
6
9
.0%
.7
.3
.5
.3
.5
.2
.8
.4
.1
.0
.7
.4
.4%
.5%
Growth Rate
Need for Funds
-8
0
-0
14
6
36
11
15
12
38
13
13
5
2
18
.2%
.0
.7
.9
.4
.1
.0
.3
.4
.3
.4
.0
.4
.5%
.1%
Source: FPC
TlBlSl
-------
Exhibit 20
COST PER KILOWATT-HOUR --BOTH TOTAL AND MAJOR
COMPONENTS - BOTTOMED OUT IN LATE 1960s, THEN CLIMBED STEADILY
Operations
Total Cost
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Per kWh
16
16
16
15
15
15
14
14
14
14
15
16
17
17
3 mills
3
0
.7
4
1
9
8
8
9
5
5
2
3
& Maintenance Costs
Per kWh
Excluding
Fuel
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
5.
6.
NA
8 mills
7
6
5
4
4
3
3
1
2
4
7
0
Fuel Only
2.
2.
2.
2.
2.
2.
2.
2.
2.
3.
3.
4.
4.
NA
9 mills
9
9
8
8
7
8
8
9
0
5
1
4
Interest Cost
Total
8.
8.
8.
8.
8.
8.
8.
8.
8.
8.
8.
9.
10.
NA
7 mills
6
5
3
2
1
1
1
0
2
9
8
4
Per kWh
1.
1
1.
1.
1.
1.
1.
1.
1.
1.
1.
2.
2.
NA
2 mills
2
2
2
1
1
1
2
3
5
8
0
1
All Other Costs
Per kWh
6.4 mills
6.5
6.3
6.2
6.1
5.9
5.7
5.5
5.5
b.2
4.8
4.7
4.7
NA
Sources: FPC, EEI, TBS estimates
TBS
-------
Exhibit 21
FUEL COST COMPONENTS BOTTOMED OUT
IN MID-TO LATE-1960S AND INCREASED SINCE
h 10,800
3
IB 10,700
£ 10,600
,3 10,500
•H
* 10,400
o>
°- 10,300
3
« 10,200
10,100
Heat Rate
1960 61 62 63 64 65 66 67 68 69 70 71 72 73
Years
Years
I960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Fuel Cost Per Million Btu
26.2?
26.7?
26.4?
25.7?
25.3?
25.2?
25.4?
25.8?
26.3?
27.2?
" 31.3?
37.5?
41.1?
R^^^SS^^^^^S^^^^ 48.4?
Source: EEI
TBS
-------
Exhibit 22
NET INCOME FROM ELECTRIC OPERATIONS
UP SUBSTANTIALLY SINCE MID-1960S
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Net Income in Millions
$1,741
$1,954
$2,100
$2,185
$2,381
*2-
531
$2,769
$2,964
$3,105
Average Growth Rate
10. i
1960-1965 1966-1973
$3,463
$4,013
$4,460
Source: FPC, TBS estimates
T
B
s
-------
Exhibit 23
ALLOWANCE FOR FUNDS DURING CONSTRUCTION BECOMING AN
INCREASINGLY LARGER PORTION OF TOTAL NET INCOME
AFDC As Percent of Net Income
9.'
5.4%
6.4%
4.4%
4-1%
4.!
3.3% 3.3% 3.5%
28.9%
M
25.2%
22.2%
17.6%
I960 1961 1962 1963 1984 1965 1966 1967 1968 1969 1970 1971 1972 1973
Sources: FPC, TBS estimates
-------
Exhibit 24
CAPITAL STRUCTURES RELATIVELY UNCHANGED
OVER THE YEARS
Year
1960
1965
1970
1973
Capital Structure Proportions
Debt Preferred Stock Common Equity
52.8% 10.7% 36.5%
51.5 9.5 39.0
54.8 9.8 35.4
52.3 12.1 35.6
Source: FPC
-------
Exhibit 25
RATE OF GROWTH OF COMMON EQUITY UP SUBSTANTIALLY IN
RECENT YEARS; COMMON STOCK GROWTH UP EVEN MORE
Growth in Common Equity in Millions
$4099
Retained
Earnings
Common
Stock
$1112
•$590'
$522
$1369
\NN\\
$74 5;
^^
$624
$1729
^86^
V v x *
c$oc^
$863
$2550
'$755-
•NSXVs
61795
$3158
§7^
^^
$2392
$3894
$1165
^
$2729
51255
$2844
1966-1967 1967-1968 1968-1969 1969-1970 1970-1971 1971-1972 1972-1973
Common Stock
12.1%
5.1%
^
Average Annual Growth
Retained Earnings
13.7%
10.6%
Total Common Equity
12.6%
1960-1965 1966-1973
1960-1965 1966-1973
1960-1965 1966-1973
Sources: FPC, TBS estimates
TBS
-------
Exhibit 26
RETURN ON COMMON EQUITY DETERIORATED IN RECENT YEARS
13.1% 13.1%
Return on Common Equity
12.
12.5%
11.8%
11.5%
11.6%
1966
1967
1968
1969
1970 1971 1972 1973
Sources: FPC, TBS estimates
TBS
-------
Exhibit 27
PRICE EARNINGS RATIO OF COMMON STOCK
DETERIORATED BADLY IN RECENT YEARS
Price Earnings Ratio
19.8
16.3
15.3
14.8
13.7
11.5 11.8
. 10.4
9.4
1965 1966 1967 1968 1969 1970 1971 1972 1973
6.1
June
1974
Source: Moody's Public Utilities Manual
JTlBlsl
-------
Exhibit 28
RATIO OF MARKET PRICE TO BOOK VALUE OF COMMON STOCK
DETERIORATED STEADILY AND IS NOW LESS THAN ONE
Ratio of Market Price to Book Value
2.22
1.89
1.77
1.61
1.48
1.17
1.20
1.07
0.93
1965 1966 1967 1968 1969 1970 1971 1972 1973
0.56
June
1974
Sources: Moody's Public Utilities Manual, TBS estimates
TJBlSl
-------
$4.12
$6.30
m
Exhibit 29
GROWTH RATE IN EARNINGS PER SHARE DETERIORATED
SHARPLY SINCE THE EARLY 19603
Earnings Per Share
1960-1965
Annual Average
Growth Rate = 8.7%
$5.41
$4.33
I
I960 1961 1962 1963 1964 1965
Earnings Per Share
1966-1973
$7.73
S6.67 86.07
$6.92 56.39
$7.14
I
I
I
Annual Average
Growth Rate= 2.8%
$7.55
\
1966 1967 1968 1969 1970 1971 1972 1973
8.7%
y.
Average Annual Growth
In Earnings Per Share
1960-
1965
1966-
1973
Source: Moody's Public Utilities Manual
TBS
-------
Exhibit 30
FACTORS INFLUENCING THE ELECTRIC UTILITY INDUSTRY'S RATE OF GROWTH IN GENERATION
CAPACITY AND ELECTRIC ENERGY UNDER MODERATE GROWTH ASSUMPTIONS
1973 to 1990
(percent)
CO
Year
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Peak Load
Growth
Rate
(1)
9.4%
1.0
4.0
6.5
6.5
6.5
6.5
6.5
6.0
6.0
6.0
6.0
6.0
5.5
5.5
5.5
5.5
5.5
Capacity
Reserve
Margin
(2)
20.0%
24.0
26.0
25.0
24.0
23.0
22.0
21.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
Reserve
Factor
Growth
Rate
(3)
—
3.3%
1.6
-0.8
-0.8
-0.8
-0.8
-0.8
-0.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Generation
Capacity
Growth
Rate
(4)
—
4.3%
5.7
5.6
5.6
5.6
5.6
5.6
5.2
6.0
6.0
6.0
6.0
5.5
5.5
5.5
5.5
5.5
Capacity
Factor
(5)
49.9%
46.2
44.9
48.0
48.0
48.0
48.0
48.0
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
Capacity
Factor
Growth
Rate
(6)
—
-7.4%
-2.8
6.9
0.0
0.0
0.0
0.0
4.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Electric
Energy
Growth
Rate
(7)
—
-3.4%
2.7
12.9
5.6
5.6
5.6
5.6
9.4
6.0
6.0
6.0
6.0
5.5
5.5
5.5
5.5
5.5
Notes:
Column 1 NPS TAC-Finance assumption
Column 2 NPS TAC-Finance assumption
Column 3 Reserve factor = 1 + reserve margin
Column 4 Column 4 = (1 + Column !)*(! + Column 3) - 1
Column 5 NPS TAC-Finance assumption
Column 6 No explanation needed.
Column 7 Column 7 = (1 + Column 4)*(1 + Column 6) - 1
Column 7 has not been adjusted for leap years.
Source: TAC-Finance
-------
Exhibit 31
TOTAL ELECTRIC UTILITY INDUSTRY GENERATION CAPACITY ADDITIONS, KKi'IREMENTS,AND TOTALS
BY PLANT TYPE AND TOTAL SALES TO ULTIMATE CONSUMERS UNDER MODERATE GROWTH ASSUMPTIONS
1973 to 1990
Year
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Total Net
Generation
Capacity
.millions,
<• of kW '
422.1
440.5
465.5
491.8
519.6
549.0
579.9
612.5
643.4
682.1
723.1
766.4
812.5
857.2
904.4
954.2
1,006.7
1,062.1
Gross
Capacity
Additions
.millions,
1 of kW ;
--
20.0
26.6
29.3
30.9
32.5
34.2
36.0
37.0
44.9
47.4
50.0
52.9
51.8
54.4
57.2
60.1
63.2
Generation from Non-Nuclear Plants
Gross
Net Capacity Capacity
Capacity Additions Retirements
.millions,
( of kW ;
394.4
406.8
423.8.
438.4
453.8
470.2
487.4
505.6
518.0
534.3
551.6
569.9
589.6
603.2
617.8
633.3
649.7
667.2
-millions,
1 of kW ;
—
14.0
18.6
17.6
18.5
19.5
20.5
21.6
18.5
22.5
23.7
25.0
26.5
20.7
21.8
22.9
24.0
25.3
1 ..millions,
1 of kW ;
—
1.6
1.6
3.0
3.1
3.2
3.3
3.4
6.1
6.2
6.4
6.6
6.8
7.1
7.2
7.4
7.6
7.8
Generation from Nuclear Plants
Gross
Net Capacity Capacity
Capacity Additions Retirements
..millions,
*• of kW ;
27.7
33.7
41.7
53.4
65.8
78.8
92.5
106.9
125.4
147.8
171.5
196.5
222.9
254.0
286.6
320.9
357.0
394.9
.millions.
1 of kW ;
—
6.0
8.0
11.7
12.4
13.0
13.7
14.4
18.5
22.4
23.7
25.0
26.4
31.1
32.6
34.3
36.1
37.9
.millions.
( of kW '
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total Sales1
toUltimate
Consumers
.billions.
( ofkWh '
1 , 845 .1
1 .. 782 . 8
1,830.9
2,067.9
2,184.8
2,308.4
2,438.4
2,575.4
2,812.5
2,981.6
3,160.8
3,350.1
3,551.6
3,747.0
3,953.3
4,171.0
4,400.5
4,642.7
H
9
0)
No attempt was made to adjust these sales to account for leap years.
