EPA-230/1-73-006
SEPTEMBER 1973
           ECONOMIC ANALYSIS
                    OF
     PROPOSED EFFLUENT GUIDELINES

   STEAM  ELECTRIC POWERPLANTS
                   QUANTITY
       U.S. ENVIRONMENTAL PROTECTION AGENCY
           Office of Planning and Evaluation
              Washington, D.C. 20460
                  I
                  55
                  V

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This report has been reviewed by the Office of Planning and Evaluation,
EPA, and approved for publication.   Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.

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       ECONOMIC IMPACT  OF PORPOSED  EFFLUENT
GUIDELINES - STEAM  ELECTRIC POWER  PLANTS

                  MARCH 1974
                               ,     or~u>ct;on Agency
                    U.S. Environmet   • «-1 -
                    Region V. Library
                    230 South Dearborn S.eet
                    Chicago, Illinois 60604
                            James  M.  Speyer
                            Office of Planning  and Evaluation
                            Environmental Protection Agency
                            Washington, B.C.   20460

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                       PREFACE

The attached document was prepared by the Office  of  Planning
and Evaluation of the Environmental Protection Agency
("EPA").  The purpose of the study is to analyze  the
economic impact which could result from the  application
of alternative effluent limitation guidelines and  standards
of performance to be established under sections 304(b) and
306 of the Federal Water Pollution Control Act, as amended.

The study supplements the technical study  ("EPA Development
Document") supporting the issuance of proposed regulations
under sections 304(b) and 306.  The Development Document
surveys existing and potential waste treatment control
methods and technology within particular industrial  source
categories and supports promulgation of certain effluent
limitation guidelines and standards of performance based
upon an analysis of the feasibility of these guidelines  and
standards in accordance with the requirements of section
304(b) and 306 of the Act.  Presented in the Development
Document are the investment and operating costs associated
with various alternative control and treatment technologies.
The attached document supplements this analysis by estimating
the broader economic effects which might result from  the
required application of various control methods and  technologies,
This study investigates the effect of alternative  approaches
in terms of product price increases, effects upon  employment
and the continued viability of affected plants, effects  upon
foreign trade and other competitive effects.

Several sections of Part II were excerpted from a  report
entitled, "Possible Impact of Costs of Selected Pollution
Control Equipment on the Electric Utility Industry and
Certain Power Intensive Industries".  The aforementioned
report was prepared for the Council on Environmental Quality
in  fulfillment of Contract No. EQC-209 by National  Economic
Research Associates, Inc.  The work was completed  as of
January 1972.  The technical appendix to this study  (e.g.,
Part III) was submitted in March, 1974 in fulfillment  of
Contract No. 68-01-2418 by Temple, Barker, and  Sloane,  Inc.
It should also be acknowledged that much ofthe analysis  in
Parts II and III is based on data supplied -by Edward Pechan,
Office of Planning and Evaluation.

This study is being released and circulated  at approximately
the same time as publication in the Federal  Register of  a
notice of proposed rule making under sections 304(b) and  306
of the Act of the subject point source category.   The  study
has not been reviewed by EPA and is not an official  EPA

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publication.  The study will be considered along with the
information contained in the Development Document and any
comments received by EPA on either document before or during
proposed rule making proceedings necessary to establish
final regulations.  Prior to final promulgation of regulations,
the accompanying study shall have standing in any EPA
proceeding or court proceeding only to the extent that
it represents the views of the Office of Planning and
Evaluation of EPA and the contractors who studied the
subject industry.  It cannot be cited, referenced, or
represented in any respect in any such proceeding as a
statement of EPA's views regarding the subject industry.

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                         CONTENTS

                                                          Page
  PART I - EXECUTIVE SUMMARY

  I.   Introduction

 II.   Pollution Control Requirements and Costs
      A.  Effluent Limitation Guidelines
          for 1977 and 1983                               1-2
      B.  Water Pollution Abatement Costs                 1-3

III.   Economic Impact of the Proposed Water Effluent
      Guidelines
      A.  Introduction                                    1-5
      B.  Financial Effects                               1-6
      C.  Price Effects                                   1-7
      D.  Capacity and Energy Penalty                     1-8
      E.  Production Effects                              1-9
      F.  Employment Effects                              1-10
      G.  Community Effects                               1-10
      H.  Balance of Trade                                1-10

 IV.   Limits to the Analysis
      A.  Uncertainty of Cost Estimates                   1-11
      B.  Critical Assumptions                            1-11


                 PART II IMPACT ANALYSIS
  I.  Structure of the Industry
      A.  Introduction                                    II-l
      B.  Supply Characteristics                          II-2
      C.  Demands Characteristics                         II-8

 IT.  Financial Profile
      A.  Profitability                                   11-20
      B.  Capital Formation                               11-20

III.  Pricing
      A.  Price Determination                             11-26
      B.  Historical Trends in Prices                     11-26
      C.  Future Trends in the Price of Electricity       11-26

 IV.  Pollution Control Requirements and Costs
      A.  Effluent Limitation Guidelines for 1977&83      11-30
      B.  Current Level of Control                        11-30
      C.  Expected Coverage of the Guidelines             11-31
      D.  Water Pollution Abatement Costs                 11-32
      E.  Comments on Cost Data                           11-32

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   V.  Economic Impact Analysis Methodology
       A.  Introduction                                   11-43
       B.  Financial Effects                              11-44
       C.  Price Effects                                  11-45
       D.  Capacity and Energy Penalties                  11-46
       E.  Production Effects                             11-47
       F.  Employment Effects                             11-47
       G.  Community Effects                              11-47
       H.  Balance of Trade Effects                       11-47

  VI.  Baseline Economic Impact Analysis
       A.  Introduction                                   11-48
       B.  Financial Effects                              11-50
       C.  Price Effects                                  11-53
       D.  Capacity and Energy Penalties                  II-54
       E.  Production Effects                             11-56
       F.  Employment Effects                             11-56
       G.  Community  Effects                             11-56
       H.  Balance of Trade Effects                       11-57

 VII.  Limits to the Analysis
       A.  Uncertainty of Cost Estimates                  11-62
       B.  Critical  Assumptions                          11-64
       C.  Remaining Questions                            11-68

                 PART III TECHNICAL APPENDIX

   I.  Purpose and Scope                                 III-l

  II.  Summary and Conclusions                           III-7

 III.  Baseline Electric Utility Industry  Projections:
         EPA Policy Alternative                          111-20

  IV.  Electric Utility Industry Projections:   EPA
         Policy Alternative                              111-44

   V.  Overview of EPA Policy:  Alternatives  Before
         Exemptions                                      111-72

  VI.  Overview of EPA Policy:  Alternatives  After
         Exemptions                                      III-107

 VII.  Impact of Reduced Industry Growth                 III-122

VIII.  Review of Alternative Technological Assumptions   III-129

Appendix A:  Research Methodology                        III-152

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                  LIST OF TABLES
Table No.                                                Page

   1       United States Electric Utility Industry       11-11

   2       Projected Growth of Electric Utility          11-12
           Generating Capacity, 1970-1990

   3       Percent of Electricity Generation by          11-13
           Source, By Region, 1969

   4       Percent of Electricity Generation by          11-14
           Source, 1960-1970

   5       Percent of Electricity Generation by          11-15
           Type of Fuel, 1970-1990

   6       Projected Annual Fuel Requirements,           11-16
           Steam Plants, 1970-1990

   7       Aggregate Energy Consumption in  the           11-17
           United States, 1960-1970

   8       Average Number of Employees of Investor       11-18
           Owned Utilities in the United  States,
           1960-1970

   9       Total Electricity Consumption  in the          11-19
           United States, 1960-1990

  10       Combined Balance  Sheets -  Year Ended          11-22
           Dec. 31, 1971, Investor -  Owned
           Electric Utilities

  11       Revenues - Total Electric  Utility             11-23
           Industry, 1959-1971

  12       Combined Income  Statements - Year Ended       11-24
           Dec. 31, 1971 - Investor-Owned Electric
           Utilities

  13       Investment - Total Electric Utility           11-25
           Industry, 1961-1971

  14       Average Revenues Per Kilowatt-Hour            11-28
           Sold - Total Electric Utility  Industry,
           1951-1971

  15       Consumer Price Index - All-City  Average,      11-29
           1951-1971

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Table No.
  16       Residential Electricity and  Consumer
           Price Index - Total Electric Utility
           Industry, 1951-1971

  17       Draft Summary of Proposed Water               11-33
           Effluent Guidelines For Thermal  Discharge:
           EPA Recommendation

  18       Draft Summary of Proposed Water               11-34
           Effluent Guidelines for Chemical  Discharges

  19       Type of Cooling  Systems for  Steam            11-35
           Electric Plants, 300 mwe and Larger,
           Being Constructed or Coming  Under
           Construction by April 1, 1974

  20       Expected Coverage of Thermal Effluent         11-36
           Guidelines: EPA Recommendation  (Before
           Exemptions )

  21       Expected Coverage of Thermal Effluent         11-37
           Guidelines: EPA Recommendation  (After
           Exempt ions )

  22       Estimates of Capital and Operating            11-38
           Costs Per Unit of Generating Capacity  -
           Thermal Effluent  Standards

  23       Estimates of Capital and Operating  Costs      11-39
           Per Unit of Generating Capacity  - Chemical
           Effluent Standards

  24       Incremental Costs of Application  of           11-40
           Mechanical - Draft Cooling Towers for
           Existing Units and New Units

  25       Estimates of Capital and Operating  Costs      11-41
           Per Unit of Generating Capacity  That
           the Utility Industry Would Have  Incurred
           in the Absence of Federal Environmental
           Regulations

  26       Estimates of Incremental Capital  and          11-42
           Operating Costs Per Unit of  Generating
           Capacity - Thermal Effluent  Standards

  27       Summary of the Economic Impact  of the         11-58
           Effluent Limitation Guidelines

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Table No.                                                Page

  28       Summary of the Economic  Impact  of             11-59
           New  Source Performance  Standards,
           1983-1990

  29       Selected Electricity  Intensive                11-60
           Industries in the United  States,  1967

  30       Impact of the Water Effluent  Guidelines      11-61
           on the Consumers of Electricity,  1977
           and 1983

  31       Minimum and Maximum Estimate  of Capital      11-69
           and Operating Costs Per  Unit  of
           Generating Capacity Associated  with
           Thermal Effluent Guidelines

  32 .      Estimates of Capital  and  Operating           11-32
           Costs Per Unit of Generating  Capacity
           Associated With Chemical  Effluent
           Guidelines

  33       Summary of the Total  Cost  of  the             11-71
           Effluent Limitation Guidelines

  34       Summary of the Total  Cost  of  New Source      11-72
           Performance  Standards,  1983-1990

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    PART I




EXECUTIVE  SUMMARY

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I.  INTRODUCTION

    The objective of this study is to provide an analysis
of the economic impact of the Environmental Protection Agency's
(EPA's) proposed water effluent guidelines^'  on the electric
utility industry.  Specifically, the following impacts are
analyzed:

              . Financial Effects

              . Price Effects

              . Capacity and Energy Penalties

              . Production Effects

              . Employment Effects

              . Community Effects

              . Balance of Payments Effects

    This study estimates the above impacts both before and
after exemptions under Section 316(a) of the Federal Water
Pollution Control Act of 1972 (FWPCA).!/

    The following report is divided into three parts.  The
first part is a summary of the economic impact of EPA's
proposed effluent guidelines while the second part contains
a more detailed analysis of the projected impact of the guide-
lines.  The final part is a technical appendix   which discusses
the economic impact of the seven policy alternatives that EPA
considered before publishing the proposed effluent guidelines.
As will be explained in later sections of the report, the
estimates in Parts I and II are based primarily on the analysis
presented in the technical appendix.
      s proposed water effluent guidelines for steam electric
  plants were published March 4, 1974 in the Federal Register,
  pp. 8294-8307.
2,/Section 316(a) of the Federal Water Pollution Control Act of
  1972 specifies that whenever the owner or operator of any
  source subject to the thermal discharge guidelines can dem-
  onstrate that the effluent limitation proposed for the control
  of the thermal discharge for that source is more stringent than
  necessary  to assure the protection and propagation of a balanced,
  indigenous population of shellfish, fish, and wildlife in and on
  the body of water, the Administrator (or, if appropriate, the
  state) may impose an alternative effluent limitation for thermal
  discharge, that will assure the protection and propagation of a
  balanced indigenous population of shellfish, fish and wildlife.

