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)
                                                        TIBISI

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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)

                                                       TIBISI

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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)
                                                       |T|B|S

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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)
                                                      TlBlSl

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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)
                                                      [TlBlS

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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)
                                                       ITIBIS

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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)

                                                IrlBlsl

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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
                                                       TIBISI

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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
                                                TIBIS

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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")
                                                T|B|S

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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)
                                                TlBlSl

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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")

                                                      ITIBISI

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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)
                                                      TlBlS

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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)
                                                       TBS

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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
                         xx
                                                      iTlBlSl

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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.
                                                      TlBlSI

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                         -2-
          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.
                                                      TlBIS

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                         -3-
          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.
                                                       TIBISI

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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
                                                       TIBIS

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                        -5-
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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                        -6-
          •    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.
                                                     TIBIS

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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
                         -7-
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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
                                                      ITIBIS

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                         -9-
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.
                                                       TBS

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                        -10-
          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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                        -li-
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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                        -12-
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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                          -13-
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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                          -14-
          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.
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                        -15-
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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                         -16-
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.
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                         -17-
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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                         -18-
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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                         -19-
          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
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                         -20-
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
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                        -21-
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.
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                        -22-
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.
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                         -23-
          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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                       -24-
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
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                        -25-
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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                         -26-
          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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                          -27-
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
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                        -28-
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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                         -29-
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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                         -30-
(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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                        -31-
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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                           -32-
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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                         -33-
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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                        -34-
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
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                         -36-
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.
                                                      IrBlsl

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                           -37-
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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                         -38-
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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                          -40-
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.
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                          -41-
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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                          -42-
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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                        -43-
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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                        -44-
          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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                         -45-
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,
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                          -46-
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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                        -47-
          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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                         -48-
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
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                         -49-
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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                         -50-
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

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                          -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

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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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                        -53-
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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                        -54-
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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                            -55-
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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                          -56-
 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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                        -57-
          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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                         -58-
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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                          -59-
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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                          -60-
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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                        -61-
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.
                                                       TIBIS

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                        -62-
          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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                       -63-
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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                       -64-
          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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                        -65-
          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

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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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                          -68-
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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                          -69-
          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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                         -70-
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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                        -71-
          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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                         -72-
          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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                         -73-
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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                         -74-
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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                          -75-
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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                           -76-
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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                          -77-
          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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                          -78-
          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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                          -79-
          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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                          -80-
          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,
                                                       TlBlSI

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                          -81-
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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                         -82-
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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                          -83-
          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.
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                          -84-
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.
                                                       TIBISI

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                         -85-
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.
                                                       TlBlSl

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                          -86-
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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                           -87-
          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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                          -88-
      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.
                                                        TlBlS

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                          -89-
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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                           -90-
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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                         -91-
    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.
                                                      IrlBlsl

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                          -92-
          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:
                                                      IrlBlsl

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                          -93-
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.
                                                        TlBlSl

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                          -94-
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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                         -95-
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.
                                                         TlBlS

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                          -96-
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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                         -97-
          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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                         -98-
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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                         -99-
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
                                                       TlBlSl

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                         -100-
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
                                                       TlBlS

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                         -101-
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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                         -102-
          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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                        -103-
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
                                                       IrlBlsl

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                         -104-
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.
                                                      IrlBlsl

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                         -105-
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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                        -106-
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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                          -107-
          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.
                                                         TlBlSl

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                         -108-
          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:
                                                         TlBlSI

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                          -109-
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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                            -110-
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
                                                         TlBlS

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                           -111-
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.
                                                        IrlBlsl

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                          -112-
          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.
                                                         iTlBTS

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                           -113-
           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.
                                                          TBS

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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.
                         -115-
                                                        ITU!

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                         -116-
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
                                                       ITIBIS

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                          -117-
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.
                                                        TlBlSl

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                         -118-
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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                         -119-
         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
                                                       TlBISl

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                         -120-
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%
-
                                                      T|B|S

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                        -121-
         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.
                                                      IrlBlsl

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                        -122-
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.
                                                     ITIBIS

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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.
                          -123-

                                                        iTlBlsl

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                         -124-
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.
                                                        ITIBISI

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                         -125-
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
                                                        ITIBISI

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                          -126-
 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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                        -127-
          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).

                         -129-

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                        -130-
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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                         -131-
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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                         -132-
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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                         -133-
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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                        -134-
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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                          -135-
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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                         -136-
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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                        -137-
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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                         -138-
          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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                         -139-
          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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                        -140-
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.
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                        -141-
          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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                        -142-,
          •    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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                        -143-
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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                        -144-  .
          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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                        -145-
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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                        -146-
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
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                         -147-
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.
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                         -148-
          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,
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                         -149-
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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                         -150-
               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
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                       -151-
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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                         -152-
           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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                        -153-
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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                         -154-
          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.
                                                      IrlBlsl

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                       -155-
          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.
                                                      PflBlsl

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                        -156-
          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

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 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.
                          -157-

                                                          JTlBlsl

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                          -158-
           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.
                                                        iTlBlSl

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                         -159-
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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                         -160-
          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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                         -161-
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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                        -162-
          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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                       -163-
              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.
                                                      JTlBlsl

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                        -164-
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
                                                       TlBlS

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                        -165-
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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                         -166-
           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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                         -167-
          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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                        -168-
          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

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                          -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

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                         -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

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                         -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

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                         -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

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                         -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

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                        -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

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                        -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

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                         -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

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                               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

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           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

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                                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%

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                               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

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                             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

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                              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



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                             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

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                                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

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                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

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                                    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

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                                     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

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                                                               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

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                                                   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

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                                                               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

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                                                                 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

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                                                                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

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                                                                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

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APPENDIX A

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       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

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                          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

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                         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

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                          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

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                           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

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                                                                                                    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

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                                                                                                 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

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                        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

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                         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

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                        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

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                         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

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                           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

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                           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

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                           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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