Source: PTm
-------
Exhibit 32
GENERATING CAPACITY COST GROWTH
(expressed in current dollars)
Non-Nuclear Generating
Capacity
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity
$ per kilowatt
% cost escalation
1973
$165.01
1977
1983
$235.62 $338.47
9.3% 6.2%
$226.47 $345.14 $497.87
11.1% 6.3%
1990
$446.26
5.0%
$700.56
5.0%
OTHER PLANT AND EQUIPMENT COST GROWTH
(expressed in current dollars)
Nuclear Fuel
$ per kilowatt
% cost escalation
Transmission and
Distribution Equipment
$ per kilowatt
% cost escalation
1973 1977 1983 1990
$ 43.16 $.48.57 $ 63.22 $ 95.05
3.0% 4.5% 6.0%
$208.37 $253.28 $339.42 $447.59
5.0% 5.0% 5.0%
Source: TAC-Finance
TBS
-------
Exhibit 33
SCHEDULE OF CONSTRUCTION WORK IN PROGRESS CASH PAYMENTS
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 Generating
Capacity (and related pollution control equipment)
placed in service during Period T incurred by:
• Period T-l 100 Percent
• Period T-2 75 Percent
o Period T-3 50 Percent
o Period T-4 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
Source: TAC-Finance
TBS
-------
Exhibit 34
OPERATIONS AND MAINTENANCE COST GROWTH
(expressed in current dollars)
1973
Operations and
Maintenance Expenses:
Non-Nuclear Generating
Capacity
mills per kilowatt hour 9.5
% cost escalation
Operations and
Maintenance Expenses:
Nuclear Generating
Capacity (excluding
fuel)
mills per kilowatt hour 4.2
% cost escalation
1977
15.3
12.63
5.1
5.0%
1983
22.3
6.5%
.1990
31.4
5.0%
6.8
5.0%
9.6
5.0%
Source: TAG Finance
TBS
-------
Exhibit 35
ECONOMIC AND FINANCIAL PROJECTIONS OF BASKLINE CONDITIONS
WITH MODERATE GROWTH ASSUMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
Excludes nuclear fuel
Source: PTm
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations & Maintenance Expenses1
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
1977
$ 17.9
60.3
$26.5
$ 10.9
35.8
$ 52.5
188.8
$ 26.4
92.0
24.0
1983
$ 28.3
203.2
$ 43.8
$ 17.8
126.3
$ 74.7
579.5
$ 38.0
292.5
23.6
1990
$ 39.1
441.4
$ 62.2
$ 23.6
272.6
$ 104.1
1,218.0
$ 49.5
603.7
22.4
-------
Exhibit 36
FACTORS INFLUENCING THE ELECTRIC UTILITY INDUSTRY'S RATE OF GROWTH IN GENERATION
CAPACITY AND ELECTRIC ENERGY UNDER HISTORIC GROWTH ASSUMPTIONS
1973 to 1990
(percent)
H
B
(fi
Year
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Peak Load
Growth
Rate
(1)
9.4%
3.0
5.0
7.2
7.2
7.2
7.2
7.2
6.7
6.7
6.7
6.7
6.7
6.6
6.6
6.6
6.6
6.6
Capacity
Reserve
Margin
(2)
20.0%
26.0
28.0
26.7
25.3
24.0
22.7
21.3
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
Reserve
Factor
Growth
Rate
(3)
5.0%
1.6
-1.0
-1.1
-1.0
-1.0
-1.1
-1.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Generation
Capacity
Growth
Rate
(4)
8.2%
6.7
6.1
6.0
6.1
6.1
6.0
6.0
6.7
6.7
6.7
6.7
6.6
6.6
6.6
6.6
6.6
Capacity
Factor
(5)
49.9%
46.2
44.9
47.4
47.4
47.4
47.4
47.4
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
49.9
Capacity
Factor
Growth
Rate
(6)
-7.4%
-2.8
5.6
0.0
0.0
0.0
0.0
5.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Electric
Energy
Growth
Rate
(7)
0.2%
3.7
12.0
6.0
6.1
6.1
6.0
11.6
6.7
6.7
6.7
6.7
6.6
6.6
6.6
6.6
6.6
Notes:
Column 1 NPS TAC-Finance assumption
Column 2 NPS TAC-Finance assumption
Column 3 Reserve factor = 1 + reserve margin
Column 4 Column 4 = (1 + Column !)*(! + Column 3) - 1
Column 5 NPS TAC-Finance assumption
Column 6 No explanation needed.
Column 7 Column 7 = (1 + Column 4)*(1 + Column 6) - 1
Column 7 has not been adjusted for leap years.
Source: TAC-Finance
-------
Exhibit 37
TOTAL ELECTRIC UTILITY INDUSTRY GENERATION CAPACITY ADDITIONS, RETIREMENTS, AND TOTALS
BY PLANT TYPE AND TOTAL SALES TO ULTIMATE CONSUMERS UNDER HISTORIC GROWTH ASSUMPTIONS
1973 to 1990
Year
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
Total Net
Generation
Capacity
-millions.
1 of kW '
422.1
456.5
487.0
516.7
547.8
581.2
616.5
653.4
689.7
735.9
785.2
837.8
894.0
953.0
1,015.8
1,082.8
1,154.3
1,230.4
Gross
Capacity
Additions
.millions.
1 of kW '
—
36.0
32.1
32.8
34.3
36.7
38.8
40.4
42.7
52.8
56.1
59.7
63.5
66.6
70.7
75.1
79.8
84.8
Generation from Non-Nuclear Plants
Gross
Net Capacity Capacity
Capacity Additions Retirements
.millions.
^ of kW '
394.4
418.0
438.9
455.5
472.9
491.6
511.4
532.1
547.1
566.9
588.2
611.0
635.4
654.4
674.8
696.7
720.3
745.5
..millions,
1 of kW >
—
25.2
22.5
19.7
20.6
22.0
23.3
24.2
21.4
26.4
28.1
29.9
31.7
26.6
28.3
30.0
31.9
33.9
, millions.
*• of kW ;
—
1.6
1.7
3.1
3.2
3.3
3.4
3.6
6.4
6.6
6.8
7.1
7.3
7.6
7.9
8.1
8.4
8.6
Generation from Nuclear Plants
Net
Capacity
. millions.
<• of kW '
27.7
38.5
48.1
61.2
74.9
89.6
105.1
121.3
142.6
169.0
197.0
226.8
258.6
298.6
341.0
386.1
434.0
484.9
Gross
Capacity Capacity
Additions Retirements
..millions.
<• of kW >
10.8
9.6
13.1
13.7
14.7
15.5
16.2
21.3
26.4
28.0
29.8
31.8
40.0
42.4
45.1
47.9
50.9
-millions,
1 of kW ;
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Total Sales
Ultimate
Consumers
.billions.
<• of kWh ;
1,845.1
1,847.5
1,915.5
2,145.5
2,274.6
2,413.3
2,559.9
2,713.1
3,014.8
3,216.8
3,432.3
3,662.2
3,907.9
4,165.8
4,440.3
4,733.2
5,045.7
5,378.4
-f.
Source: PTm
-------
Exhibit 38
H
fi
V)
ECONOMIC AND FINANCIAL PROJECTIONS OF BASELINE
CONDITIONS WITH HISTORIC GROWTH, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
1973
Capital Expenditures
Total for year $18.3
Total since 1973
Construction Work in Progress
End of year $24.0
External Financing
Total for year $ 11.8
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses1
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
1977
$ 20.1
72.9
$ 29.9
$ 12.4
45.4
$ 55.5
198.4
$ 27.3
95.0
24.4
1983
$ 34.3
241.2
$ 53.5
$ 22.3
154.4
$ 81.9
619.4
$ 40.7
306.6
23.9
1990
$ 53.4
555.2
$ 85.0
$ 33.7
355.6
$122.8
1,348.5
$ 56.1
650.8
22.8
Excludes nuclear fuel
Source: PTm
-------
Exhibit 39
ECONOMIC AND FINANCIAL IMPACT OF REDUCED GROWTH - 1977
(dollar figures in billions of 1974 dollars)
Historic
Growth Impact of
Conditions Reduced Growth
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses!