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 II.   POLLUTION CONTROL REQUIREMENTS AND COSTSl/

     A.   Effluent Limitation Guidelines for 1977 and 1983

         As shown in Tables 18 and 19 (pp. 11-33-34) the
 proposed effluent guidelines specify the level of chemical
 and  thermal pollution which can be discharged in 1977 and 1983.
 While about 83% of the existing capacity and 92% of the planned
 capacity will have to comply by 1977 with the chemical guide-
 lines for best practicable control technology, there is a
 phased  schedule for compliance with the thermal guidelines.
 Specifically, the utility industry is required to install closed
 cycle cooling system according to the following schedule:

                 Units.!/                            Date
         - All units installed after           Time of initial
           July 1, 1977                        operation

         - Baseload 500 mw and over            July 1, 1978

         - Baseload 300 mw and over            July 1, 1978

         - Baseload in plants larger           July 1, 1980
           than 25 mw and in systems
           larger than 25 mw

         - All other baseload                  July 1, 1983

         - All cyclic and peaking              July 1, 1983


         The  expected  coverage  by  1983  of  the  thermal  guide-
 lines is  summarized  below:3_/
I/  This is a summary of Part II, Section IV  n   TT  Tn
21 See Table 17, p. h-33 for definitions of' each category
3/ See Tables 20 and 21, p. 11-33-37 for estimates of the
   coverage of the guidelines by each year.
                        1-2

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                             Cumulative Coverage by 1983  (e.g.
Capacity Placed             % of capacity requiring closed
  in Service                cycle cooling )	
                            Before Exemptions   After Exemptions—

Non-Nuclear
- Prior to 1971                   51%               10.2%
- 1971-1973                       52%               10%
- 1974-1977                       89%               40%
- 1978-1990                       79%               38%

Nuclear

- Prior to 1971                   80%               16%
- 1971-1973                       67%               13%
- 1974-1977                      100%               46%
- 1978-1983                      100%               44%
    B.   Water Pollution Abatement Costs

        The impact analysis in this report is based on cost
estimates contained in a document prepared for EPA by Burns
and Roe, Inc.—'   The most important cost parameters are
summarized below:—'

                            Non-Nuclear      Nuclear
                              Capacity       Capacity
                            ($/kilowatt )     ($/kilowatt)

Capital Costs (1970 Prices)
- Cooling Towers on New Plants   $7.50           $10
- Cooling Towers on Existing     15.00            18
   Plants

Annual Operating Costs (1970 Prices)
- Replacement Power
   . 1977                           42            42
   . 1983                           15            12

Capacity Losses
- Power to Operate Cooling           3%            3%
   Tower and to Compensate
   for Efficiency Losses
!_/ The figures reflect EPA's best estimate of the  impact  of
   appeals under  Section 316(a) of the FWPCA of 1972.
2^ EPA, Development Decoument for Proposed Effluent Limitation
   Guidelines and New Source Performance Standards for the"
   Steam Electric Power Generating Point Source Category,
   March, 1974
_3/ See Tables 22 and 23 (pp 11-38 and 39) for a complete  summary
   of cost estimates for the thermal and chemical  guidelines.


                       1-3

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        In order to estimate the impact of  the  guidelines
in current dollars, it was necessary  to estimate  the  rate
of inflation for capital and operating costs.   A  summary
of these estimates is presented in the technical  appendix
(pp.  111-26 and 111-31).

        It should be emphasized that  in the  absence of
federal legislation, the utilities would have  installed
alternative cooling systems.  The incremental  cost of  the
thermal guidelines, therefore, is the cost  of  cooling  towers
minus the costs that the utility industry would have  spent
for alternative cooling systems (e.g., once  through cooling
in most cases and cooling towers in some cases).   In  order
to quantify the above factors, this report  assumed that  in
the absence of federal legislation, the mix  of  cooling  systems
in the 1973-1990 period would correspond to  the 1970  mix  of
cooling systems.  It is then possible to deduct the cost
of installing the 1970 mix of cooling system (e.g., Table  23,
p. 11-39 ) from the total cost of complying with  the thermal
guidelines (e.g., Table 22, p. 11-38) in order  to derive
estimates of the incremental cost of  the thermal  guidelines
(e.g., Table 24, p. 11-40).
                          1-4

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III.  ECONOMIC IMPACT OF THE PROPOSED  WATER  EFFLUENT
      GUIDELINE
    A.  Introduction

        In order to assess  the economic  impact  of  the  guide-
lines it is necessary to establish baseline  projections  for
the utility industry.  According  to  the  assumptions  presented
in the technical appendix the financial  projections  for  the
utility industry in the absence of expenditures for  water
pollution control are as follows:^.'


              Capitalized         Total  Yearly     Average  Consumer
  Period      Expenditures        Revenue  at      Charges  at End
              During Period       End  of Period   of Period _
              (billions of  current dollars)        (Mills/Kwh)

1974-1977         93.8                 57.0            24.0
1974-1983        364.0               113.6            31.9
1974-1990        968.1               240.9            43.2
        The next step is to develop  similar  projections  that
include the expenditures that will be  required  to  comply with
the water effluent guidelines.  The  difference  between  the two
sets of projections, represents the  total  cost  of  EPA's  guide-
lines.  Finally, in order to calculate the  incremental  costs
of the guidelines, it is necessary to  deduct  the  costs  that
the utility industry would have incurred for  alternative cool-
ing systems (e.g., once through cooling  in most cases and cool-
ing towers in a few instances) in the  absence of  federal
environmental legislation.

        In order to evaluate the economic  impact  of  the  guide-
lines, the principal focus of the following  analysis will be
to compare the estimates of the incremental  costs  of the
guidelines (e.g., Tables27 and 28i/, PP- H-41-42) to the
baseline projections.   Similar estimates of  the total costs
of the guidelines are presented in Tables  34  and  35^.'  (PP • II-
71-72) and their effect will also be examined.
JY This is a summary of Part II,  Section VI  p.  11-48
2y A detailed explanation of the  baseline  projections  is
   presented in Part III, pp. 111-20-43.
3_/ The estimates in Tables 27 and  28 were  derived  from the
   technical appendix by taking the difference  between Policy
   Alternatives 7 and 7E (pp 111-98 and 11-116) and Policy
   Alternative 0-T  (pp-III-70).
4_/ The estimates in Tables 34 and  35 were  derived  from the
   technical appendix by taking the difference  between Policy
   Alternatives 7 and 7E and Policy Alternative 0  (p.  111-36)

                           1-5

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        A  complete discussion  of  the economic  impact
methodology  is presented in Part  II, p. 11-43  and  in  Part
III,  p. III-149.

    B.  Financial Effects
         1.   Capital Requirements

             Before exemptions  the  guidelines will  increase
the utility  industry's capital  requirements by an  additional
23.2 billion dollars or 6.3% by 1983 and an additional  163
billion  dollars  or 2.6% between 1983 and 1990.  The  comparable
figures  after  exemptions are 9.2 billion or 2.5% by  1983  and
5.2 billion  or  .8% between 1983 and  1990.-'

             If  one adds the capital  costs that the utilities
would have incurred in the absence  of the federal  legislation,
the total capital required by  the  guidelines before  exemptions
will be  $28.5  billion (or 7.8%) by  1983 and $23.2  billion
(or 3.84) between 1983 and 1990.   The comparable figures  after
exemptions are  $14.5 billion (or 4.5%) by 1983 and $12.1
billion  (or  2.0%)between 1983  and  1990.

         2.   Sources of Financing

             The  u-tilities will  finance the expenditures for
pollution control equipment through  internal (e.g.,  deprecia-
tion, retained  earnings, tax deferrals) and external sources
(e.g., long-term debt, preferred stock, common stock).
Based on assumptions incorporated  into the PTm model,—' the
utilities could  finance 34% of  the  (1970-1990) capital
expenditures through internal  financing while the  remainder
would have to  come from external sources.  There are several
reasons  why  the  utilities should be  able to obtain the
required external financing.   First  the utilities  were  able to
increase the level of capital  investment by 11% per  year  in
the 1960's even  though the industry's interest coverage ratio
fell from 5.11  in 1961 to 3.03  in  1971.    Second, the  guide-
lines have an  insignificant effect  on the industry's coverage
ratios in 1977,  1983, and 1990-3/   Finally, if the utilities
are going to be  able to finance over 900 billion dollars  of
investment for  transmission and generation facilities by  1990,
it doesn't appear to be a major problem to finance an additional
14,4 billion dollars   for pollution control equipment  by 1990. **J


  I/ The estimates  represent the  incremental costs  of the water effluent
    guidelines.
  2/ The PTm (folicy Testing Model) was developed by Dr. Hower Pifer of
  ~ Temple, Barker, and Sloane,  Inc. and Professor Michael L.  Tennican
    of the Harvard Business School  to provide projections for the Technical
    Advisory Committee on Finance to the 1973-74 Rational ?ower Survey.
    A brief overview of PTm is provided  in Part III, p.  III-152.
  3/ See p. 11-51 for estimates of the coverage ratios with  and without
    pollution control expenditures.
  4_/ Total incremental impact after  exemptions of the guidelines by  1990.
                             1-6

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It can be concluded, therefore,  that  if  the  utility industry
experiences problems in  securing  long  or  short  term capital,
it will be the result of  the  large  capital expenditures
required to expand transmission  and generation  facilities.

    C.  Price Effects

        As shown in the  following table,  the utilities will
have to increase the price of  electricity in order  to  finance the
operating costs and fixed charges associated with the  guide-
lines .

                  Yearly  Cost  to  the  Con- Price  Increase at the
                sumer at the End of the Period End  of the  Period
  Period          Before        After        Before        After
                Exemptions   Exempt ions    Exempt ior s   Exemptions
               (Billions °f current  $)         (%  Increase)

1974-1983          5.6            3.1          4.7%         2.5%
1984-1990          3.5            1.7           .2%          .0%!'
        An increase in  the  price  of  electricity will also have
an effect on the prices of  other  goods  and  services.  However,
the average price increase  is  expected  to be  small since
purchases of electric power account  for only  .8% of the total
value of industrial shipments.!'   Even  if it  is assumed that
the increased power costs are  completely passed on to the final
consumer, the market price  of  the most  power  intensive industry
(e.g., primary production of aluminum)  will increase only .3%
(after exemptions) by 1983.17

        Based on the above  estimates,  it can  be concluded that
both the direct and secondary  price   increases associated
with the water effluent guidelines will be  very small.
3^7 The increase in the  sales  of  electricity  between 1984 and
~~  1990 is sufficient to  generate  the  1.7  billion dollars of
   additional revenue by  1990 without  an  additional price
   increase.
2_/ National Economic Research Associates,  Inc.,  Possible Impact
   of Costs of  Selected Pollution  Control  Equipment on the
   Electric Utility Industry  and Certain  Power Intensive Consumer
   Industries. 1972
_3_/ Estimate was calculated by multiplying  the percentage of pro-
   duction costs accounted for by  electricity in the aluminum
   industry, namely 11% by the projected  price increase after
   exemptions, namely 2.5%.
                         1-7

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    D.  Capacity and Energy Penalty

        1.  Capacity Penalty

            Installation of cooling towers will require  the
construction of new capacity to generate power to run  the
cooling towers and to compensate for the loss of efficiency
due to the increase in turbine back-pressure.i'  The baseline
case assumes that in 1977 the utilities will provide this
increased capacity through the construction  of gas-turbine
units.  However, by 1983 the utilities will  be able  to
construct large fossil and nuclear plants to replace the
lost capacity.

            Before exemptions the total capacity penalty will
be 1,900 MWe by 1977 and 14,700 MWe by 1983.  The comparative
figures after exemptions are 800 MWe by 1977 and 3,300 MWe
by 1983.  The composition of the capacity penalty by type of
plant is estimated to be as follows:


                                       Capacity Loss (in MWe)
                            1977                         1983
Type of Plant       Before          After       Before     After
                    Exemptions   Exemptions   Exemptions Exemptions

1. Peakers (e.g.      1,900          800        1,900       800
   gas turbines )

2. Base Loading        	           	       12,800     2,500
   (Fossil and
   Nuclear)           	

      Tota]            1,900          800       14,700     3,300


            The projected capacity loss before exemptions will
increase the national demand for generating  capacity by  only
.4% by 1977 and 2.2% by 1983.   The comparable figures after
exemptions are .2% by 1977 and .4% by 1983.  In view of  the
small increase in the demand for generating  capacity it  can be
concluded that the utilities should not experience serious
problems in replacing the projected loss in  generating capacity.

        2.   Fuel Penalty

            There is a fuel penalty associated with the water
effluent guidelines.   This penalty results from the following
factors:
!_/ It is estimated that the total capacity penalty will be
   3% of the plants total capacity.
                         1-8

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            a.  Additional fuel required to operate the
                closed cycle cooling system (e.g., 1%).

            b.  Additional fuel required per kwh of
                electricity  (e.g., higher heat rate) due
                to the increase in turbine back pressure
                (e.g., 2%).

The fuel penalty before exemptions will be approximately  4
millions tons equivalent of coal per year by 1977 and 33  mill-
ion tons per year by 1983.  The comparable figures after
exemptions are 2 million tons by 1977 and 7 million tons  by
1983.I/

            In view of the current shortage of energy it  is
important to evaluate the effect of the fuel penalty on the
national demand for energy, especially on the demand for  oil.

                                                                2 /
            Based on the Department of the Interior's estimates,—
the fuel penalty after exemptions will increase the national
demand for energy ,05% by 1977 and .2% by 1983.  Also, if  one
assumes that the fossj.1 fuel penalty will be evenly divided
between coal and oil,i'  the guidelines after exemptions would
increase the national demand for oil 4 million barrels per
year or .06% by 1977 and 14 million barrels per year or -2% by
1983.  It can be concluded, therefore, that the effluent  guide-
lines will have an insignificant effect on both the nation's
ability to satisfy the projected demand for energy and the
country's dependency on foreign sources.

    E.  Production Effects

        Even if the utilities experience delays in obtaining
rate increases to finance expenditures for pollution control
equipment, it is unlikely that an entire power plant will
shut-down because of the higher costs.  The one production
effect of the guidelines, however, may be to force certain
utilities to prematurely retire some older units in order
to avoid spending large amounts for pollution control equip-
ment.  Such an option will probably be used only after 1977
when it would be possible to replace the retired unit with
new  large fossil or nuclear units.  Finally,  the guidelines
W The fuel penalty was converted to coal equivalency by taking
   the total increase in demand for nuclear and fossil fuel
   expressed in million BTU, and dividing by the average BTU per
   ton -of coal (e.g., 24 million BTU/ton).
2J Dupree, Walter G. and West, James A., United States Energy
   Through the Year 2.000. U. S. Department of the Interior,
   December, 1972.
_3_/ This is probably a conservative assumption since if the fossil
   fuel penalty was distributed according to the projected
   utility demand for coal and oil, the eaergy penalty would be
   65% coal and 35% oil.

                        1-9

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won't have a  large  effect  on the growth of the electric
utility industry  since  the  projected  increases in the price
of electricity  (e.g., 2.5%  after exemptions by 1983 is not
expected  to have  a  large impact  on  the  demand for electricity.

    F .  Employment  Effects

        Since the price increases associated with the guide-
lines are not expected  to  have  a significant effect on the
growth in demand  for  electricity, the overall level of employ-
ment in the electric  utility industry will increase in order
to meet the projected increase  in demand  for electricity.
Also as discussed in  the previous section, the guidelines are
not expected  to  cause any  plant  closures  and any employment
effects due to  the  early retirement of  inefficient generating
units will probably be  offset by the  projected expansion in gen
erating capacity.   Furthermore,  if  the increased demand for
generating capacity due to  capacity penalties (e.g.,  .42 after
exemptions by- 1983),  is greater  than  the  reduction due to the
projected price  increase,  the guidelines  will Increase the
level of  employment.

    G .  Community
        The water effluent  guidelines  will  impact the community
directly through increased  price  for  electricity and indirectly
through price increases  for  final  goods  and services.  As shown
in Table 30, p. 11-61),  the  guidelines after exempt ionsl7 will
increase the average resident's monthly  electricity bill $.39
or 1.6% by 1977 and $1.08  (2.5%)by 1983.  The indirect price
increases, however, will be  so small  (e.g., less than. 3%) that
its impact is considered to  be insignificant.

    H.  Balance of Trade

        The guidelines will  have  a small  effect  on the balance
of trade because part of the  increased fuel consumption
associated with closed cycle  cooling  systems will be met by
increased imports of residual fuel oil.   Based  on the assumptions
used to estimate the fuel penalty,  the guidelines before
exemptions will increase oil  imports by 38  million barrels per
year or 1.2% by 1977 and 66 million barrels per  year or 1.7% by
1983.   The comparable figures after exemptions  are 4 million
barrels or .6% by 1977 and  14 million  barrels  or  ,4% by 1983.

        It is difficult  to  estimate the  total  balance of payments
costs  of the guidelines  since there is considerable uncertainty
concerning the future price of imported  oil.   If one assumes
a net  out-flow of $7 per barrel of oil,  however, the balance
of payments costs before exemptions would be 56   million dollars
per year by 1977 and 462 million dollars  per year by 1983.
The comparable figures after  exemptions  are 28 million dollars
by 1977 and 98 million dollars by  1983.   Since  the level
of imports in 1973 was approximately 70 billion  dollars,  it  can be
concluded that the guidelines will have  an  insignificant impact
on the nation's balance  of trade.
17 The comparable figures before  exemptions  are  also  estimated
   in Table 30.

                          1-10

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IV.  LIMITS TO THE ANALYSIS!/
    A.  Uncertainty of Cost Estimates

        The analysis indicates that alternative assumptions
about the capital and operating costs of chemical and  thermal
pollution control equipment and about the impact of closed
cycle cooling systems on generating efficiencies have  a
substantial impact on the projected economic  impact of the
guidelines.  The effects over the 1974-1984 period of  these
technological uncertainties are summarized below.—'

        The costs shown are the impact of each assumption
relative to the assumptions incorporated in EPA's proposed
guidelines.

                               Increase in Capitalized Expendi-
                                tures After Exemptions —
Chemical Cost Factors
.  Maximum
                                 Increase—
                                 + 200%
                     $ Increase
                 (billions current $)
                       + 12.9
  Thermal Capital Costs
  for Retrofits
  .  Maximum
  .  Minimum
    +  35%
    -  16%
                                                       .95
                                                       .43
  Thermal Operating Costs
  and Efficiency Losses
  .  Maximum
  .  Minimum
       38%
       ' 7%
                                                     1.0
                                                       .2
        If one assumes the maximum set of assumptions  for  both
the thermal and chemical guidelines the capital  cost of  the
guidelines after exemptions by 1983 would increase  from  9.2  to
24.1 billion dollars.  It can be concluded, therefore, that  under
the most conservative set of assumptions, the effluent guidelines
will increase the utility industry's capital requirements  by only
6.5% by 1983.
I/
2/
3/
II, Section VII
                                               11-62
This is a summary of Part
See Part II, p. 11-62 and Part III, p. III-129 for a more
detailed discussion of the impact of alternative technological
as sumpt ions.
These estimates assume that the percent variation in impact
for EPA's guidelines after exemptions  (e.g., Policy Alternativ
7-E in Part III) is the same as the percent variation  for
the technology based guidelines (e.g., Policy Alternative l(a)
in Part III ).
Percent increase over estimates presented in Table 27, p. II-
58 (e.g., 2.7 billion dollars for thermal guidelines and 6.5
billion for the chemical guidelines after exemptions by 1983).
                          1-11

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    B.   Critical Assumptions

        While the preceding sections have analyzed  the
impact  of the guidelines based on a single set of assumptions
about the growth in demand for electricity,  similar  calcula-
tions have been made using a low forecast for the growth  in
demand.!-'  The analysis indicates that under the low demand
case the utility industry's projected expenditures  between
1974 and 1983 for transmission and generation facilities  is
reduced about 31% from 364 to 250 billion dollars.   Since
the projected impact of the guidelines after exemptions is
reduced by only 20%, the incremental impact  of the  guidelines
will be slightly increased.  Specifically, the guidelines
after exemptions will increase the utility industry's
capital requirements 3.0% by 1983 (compared  to 2.5%  in the
high demand case.  It can be concluded, that even under assump-
tions of low demand, the utility industry should be  able  to
comply  with the guidelines without experiencing serious pro-
blems in financing the required expenditures.

        Another critical assumption was that in the  absence
of federal environmental regulations, the mix of cooling
facilities in the 1973-1983 period would correspond  to the
1970 mix of cooling facilities.  Therefore,  for new  power plants
the incremental cost of the thermal guidelines would equal the
cost of cooling towers minus the cost of the basic  cooling
facility that the utility would have installed (e.g., once
through cooling in most cases and cooling ponds, combination
systems or cooling towers in the remaining cases).   For exist-
ing power plants, however, the incremental cost and  the total
cost of the thermal guidelines would both be equal  to the
cost of cooling towers.

        There are a number of problems concerning this
assumption.  First, it is extremely difficult to forecast
what mix of cooling facilities would have been installed
in the  absence of federal environmental regulations. Second,  a
certain percentage of the new power plants have already incurred
costs for the construction of cooling facilities.   Thus,  the
incremental costs presented in Table-26 (p.  11-42)  which  were
calculated based on the assumption that no costs had been
incurred for alternative cooling facilities, actually under-
estimate the impact of the guidelines.  Finally, there was a
computational error in the computer run that calculated the
incremental cost of the guidelines after exemptions  (e,g,,
policy  alternative 7(e) in Part III).  Specifically, the  costs
   See Part III, p. III-122 for a description  of  the  low demand
   case.
                        1-12

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that the utility industry would have incurred for cooling systems
in the absence of federal legislation (e.g., Table-25, p.II-4l)
were not included for that fraction of new capacity which will
not be covered under the guidelines.  In order to accurately pre-
dict the incremental costs of the guidelines after exemptions,
these costs would have to be added to the estimates which wpre
presented in Tables 27 and 29 (pp. 11-58-59).