Total for year
Total since 1973
Consumer Charges (Mills/kWh)
Average for year
$20.1 - 2.2
72.9 -12.6
$29.9 - 3.4
$12.4 - 1.5
45.4 - 9.6
$55.5 - 3.0
198.4 - 9.6
$27.3 - 0.9
95.0 - 3.0
24.4 - 0.4
Baseline
Conditions
$17.9
60.3
$26.5
$10.9
35.8
$52.5
188.8
$26.4
92.0
24.0
Excludes nuclear fuel
Source: PTm
-------
Exhibit 40
ECONOMIC AND FINANCIAL IMPACT OF REDUCED GROWTH - 1983
(dollar figures in billions of 1974 dollars)
Historic
Growth
Conditions
Capital Expenditures
Total for year $ 34.3
Total since 1973 241.2
Construction Work in Progress
End of year $ 53.5
External Financing
Total for year $ 22.3
Total since 1973 154.4
Operating Revenues
Total for year $ 81.9
Total since 1973 619.4
Operations and Maintenance Expenses1
Total for year $ 40.7
Total since 1973 306.6
Consumer Charges (Mills/kWh)
Average for year 23.9
Impact of
Reduced Growth
- 6.0
-38.0
- 9.7
- 4.5
-28.1
- 7.2
-39.9
- 2.7
-14.1
- 0.3
Baseline
Conditions
$ 28.3
203.2
$ 43.8
$ 17.8
126.3
$ 74.7
579.5
$ 38.0
292.5
23.6
Excludes Nuclear Fuel
Source: PTm
-------
Exhibit 41
ECONOMIC AND FINANCIAL IMPACT OF REDUCED GROWTH - 1990
(dollar figures in billions of 1974 dollars)
H
Capital Expenditures
Total for year
Total since 1973
Construction ffork in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Historic
Growth
Conditions
$ 53.4
555.2
$ 85.0
$ 33.7
355.6
$122.8
1,348.5
Operations and Maintenance Expensesl
Total for year $ 56.1
Total since 1973 650.8
Consumer Charges (Mills/kWh)
Average for year
22.8
Impact of
Reduced Growth
- 14.3
-113.8
- 22.8
-10.1
- 83.0
-18.7
-130.5
- 6.6
- 47.1
- 0.4
Baseline
Conditions
$ 39.1
441.4
$ 62.2
$ 23.6
272.6
$104.1
1,218.0
$ 49.5
603.7
22.4
Excludes Nuclear Fuel
Source: PTm
-------
Exhibit 42
CAPITAL COST GROWTH - THERMAL GUIDELINES
(expressed in current dollars)
1973
1977
1983
1990
Non-Nuclear Generating
Capacity: Retrofitted
Units
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Retrofitted
Units
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
$21.58 $26.89 $36.71 $51.66
5.7% 5.3% 5.0%
$ 5.17 $ 6.44 $ 8.79 $12.36
5.7% 5.3% 5.0%
$26.01 $32.58 $44.67 $62.86
5.8% 5.4% 5.0%
$ 4.06 $ 5.09 $ 6.98 $9.82
5.8% 5.4% 5.0%
Source: Burns and Roe, Sargent and Lundy
TBS
-------
Exhibit 43
ANNUAL OPERATING COST GROWTH - THERMAL GUIDELINES
(expressed in current dollars)
All Generating Capacity:
Retrofitted Units
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: New Units
$ per kilowatt
% cost escalation
1973
$45.32
1977
1983
$45.34
$24.28
$29.51
5.0%
$39.54
5.0%
1990
$72.95 $106.38 $149.69
12.6% 6.5% 5.0%
$72.99 $106.44 $149.77
12.6% 6.5% 5.0%
$55.64
5.0%
Source: EPA estimates
TBS
-------
Exhibit 44
NON-NUCLEAR CAPACITY COVERAGE BY IN SERVICE YEAR
Percent Covered
Existing Capacity
(prior to 1974)
Capacity under
Construction
(1974-1978)
Closed-cycle
Open-cycle
New Source Capacity
(1979-1990)
4.6
3 2.2%
100
24.5%
31%
10.(
32.5%
49%
49%
75%
Legend:
Before 316(a)
Exemptions
After 316(a)
Exemptions
Installed for
Economic Reasons
Source: ERCO, EPA estimates
TBS
-------
Exhibit 45
NUCLEAR CAPACITY COVERAGE BY IN SERVICE YEAR
Percent Covered
Existing Capacity
(prior to 1974)
Capacity under
Construction
(1974-1978)
Closed-cycle
Open-cycle
New Source Capacity
(1979-1990)
0 10
1 i i i i
[45.8%
::;:::if&:;| 12 9%
W////////< 5°%
r$ffiy$jffiffi XXK**™XXXV*. 50%
25%
| 50%
H:H:S!:i:;:i:i:SK:H:::i:;:;l 27 . 7%
y///////////m
•^i i
1 7O O<7
i i *°
100%
34.5%
Legend:
. Before 316(a)
• Exemptions
. After 316(a)
• ' i . r^xu^x *jj±\j\
{ } • Exemptions
Installed for
V///////A ' Economic Reasons
Source: ERGO, EPA estimates
TBS
-------
Exhibit 46
INSTALLATION SCHEDULE FOR RETROFITTED UNITS
(percentage of units)
1981 1982 1983 Total
Non-Nuclear Generating Capacity:
Placed in Service Prior to 1974
Before 316(a) Exemptions 4.6% - - 4.6%
After 316(a) Exemptions 2.2% - - 2.2%
Non-Nuclear Generating Capacity:
Placed in Service 1974-1978
Before 316(a) Exemptions 21.3% 6.3% 3.4% 31.0%
After 316(a) Exemptions 7.4% 2.2% 1.0% 10.6%
Nuclear Generating Capacity:
Placed in Service Prior to 1974
Before 316(a) Exemptions 45.8% - - 45.8%
After 316(a) Exemptions 12.9% - - 12.9%
Nuclear Generating Capacity:
Placed in Service 1974-1978
Before 316(a) Exemptions 49.6% 0.4% - 50.0%
After 316(a) Exemptions 27.7% - - 27.7%
Source: ERCO, EPA estimates
TBS
-------
Exhibit 47
ECONOMIC AND FINANCIAL PROJECTIONS WITH THERMAL POLLUTION CONTROL
EQUIPMENT FOR ECONOMIC REASONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H
H
0)
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses1
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1977
$ 18.0
60.9
$ 26.7
$ 11.0
36.3
$ 52.6
189.0
$ 26.5
92.1
24.1
0.8
0.1
1983
$ 28.5
205.1
$ 44.3
$ 18.0
127.8
$ 75.1
581.2
$ 38.1
293.2
23.7
3.0
0.2
1990
$ 39.5
445.5
$ 62.9
$ 23.8
275.5
$ 104.9
1,223.5
$ 49.8
606.1
22.6
7.0
0.4
^-Excludes nuclear fuel
Source: PTm
-------
Exhibit 48
H
B
(0
ECONOMIC AND FINANCIAL PROJECTIONS OF FINAL THERMAL GUIDELINES
BEFORE SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
Kxcludes micleav fuel
Source: PTm
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses-*-
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year —
1977
$ 18.5
62.4
$ 27.9
$ 11.5
37.6
$ 52.7
189.3
$ 26.5
92 . 2
24.1
1.6
0.1
1983 1990
$ 29.0 $ 40.0
211.2 455.2
$ 45.2 $ 64.2
$ 18.3 $ 24.2
132.6 282.3
$ 76.2 $ 106.5
585.3 1,237.3
$ 38.5 $ 50.5
294.7 611.2
24.1 22.9
9.8 20.2
0.6 1.1
-------
Exhibit 49
ECONOMIC AND FINANCIAL PROJECTIONS OF FINAL THERMAL GUIDELINES
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $39.5
Total since 1973
Operations and Maintenance Expenses
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1977
$ 18.3
61.8
$ 27.4
$ 11.2
37.1
$ 52.7
189.2
$ 26.5
92.2
24.1
1.6
0.1
1983 1990
$ 28.8 $ 39.8
208.3 450.8
$ 44.8 $ 63.7
$ 18.2 $ 24.0
130.3 279.2
$ 75.7 $ 105.7
583.6 1,231.2
$ 38.3 $ 50.2
294.1 609.1
23.9 22.8
7.0 14.6
0.4 0.8
Excludes nuclear- fuel
Source: PTm
-------
Exhibit 50
ECONOMIC AND FINANCIAL IMPACT OF THERMAL POLLUTION CONTROL
EQUIPMENT FOR ECONOMIC REASONS - 1977
(dollar figures in billions of 1974 dollars)
H]
w
Baseline
Conditions
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Tt\ Excludes nuclear fuel
1 Source: PTm
$ 17
60
$ 26
$ 10
35
$ 52
188
$ 26
92
24
—
.9
.3
.5
.9
.8
.5
.8
.4
.0
.0
Impact
of
Economic Reasons
+0.
+0.
+0.
+0.
+0.
+0.
+0.
+0.
+0.
+0.
+0.
+0.
1
6
2
1
5
1
2
1
1
1
8
1
Projections
Thermal
Equipment
With
For
Economic Reasons
$ 18.0
60.9
$ 26.7
$ 11.0
36.3
$ 52.6
189.0
$ 26.5
92.1
24.1
0.8
0.1
-------
Exhibit 51
ECONOMIC AND FINANCIAL IMPACT OF THERMAL POLLUTION CONTROL
EQUIPMENT FOR ECONOMIC REASONS- 1983
(dollar figures in billions of 1974 dollars)
Baseline
Conditions
Capital Expenditures
Total for year $28.3
Total since 1973 203.2
Construction Work in Progress
End of year $ 43.8
External Financing
Total for year $ 17.8
Total since 1973 126.3
Operating Revenues
Total for year $74.7
Total since 1973 579.5
Operations and Maintenance Expenses
Total for year $ 38.0
Total since 1973 292.5
Consumer Charges (mills/kWh)
Average for year 23.6
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads')
Total for year
Projections With
Thermal
Impact of Equipment for
Economic Reasons Economic Reasons
+0.2 $ 28.5
+1.9 205.1
+0.5 $ 44.3
+0.2 $ 18.0
+1.5 127.8
+0.4 $ 75.1
+1.7 581.2
+0.1 $ 38.1
+0.7 293.2
+0.1 23.7
+3.0 3.0
+0.2 0.2
H
H
ft
Excludes nuclear fuel
Source: PTm
-------
Exhibit 52
ECONOMIC AND FINANCIAL IMPACT OF THERMAL POLLUTION CONTROL
EQUIPMENT FOR ECONOMIC REASONS - 1990
(dollar figures in billions of 1974 dollars)
H
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Baseline Impact of
Conditions Economic Reasons
$ 39.1 +0.4
441.4 +4.1
$ 62.2 +0.7
$ 23.6 +0.2
272.6 +2.9
$ 104.1 +0.8
1,218.0 +5.5
$ 49.5 +0.3
603.7 +2.4
22.4 +0.2
+7.0
+0.4
Projections With
Thermal
Equipment For
Economic Reasons
$ 39.5
445.5
$ 62.9
$ 23.8
275.5
$ 104.9
1,223.5
$ 49.8
606.1
22.6
7.0
0.4
Excludes nuclear fuel
Source: PTm
-------
Exhibit 53
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
BEFORE SECTION 316(a) EXEMPTIONS-1977
(dollar figures in billions of 1974 dollars)
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Projections
With Thermal
Equipment for
Economic Reasons
$ 18.0
60.9
$ 26.7
$ 11.0
36.3
$ 52.6
189.0
$ 26.5
92.1
24.1
0.8
0.1
Impact
of Thermal
Requirements
Before 316(a)
+0.5
+1.5
+ 1.2
+0.5
+1.3
+0.1
+0.3
+0.0
+0.1
+0.0
+0.8
+0.0
Projections
With Thermal
Requirements
Before 316(a)
$18.5
62.4
$27.9
$ 11.5
37.6
$52.7
189.3
$26.5
92.2
24.1
1.6
0.1
Excludes nuclear fuel
Source: PTm
-------
Exhibit 54
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
BEFORE SECTION 316(a) EXEMPTIONS- 1983
(dollar figures in billions of 1974 dollars)
Projections
With Thermal
Equipment for
Economic Reasons
Capital Expenditures
Total for year $28.5
Total since 1973 205.1
Construction Work in Progress
End of year $44.3
External Financing
Total for year $ 18.0
Total since 1973 127.8
Operating Revenues
Total for year $ 75.1
Total since 1973 $581.2
Operations and Maintenance Expenses
Total for year $38.1
Total since 1973 293.2
Consumer Charges (mills/kWh)
Average for year 23 . 7
Capacity Losses (millions of kW)
Total since 1973 3.0
Energy Penalty (Quads)
Total for year 0.2
Impact Projections
of Thermal With Thermal
Requirements Requirements
Before 316(a) Before 316 (a)
+0.5 $ 29.0
+6.1 211.2
+0.9 $ 45.2
+0.3 $ 18.3
+4.8 132.6
+1.1 $ 76.2
+4.1 585.3
+0.4 $ 38.5
+1.5 294.7
+0.4 24.1
+6.8 9.8
+0.4 0.6
H
I
(0
Excludes nuclear fuel
Source: PTm
-------
Exhibit 55
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
BEFORE SECTION 316(a) EXEMPTIONS - 1990
(dollar figures in billions of 1974 dollars)
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Projections
With Thermal
Equipment for
Economic Reasons
$ 39.5
445.5
$ 62.9
$ 23.8
275.5
$ 104.9
1,223.5
$ 49.8
606.1
22.6
7.0
0.4
Impact
of Thermal
Requirements
Before 316(a)
+0.5
+9.7
+1.3
+0.4
+6.8
+1.6
+14.0
+0.7
+5.1
+0.3
+13.2
+0.7
Projections
With Thermal
Requirements
Before 316(a)
$.40.0
455.2
$ 64.2
$ 24.2
282. 3
$ 106.5
1,237.5
$ 50.5
611.2
22.9
20.2
1.1
H
1
CD
Excludes nuclear fuel
Source: PTm
-------
Exhibit 56
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
AFTER SECTION 316(a) EXEMPTIONS - 1977
H
CO
(fi
Capital Expenditures
Total for year
Total since 1973 ,
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expensesl
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Projections
With Thermal
Equipment for
Economic Reasons
-
$ 18.0
60.9
$ 26.7
$ 11.0
36.3
$ 52.6
189.0
$ 26.5
92.1
24.1
0.8
0.1
Impact
of Thermal
Requirements
After 316(a)
+ 0.3
+ 0.9
+ 0.7
+ 0.2
+ 0.8
+ 0.1
+ 0.2
+ 0.0
+ 0.1
+ 0.0
+ 0.8
+ 0.0
Projections
With Thermal
Requirements
After 316(a)
"
$ 18.3
61.8
$ 27.4
$ 11.2
37.1
$ 52.7
189.2
$ 26.5
92.2
24.1
1.6
°'i1
Excludes nuclear" fuel.