        It can be concluded, therefore, that the actual incre-
mental costs of the guidelines fall in between the total cost
estimates (Table-22, p. 11-38) and the incremental cost
estimates (Table 26).  If one assumes the worst case, namely
that the incremental cost actually equals the total cost, the
capital requirements of the guidelines would increase 5.8
billion dollars by 1983.I/  However, since this would increase
the utility industry's capital requirements only an additional
1.4% by 1983, there is no reason  to question the validity of
the analyses' major conclusions.
 I/  Similar estimates for other impacts (e.g., price, capacity
 ~~  and fuel penalty, etc.) are given in Tables 33 and 34, pp. II
    71-72.
                          1-13

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     PART II




IMPACT ANALYSIS

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I.  STRUCTURE OF  THE  INDUSTRY

    A.  Introduction

        The electric  utility industry is primarily composed
of the following  types  of  production facilities:

             1.   Steam  Electric (fossil and nuclear)
             2.   Hydro-electric
             3.   Internal  combustion (e.g., diesel
                  and  gas  turbine)

In 1970 steam electric  plants generated 83.6% of the nation's
electricity  while  hydro-electric and internal combustion
plants produced 16.1% and  .3% respectively of the nation's
electrical output.—'

     Although the proposed water effluent guidelines will
apply almost exclusively  to steam  electric plants,—there
was not sufficient  time to segment the existing financial
data by type of production facility.  Therefore, sections
I, II and III will  discuss the structure of the entire
electric utility  industry.  The economic impact analysis
(e.g., sections IV, V,  VI, VII)             estimates the
costs that steam  electric  power plants (and where appropriate
internal combustion plants) will incurr in order to comply
with the proposed water effluent guidelines.
!_/ Edison Electric  Institute,  Statistical Yearbook of the
   Electric Utility  Industry  for  1970,  September 1971
2_/ The thermal guidelines  will apply exclusively to steam
   electric plants  (e.g, plants that have a steam cycle).  However, the
   chemical guidelines will be applicable to internal  combustion
   generation facilities as well as to  steam electric  plants.
                        II-l

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    B.   Supply Characteristics i

        1.   Types of Firms

             The electric utility industry is composed of four
types of entities—investor-owned,  publicly owned (non-Federal),
Federally owned and cooperatives.  In 1965,.2.' the industry was
composed of 3,550 systems, of which 437 were investor-owned,
2,101 were  publicly owned, 971 were rural electric cooperatives
and 41  were Federally owned bodies  (see Table -1-).   The rela-
tionships among the 3,550 systems are diverse: some either
generate no power or supply only a  portion of their own needs,
others  have no retail customers but are engaged only in genera-
tion and the wholesaling of power to distributors in the retail
business.  As shown in Table -3-, the vast majority of the
investor-owned utilities are engaged in generation,  transmission
and distribution, whereas almost two-thirds of the publicly
owned utilities purchase all of their power and only a few coopera-
tives have any generation and transmission facilities.  Federally
owned utilities, on the other hand, are almost totally engaged
in generation and transmission.
             In 1970, the investor-owned utilities accounted for
about 80      percent  of total generating capacity arid over
77 percent   of the total production of electricity,  thus
constituting the largest segment of the industry.  The publicly
owned utilities represented 10 percent of the total generating
capacity and about 12 percent of the total production, while
the cooperatives accounted for only 1 percent of capacity and
percent of  total production.    Federally owned utilities
represented 11 percent of the generating capacity, and supplied
about 12 percent of total production.

             For several reasons, publicly owned and cooperative
systems are able to obtain capital at a lower cost.3-'   Federal
projects, other than TVA, obtain capital directly from the
U.S. Treasury.  REA cooperatives also obtain capital directly
from the Federal government.
1./  This section was exerpted from a report, entitled  Possible
     Impact of Costs of Selected Pollution Control Equipment
     on the Electric Utility Industry and Selected Power InFensive
     Consumer Industries, 1972, which was prepared for the
     Council on Environmental Quality.
2./  The most recent year data are available in terms of genera-
     tion, transmission and distribution functions.
3./  In the accounting sense of that word.
                         II-2

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     2.  Regulation^-/
        Regulators directly control profits and thus  the
 general level of utility prices by allowing utilities  to  earn
 no  more than a "fair" rate of return on invested capital.   In
 order  to  penalize inefficiency and control costs, regulation
 requires  that only those expenses and investments which are
 prudently made can be recovered in rates.  Moreover,  if elec-
 tric utilities have excessive capital costs because of inappro-
 priate capital structures, commissions may substitute  hypo-
 thetical  structures and refuse to allow rates higher  than  would
 be  needed to cover the lower hypothetical capital costs.   Undue
 price discrimination is prohibited by providing cost-based tests
 for the setting of individual rates.

        In order to promote "adequate" reliable service,
 commissions control the terms of service extensions and serv-
 ice obligations.  They also provide a forum for consumers  to
 voice service complaints.   Finally, regulators have resorted
 increasingly to withholding rate increases in order to induce
 regulated companies to develop satisfactory service quality
 standards.

        There are six rather well defined specific areas  of
 regulatory activity which  can be distinguished for the elec-
 tric utility industry.  The first of these is what is  generally
 thought of  when the term "utility-type" regulation is  used.
 With few  exceptions this applies only to investor-owned utili-
 ties and  is accomplished at the state or local level  through a
 public service commission  or body with some equivalent desig-
 nation.   Utility-type regulation constitutes the basic means
 by  which  the government comprehensively oversees operation of
 the monopoly franchise granted to each investor-owned  utility.
 All Federal utility operations and, in most cases, municipals
 and REA cooperatives are exempt from utility-type regulation.

        The Federal Power  Commission implements a parallel
 type of regulatory activity.  It has jurisdiction over the
 wholesale rates charged by private utilities, and, in addition,
 jurisdiction over the interconnection of utility systems,  the
 provision of wholesale service, and the general reliability
 standards of all utilities.  The FPC has also become  involved
 in  joint  planning by private and public electric utilities
 for meeting regional power loads.
I./  This section was exerpted from a report, entitled "Possible Impact
    of Costs of Selected Pollution Control Equipment on the Electric
    Utility Industry and Selected Power Intensive Consmer Industries,
    1972, which was prepared for the Council on Environmental Quality

                         II-3

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         All utilities, whether  private or public, are  faced
with   the second regulatory activity,  which is the hydrolicensing
function of the Federal Power Commission.  Any hydro project
which  involves the construction of  a dam on a navigable  stream
must obtain a license from the  FPC.   This license is good  for
a  specified number of years at  the  end of which time it  must
be  renewed subject again to the FPC's  approval.  The Commission,
moreover, has the right to  "recapture" or take over the hydro-
power   project in the name of  the government at the expiration
of  its license.

         The third area of regulation is carried on by  the
Atomic Energy Commission.  This is  divided into two subareas,
the first of which is licensing.  All  nuclear power plants,
whether built by public or private  utilities, must first
receive AEC approval of the design,  then obtain a license  for
construction of the plant, and, finally, a license for its
operation.  A second subarea  of AEC  regulation is general
monitoring to see that health and safety standards are
maintained.

         The fourth area of regulation  is antitrust.  Increas-
ingly  in recent years the Justice Department has taken the
position, through both pronouncement and participation in
cases,  that the situation of  the utility industry in being
subject to regulation does not  grant it immunity from  anti-
trust consideration.  Thus, the Justice Department has challenged certain
mergers between private utilities and has brought pooling arrangements
under its scrutiny.  In addition to the Justice Department's direct roles,
the licensing section of the Atomic Energy  Act provides that the  review
procedure for licensing nuclear plants must include consultation  on the
antitrust aspects with the Justice Department.  The regulatory responsibilities
of the Securities and Exchange Commission under the Public Utility  Holding
Company Act also include consideration of antitrust factors.

          The  fifth area  is  the industry's financing  activities.
 Both  the FPC and the  SEC  have jurisdiction over  various aspects
 of the issue of  securities  and  notes  and short-term bank borrow-
 ing.

          The  final area  of  regulation  is  the  environmental
 area,  especially since  the  Calvert   Cliffs decision.   The
 regulation  in  this  area  is  not  as direct as  in the  preceding
areas  but comes about through the legal necessity, under
Calvert Cliffs, of assuring  that the Environmental  Protection
Agency s standards and  criteria will be met  in the  construction
and opeation of generating and  transmission  facilities.
                         II-4

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             The Tennessee Valley Authority is a special case:
since 1961 it has been permitted to issue taxable revenue
bonds to finance new construction.  As an agency of the
Federal government it borrows at lower interest rates and is
spared the need to raise high-cost equity capital.  TVA also
benefits from the fact that charges on its pre-1961 capital
derived from appropriations are equal only to the average
interest rate paid by the U.S. Treasury, and such capital
derived from retained earnings is available without cost to
TVA.

             Municipals, like private utilities, must go to the
marketplace to obtain capital, but no Federal income tax is
imposed on the interest received by municipal bondholders.
Municipals thus pay their bondholders only the net rate of
return they demand.

             Publicly owned electric utilities are also free
from direct taxation.  These  systems normally pay no Federal
or  state corporate income tax and no property tax (however,
some payments in lieu of local property taxes are often made).

        3.  Generation of Electricity by Type of Plant

             At the present time, fossil fueled plants
represent only  79%of total generating capacity.  The remainder
is  accounted for by hydro-electric generation both of the
once-through and pumped-storage types, and by direct com-
bustion-generation processes, such as gas turbines and diesel
engine driven generators  (see Table ~2-. for percentages).

             However, as shown in Table -2- the composition
of  generating capacity is expected to change drastically over
the next two decades.  Fossil fueled plants will decline from
79% to 44% of total capacity  and  nuclear plants will increase
from 2%  to 40%  of  total capacity.  While conventional hydro-
electric power  will decline from  15% to 6% of total capacity,
hydroelectric-pumped storage  will increase from 1% to 6% of
total  capacity.
                          II-5

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         4.  Present  and  Projected  Use of Fuels

             In  1970,  of  the  1,529.6 billion kilowatt-hours of
electricity produced by  the  electric utility industry in
the United States, 709.1  billion kilowatt-hours, or 46.4
percent, was produced  by  coal.   Natural gas represented
the second largest portion of  generation,  at 24.2 percent.
Electricity generated  from hydropower and  from oil-fired
boilers was 16.2 per cent and  11.8 percent, respectively,
and nuclear generation represented only 1.4 percent of
total generation.L'  As  Table  -3-  shows, the pattern in 1969
varied distinctly from region  to region.  Gas clearly is the
dominant fuel in the West South  Central region, accounting
for 96 percent of fuels  used  for electricity generation in
that area.  Nebraska and  California also consume substantial
amounts of gas in the  generation of electric energy,.  Hydro-
electric production  dominates  in the Far West (excluding
California) .  Coal is,  dominant  in  the East North Central and
the East South Central (including  TVA)  regions and, to a
slightly lesser  degree,  in the  South Atlantic region.  Oil-
fired generation accounts for  almost 60 percent of all
generation in New England.

             Table -4-shows  for  the last decade the percentage
contribution of  each of  the  fuels  and hydropower to electric-
ity generation in the  United  States as  a whole.  As can be
seen from the Table, coal has  been losing  its relative posi-
tion, while oil  and  gas  are  increasing  as  sources of
electricity and  hydropower has  remained relatively stable.

             As  Table  -5- indicates, the shift in fuel use
will accelerate  in the 1970's  and  1980's.   In 1980 27.6% of
total electricity generation  will  be made  up by nuclear,
36.5% by coal, 12.4% by  natural  gas, 12.4% by oil, and 11.4%
by hydro.    By  1990,  nuclear  will amount  for 47.3%, coal  26.7%
gas 7.2%, oil 8.0%,  and  hydro  10.8%. Id

             However,  even though  the relative importance of coal
and oil will decline,  the total  demand  for steam coal and fuel
oil more than double by  1990.  Also,as  shown in Table -6, there
will be a 1600%  increase  in  the  demand  for uranium ore.
_!_/ Federal Power Commission,  News  Release of March 18, 1971,
   No. 17372.
2/ The figures in Table-5- will change because of the recent increases in
   the price of oil and the Federal government's commitment to achieving
   greater energy self-sufficiency.  In particular the use of coal will
   increase faster than previously projected.
                         II-6

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          5.  Employment in the Industry

              Since the electric utility industry is the most capital-
intensive industry in the United States, it employs relatively few
workers.  As Table -^7-> demonstrates, for the year 1970, investor-owned
electric utilities employed a total only 384,900 workers, or only 0.4
percent of the United States labor force.  Almost 25 percent of these
were engaged in construction work for the industry.  Therefore, there
would be little effect on general employment levels even if the increased
costs associated with water pollution abatement control were to lead to
the laying off of workers.
                                 11-7

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    C.  Demand  Characteristics

        1.  Aggregate  Energy

              It would  be unrealistic to consider  the  demand
for electricity alone  without considering it  in  the  context of
the demand for  energy  in all of its forms.  The  economy demands
energy; not necessarily electricity, or natural  gas,  or any
specific  fuel.  As  we  shall later explain,  there  are  various
possibilities for  substitution between different  energy sources.

              During the 1960's the aggregate  demand  for all
forms of  energy  (see Table -8-) in the United States increased by
53 per cent  (or at  a compounded annual growth rate  of 4.4 per
cent), primarily as a  result of a pronounced  acceleration in
energy consumption  during the latter half of  the  1960s.  During
this same period the total demand for electricity (see Table -9-)
increased by 104% or at a compounded annual  growth rate of 7.2%.

              A  recent  study by the FPC.L/  indicates  that
demand for electricity will increase by 7.5%  per  year between
1970 and  1980 and  by 6.5 % per year between  1980 and 1990,
However, mitigating factors such as large price increases, energy conserva-
tion programs,  may substantially reduce the projected  demand for electricity,
         2.   Substitutability Among Primary  Fuels  and
             Electricity   & I

              In some applications electricity and the primary
fuels are  highly substitutable, whereas  in  others the use of
one particular  energy form is dictated by currently prevail-
ing technologies and relative prices.  One  can identify
several  distinct levels of Substitutability.   The residential
small appliance and lighting market,  for  example, is differ-
entiated  by  the fact that no present  or  foreseeable potential
substitute product is capable of rendering  the services now
provided  by  electric energy.  Similarly,  an appreciable element
of the demand by commerical customers  is  in lighting, which
generally  cannot be satisfied by other energy forms.  This
does not  mean,  however, that commerical  customers are completely
dependent  on electric utilities for  their energy.  They may
have the  option of "total energy;" that  is, under certain
special  conditions they can install  their own generators which
can be fired by either gas or oil.   The  generator supplies
electricity  needs while waste heat from  the turbine or engine
supplies  heating and cooling needs.   The  need for a well
 l_l  Federal Power Commission, Forecasts  of  Electric Energy and
    Demand to the Year 2000, June  1973.
 2j This section was exerpted from a report, entitled  Possible  Impact
   of Costs of Selected Pollution Control Equipment on
   Utility Industry and Selected Power Intensive Consumer Industries j
   1972, which was prepared for the Council on Environmental Quality.

                             II-8

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balanced energy load to make total energy an economical
alternative, however, puts an effective limit on the signi-
ficance of total energy as a competitor of electric utilities.
Clearly, commercial customers who require energy primarily
for lighting generally will not find it feasible to go to
total energy.  We can assume, therefore, that residential and
commercial small appliance and lighting markets are serviced
mainly by electric utilities.

             In contrast, distinct residential and commercial
large appliance and space heating markets would seem clearly
to be characterized by a high degree of substitutability among
electricity, gas and oil energy inputs.  For space heating
and water heating applications, electricity faces, as primary
potential substitutes, oil and gas, and in commercial uses,
possibly coal.  Indeed, in these markets, electric energy is
generally the new entrant.  There may, of course, be areas in
which neither oil nor natural gas facilities are available
and the electric utility therefore may face only such alter-
natives as bottled liquefied gas for these energy uses.
Similarly, for such applications as cooking, clothes drying
and air conditioning, electricity would be in potential com-
petition only with either natural gas where it is available
or with bottled gas.  Where neither is available, the electric
energy supplier would be in a monopolistic position.  In
general, however, it would seem a_ priori that the residential
and commerical markets for large appliance and heating appli-
cations may be served by electricity and gas, and to a more
limited extent, oil or coal.

             Despite the fact that the nature of industrial
energy demand varies widely with the specific industry, some
general observations can be made.  For large customers, the
bulk of the energy demand is likely to be for applications
other than lighting.  Where the demand is largely for process
heat, for example, gas, oil and coal may compete effectively
with electricity.  Even where the demands are of a nature that
must be met necessarily by electric energy, such as stationary
drive requirements, several substitution possibilities may
exist.  The large industrial customer may be able to employ a
total energy installation or may be able to self-generate his
power in a conventional fossil-fuel station.  Thus, it would
seem, generally, that the greatest energy product substitution
possibilities are open to industrial customers.
                         II-9

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        3.   Elasticity of Demand for Electricity

             A crucial variable in discussing and assessing the
effects of  pollution control on electric utilities is the
demand responsiveness of the consuming public to changes in
the price of electricity.  If,  for example, the elasticity
of demand for all electric utility customers were zero, then
any increase in the price of electricity would cause no decrease
in the quantity demanded.  In such a situation, all pollution
control costs could be passed on to consumers of electricity
without any change in the demand for that form of energy.
However, if the elasticity of demand for electricity was 1.0,
then an increase in the price of electricity, say of 10 percent,
would cause a decrease in the demand for electricity of 10 percent

             A review of several econometric studies which have
attempted to measure the elasticity of electricity demand
indicates that the data on which these studies were based (quite
aside from the appropriateness of the econometric
techniques employed) were too broad, too frag»entarjr or too
ambiguous to give the results much validity.  There is, there-
fore, for practical purposes, no measure of the elasticity of
electric demand usable for our purposes.

             Probably the only conclusions that can be made are
that the short-run elasticity is likely to be considerably less
than the long-run elasticity and that the elasticity of demand
for small changes in the price of electricity  (e.g., about 5-
10%) are likely to be considerably less than the elasticity
for large changes in prices  (e.g., greater than 10%).
                            11-10

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                                        TABLE  -1-




                        UNITED STATES  ELECTRIC  UTILITY  INDUSTRY
Number of Systems!/
Ownership
Investor-Owned
Public (Non-Federal)
Cooperatives
Fedeail
Total
(1)
437
2,101
971
41
TOTAL 3,550
I/ 1965 data.
2j 1970 data, preliminary
_3/ Col. (5) -Col (6) - Burns & Roe, Inc
and Standards of Performance: Steam
Engaged in
Generation
and Trans-
mission
(2)
262
725
72
39
1,098
. , Development
Engaged in
Distribution
Only
(3)
175
1,376
899
2
2,652
Document for
Generating-/ Production3-/
Capacity,
Percent 106 MWH
of Total
(4) (5)
77.2 1,182
10.1 140
1.4 22
11.4 185
4/ 1,528
Effluent Limitation Guidelines
Percent
(6)
77.53
9.1
1.4
12.1
I/
Electric Plants, June 1963
j4/ Percentages do not add to one hundred due to rounding.

-------
                                               TABLE -2-
i
V-
                    PROJECTED GROWTH OF UTILITY ELECTRIC GENERATING CAPACITY
                                (Figures in thousands of megawatts)
                               1970 (actual)
                                          % of
                                                   1980
                                      1990
Type of Plant

Fossil Steam

Nuclear Steam

   Subtotal Steam

Hydroelectric-
   conventional

Hydroelectric-
   pumped storage

Gas-Turbine and Diesel
                               Capacity   Total
                               260

                               _ 6

                               266


                                52
             TOTALS

      Notes:   (1)

               (2)
               (3)
                        341
 76

 _2

 78


 15


  1

	6

100
           % of
Capacity   Total

            59

            22.

            81
  68
 666
 10


  4

	5

100
           % of
Capacity   Total

  557       44

  500       4_0_

1,057       84


   82        6
                        71

                        51
             6

             4
1,261
100
             These projections are keyed to the electrical energy demand projections made
             by Regional Advisory Committee studies carried out in the 1966-1969 period.
             The projections are premised on an average gross reserve margin of 20%.
             Since different types of plants are operated at different capacity factors,
             this capacity breakdown is not directly representative of share of kilowatt-hours
             production.  For example, since nuclear plants are customarily used in base-load
             service and therefore operate at comparatively high capacity factors, nuclear
             power's contribution to total electricity production would be higher than its
             capacity share.
      SOURCE
             EPA,  Development  Document  for Proposed Effluent Limitation Guidelines  and
             New Source  Performance  Standards for  the  Steam Electric Power Generating
             Point Source  Category,  Sept. 1973.

-------
                               TABLE -3-

    PER CENT OF ELECTRICITY  GENERATION BY SOURCE, BY REGION
                              1969
          Region
Coal
       Oil
Gas
Nuclear  Hvdi o
                                          (Per Cent)
New England

Middle Atlantic

East North Central

West North Central
(Except Nebraska)

Nebraska

South Atlantic

East South Central
(Except TVA)
Tennessee Vctl-ley AuLhu.tiLy

West South Central

Rocky Mountain

Far West

California
22.1% 59.3%   0.9%

5?. 3  26.1    7.1

92.4   0.6    5.0


47". 7   1.1   36.

28.2   1.2

69.2  14.4   10.4


74.5   0.3

8l. I   —

 I/    0.2

33.5   2.1

 1.5   I/

      10.2
                       8.5%    9.3%

                       0.9     13.6

                       0.4      1.5
36.3
53.8
10.4
19.9
2.3
96.1
28.6
1.8
53.4
14.9
16.8
6.0
r: o
"""" j * -j
16.5
3.8
35.8
3.3 93.4
2.1 34.4
   Less than  0.1. per cent.

 Source:  Edison  Electric Institute, Statistical Year  Book of
              g_lectric Uti3_i_ty__In_d_us try for J^JO ,  Tables 1 3 S
                 ~
         National  Coal Association, S t e anv-E 1 ec t r i c _ P 1 an t
                       , Table 1.
         Tenries'soe  Valley Authority, Power Annual  Report, 1969 ,
         p.  23.
                                   11-13

-------
                           TABLE- 4-
           PER CENT OF ELECTRICITY GENERATION,
                   BY SOURCE, 1960-1970
Year
Coal
Oil    Jf£Ls_   Nuclear
     (Per Cent)	
Hydro
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
53.6
53.5
53.1
54.2
53.8
54.5
54.1
52.6
52.5
49.0
46.4
6.1
5.9
5.5
5.7
5.8
6.1
6.9
7.4
7.8
9.6
11.8
21.0
21.4
21.6
22.0
22.4
21.0
22.0
21.8
22.9
23.1
24.2
^/
y
V
y
V
y
y
y
y
1.0
1.4
19.3
19.2
19.7
18.1
18.0
18.4
17.0
18.2
16.7
17.3
16.2
I/  'Small percentage included  with  coal.
Source:  1960-1968:  U.  S.  Department of Commerce, Statistical
         Abstract of the United  States,  1964-1970.
         lfJ69^r9T(r'  Calculated  from data in Federal Power
         Commission, News  Release  of March 18, 1971, No. 17372
                           11-14

-------
                          T ABLE- 5-
       PERCENT OF ELECTRICITY GENRATION BY TYPE OF  FUEL
                         1970-1990
                                  PERCENTAGE

YEAR          COAL         OIL          GAS           NUCLEAR      HYDRO


197(>i/        46.4         11.8         24.2             1.4         16.2


              36.5         12.4         12.4            27.6         11.1


              26.7          8.0          7.2            47.3         10.8
I/ Federal Power Commission, News Release of March  18,  1971,
   No, 17372
2/ Estimated from data in National Economic Research Associates,Inc.,
   Possible Impact of Cost of Selected Pollution  Control  Equipment
   on the Electric Utility Industry and Certain Power Intensive
   Consumer Industries, 1972 and Burns and Roe, Inc.,  Development
   Document for Effluent Limitation Guidelines and  Standards
   of Performance, June, 1972.
                              11-15

-------
                       TABLE-6-
        PROJECTED ANNUAL FUEL REQUIREMENTS STEAM
                  ELECTRIC POWERPLANTS
                       1970-1990
     FUEL

Coal

Natural Gas

Residual Fuel Oil

Uranium Ore
UNIT
106tons
109cu.f t.
106bbl
tons
1970
322
6,600
331
7,500
1980
500
3,800
640
41,000
1990
700
4,200
800
127,000
(1) Tons of V^Og required to supply feed for difussion plants
    without plutonium recycle.
SOURCE:  Burns and Roe, Inc., Development Document for Effluent
         limitation Guidelines and Standards of Performance;
         Steam Electric Plants, Jane 1963
                          11-16

-------
                         TABLE-7-
           AGGREGATE ENERGY CONSUMPTION
         IN TilE UNITED STATES,  1960-1970
Year
Amount
  Per Cent
 Change from
Preceding Year

1960
1961
1962
1.963
1964
1965
IS* 6 G
1967
1968
1969
1970 p.
(Trillion Ubii)
44,960
45,573
47,620
49,649
51,515
53,785
56,948
58,868
62,448
65,832
68,810
(Per Cent)
-
+ 1.4
+ 4.5
+ 4.3
+ 3.8
+ 4.4
+ 5.9
+ 3.4
+6.1
+ 5.4
+ 4.5
p. - Preliminary.
Source:  1960-1969:  U. S. Department of the  Interior,
         Minerals Yearbook, Vol. II, 1962-1969.
         1970:  U. S. Department of the Interior, News
         Release of March 9, 1971.
                         11-17

-------
                          TABLE -8-
             AVKRAGE NUMBER OF EMPLOYEES OF             I/
INVESTOR-OWNED ELECTRIC UTILITIES IN THE UNITED STATES  ~

                        1960-1970
    Year
 Operation
    and
Maintenance
Construction
Total

1960
196.1
1962
1963
1964
1965
1966
1967
1968
19G9
1970
*" "*~

274
272
268
268
268
268
271
275
279
282
290
-•_-,-.