Source: PTm
-------
Exhibit 57
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
AFTER SECTION 316(a) EXEMPTIONS - 1983
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses1
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Projections
With Thermal
Equipment for
Economic Reasons
$ 28.5
205.1
$ 44.3
$ 18.0
127.8
$ 75.1
581.2
$ 38.1
293.2
23.7
3.0
0.2
Impact
Of Thermal
Requirements
After 316(a)
+ 0.3
+ 3.2
+ 0.5
+ 0.2
+ 2.5
+ 0.6
+ 2.4
+ 0.2
+ 0.9
+ 0.2
+ 4.0
+ 0.2
Projections
With Thermal
Requirements
After 316(a)
$ 28.8
208.3
$ 44.8
$ 18.2
130.3
$ 75.7
583.6
38.3
294.1
23.9
7.0
0.4
H
M
(fl
Excludes nuclear fuel.
Source: PTm
-------
Exhibit 58
ECONOMIC AND FINANCIAL IMPACT OF FINAL THERMAL GUIDELINES
AFTER SECTION 316 (a) EXEMPTIONS -1990
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses!
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 19.73
Energy Penalty (Quads)
Total for year
Projections
With Thermal
Equipment for
Economic Reasons
$ 39.5
445.5
$ 62.9
23.8
275.5
$ 104.9
$1,223.5
$ 49.8
606.1
22.6
7.0
0.4
Impact Projections
Of Thermal With Thermal
Requirements Requirements
After 316(a) After 316(a)
+0.3 $ 39.
+ 5.3 450.
+ 0.8 $ 63.
+0.2 $ 24.
+ 3.7 279.
+ 0.8 $105.
+ 7.7 $1,231.
+ 0.4 $ 50.
+3.0 609.
+ 0.2 22.
+7.6 14.
+ 0.4 0.
8
8
7
0
2
7
2
2
1
8
6
8
H
fi
ft
Excludes nuclear fuel.
Source: PTm
-------
Exhibit 59
CAPITAL COST GROWTH- 1977 CHEMICAL GUIDELINES
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
1973 1977 1983 1990
$ 1.80 $ 2.24 $ 3.05 $ 4.30
5.7% 5.3% 5.0%
$ 1.36 $ 1.70 $ 2.32 $ 3.26
5.7% 5.3% 5.0%
$ 0.61 $ 0.77 $ 1.05 $ 1.48
5.8% 5.4% 5.4%
$ 0.61 $ 0.77 $ 1.05 $ 1.48
5.8% 5.4% 5.4%
Source: EPA estimates
TlBlSI
-------
Exhibit 60
CAPITAL COST GROWTH - 1983 CHEMICAL GUIDELINES1
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed In
Service 1979-1990
$. per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service 1979-1990
$ per kilowatt
% cost escalation
1973 1977 1983 1990
$ 0.61 $ 0.76 $ 1.04 $ 1.47
5.7% 5.3% 5.0%
$ 0.55 $ 0.68 $ 0.93 $ 1.31
5.7% 5.3% 5.0%
$ 1.72 $ 2.15 $ 2.93 $ 4.12
5.7% 5.3% 5.0%
$ 0.51 $ 0.64 $ 0.87 $ 1.23
.5.8% 5.4% 5.0%
These capital expenditures are in addition to those
required to meet the 1977 guidelines.
Source: EPA estimates
TBS
-------
Exhibit 61
ANNUAL OPERATING COST GROWTH- 1977 CHEMICAL GUIDELINES
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed In
Service Prior to 1974
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service prior to 1974
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed In
Service 1974-1978
$ per kilowatt
% cost escalation
1973 1977 1983 1990
$ 0.57 $ 0.69 $ 0.92 $1.30
5.0% 5.0% 5.0%
$ 0.26 $ 0.32 $ 0.43 $ 0.61
5.0% 5.0% 5.0%
$ 0.21 $ 0.26 $ 0.34 $ 0.48
5.0% 5.0% 5.0%
$ 0.21 $ 0.26 $ 0.34 $ 0,48
5.0% 5.0% 5.0%
Source: EPA estimates
TBS
-------
Exhibit 62
ANNUAL OPERATING COST GROWTH- 1983 CHEMICAL GUIDELINES1
(expressed in current dollars)
Non-Nuclear Generating
Capacity: Placed in
Service Prior to 1974
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed in
Service 1974-1978
$ per kilowatt
% cost escalation
Non-Nuclear Generating
Capacity: Placed in
Service 1979-1990
$ per kilowatt
% cost escalation
Nuclear Generating
Capacity: Placed in
Service 1979-1990
$ per kilowatt
% cost escalation
1973 1977 1983 1990
$ 0.06 $ 0.08 $ 0.10 $ 0.14
5.0% 5.0% 5.0%
$ 0.02 $ 0.03 $ 0.03 $ 0.05
5.0% 5.0% 5.0%
$ 0.26 $ 0.32 $ 0.43 $ 0.60
5.0% 5.0% 5.0%
$ 0.21 $ 0.26 $ 0.34 $ 0.48
5.0% 5.0% 5.0%
These annual operating expendutres are in addition to
those required to meet the 1977 guidelines. •.
Source: EPA estimates
TBS
-------
Exhibit 63
ECONOMIC AND FINANCIAL PROJECTIONS OF FINAL CHEMICAL GUIDELINES,
FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses1
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
1977 1983 1990
$ 18.2 $ 28.4 $ 39.1
61.3 204.7 443.3
$ 26.8 44.0 $ 62.3
$ 11.2 $ 18.0 $ 23.6
36.7 127.4 273.7
$ 52.8 $ 75.2 $ 104.7
189.5 582.9 1,225.0
$ 26.7 $ 38.3 $ 49.9
92.5 294.6 608.2
24.2 23.8 22.5
H
Rxalurfes nuclear1 fuel
Source: PTm
-------
Exhibit 64
ECONOMIC AND FINANCIAL IMPACT
OF FINAL CHEMICAL GUIDELINES - 1977
(dollar figures in billions of 1974 dollars)
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses!
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Baseline
Conditions
$17.9
60.3
26.5
$10.9
35.8
$52.5
188.8
$26.4
92.0
24.0
Impact of
Chemical
Requirements
+ 0.3
+ 1.0
+ 0.3
+ 0.3
+ 0.9
+ 0.3
+ 0.7
+ 0.3
+ 0.5
+ 0.2
Projections
With
Chemical
Requirements
$ 18.2
61.3
$26.8
$ 11.2
36.7
$52.8
189.5
$26.7
92.5
24.2
H
M
(fl
Excludes nuclear fuel
Source: PTm
-------
Exhibit 65
ECONOMIC AND FINANCIAL IMPACT
OF FINAL CHEMICAL GUIDELINES - 1983
(dollar figures in billions of 1974 dollars)
Hi
03
(0
Impact of
Baseline Chemical
Conditions Requirements
Capital Expenditures
Total for year $ 28.3 +0.1
Total since 1973 203.2 +1.5
Construction Work in Progress
End of year $ 43.8 +0.2
External Financing
Total for year $ 17.8 +0.2
Total since 1973 126.3 + 1.4
Operating Revenues
Total for year $ 74.7 +0.5
Total since 1973 579.5 + 3.4
Operations and Maintenance Expenses^
Total for year $ 38.0 +0.3
Total since 1973 292.5 +2.1
Consumer Charges (mills/kWh)
Average for year 23.6 +0.2
Projections
With
Chemical
Requirements
$ 28.4
204.7
$ 44.0
$ 18.0
127.4
$ 75.2
582.9
$ 38.3
294.6
23.8
Excludes nuclear fuel
Source: PTm
-------
Exhibit 66
ECONOMIC AND FINANCIAL IMPACT
OF FINAL CHEMICAL GUIDELINES - 1990
(dollar figures in billions of 1974 dollars)
H
fi
ft
Impact of
Baseline Chemical
Conditions Requirements
Capital Expenditures
Total for year $ 39.1 +0.0
Total since 1973 441.4 + 1 . 9
Construction Work in Progress
End of year 62.2 +0.1
External Work in Progress
Total for year $ 23.6 +0.0
Total since 1973 272.6 +1.1
Operating Revenues
Total for year $ 104.1 + 0.6
Total since 1973 $1,218.0 + 7.0
Operations and Maintenance Expenses^-
Total for year $ 49.5 + 0.4
Total since 1973 603.7 +4.5
Consumer Charges (mills/kWh)
Average for year 22.4 +0.1
Projections
With
Chemical
Requirements
$ 39.1
443.3
$ 62.3
$ 23.6
273.7
$ 104.7
$1,225.0
$ 49.9
608.2
22.5
Excludes nuclear fuel
Source: PTm
-------
Exhibit 66
ECONOMIC AND FINANCIAL IMPACT
OF FINAL CHEMICAL GUIDELINES - 1990
(dollar figures in billions of 1974 dollars)
Impact of
Baseline Chemical
Conditions Requirements
Capital Expenditures
Total for year $ 39.1 +0.0
Total since 1973 441.4 +1.9
Construction Work in Progress
End of year 62.2 +0.1
External Work in Progress
Total for year $ 23.6 + 0.0
Total since 1973 272.6 +1.1
Operating Revenues
Total for year $ 104.1 +0.6
Total since 1973 $1,218.0 + 7.0
Operations and Maintenance Expenses-*-
Total for year $ 49.5 + 0.4
Total since 1973 603.7 + 4.5
Consumer Charges (mills/kWh)
Average for year 22.4 +0.1
Projections
With
Chemical
Requirements
$ 39.1
443.3
$ 62.3
$ 23.6
273.7
$ 104.7
$1,225.0
$ 49.9
608.2
22.5
Excludes nuclear fuel
Source: PTm
-------
Exhibit 67
ECONOMIC AND FINANCIAL IMPACT OF
FINAL REGULATIONS - 1977
(dollar figures in billions of 1974 dollars)
Impact of Impact Final Regulations
Baseline Economic Thermal Chemical
Conditions Reasons Requirements Requirements
Capital Expenditures
Total for year $17.9 +0.1 +0.3 +0.3
Total since 1973 60.3 +0.6 +0.9 +1.0
Construction Work in Progress
End of year $ 26.5 + 0.2 + 0.7 + 0.3
External Financing
Total for year $10.9 +0.1 +0.2 +0.3
Total since 1973 35.8 +0.5 +0.8 +0.9
Operating Revenues
Total for year $52.5 +0.1 +0.1 +0.3
Total since 1973 188.8 + 0.2- + 0.2 + 0.7
Operations and Maintenance Expenses 1
Total for year $26.4 +0.1 +0.0 +0.3
Total since 1973 92.0 + 0.1 + 0.1 + 0.5
Consumer Charges (mills/kWh)
Average for year 24.0 +0.1 +0.0 +0.2
Capacity Losses (millions of kW)
Total since 1973 — + 0.8 + 0.8
Energy Penalty (Quads)
Total for year — + 0.1 + 0.0
Projections
With Final
Regulations
$ 18
62
$ 27
$ 11
38
$ 53
189
$ 26
92
24
1
0
.6
.8
.7
.5
.0
.0
.9
.8
.7
.3
.6
.1
H
fl
0)
Excludes nuclear fuel
Source: PTm
-------
Exhibit 68
ECONOMIC AND FINANCIAL IMPACT OF
FINAL REGULATIONS - 1983
(dollar figures in billions of 1974 dollars)
Baseline
Conditions
Capital Expenditures
Total for year $ 28.3
Total since 1973 203.2
Construction Work in Progress
End of year $ 43.8
External Financing
Total for year $ 17.8
Total since 1973 126.3
Operating Revenues
Total for year $ 74.7
Total since 1973 579.5
Operations and Maintenance Expenses!
Total for year $ 38.0
Total since 1973 292.5
Consumer Charges (mills/kWh)
Average for year 23.6
Capacity Losses (millions of kW )
Total since 1973
Energy Penalty (Quads)
Total for year
Impact of
Economic
Reasons
+ 0.2
+ 1.9
+ 0.5
+ 0.2
+ 1.5
+ 0.4
+ 1.7
+ 0.1
+ 0.7
+ 0.1
+ 3.0
+ 0.2
Impact Final Regulations
Thermal Chemical
Requirements Requirements
+0.3 +0.1
+ 3.2 + 1.5
+ 0.5 + 0.2
+ 0.2 + 0.2
+ 2.5 + 1.4
+ 0.6 + 0.5
+ 2.4 + 3.4
+0.2 +0.3
+0.9 +2.1
+ 0.2 + 0.2
+ 4.0
+ 0.2
Projections
With Final
Regulations
$ 28.9
209.8
$ 45.0
$ 18.4
131.7
$ 76.2
587.0
$ 38.6
296 . 2
24.1
7.0
0.4
Excludes nuclear fuel
Source: PTm
-------
Exhibti 69
ECONOMIC AND FINANCIAL IMPACT OF
FINAL REGULATIONS - 1990
(dollar figures in billions of 1974 dollars)
Impact of Impact Final Regulations Projections
Baseline Economic Thermal
Conditions Reasons Requirements
Capital Expenditures
Total for year $ 39 1 +0.4 +0.3
Total since 1973 441.4 +4.1 +5.3
Construction Work in Progress
End of year $ 62.2 +0.7 +0.8
External Financing
Total for year $ 23.6 +0.2 +0.2
Total since 1973 272.6 +2.9 +3.7
Operating Revenues
Total for year $ 104.1 +0.8 +0.8
Total since 1973 1,218.0 +5.5 +7.7
Operations and Maintenance Expenses
Total for year $ 49.5 +0.3 +0.4
Total since 1973 603.7 +2.4 +3.0
Consumer Charges (mills/kWh)
Average for year 22.4 +0.2 +0.2
Capacity Losses (millions of kW)
Total since 1973 — +7.0 +7.6
Energy Penalty (trillions of Btu's)
Tota'l for year — +0.4 +0.4
Chemica.1 With Final
Requirements Regulations
+0.0 $ 39.
+1.9 452.
+0.1 $ 63.
+0.0 $ 24.
+1.1 280.
+0.6 $ 106.
+7.0 1,238.
+0.4 $ 50.
+4.5 613.
+0.1 22.
14.
0.
8
7
8
0
3
3
2
6
6
9
6
8
H
M
CD
Excludes nuclear fuel
Source: PTm
-------
Exhibit 70
NON-NUCLEAR COVERAGE FOR EXISTING UNITS
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
(March 1974)
Percent Covered
I I I
m\ 2.2%
O.I
0.0%
21 G
. J./I
11.6%
14.7%
25
22. 7%
Legend
: After 316 (a) Exemptions
Source: ERCO, EPA estimates
TBS
-------
Exhibit 71
NUCLEAR COVERAGE FOR EXISTING UNITS
Percent Coveredv. ;. . , ;
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guideline:
I I I I
0.0%
0.0%
Legend
12.!
12.!
12.9%
14.
14.
25
After 316 (a) Exemptions
Source: ERCO, EPA estimates
T|B|S|
-------
Exhibit 72
ECONOMIC AND FINANCIAL PROJECTIONS OF OPTION 1 (1979)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year —
1977 1983
$ 18.1 $ 28.8
61.4 207.0
$ 27.0 $ 44.8
$ 11.1 $ 18.2
36.8 129.3
$ 52.7 $ 75.4
189.2 582.7
$ 26.5 $ 38.3
92.2 293.9
24.1 23.8
1.6 5.9
0.1 0.4
1990
$ 39.8
449.4
$ 63.7
$ 24.1
278.4
$ 105.5
1,228.7
$ 50.1
608.3
22.7
13.6
0.8
Excludes nuclear fuel
Source: PTm
-------
Exhibti 73
ECONOMIC AND FINANCIAL PROJECTIONS OF OPTION 2 (1974)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H
M
V)
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses
Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1977 1983 1990
$ 18.2 $ 28.8 $ 39.8
61.7 207.9 450.3
$ 27.2 $ 44.8 $ 63.7
•
$ 11.2 $ 18.2 $ 24.0
37.0 130.0 279.0
$ 52.7 $ 75.6 $ 105.7
189.2 583.3 1,230.4
$ 26.5 $ 38.3 $ 50.2
92.2 294.0 608.8
24.1 23.9 22.8
1.6 6.6 14.3
0.1 0.4 0.8
Excludes nuclear fuel
Source: PTm
-------
Exhibit 74
ECONOMIC AND FINANCIAL PROJECTIONS OF OPTION 3 (1972)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses
Total for year $ 17.7
Total since 1973
Consumer Charges (raills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1977 1983
$ 18.2 $ 28.9
61.7 208.4
$ 27.3 $ 44.9
$ 11.2 $ 18.2
37.1 130.3
$ 52.7 $ 75.7
189.2 583.6
$ 26.5 $ 38.3
92.2 294.1
24.1 23.9
1.6 7.0
0.1 0.4
1990
$ 39.8
450.8
$ 63.7
$ 24.0
279.2
$ 105.7
1,231.2
$ 50.2
609.1
22.8
14.6
0.8
Excludes nuclear fuel
Source: PTm
-------
Exhibit 75
ECONOMIC AND FINANCIAL PROJECTIONS OF OPTION 4 (1961, <200 MW)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H]
CO
m
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses
Total for year $17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year —
Excludes nuclear fuel
Source : PTm
1977
$ 18.2
61.7
$ 27.3
$ 11.2
37.1
$ 52.7
189.2
$ 26.5
92.2
24.1
1.6
0.1
1983 1990
$ 30. 1 $ 39.8
210.1 452.0
$ 45.4 $ 63.7
$ 19.3 $ 24.0
131.8 280.0
$ 75.9 $ 106.0
583.9 1,233.2
$ 38 . 5 $ 50 . S
255.8 609.8
24.0 22.8
8.1 15.8
0.5 0.9
-------
Exhibit 76
ECONOMIC AND FINANCIAL PROJECTIONS OF OPTION 5 (1956, 4 25 MW, < 40%)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
H
a
(0
1973
Capital Expenditures
Total for year $ 13.9
Total since 1973
Construction Work in Progress
End of year $ 19.6
External Financing
Total for year $ 7.6
Total since 1973
Operating Revenues
Total for year $ 39.5
Total since 1973
Operations and Maintenance Expenses
• Total for year $ 17.7
Total since 1973
Consumer Charges (mills/kWh)
Average for year 21.4
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1977 1983 1990
$ 18.2 $ 30.6 $ 39.8
R1.7 210.7 453.4
$ 27.3 $ 45.6 $ 63.7
$11.2 $ 19.7 $ 24.0
37.1 132.4 280.3
$ 52.7 $ 7fi.O $ 106.0
189.2 584.0 1. ,233.9
$ 26 . 5 $ 38 . R $ RD . 3
92.2 294.3 610.0
24.1 24.0 22.8
1.6 8.5 16.1
0.1 0.5 0.9
Excludes nuclear fuel
Source: PTm
-------
Exhibit 77
ECONOMIC AND FINANCIAL PROJECTIONS OF
PROPOSED GUIDELINES (MARCH 1974)
AFTER SECTION 316(a) EXEMPTIONS, FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
1973 1977
Capital Expenditures
Total for year $ 13.9 $ 18.3
Total since 1973 — 61.8
Construction Work in Progress
End of year $ 19.6 $ 27.4
External Financing
Total for year $ 7.6 $ 11.2
Total since 1973 — 68.0
Operating Revenues
Total for year $39.5 $ 52.7
Total since 1973 — 189.2
Operations and Maintenance Expenses
Total for year $ 17.7 $ 26.5
Total since 1973 — 92.2
Consumer Charges (mills/kWh)
Average for year 21.4 24.1
Capacity Losses (millions of kW)
Total since 1973 — 1.6
Energy Penalty (Quads)
Total for year — 0.1
1983 1990
$ 31.8 $ 39.8
212.1 453.4
$ 46.1 $ 63.7
$ 20.9 $ 24.0
133.7 281.0
$ 76.2 $106.2
584.3 1,235,7
$ 38.7 $ 50.4
294.5 610.6
24.1 22.9
9.4 17.1
0.5 1.0
szclitdes nuclear fuel
Source: PTm
-------
Exhibit 78
NON-NUCLEAR COVERAGE FOR EXISTING UNITS
22 . 7%
25
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
2.2%
j L
14.7%
20.5%
22.7%
22. 7%
Legend
: After 316 (a) Exemptions
State Water Quality Standards
Source: ERCO, EPA estimates
TlBlSl
-------
Legend
Exhibit 79
NUCLEAR COVERAGE FOR EXISTING UNITS
Final Guidelines
Option 1
Option 2
Option 3
Option 4
Option 5
Proposed Guidelines
I I
12 .9%
12.i
12.9%
14. (
14 .0%
II
25
14. 0%
I
1.1%
i.:
1.1%
: After 316 (a) Exemptions
: State Water Quality Standards
Source: ERCO. EPA estimates
TBS
-------
Exhibit 80
H
fi
0)
ECONOMIC AND FINANCIAL PROJECTIONS
OF FINAL THERMAL GUIDELINES AFTER
SECTION 316(a) EXEMPTIONS AND AFTER STATE WATER QUALITY STANDARDS
FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
1973 1977 1983 1990
$ 1S.9 $ 18.3 $ 31.8 $ 39.8
61.8 212.1 453.4
$ 19.6 $ 27.4 $ 46.1 $ 63.7
$ 7.6 $ 11.2 $ 20.9 $ 24.0
68.0 133.7 281.0
$ 39.5 $ 52.7 $ 76.2 $106.2
189.2 584.3 1,235.7
$ 17.7 26.5 38.7 50.4
92.2 294.5 610.6
21.4 24.1 24.1 22.9
1.6 9.4 17.1
0.1 0.5 1.0
excludes nuclear fuel
Source: PTm
-------
Exhibit 81
ECONOMIC AND FINANCIAL IMPACT OF
STATE WATER QUALITY STANDARDS - 1977
Projections
After 316(a)
Exemptions
Capital Expenditures
Total for year $ 18.3
Total since 1973 61.8
Construction Work in Progress
End of year $ 27.4
External Financing
Total for year $ 11.2
Total since 1973 37.1
Operating Revenues
Total for year $ 52.7
Total since 1973 189.2
Operations and Maintenance Expenses
Total for year $ 26.5
Total since 1973 92.2
Consumer Charges (mills/kWh)
Average for year 24.1
Capacity Losses (millions of kW)
Total since 1973 1-6
Energy Penalty (Quads)
Total for year 0.1
Projections
T - . . After 316(a)
ImPact °f Exemptions
State Water Quality and
-------
Exhibit 82
ECONOMIC AND FINANCIAL IMPACT OF
STATE WATER QUALITY STANDARD - 1983
Projections
After 316(a)
Exemptions
Capital Expenditures
Total for year $ 28.8
Total since 1973 208.3
Construction Work in Progress
End of year $44.8
External Financing
Total for year $ 18.2
Total since 1973 130.3
Operating Revenues
Total for year $ 75.7
Total since 1973 583.6
Operations and Maintenance Expenses
Total for year $38.3
Total since 1973 294.1
Consumer Charges (mills/kWh)
Average for year 23.9
Capacity Losses (millions of KWh)
Total since 1973 7.0
Energy Penalty (Quads)
Total for year 0.4
Impact Projections
of State After 316(a)
Water Quality Exemptions and
Standards (SWQS) SWQS
+ 3.0 $ 31
+ 3.9 212
+1.3 $ 46
+ 2.7 $ 20
+ 3.4 133
+0.5 $ 76
+0.7 584
+ 0.4 $ 38
+0.4 294
+ 0.2 24
+ 2.4 9
+ 0.1 0
8
2
1
9
7
2
3
7
5
1
4
5
H
Excludes nuclear fuel.