.5
.0
.9
.7
.6
.4
.0
.5
.3
.6
.2
- (THbusan
71
71
70
70
72
77
78
81
86
89
94
do}

.4
.0
.9
.8
.9
.0
.1
.9
.0
.9
.7


345.9
343.0
339.8
339.5
341.5
345.4
349.1
357.4
365.3
372.5
384.9
               I/
               "Includes Alaska and Hawaii.
    Source:   Edison Electric Institute, Statistical Year
             Book of the Electric Utility'Industry , 1970.
                          11-18

-------
                               TABLE -9-
           TOTAL  ELECTRICITY CONSUMPTION IN UNITED STATES
                                1960-1990
YEAR

1960

1970

1980

1990
   KWH
GENERATED (Million)
   684, OOO!/

 l,396,000l/
 5,557,000.?7
PERCENT CHANGE
DURING PERIOD
    104%

    110%

     90%
ANNUAL GROWTH
    RATE -'
                                                                7%
I/ Edison Electric  Institute,  Statistical Yearbook of the
   Electric Utility Industry for 1971, Oct, 1972.
2/ Federal Power, National Fewer Sur.ey Tech;n,j.ca,l Advisory
   Commitee for Itnance.  1973
W Percentages are  rounded off.
                              11-19

-------
II.  FINANCIAL PROFILE

    A.  Profitability—/

        1.  Total  Assets

             The electric  utility industry is the most
capital intensive  industry in the United States.  As shown
in Table-10, the total assets  of  the investor-owned electric
utilities were approximately  100 billion dollars in 1971.
Since, the investor-owned  utilities account for about 77%
of total generating  capacity, the total assets of the entire
electric utility industry  were approximately 125 billion
dollars in 1971.

        2.  Total  Sales

             As shown in Table-11-, total sales of electricity
in 1971 were about 25 billion dollar.    The investor-owned
utilities accounted  for approximately  85% of total sales.

             In the  period 1960-1971,  total sales increased
by 115% which was  equivalent  to an annual growth rate of about
7.3%.
        3.  Net Income

             As shown in Table-12 , the net income after
taxes  in 1971 for  the investor owned utilities was about
3.8 billion dollars.  Inclusion of the public owned utilities
should not significantly change this figure, since net income
for the public sector   (e.g., after allowance for depreciation
and other fixed charges) should theoretically be zero. "LJ

             In the  period 1964-1971,  net income in the
private sector, increased  by   74% which was equivalent to
an annual rate of  about    8%.

    B.  Capital Formation

        1.  Historical  Trends in Total Investment

             As shown  in Table-13-,  total investment by
the electric utility industry was 14.8 billion  dollars
in 1971.  During  the period 1961-71, the total  cumulative
investment was  88 billion dollars.  In the same period
total  annual investment  grew by 200 % which was  equivalent
to an  annual rate  of approximately 11%.
If While this section includes financial data on the entire Electric
   Utility Industry,  it should be emphasized  that about 9% of the
   industry is involved in the distribution  and sale  of natural gas.
2_/ This  assumes  that  a public utility will  charge rates that
   will  just  cover operating expenses plus  allowance for
   depreciation  and other  fixed charges.


                         11 '20

-------
           2.   Projected Investment for 1973-1990

                Recent  projections—  indicate that  in  the  period
  1973-1990  the electric utility industry will have to  raise
  968 billion  dollars  just to finance the expansion of  generating
  transmission and  distribution facilities.  In this  period  total
  annual investment will grow by 13% per year.  In later sections of
  this report, estimates will  be made of the additional  capital requirements
  associated with the  water effluent guidelines,


           3.   Sources  of Financing

                The  utilities finance capital expenditures
  through  internal  and  external sources.  Internal financing is
  generated  by retained earnings,  depreciation  (both  on fixed
  assets and nuclear fuel),  and tax deferrals.  The sources  of
  external financing are long-term debt, preferred stocK  and
  common stock.
               The  financial  model—'  used to estimate the
  required investment  for  generation, transmission and destribu-
  tion calculated that  the utilities  would finance  37%  of  the
  1973-90  financial needs through internal financing and
  the remainder  through external financing.  Looking specifically
  at the investor-owned utilities, the required investment  will
  be financed in the following  manner:

                                                Financial
               Type of  Financing               Requirements
                                                  1973-90
                                                (Billion $)

           1. Internal  Financing
              retained earnings                        62
              non-cash charges                       235
              (depreciation  and  deferrals)             	
              Total  Internal Financing                297

           2- External  Financing
              long-term debt                       324
              pEEferred s^tock                      56
              common stock                        132
              Total External  Financing            5~i2"

           3. Total Financing                      809
I/  See Part III,  P.  111-20 for detailed estimates of  the  baseline
   projections.
2.7  See Part III,  P.  III-158-for a description of the  model's
   financial module.
                           11-21

-------
                                    TABLE-10-
COMBINED BALANCE SHEETS—YEAR ENDED DEC. 31—INVESTOR-OWNED ELECTRIC UTILITIES!/
INTERCOMPANY TRANSACTIONS ELIMINATED
MILLIONS OF DOLLARS
1071 1070 1000 1068
ASSKTS
I'tilitv Plant
Klcctnc
Accumulated Provision lor Depreciation
and Amortization
Net Electric Utility Plant
Nuclear Fuel*
Accumulated Provision for Amortization
of Nuclear Fuel Assemblies
Net Nuclear Fuel
Net Total Electric Utility Plant
Other .
Accumulated Provision for Depreciation
and Amortization
Net Other Utility Plant .
Total I'tilitv Plant Kvluding Nuclear Fuel
Accumulated Provision for Depreciation
and Amortization Kxcluding Nuclear Fuel
Net Total Utility Plant Excluding
Nuclear Fuel
Total I'tilitv Plant Including Nuclear Fuel
Accumulated Provision for Depreciation
and Amortization Including Nuclear Fuel
Net Total Utility Plant Including
Nuclear Fuel
Other Proper! v and Investment
Total Current and \ccried Assets
Total Deferred Debits
Total Assets
LIAWLITIKS
Capitalization:
Common Capital Stock
Other Paid-in Capital Kxcluding
Karned Surplus** .
Karned Surplus (Retained Income)
Total Common Capital Stock Equity
Preferred Stock
Long-Term Debt :
Mortgage lionds
Other Long-Term Debt
Total Long-Term Debt
Total Capitalization
Total Current and Accrued Liabilities
Total Deferred Credits and Operating
Reserves . .
Contribution in Aid of Construction
Deferred Income Taxes
Other Deferred Items . ...
Total Liabilities


SUM

22
$82



$
$83
0

-
$ 6




11 1

21

$90
1
5

$98


$13

5
II
$20
0

1 1
3
is 17
$86
7

1

•2

$98


033

101
820
842

67
775
604
118

1 10
069




803

320

573
037
821
611
045


135

300
010
817
157

001
1 18
122
096
805

006
55 1
101
33
045


MI3

20
$73



$
$73
8

1
$ 6
•



102

22

$80

5

$87


$11

1
10
$26
7

30
'2
$12
$76
7



•j

$87


824

373
451
174

25
449
900
023

081
639
-



921

382

530
902
25 1
528
220


9S5

382
186
553
40(i

331
833
1 64
183
425

804
487
200
22
220


$81 307

IS 781
$65 613





8 060

1 832
$ 6 237
02 106

20 010
$71 850
-

--


950
4 013
381
$77 794


$1 1 039

3 037
9 278
$23 954
0 300

31 317
2 780
$37 127
$67 441
7 012

832
134
2 051
24
$77 794


$70 702

17 309
$59 393



-

' 7 700

1 715
$ 5 091
84 468

19 084
$65 384
—

—

- —
009
4 293
390
$70 976


$10 830

3 217
8411
$22 464
5 970

31 100
2 485
$33 585
$62 019
5 770

772
392
1 992
25
$70 076
1007


$70 305

16 126
$54 239
—




7 212

1 505
$ 5 647
77 007

17 721
$59 886
—

—

- —
750
4 000
350
$65 085


$10 700

2 844
7 571
$21 181
5 515

28 302
2 147
$30 440
$57 145
4 081

007
358
1 878
50
$65 085
1000


$04

14
$49





0

1
$ 5
71

10
$55
-





4

$60


$10

•2
6
$20
5

25
1
$27
$52
4



1

$60


717

001
843


-
--
-
917

472
445
004

370
288
-



--
027
OK)
334
259
*

502

707
921
130
045

870
943
813
988
482

579
329
822
59
259
1905


$00 385

13 691
$46 691
—

—

-
0 478

1 430
$ 5 048
00 803

15 124
$51 739
--

—

—
010
3 038
320
$56 313


$10,196

2 815
' 6 208
$19 219
4 089

23 752 '
T90I
$25 653
$49 561
4 115

507
200
I 770
04
$56 313
1 004


$50 001

12 777
$44 184
—

—
-

6 070

1 108
$ 4 911
03 040

13 045
$49 095
—

—

—
571
3- 643
318
$53 627


$ 0 904

. 2 721
5 504
$18 249
4 549

22 872
I 050
$24 522
$47 320
3 795

405
204
1 714
09
$53 627
* Prior to 1070 included in "Other Property and Investment "
** Includes Premium on Common and Preferred
I/ Edison Electric Institute,
Stock.


Statistical




Yearbook of the Electric


Utility


Industry
   for  1971, Oct. 1972.
                                    11-22

-------
                                               TABLE ~11<-

                           REVENUES—TOTAL ELECTRIC UTILITY  INDUSTRY*

                                   BY YEARS  AND CLASSES OF SERVICE
                                            THOUSANDS OF DOLLARS
Year

Total
Revenue
from
Salosf
From Kx-
]>orts to
Canada
and
Mexico

Total
from
Ultimate
Customers
                                   Resi-
                                  dential
Commercial and Industrial   Street     Other
  Small        Large      and      Public
 flight and    Light and    Highway   Author-
  Power**      Power**    Lighting     ititw
Railroads   Inter-
  and    depart-
Railways  mental
1971
$24 734 300p  $ 9 141p $24 725 159  $10 483 526  $7 071 971   $6 133 964   $411 534   $512 772  $77 862   $33 530
1(170.
1909
1908
19(57
1906. .
1005
1904 .
1903 .
1902 . .
1901 .
1900 . .
1959.
22 070
•20 1 1-1
. . 18 585
. 17 220
. . 10 1!)'.)
15 102
. 1 t .li:{
. 13 70S
..IK 033
. 12 177
11 523
. . 10 580
885 r
225
308
235
140
538
138
178
1189
388
571
277
11 ()23r
•1 870
5 -18!)
3 515
3 00-4
•1 159
-1 080
10 972
9 015
8 085
7 915
7 025
22 005
20 139
18 579
17 222
10 190
15 158
11 -108
13 097
13 02-1
12 109
11 515
10 572
802
319
879
720
130
379
•158
200
944
303
050
052
9 -115
8 532
7 802
7 183
0 733
0 328
0 010
5 722
5 457
5 115
4 855
4 514
707
729
033
908
714
750
081
544
01-1
799
799
707
0 290 225
5 701 7(i-l
5 315 100
4 935 9 1 1
4 049 084
4 312 859
4 028 198
3 788 310
3 420 013
3 108 055
2 828 180
2 598 452
5
5
4
4
1
3
3
3
3
3
3
3
129 S52
Oil 857
072 211
301 759
134 538
884 7-18
733 309
590 121
591 097
309 749
333 890
009 680
377 791
350 503
327 190
307 272
281 584
202 509
218 225
230 4-18
223 445
205 411
194 043
180 094
453 10-1
117 571
379 435
319 323
321 001
290 892
278 319
275 030
255 8,15
232 319
232 868
209 380
09 109
02 981
01 440
(iO 009
59 132
00 903
61 702
01 749
63 255
02 872
62 640
52 912
30 014
25 884
22 464
20 938
17 083
17 652
17 964
16 998
13 705
15 098
7 624
6 821
  t Kxcludes other electric revenues.
  * Alaska :ind ll:i\v:ni included since 1900.
  ** Small Light and Power and Large Light and Power are not wholly comparaltle on a year-to-year basis due to changes from one classification
to another.
  p Preliminary.    r Revised.
       Edison  Electric  Institute,  Statical  Yearbook  of  the  Electric
       Utility Industry  for  1971,  Oct.  1972.
                                                 11-23

-------
                                    TABLE -12-
COMBINED INCOME STATEMENTS—YEAR ENDED DEC. 31—INVESTOR-OWNED ELECTRIC UTILITIES^
INTERCOMPANY TRANSACTIONS ELIMINATED
MILLIONS OF DOLLARS
1971 1970 1909 I90S
ELECTRIC
Operating Revenues $21 230
( )pcriltlllg KxpellSCV
( Iperation . * S
Maintenance 1
Depreciation and Depletion '-'
Amort i/at ion Charged to ( >peration.
1'ropi'rtv Lo«-cs Chained to Operation
Taxes Othei 'I'liaii Income Taxes '_'
Federal Income Taxes
State Income Taxes
Provision for Deferred or Futuie Income Taxes:
Due to l,ilierali/.e 1 S
III)
:i
• »
382
(.)17
S7
•227
( I7i
'.)(>
256
971
ALL
053
ID!)
088
03 1
5
1
099
015
t)(i
•2-1 (i
1 18)
05
630
423
122
S22
367
117
15:!
'>
IS
C.50
717
57
774
193
2S1
I'.M
000
DEPARTMENT ONLY
$18 830 $17 164 $15
s 7
1
•)
•)
1
$14
S> '1
322
373
mi;
;\
I
130
li:i
si
l i-l
(•Hi)
27
347
•1815
S (i 208
1 1SI
2 005
2
• )
1 901
1 1 19
8(i
1 10
(58)
til
$13 046
$4 118
DEPARTMENTS
$22 276 $20 324
S 0
1
2
2
1
$17
S 1
$ 5
S 2
* 2
$ 3
$ 3
$ 2
2
$
* Includes investment tax credits reported as charges to income I'oi
** Prior to 19*70 shown as a credit to interest charges.
( ) Denotes negative figure
I/ Edison Electric Institute, Statistical
552
520
404
7
3
121
23 I
91
158
(•17)
25
374
902
107
594
603
010
198
(i'2
270
333
333
301
972
022
050
S 8 283
1 322
2 201
5
4
•2 1(17
1 580
9(1
155
(lit))
1)8
$15 827
S -1 497
51
•105
$ 4 053
S 1 021
127
(2)
77
S 1 8215
$ 3 130
$ 3 130
1(07
* 2 82;;
1 880
$ 043
!$ ."i
1
1
1
1
$12
$ 3
$18
$ 7
1
2
1
1
$14
$ 4
$ 4
S 1
* 1
$ 2
$ 2
$ 2
1
$
810
(> 18
Olil
851
1
•J
737
5'2 1 500 S 4
870
1 525 1
1
1
1 315 1
1 31 17 1
01
85
( 10)
54
$ 9 781 $ 9
.S 3 100 * 2
$15 404 $14
S 0 075 S 5
988
1 079 1
(
1511 1
1 501 1
07
91
(41)
02
$11 978 $11
$ 3 42(5 $ 3
28
94
$ 3 548 $ 3
S 953 S
19
20
S 992 8
$ 2 556 $ 2
$ 2 556 $ 2
210
S 2 310 $ '_>
1 520 1
$ 814 $
Industry
211
204
825
431
1
I
272
305
58
87
(28)
49
328
883
624
779
935
577
8
157
498
02
97
(29)
57
446
178
39
80
303
905
10
1
19
911
362
362
209
153
42'2
731
   for 1971, Oct.  1972

-------
                            TABLE -13-

           	-  TOTAL  ELECTRIC  UTILITY INDUSTRY
                         (Million  of  Dollars)

                             II                          2_l
                     Industry               Investment  By
   Year           Total  Investment    Investor Owned Utilities

   1971             14,796 Ll                   11,894
   1970             12,575 LI                   10,145
   1969             10,581 LI                    8,294
   1968              9,140 LI                    7,140
   1967              7,820 LI                    6,119
   1966              6,345 1'                    4,932
   1965              5,254 U                    4,027
   1964              4,801 1'                    3,551
   1963              4,357 l!                    3,319
   1962              4,271 I.'                    3,154
   1961              4,608 1.1                    3,256
^/Electrical world, March  15,  1973,  p.  38.

2^/Federal Power Commission,  1970  National  Power Survey.

2/Edison Electric  Institute,  Statistical Yearbook for 1971,
  Oct. 1972.
                               11-25

-------
  III.  PRICING

     A.   Price  Determination

          The  price  that  the utilities can charge is regulated
  by  local,  state, and  federal  regulatory agencies.  While regula-
  tory  policies  vary considerably,  most regulatory agencies
  allow the  utilities to  set a  price that will insure them an
  adequate return  on common  equity.  For the purposes of this
  analysis,  it was    assumed  that  the utility industry will be
  able  to  set  a  price that will enable it to earn a 12% return
  on  total common  equity.   Since 'pollution control expenditures will
  increase the amount of  revenues that utilities must generate
  in  order to  maintain  a  given  rate of return,  the price
  increase for any given  year  can be expressed as a  simple
  equation:

    n .           f     • \   -.  Increase in total revenues (year i)—'
    Price increase (year i)   -  Total  production of electricity (kwh in year i)
      B.   Historical  and  Trends in Prices

          As  shown in Table~14-,   the average price of electricity
  (e.g.,  average  revenue  per kilowatt-hour sold) declined from
  17.8 mills/kwh  in 1951  to 15.4 mills/kwh in 1969.  Between 1969
  and  1971 the  price  of electricity increased to 16.9 mills/kwh -
  an  increase of  about 10%.

          It  is important to analyze the price of electricity
  relative to the prices  of other goods and services.  As shown
  in  Table^l5-r, the consumer price index has risen more rapidly
  than the electricity price index.  Therefore, from the con-
  sumer's viewpoint,  electricity has become cheaper relative
  to  other commodities.

      C.   Future  Trends in the Price of Electricity

          The results of  this analysis.2-/ indicate that even without
 expenditures for pollution control equipment the average cost of
 electricity  will increase from 16.9 mills/kwh in 1971 to 27.6
 mill/kwh in  1980 and 43.2 mills/kwh in 1990.  The above
I/ See Part III, p. III-162 for an explanation  of  the  methodology
   used to calculate the required increase  in total  revenues.
21 See Part III, p. 111-20 for an explanation of  the baseline
   projections.
                            11-26

-------
figures are equivalent to a 5% annual growth rate between
1970-80 and a 4.5% annual growth rate between 1980 and 1990
In view of recent trends in the consumer price index, the
price of electricity relative to other goods and services
should either remain constant or decline slightly.
                          11-27

-------
                                     TABLE -14-
  AVERAGE REVENUES PER KILOWATT-HOUR SOLD—TOTAL ELECTRIC UTILITY  INDUSTRYI/



Year
1971
(170
909
908
1)07 .
1)00 .
905 .
904
90H .
902 . . .
!)01 . .
1900 	
195!) 	
] !_ . )
:i is
:> 12
:} 05
2 09
2 99
1! 05
:; 01
':! 01
:i 18
:i 08
:i 08
3 05
li 05
U.05
:! 07
;{ 07
:i oo
:! 08
20
1C,
18
.19
21
;ii
:>5
:«;
:<9
41
49
47
49
47
.42
42
.42
;{9
U!)
19
:;9
.:!5
:i:i
.;ii
:ti
:u
:!2
HI
:(i
,'ii
.28
25
.22
.17
.15
.1 1
08
()l
.US 0 99
5!)
51
.55
5(i
51 i
.59
02
05
.OK
.09
09
!<)!)
71
07
04
.07
.77
.77
79
^78
I/ Edison Electric  Institute, Statistical Yearbook of  the Electric Utility
   Inddstry for  1971, Oct. 72.

2J All prices are in current dollars.
                                   11-28

-------
                                                    TABLE -15V

                             CONSUMER  PRICE  INDEX— /ALL-CITY AVERAGE*

                                                    1951-1971
                                              INDEX  NUMBERS: 1967=100

Date
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
December,
*Alaska am
Source: U.


1071
070
000 . . .
008
007
000
005
00 1
003
902
1901 . .
900 	
()5()
058
057 	
950 	
055 .
054 	
953 .
952 .
951 . .
Hawaii included since 1003.
S. Bureau of Labor Statistics.
All
Items
123 1
111) 1
112 0
MX) 1
101 0
98 0
1)5 4
(13 0
1)2 5
1)1 0
80 9
89 3
88 0
80 7
85 2
82 7
80.4
80.1
80.5
80 0
79 3



Klectricity
116 0
100 0
101 2
101 0
100 5
00 2
00 1
00 3
100 0
100 3
100 1
100 0
00 0
07 0
90 3
95 5
95 4
04 7
1)3 1
03 . 0
01 7


Gas and
Klectricity
118 2
110 7
101.8
101 4
100 2
09 4
99 5
90 8
00 0
00 0
90 4
1)0 3
07.0
03 5
90 3
88 0
88 1
80 3
84 7
o'> r
81.8


Total
Housing
126 8
122 0
111 2
107 0
101 5
98 0
95 7
94 3
93 5
92 0
91.3
90 8
89 5
87 0
87 1
84,8
82 0
82.2
81.0
79.0
78.1



Food
120.3
115 3
112 8
105 2
100 9
99 7
1)0 0
02 8
01 5
80 8
88.5
80 3
80.0
87.3
85.4
83 1
80 0
81 3
82 0
83 7
84 0



Apparel
121 8
111) 2
II 1.7
109 0
102.5
08.5
01 8
03 5
03 1
01 1
00 8
00.5
89 4
88.0
88.1
87.5
85.7
85.4
80 1
80 0
88 4


                                                    TABLE -16-

  RESIDENTIAL ELECTRICITY  AND  CONSUMER PRICE  INDEX-^TOTAL  ELECTRIC UTILITY  INDUSTRY*
Average
Ueveiiue
per
Residential
Kwhr Used
2 \$t
•2 10
2 1)0
2 12
2 17
2 20
2 25
2.; ;n
2 ,'{7
2 41
2 45
2 47
2.51
2 54
2 50
2 01
2 65
2 70
2 74
2 77
2 81


100 Kwhr
Average
Average
Price per
250 Kwhr
Hate per Kwhr H;
of Typical Bills in
Kwhr for iVIonthh
500 Kwhr
ised on
Cities**
Use of:
750 Kwlii-
	
	

U.S. Bureau of Labor Statistics
Index Numbers Based on

KOOO Kwhr
I'.H
Klectricity
(Federal Power Commission)

4 25 «<
4 00
4 05
4 03
4 03
4 00
4.02
4 03
4 00
4 00
4 05
4 04
3 08
3 015
3 80
•A 88
:i 80
•A 82
:i 81
'A 70

i 14?
!.0()
2 . 90
2 95
2 05
2 04
2.05
2 07
2 00
2 90
2 08
2 08
2 04
2 02
2 89
2.88
2 87
2 84
2 83
2 70

2.23ff
2 10
2 00
2.07
2 07
2 07
2 . 08
2.12
2 13
2 13
2.13
•2 12
2 10
2 . 00
2 08
2 07
2 00
2 05
2 04
2.02