Source: PTm
-------
Exhibit 83
ECONOMIC AND FINANCIAL IMPACT OF
STATE WATER QUALITY STANDARDS- 1990
H
GO
ID
Capital Expenditures
Total for year
Total since 1973
Construction Work in Progress
End of year
External Financing
Total for year
Total since 1973
Operating Revenues
Total for year
Total since 1973
Operations and Maintenance Expenses
Total for year
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Projections
After 3l6(a)
Exemptions
$ 39.8
450.8
$ 63.7
$ 24.0
279.2
$ 105.7
1,231.2
$ 50.2
609.1
22.8
14.6
0.8
Impact
of State
Water Quality
Standards (SWQS)
+ 0.0
+ 2.6
+ 0.0
+ 0.0
+ 1.8
+ 0.5
+ 4.5
+ 0.2
+ 1.5
+ 0.1
+ 2.5
+ 0.2
Projections
After 316(a)
Exemptions
and SWQS
$ 39.8
453.4
$ 63.7
$ 24.0
281.0
$ 106.2
$1,235.7
$ 50.4
610.6
22.9
17.1
1.0
Excludes nuclear fuel.
Source : PTm
-------
Exhibit 84
ANNUAL MIX OF RECEIVING WATER TYPES - OPEN CYCLE STEAM SLECTRIC CAPACITY
100%
30%
a
oj
o
60%
o
I
c
0)
D.
O
40%
-------
Exhibit 85
ANNUAL MIX OF COOLING METHOD- STEAM ELECTRIC CAPACITY
100%
> 80%
o
at
O
rt
60%-
Qnce-Through Cooling
O
0)
0)
•p
w
rH 40%
-p
c
a)
o
h
(V
a
20%-
0%
I
1950
I
1960
Year of Operation
1970
1977
Source: Sample of 180 Steam-Electric Utility Plants, 1974
TBS
-------
Exhibit 86
SAFEZONE ON RIVERS USED FOR ONCE-THROUGH COOLING
(percent of river flow not affected by thermal effluent)
100%
0%
1950
1960
Year of Operation
1970
1977
Source: Sample of 180 Steam Electric Utility Plants, 1974
TBS
-------
Exhibit 87
MIX OF CAPACITY BY UNIT SIZE
100%
80%
w
to
a)
o
0)
tsi
•H
w
c
0)
o
t-l
o
o
ni
£>.
ci
O
-------
Exhibit 88
DISTRIBUTION OF PROJECTED 1978 UNITS BY YEAR PLACED IN SERVICE
1978 Capacity
1978 Net Generation
Before '46
(2%)
Before '46,
(1%)
(Shaded area represents portion exempted under
final option by year placed in service)
Source: Sample of 180 Steam Electric Utility Plants, 1974
TBS
-------
Exhibit 89
COMPARISON OF CAPACITY PROJECTIONS
USED FOR ENVIRONMENTAL VERSUS ECONOMIC ANALYSIS
Fossil and Nuclear Capacity
(millions of kilowatts)
Cajpacity
January 1, 1974
January 1, 1978
January 1, 1983
Economic
Analysis
Projection
(Moderate Growth)
355.1
440.4
580.9
Environmental
Analysis
Projections
340
426
573
Percent
Difference
-4 . 3%
-3.3%
-1.4%
Source: ERCO and PTm
TBS
-------
Exhibit 90
AGE COMPOSITION AND RISK CHARACTERISTICS
OF CAPACITY IN-SERVICE BY 1983
Year Placed In-Service
Prior to 1970, still
in operation in 1983
1970-1973, < 500 MW
1970-1973, > 500 MW
1974-1977
1978-1982
Combined
% of % % %
1983 High Low Closed
Capacity Risk Risk Cycle
37.7% 30.0% 56.0% 14.0%
4.4% 16.0% , 25.0% 59.0%
12.7% 16.0% 25.0% 59.0%
16.8% 16.0% 18.0% 66.0%
28.4% 16.0% 18.0% 66.0%
100.0% 21.5% 33.3% 45.2%
TBS
-------
Exhibit 91
Environmental Risk
Variations on 1970-73 Size Criterion
With 1970 Exemption
= Exempted
% Capacity Exempted
Net Generation Exempted)
1970-73 Size
Criterion
0 Mw (Pure 1970)
% 1983
High Risk Units
53%
(40%)
% All 1983
Fossil and Nuclear Units
11%
(8%)
300 Mw
55%
(43%)
12%
(3%)
500 Mw (Final Option)
56%
(44%)
12%
(8%)
700 Mw
59%
(46%)
13%
(9%)
1300 Mw (Pure 1974)
66%
(54%)
14%
(10%)
TBS
-------
Exhibit 92
Exempted
Environmental Risk
Alternative Age Criteria
% Capacity Exempted
Net Generation Exempted)
Year
Exempted
1950
% 1983
Hie;h Risk Units
4%
(1%)
% All 1983
Fossil and Nuclear Units
Less than 1%
(0.2%)
1961
24%
(19%)
(4%)
1970
52%
(40%)
11%
(8%)
1974
66%
(54%)
14%
(10%)
1978
79%
(71%)
17%
(14%)
1983
100%
(100%)
22%
(19%)
TBS
-------
Exhibit 93
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS OF FINAL
THERMAL GUIDELINES FOR THE PERIOD 1974-1983
(dollar figures in billion of 1974 dollars)
H
Capacity Coverage:
Capital and Operating Cost Estimates:
Capital Expenditures
Total since 1973
Construction Work in Progress
Increase since 1973
External Financing
Total since 1973
Operating Revenues
Total since 1973
Operations & Maintenance Expenses
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Capacity Losses (millions of kW)
Total since 1973
Energy Penalty (Quads)
Total for year
Economic
EPA
NPS
Baseline Economic
Conditions Reasons
$203.2 $205.1
$ 24.2 $ 24.7
$126.3 $127.8
$579.5 $581.2
$292.5 $293.2
23.6 23.7
3.0
0.2
Reasons
UWAG
UWAG
Case #1
$205.3
$ 24.7
$128.3
$581.9
$293.9
23.8
3.0
0.2
After 316(a) Exemptions
EPA UWAG
After 316(a) UWAG
Exemptions Case #2
$208.4 $208.8
$ 25.2 $ 25.3
$130.3 $130.6
$583.6 $586.0
$294.1 $296.1
23.9 24.1
7.0 7.0
0.4 .0.4
Excludes nuclear fuel
Source: PTm
-------
Exhibit 94
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS
OF FINAL CHEMICAL GUIDELINES FOR THE PERIOD 1974-1983
(dollar figures in billions of 1974 dollars)
Capital and Operating
Cost Estimates:
Capital Expenditures
Total since 1973
Construction Work in Progress
Increase since 1973
External Financing
Total since 1973
Operating Revenues
Total since 1973
Operations and Maintenance Expenses
Total since 1973
Consumer Charges (mills/kWh)
Average for year
EPA UWAG
NFS
Baseline UWAG
Conditions Chemical Case #3
$203.2 $204.7 $206.5
$ 24.2 $ 24.3 $ 24.3 •
$126.3 $127.4 $128.5
$579.5 $582.9 $584.7
$292.5 $294.6 $294.5
23.6 23.8 23.8
Excludes nuclear fuel
Source: PTm
-------
Exhibit 95
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS OF
BASELINE CONDITIONS FOR THE PERIOD 1974-1983
(dollar figures in billions of 1974 dollars)
H
Industry Growth Rate Assumptions:
Interest and Preferred
Dividend Rate Assumptions:
Capital Expenditures
Total since 1973
Construction Work in Progress
Increase since 1973
External Financing
Total since 1973
Operating Revenues
Total since 1973
Operations & Maintenance Expenses
Total since 1973
Consumer Charges (mills/kWh)
Average for year
Moderate Historic Historic
NFS NFS UWAG
NPS UWAG
Baseline Historic r aA
Pnnrii t i r>n~ fnnrt i + i nn~ LaSC ff4
$203.2 $245.6 $245.6
$ 24.2 $ 33.9 $ 33.9
$126.3 $158.5 $158.5
$579.5 $619.3 $634.1
$292.5 $306.6 $306.6
23.6 23.9 24.6
Excludes nuclear fuel
Source: PTm
-------
Exhibit 96
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS
OF FINAL THERMAL GUIDELINES FOR THE PERIOD 1974-1983
(dollar figures in billions of 1974 dollars)
H
1
(fl
Capacity Coverage _
Capital and Operating
Cost Estimates
UWAG
Case #4
Capital Expenditures
Total since 1973 $245.6
Construction Work in Progress
Increase since 1973 $ 33.9
External Financing
Total since 1973 $158.5
Operating Revenues
Total since 1973 $634.1
Operations and Maintenance Expenses
Total since 1973 $306.6
Consumer Charges (mills/kWh)
Average for year 24.6
Capacity Losses (millions of kw)
Total since 1973
Energy Penalty (Quads)
Total for year -
Economic
Reasons
EPA
UWAG
Case #5
$247.8
$ 34.5
$160.3
$636.2
$307.5
24.8
3.6
0.2
After 316(a)
Exemptions
EPA
UWAG
Case #6
$251.6
$ 35.2
$163.2
$639.4
$308.6
25.0
8.2
0.5
F-ccludes nuclear fuel
Source: PTm
-------
Exhibit 97
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS
OF FINAL THERMAL GUIDELINES FOR THE PERIOD 1974-1983
(dollar figures in billions of 1974 dollars)
H
U
CD
Capacity Coverage
Capital and Operating
Cost Estimates -
UWAG
Case f?4
Capital Expenditures
Total since 1973 $245.6
Construction Work in Progress
Increase since 1973 $ 33.9
External Financing
Total since 1973 $158.5
Operating Revenues
Total since 1973 $634.1
Operations and Maintenance Expenses
Total since 1973 $306.6
Consumer Charges (mills/kWh)
Average for year 24.6
Capacity Losses (millions of kw)
Total since 1973
Energy Penalty (Quads)
Total for year
Economic
Reasons
UWAG
UWAG
Case #7
$248.0
$ 34.5
$160.4
$637.2
$308.2
24.8
3.6
0.2
After 316(a)
Exemptions
UWAG
UWAG
Case #8
$252.1
$ 35.2
$163.6
$642.2
$310.9
25.2
8.2
0.5
Excludes nuclear fuel
Source: PTm
-------
Exhibit 98
A SUMMARY OF ALTERNATIVE ECONOMIC AND FINANCIAL PROJECTIONS
OF FINAL CHEMICAL GUIDELINES FOR THE PERIOD 1974-1983
(dollar figures in billions.of 1974 dollars)
Capital and Operating
Cost Factors
UWAG
Case #4
Capital Expenditures
Total since 1973 $245.6
Construction Work in Progress
Increase since 1973 $ 33.9
External Financing
Total since 1973 $158.5
Operating Revenues
Total since 1973 $634.1
Operations and Maintenance Expenses
Total since 1973 $306.6
Consumer Charges (mills/kWh)
Average for year 24.6
EPA UWAG
UWAG UWAG
Case #9 Case #10
$247.2 $249.0
$ 34.0 $ 34.0
$159.6 $160.8
$637.7 $639.8
$308.7 $308.7
24.8 24.9
H
Excludes nuclear fuel
Source: PTm
-------
APPENDIX A
-------
APPENDIX A: PTw RESEARCH METHODOLOGY
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 Drs. Howard W. Pifer and
Michael L. Tennican of Temple, Barker & Sloane, Inc.
to provide 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 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
1. DPS. Fife? and Tennican gratefully acknowledge the counsel
and assistance of a number of individuals from industry,
the .Federal Power Commission, and various financial insti-
tutions — especially Messrs. John Childs3 Gordon Corey,
Fred Eggerstedt, Robert Fortune, John Glover, Rene Males,
John 0 'Connor, and Robert Uhler.
A-l
TlBlSl
-------
A-2
physical plant, equipment, fuel, and labor requirements.
These physical requirements and the relevant factor
costs, which are also influenced by economic consider-
ations 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
requirements 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 consideration 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-l 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 im-
pact on the cost of electrical power and hence on
demand. As a second illustration, because the financial
TlBlS
-------
A-3
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.
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
amd 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 projections 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 as a set of related models,,
TIBISI
-------
A-4
PHYSICAL PLANT AND EQUIPMENT MODULE
The primary relationships determining the
industry's physical plant and equipment requirements
are shown in Figure A-2. Consistent with the assump-
tion that demand will be met, the industry's gross
generation 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 impact and operation power drain of pollu-
tion 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 inclusion 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 mater-
ializes. As. is shown in Figure A-2, 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
-------
A-5
placing generating capacity in service is radically
different for peaking units, fossil-fueled base load
plants, and nuclear units, PTm computes construction
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 proportions of nuclear and fossil
additions that change over time.
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.
USES OF FUNDS
The industry's uses of funds depicted in
Figure A-3 are determined primarily 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
TBS
-------
A-6
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 Fieure A-3, 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 financial terms are the cost per
unit of each type of asset and the schedule of pay-
ments required by contractors while such plant and
equipment are under construction.
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.
TBS
-------
A-7
For the public sector, it is simply assumed that a
percentage of total funds used are met from internal
sources. As is shown in Figure 4a, any shortfall
between total uses and internal sources is met via
external financing.
Figure A-4b shows these same relationships
in a format that is slightly different and that
shows how the private sector's total required ex-
ternal 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.
REVENUES AND RELATED VARIABLES
The third segment of the financial module
determines total industry revenues, expenses, profits,
and related statistics 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 computed 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 financial module (e.g., plant and
equipment expenditures provide the base for computing
ITIBISI
-------
A-8
depreciation expense). The structure of the revenue
segment and the interactions between this segment and
other parts of the total model are depicted in Figure A-5,
As shown at the t.op of Figure A-5, 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
2
equity set by regulatory policy. 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.
Earnings before interest and taxes (EBIT)
are simply the sum of EBT and interest expense and are
computed 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, depre-
ciation and amortization of plant and equipment, is
a variable 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
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.
TIBIS
-------
A-9
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 pol-
lution 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 allowance 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.
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
IrlBlsl
-------
A-10
dividend rate on the industry's outstanding preferred
stock. The dividend yield on new preferred 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 ex-
pense 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 somewhat 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 allowances for funds used during construction
as non-cash credits to income) must be taken into
account. As a consequence of these differing pro-
visions, taxable EBT and regulatory EBT may - and
typically do - differ. Secondly, as mentioned earlier,
there exist two substantially different regulatory
methods for determining 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 stockholders are to reach
prescribed levels.
TIBIS
-------
A-ll
A CONCLUDING COMMENT
As has been outlined above, the operating,
financial, tax, regulatory, and accounting relation-
ships and constraints relevant to making economic and
financial projections for the industry are individually
rather simple. However, the number of these relation-
ships and constraints are so great as to dictate
the use of a computer model such as PTm. Moreover,
because of interactions between the various industry
relationships and constraints, attempts to reduce
the number of factors through shortcut approximations
3
are hazardous. Furthermore, such shortcuts, even if
based on careful econometric analyses of historical
data, would tend to preclude 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 share-
holder 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 expenditures in the current and past years;
and, the reduced asset lifetimes, the accelerated methods
of depreciation, the investment credits, and the other
income statement items allowed, for tax purposes, but not
for regulatory purposes. These current and past expendi-
tures 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.
iTlBlSl
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A-12
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 distribution capacity, thermal and
chemical pollution equipment; etc. PTm then
generates projections for a variety of physical and !
financial 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 reconciliations of regulatory and Internal
Revenue Service income tax expense figures; and summary
statistics such as interest coverage figures.
IrlBlsl
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FIGURE A-i
INTERACTIONS BETWEEN THE ENVIRONMENT AND THE PHYSICAL AND FINANCIAL
CHARACTERISTICS OF THE ELECTRIC UTILITY INDUSTRY
PLANT, EQUIPMENT, AND
ELECTRICAL POWER
PRODUCTION REQUIREMENTS
PLANT, EQUIPMENT, AND
OPERATING CASH NEEDS
CASH PROVIDED BY
OPERATIONS
EXTERNAL FINANCING
H
fi
CD
KEY
: VARIABLES TAKEN AS GIVEN BY PTM
: VARIABLES DETERMINED WITHIN PTM
-------
FIGURE A-2
DETERMINANTS OF PLANT AND EQUIPMENT IN SERVICE
AND IN CONSTRUCTION FOR THE ELECTRIC UTILITY INDUSTRY
FUTURE DEMAND
FUTURE
RETIREMENTS
IMPACT OF FUTURE POLLUTION
EQUIPMENT ON GENERATING
PLANT EFFICIENCY
FUTURE REQUIRED
GROSS CAPACITY
CONSTRUCTION FOR
FUTURE REQUIREMENTS
ADDITIONS TO PLANT AND
EQUIPMENT IN SERVICE AND
IN CONSTRUCTION
IMPACT OF CURRENT POLLUTION
EQUIPMENT ON GENERATING
PLANT EFFICIENCY
CURRENT REQUIRED
GROSS CAPACITY
POLLUTION CONTROL EQUIPMENT
REQUIREMENTS
CONSTRUCTION FOR
CURRENT REQUIREMENTS
CURRENT DEMAND
CURRENT
RETIREMENTS
CR
KEY
: VARIABLES TAKEN AS GIVEN BY PTM
| [ : VARIABLES DETERMINED WITHIN PTM
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FIGURE A-3
DETERMINANTS OF USES OF FUNDS
FOR THE ELECTRIC UTILITY INDUSTRY
COST PER UNIT OF PLANT
AND EQUIPMENT
PLANT AND EQUIPMENT
CONSTRUCTION FOR CURRENT
REQUIREMENTS
PLANT AND EQUIPMENT
CONSTRUCTION FOR FUTURE
REQUIREMENTS
EXPENDITURES FOR IN-SERVICE
PLANT AND EQUIPMENT
ALLOWANCE FOR FUNDS
USED FOR CONSTRUCTION
IN PROGRESS
EXPENDITURES FOR INCREASING
PLANT AND EQUIPMENT
IN CONSTRUCTION
TOTAL USES OF FUNDS
COST PER UNIT OF PLANT
AND EQUIPMENT
KEY.
: VARIABLES TAKEN'AS GIVEN BY P?M
| | : VARIABLES DETERMINED WITHIN PTM
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FIGURE A-'l
DETERMINANTS AND COMPOSITION
OF TOTAL SOURCES OF FUNDS FOR THE ELECTRIC UTILITY INDUSTRY
TOTAL
USES OF FUNDS
^
)
EXTERNAL
FINANCING
f
\
FUNDS PROVIDED
BY OPERATIONS
1
KFY
TOTAL SOURCES OF FUNDS
INITIAL
CAPITAL STRUCTURE
: VARIABLES TAKEN AS GIVEN BY PTM
| | ! VARIABLES DETERMINED WITHIN P?M
TOTAL USES OF
FUNDS
TOTAL SOURCES OF FUNDS
\
I
— _ 1
/
\
DEFERRALS
ENDING
CAPITAL STRUCTURE
CASH
ISSUES OF PREFERRED
CASH ISSUES OF DEBT
/
k
DEBT RETIREMENTS
CASH ISSUES OF COMMON
-------
FIGURE A-5
DETERMINANTS OF REVENUES, EXPENSES, AND PROFITS FOR THE
ELECTRIC UTILITY INDUSTRY
RETURN ON EOU1TY
H
PREFERRED STOCK
CURRENT DEMAND
EMBEDDED COST
OF PREFERRED STOCK
PREFERRED DIVIDENDS
EMBEDDED COST
OF DEBT
INTEREST
s—N
POLLUTION CONTROL
POLICY
OPERATING ft MAINTENANCE
EXPENSES
<^> : VARIABLES TAKEN AS GIVEN BY PTn
| | : VARIABLES DETERMINED UITHIN PTn
PROFIT AVAILABLE
TOR COMMON STOCK
NET PROFIT
EARN I (IPS BEFORE
INCOME TAXES
EARNINGS BEFORE
INTEREST ,", TAXES
DEPRECIATION ?,
AMORTIZATION OF
PLANT AND EQUIPMENT
COMMON EOUITY
INCOME TAXES
DEFERRED TAXES
ALLOWANCE ON FUNDS
USED DURINC CONSTRUCTION
TAXES OTHER THAN
INCOME
PLANT £ EflUIPMENT
IN SERVICE
PLANT Z EdUIPMENT
IN SERVICE
TAXES PAYABLE
FUTURE DEMAND
PLANT 6 EQUIPMENT
IN CONSTRUCTION
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APPENDIX B
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APPENDIX B: PTM SUMMARY STATISTICS
INTRODUCTION
Throughout the text of this report, TBS
has projected the operating conditions within the
electric utility industry under differing assump-
tions with respect to industry growth and , more
importantlys pollution control equipment associated
with alternatives for both thermal and chemical guide-
lines. In so doing, an attempt has been made to re-
duce the output from PTm to a manageable level by
focusing on three years (1977, 1983 and 1990), and
only three time periods:
• short-run (or near-term) 1974-1977
• next decade 1974-1983
• long-run 1984-1990
The short-run essentially focuses upon the
period in which very little can be implemented which
will impact the industry's performance with the ex-
ception of meeting the 1977 chemical guidelines.
The next decade coincides with the period
i
in which all conversions from open to closed-cycle
must be completed as well as the time period
specified for compliance with both the 1977 and
1983 chemical guidelines.
B-l
FflBlsl
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B-2
KEY VARIABLES
For each set of alternative conditions
that was evaluated within this report, the economic
and financial projections were summarized for selected
years in the form of Exhibit B-l . These data were
provided in constant 1974 dollars. In addition,
Exhibits B-2 to B-5 provide an example in current
dollars of the level of detail within the investor-
owned sector which is captured in any given year.
The following detailed explanation of each
summary statistic for 1983 baseline conditions should
assist in understanding the definitions employed with-
in PTm.
CAPITAL EXPENDITURES
Capital expenditures are the sum of ex-
penditures for plant and equipment placed in service
and the change in construction work in progress
(CWIP) during any given year. For example, the 1983
1. Exhibit B-l reproduces Exhibit 35 from Chapter II.
TIBISI
-------
B-3
capital expenditures of $43.9 billion in current
dollars can be segmented into:
Private Public
Sector Sector
Generating Plant:
non-nuclear $ 6.4 $ 1.6
Generating Plant:
nuclear 9.4 2.4
Nuclear Fuel 1.2 0.3
Transmission and
Distribution 12.9 3.2
Pollution Control
Equipment
Increase in CWIP 5.4 1.1
$35.3 $ 8.6
This current dollar amount is equivalent to $28.3
billion in constant 1974 dollars.
CONSTRUCTION WORK IN PROGRESS
Construction work in progress (CWIP)
represents the cash progress payments which have
been made in the form of capital expenditures
for plant and equipment currently under construction
IrlBlsl
-------
B-4
for in-service operation in the near future. While
these expenditures represent actual cash disburse-
ments by the industry, they are not at this time
included in computations of the rate base. Some
proportion of the financing costs associated with
CWIP is allowed to be capitalized at the time that
the plant and equipment are placed in service. In
addition, this allowance for funds used during con-
struction is then shown as a noncash source of income
for investor-owned utilities. CWIP for 1983 amounted
to $67.9 billion (private sector, $56.1; public, $11.8)
in current dollars and $43.8 billion in constant
1974 dollars.
EXTERNAL FINANCING
External financing requirements are the
sum of long-term debt, preferred stock and common
stock issues in any given year, including the re-
financing of maturing long-term debt.^ For example,
the 1983 requirement of $27.7 billion in current
dollars can be segmented into:
2. A schedule of long-term debt refundings through 1990 has been
estimated from published sources and in no year exceeds $1.7
billion. Further,, the TAc-Finance assumed that no new long-
term debt issues will mature prior to 1990.
TlBIS
-------
B-5
Private Public
Sector Sector
Long-Term Debt Issues $ 14.3
Preferred Stock Issues 2.5
Common Stock Issues 5.3
$ 22.1 $ 5.6
These 1983 financing requirements are equivalent to
$17.8 billion in constant 1974 dollars.
The difference between capital expendi-
tures and external financing requirements in any
given year is the amount of funds generated inter-
nally in the form of retained earnings, depreciation
and tax deferrals less the refundings of long-term
debt. In 1983, internal cash generation in current
dollars was:
Private Public
Sector Sector
Retained Earnings $ 3.3
Depreciation (including
nuclear fuel) 8.8
Tax Deferrals 1.8 '-
$13.9 $3.0
iTlBlSl
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B-6
OPERATING REVENUES
Operating revenues in the investor-owned
sector are those required to yield a 14 percent
rate of return on average common equity. Public
sector revenues are then based on the same revenue
per kilowatt-hour. In 1983, total operating revenues
were $115.9 billion in current dollars (private sector,
$92.7 billion; public sector, $23.2 billion) and $74.7
billion in constant 1974 dollars.
OPERATIONS AND MAINTENANCE EXPENSES
Operations and maintenance expenses in-
clude those items so defined by the Federal Power
Commission in its Statistics of Privately-Owned Eleatri-a
Utilities in the United States, with the exception of
nuclear fuel. For example, the 1983 operations and
maintenance expenses are estimated to be $64.5
billion in current dollars (private sector, $47.1;
public sector, $17.4) and $38.0 in constant 1974
dollars.
CONSUMER CHARGES
Consumer charges are the average amount
per kilowatt-hour which is being paid in any given
ITIBIS
-------
B-7
year. The amount of electrical energy consumed
is based upon the growth in peak load demand, the
reserve margin and the capacity load factor. For
example, the 1977 electrical energy amount of 3160.8
billion kilowatt-hours is obtained from:
1973 peak load demand of 351.8
million kilowatts,
Growth in peak load demand between
1973 and 1983 of approximately 5.5
percent per year,
Reserve margin of 20 percent,
Capacity load factory of 49.9
percent, and
8760 hours per year.
The average consumer charge per kilowatt-
hour is then obtained by dividing operating revenues
by the total electrical energy consumed. For ex-
ample, the average consumer charge for 1983 in con-
stant 1974 dollars is estimated to be:
kWh • 2.360/«h-23:6»ills/kWh
T
B|S
-------
Exhibit B-l
ECONOMIC AND FINANCIAL PROJECTIONS OF BASELINE CONDITIONS FOR SELECTED YEARS
(dollar figures in billions of 1974 dollars)
1973
1977
1983
1990
Capital
Total
Total
Expenditures
for year $ 13.9
since 1973
$ 17.9 . $ 28.3 $ 39.1
60.3 203.2 441.4
Construction Work in Progress
End of
External
Total
Total
year $ 19.6
Financing
for year $ 7.6
since 1973
$26.5 $ 43.8 $ 62.2
$ 10.9 • $ 17.8 $ 23.6
35.8 126.3 272.6
Operating Revenues
Total
Total
for year $ 39.5
since 1973
$ 52.5 $ 74.7 $ 104.1
188.8 579.5 1,218.0
Operations & Maintenance Expenses1
Total
Total
for year $ 17.7
since 1973
$ 26.4 $ 38.0 $ 49.5
92.0 292.5 603.7
Consumer Charges (mills/kWh)
Average for year 21.4
H
00
m
Excludes
Source:
nuclear fuel
PTm
24.0 23.6 22.4
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Exhibit B-2
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED INCOME STATEMENT
Baseline Conditions - 1983
(billions of current dollars)
Operating Revenue
-Operating and Maintenance Expenses
(excluding nuclear fuel) $ 47.1
-Taxes other than Income 9.7
-Depreciation (including nuclear fuel) 8.8
+Allowance for Funds used During
Construction (AFDC) 3.6
Earnings Before Interest and Income Taxes
-Interest Charges
Earnings Before Income Taxes
-Income Taxes (State and Federal) . $ 8.8
+Investment Tax Credits 0.6
Net Income
-Dividends on Preferred Stock $ 1.7
-Dividends on Common Stock 7.8
Retained Earnings
$92.7
62.0
$30.7
9.7
$21.0
8.2
$ 12.8
9.5
$ 3.3
Source: PTm
TBS
-------
Exhibit B-3
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED BALANCE SHEET
Baseline Conditions - 1983
(billions of current dollars)
Asset Accounts
Gross Plant in Service $ 264.9
-Accumulated Depreciation 69.2
Net Plant in Service $ 195.7
Net Nuclear Fuel 3.6
Construction Work in Progress 56.1
Net Electric Plant $ 255.3
Net Working Capital
(assumed to be constant) 0.1
Total Assets $ 255.4
Liability and Equity Accounts
Deferred Tax Items $ 15.3
Long-Term Debt—outstanding prior to 1973 $ 37.0
—issued after 1972 95.4
Long-Term Debt—Total $ 132.4
Preferred Stock—outstanding prior to 1973 $ 10.6
—issued after 1972 13.4
Preferred Stock—Total $ 24.0
Owners' Equity—outstanding prior to 1973 $ 31.6
—cash issues after 1972 29.0
—retained earnings after 1972 23.4
Owners' Equity—Total $ 84.0
Total Liabilities and Owners' Equity $ 255.4
Source: PTm
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Exhibit B-4
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED APPLICATIONS
AND SOURCES OF FUNDS
Baseline Conditions - 1983
(billions of current dollars)
Applications of Funds
Capital Expenditures
$6 4
Non-Nuclear Generating Plant '
Nuclear Generating Plant 9.4
Nuclear Fuel 1.2
Transmission and Distribution Equipment 12.9
Pollution Control Equipment 0.0
Increase in Construction Work in Progress 5.4
Total $35.3
Refundings of Long-Term Debt 0. 8
Total Applications $36.0
Sources of Funds
Internal Cash Generation
Retained Earnings $3.3
Depreciation (including nuclear fuel) 8.8
Deferred Tax Items 1.8
Total
Source: PTm
Total $13.9
External Financing
Long-Term Debt $14.3
Preferred Stock Issues 2.5
Common Stock Issues 5.3
Total Sources $36.0
TBS
-------
Exhibit B-5
INVESTOR-OWNED ELECTRIC UTILITIES COMBINED RECONCILIATION OF TAXES
Baseline Conditions - 1983
(billions of current dollars)
Earnings Before Income Taxes: Reported $21.0
-Accelerated Depreciation $ 3.5
-Allowance for Funds used During
Construction (AFDC) —^-2. 7.1
Earnings Before Income Taxes: Tax Base $13.9
Income Taxes: Paid 7.3
-Investment Tax Credits (Actual) $ 0.4
+Deferred Tax Items 1.8
-(-Investment Tax Credits (Amortized) 0.1 1.5
Income Taxes: Reported $ 8.8
Source: PTm
TBS
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•|i-:riiNir/\L KI.PORT
DATA ij/u;u
1. Report No.
EPA230/2-74-006
3. Recipient's Accession No.
4. Title and Sulilillc
Economic Analysis of Effluent Guidelines
Steam Electric Powerplants
5. Report Date
December 1974
6.
j 7. Aulli.xls)
Howard W. Pifer Michael L. Tennican et. al
8. Performing Organization Rept. No.
y. IVrtoriiiiiijt Orianicilioii Name ami Address
Temple, Barker & Sloane, Inc.
15 Walnut Street
Wellesley Hills, Massachusetts 02181
10. Project/Task/Work Unit No.
11. Contract/Grant No.
68-01-2803
12. Sponsoring Organization Name and Address
Office of Planning and Evaluation
Environmental Protection Agency
Washington, B.C. 20460 .
13. Type of Report & Period Covered
Final
u.
IS. Supplementary Notes
16. Abstracts
17. Key Words and Document Analysis. 17a. Descriptors
Economic Analysis
Effluent Guidelines
Steam Electric Powerplants
Electric Utility Industry
Policy-Testing model (PTm)
17b. IJcntifiers/Open-Ended Terms
17k- COSATI Held/Croup
IK. Availability Stulcnicnl
19. Security Class (Tliis
Report)
UNCLASSIFIED
20. Security Class (This
Uf CLASSIFIED
21. No. of
22. Price
I OHM NTIS-.15 (RKV. .1-72)
USCOMM-W 14952-1-72
TBS
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