2.00f>
1 00
1 80
1 80
1 89
1 89
1.01
1 03
1 95












1 92 f!
1 83
1 SO
1 83
1 83
1 .83
1 .80
1 89












113 2
100 '2
IO-2 8
100 9
100 0
99 1
09 1
09.0
100 1
100 1
100 1
00 8
08 5
07 1
95 0
95 5
95 2
94 0
93 0
92 4
91 5
>7 = 100f
Consumer Price
IndexJ
121 3
110 3
109 8
104.2
100.0
97 2
94 . 5
92.9
01 7
00 0
89 G
88 7
87 3
80 0
84 3
81 4
80.2
80 5
80.1
79 5
77 8
    Year

1971

1070
1900.
1908
1907
1000

1905
11164
1963
1902
1001

1000
1059
1058
1957
1956

1055
1954
1953
1052
1951

  * Alaska and Hawaii included since 1000.
  ** As determined by the Federal Power Commission in its "Typical Klectnc Bills." The ligures cover rale schedules as of December 31 in all
cities with populations of '2,500 or more.
  t "Index numbers" are percentages of the base year 1007. For a description of the components and characteristics of this Index, see the
February, 1953, Mnitllili/ Lnlmr Hevinn of the Bureau of Labor Statistics.
  } The ••Consumer Price Index" measures the average change in prices of goods and services purchased by urban wage-earner and clerical-
worker families. Fleetncity is one of these components. The Index does not  relied the over-all effect of the increased use of electricity by Hesi-
dential customers -for which see "Average Revenue per Residential  Kwhr Used," column 2 of this table; also see Tables 41 K, 45 S and 00 S
ol this publication.
     I/ Edison Electric  Institute,  Statistical Yearbook  of  the Electric  Utility

         Industry  for  1971. Oct.  1972.            2g

-------
IV.   POLLUTION CONTROL REQUIREMENTS AND  COSTS

     A-   Effluent Limitation Guidelines  for  1977  and  1983

         The economic analysis presented in  this  report  is
 based on a preliminary draft of the water effluent limitation
 guidelines which are summarized in Tables -17 and 18
 As  shown in these tables, the two major guidelines are  for  the
 control of chemical and thermal discharges. A third  guideline
 applies to the construction and design  of intake  structures.  I./
 However,  the cost of complying with the guidelines for  intake
 structures has been excluded from the economic impact analysis
 for  several reasons.  First, the installation of  closed cycle
 cooling systems would probably fulfill  all  of the requirements
 of  the  intake structure guidelines.  Second, even if a  power
 plant  would have to modify its existing intake  structures,
 it  would be difficult to estimate the associated  costs  because
 the  guidelines will be applied on a case-to-case  basis.  Third,
 the  projected impact of the intake structure guidelines was  a
 very small percentage of the total cost of  the thermal  and
 chemical guidelines.

     B.   Current Level of Control

         As shown below, about 74% of the generating  capacity
 in  1970 used once-through cooling systems,  while  13% had
 cooling towers and 13% had either cooling ponds  or combination
 systems.

                                                             2 /
         Types of Cooling System          %  of 1970 Capacity—7

         Once-Through (Fresh Water)                51.0%
         Once-Through (Saline)                     23.2
         Cooling Pond                              6.8
         Wet Cooling Tower                         13.0
         Combination                               6.0

         However, as shown in Table - 19, a  much  larger  percent-
 age  of  the post-1974 capacity is planning to install either
 cooling towers or combinations systems.  Specifically,  42%
 of  the  fossil plants and 33% of the nuclear plants are  already
 planning to install cooling towers.


 JL_/  EPA  proposed regulations for cooling water intake
    structures were published in the Federal Register on
    December 13, 1973 (p. 34410)
 I/  Estimates were derived from an analysts ty  Edward Pechan of EPA*s
    Office of Planning and Evaluation of data from the Federal  Power
   Commission's Form 67.

                          11-30

-------
    C.   Expected Coverage of the Guidelines

        The guidelines that were summarized  in  section-A
require that a large percentage of both the  existing  and
planned generating capacity will have to install pollution
control equipment.  For example, 83% of existine capacity
and 92% of planned capacity will be covered  by  the  chemical
guidelines.  The coverage is also extensive  for  the thermal
guidelines.  Specifically, for the non nuclear  capacity, a
maximum of 51% of the pre-1970 capacity, 52%  of  the 1971-73
capacity, 52% of the 1974-77 capacity, and 73%  of the.1978-83
capacity will have to install cooling towers  by  1983,—'  The
equivalent percentages for the nuclear capacity  are 80%, 67%,
67%, and 100%.  More detailed estimates of the maximum  coverage
of the thermal guidelines are given in Tables 20 and  21.

        It should be emphasized that the actual  impact  of  the
thermal guidelines will be considerably less  due to the follow-
ing factors:

        1.  exemptions under Section 316(a)_'

        2.  exemptions due to lack of land and/or adverse
            environmental impact from salt water drift.

        3.  some power plants will be able to comply  with
            the guidelines by installing less expensive
            closed cycle cooling systems (e.g.,  cooling
            ponds and spray canals)
!_/ These estimates are maximum values  because  they  do  not
   reflect exemptions under  Section  316(a)  of  the Federal
   Water Pollution Control Act of  1972  or  the  exemptions
   due to the lack of land and/or  adverse  non-water quality
   environmental impacts.
2y Section 316(a) of the Federal Water  Pollution Control Act
   of 1972 specifies that whenever the  owner or operator of
   any source subject to the  thermal discharge guidelines  can
   demonstrate that the effluent limitation proposed for the
   control of the thermal discharge  for  that source is more
   stringent than necessary  to assure  the  protection and
   propagation of a balanced, indigenous population of shellfish,
   fish, and wildlife in and  on  the  body of water,  the
   Administrator (or, if appropriate,  the  state) may impose an
   alternative effluent limitation for  thermal discharge,  that
   will assure the protection and  propagation  of a  balanced
   indigenous population of  shellfish,  fish and wildlife.
                          11-31

-------
At the present  time,  however,  adequate data is only available
to estimate  the  impact  of  exemptions under Section 316(a). Thus,
the estimates of the projected  coverage of the thermal guidelines
after exemptions  (e.g., Table 21)   over estimate the actual
impact of  the thermal guidelines.

    D.  Water Pollution Abatement  Costs

        The  impact  analysis  in this report is based on cost
estimates  contained  in  a document  prepared for EPA by Burns
and Roe, Inc.—'   The  most  important cost parameters are
summarized in Tables  22 and  23.   As indicated in Table 24,
the installation  of  cooling  towers will increase the average
production costs  of  existing baseload units by 11 to 22%
and the production  costs of  new baseload units by 10%.
However, the incremental cost  of the guidelines will be con-
siderably  less  since  as shown  in Table 25 the utilities, in the
absence of federal  legislation would have incurred substantial
costs in order  to  install  the  most economical cooling system
(e.g., once  through cooling  in most cases and cooling towers in some
cases).  The incremental cost  of the thermal guidelines (see
Table 26), therefore, is the difference between the total cost
of cooling towers  (e.g.,  Table  22)and the cost that the utilities would have
incurred for basic cooling facilities  (e.g., Table 25).

    F.  Comments  on Cost Data

        In view of  the  uncertainty concerning many of the cost
parameters,  especially  the cost of installing cooling towers
on existing  plants,  a range  of cost estimates was included in
the economic impact analysis.   As will be documented later in
this  report,  allowance  for variation in the principal cost
parameters has  a  significant impact on the total cost of
meeting the  1977  and  1983  standards.
_!/  EPA,  Development Document for Proposed Effluent Limitation
    Guidelines and New Source Performance Standards for  the  Steam
    Electric  Power Generating Point Source Category, March, 1973.
                          11-32

-------
                                                TABLE-17-
                 DRAFT  SUMMARY  OF PROPOSED  EFFLUENT GUIDELINES  FOR  THERMAL DISCHARGE:
EPA RECOMMENDATION


ND
NL
= No discharge of heat except that blowdown
may be
» No technology-based limit (e.g., no restrictions
CATEGORY TYPE OF UNIT





M
M
Ui
OJ


I.




II.
III.
IV.
V.
Large Baseloadi/
A. Existing units larger than 500 mw
B. Existing units 300-500 mw
C. Existing units smaller than 300 mw
D. All units on line after July, 1977
Small baseloadr/
Cyclic!/
Peaking*/
Exceptions !/
1977

—
-
-
ND
NL
NL
NL

discharged from cold side (e.g., closed cycle coolir
on type of cooling system)
1978 1979 3,930 1983 NEW SOURCES

ND ,r ND
W r- r* ND
- ND ND ND
ND
ND ND
ND ND
ND ND

I/ The term large baseload unit will include all units with average boiler capacity  factors greater than
   .60 that won't retire before July,  1983,all nuclear units, and all units for which construction begins
   after Oct,  1973.
2/ The term small baseload unit shall  mean a unit which is a part with a rated
   capacity of les» than 25 megawatts  or  part of a system of less than 150 megawatts.
3/ Units with capacity factors between .2 and  .6 that won't retire before July 1983.
4/ Units with capacity factors less than  .2.
5/ Exemptions are the same as in Table 17.

-------
                                      TABLE- 18

          DRAFT  SUMMARY OF PROPOSED EFFLUENT  GUIDELINES FOR CHEMICAL DISCHARGES
Numbers listed are average
ND


I.

II.






III.




IV.


V.
VI.
= No discharge NL
CATEGORY
Waste Water Source
High-Volume

Intermediate-Volume






Low-Volume




Rainfall Runoff


Sanitary Wastes
Radwastes
concentrations of pollutants,
= No technology-based limit
POLLUTANT

Free chlorine residual
Copper
Free chlorine residual
Total residual chlorine
Copper
Chemical additives
Oil and grease
PH
Phosphates (as P)
Total suspended solids
Copper
Iron
Oil and grease
PH
Total suspended solids
Oil and grease
PH
Total suspended solids
Biochemical oxygen demand

except for
MS = Munic
1977

0.2
NL
0.2
NL
NL
NL
10
6-9
ill/
1
1
10
6-9
15
10
6-9
15
MS
NL
pH
ipal standards


1983 NEW SOURCES

0.2
NL
0.2
NL
NL
NL
10
6-9
ill/
ND
ND
NB
-
ND
10
6-9
15
MS
NL

0.2
ND
_
approx. ND
ND
approx. ND
10
6-9
ill/
1
1
10
6-9
15
10
6-9
15
MS
NL
I/ Note: For ash sluicing add "or not to exceed influent pounds/day,  whichever is greater"
2_l Note: No discharge for wastewater pollutants from nonrecirculating bottom ash handling
        'systems or from fly ash handling systems.

-------
                                     TABLE-19-

        TYPE OF COOLING SYSTEMS FOR STEAM-ELECTRIC PLANTS 300 Mw AND LARGER,  BEING
        CONSTRUCTED OR COMING UNDER CONSTRUCTION BY APRIL 1, 1974, BY EPA REGION,
                                   BY COOLING METHOD
Region 1 •
A. r-ysM -fired
Cco!:-^ Tov.ir2.-HS*
<• v[ ('.nils
?:•! ;'l . Oil ipq-JS«
* of Units
•Vs <••?-: '•roi":h"-K»
•'; oi : Hi ts
To» ?1 - ».
« cf r.-iits
% distrib.-J&f
V B. !-'uc!"ar Plants:
01 C^n — Tov.«r5-K«
~ cf ('nits
S';n"'l . I'rol ir:T-«!vi
•" i'! I'ni ts
JTrre-t >;ro'' jh^-Ms*
B of ! nits

T,.,tr!l - V»
' <•: L:sits
£  . •••<
r of U.-^its
% Jiitrib. -:•.;-


400
1
-
-
3,522
7
3,922
0
4%

513
1
-
.
3,492
4

4,0"; 3
5
4%

913
2
-
-
7,014
11
7 <5?7
13
-> 4%

Real on 21


-
316
1
5,647
10
5,9'.3
U
5%

2,200
2
-
-
8,684
9

10. r 4
11
12%

2,200 •
2
316
1
14,331
19
16 fM7
VHLAtft . »'*VM
22
c;j

Rcnion 3 Region 4 Region 5

13.545
17
2,323
3
2,160
5
is.cro
25
17J{

9.406
10
2, ICO
2
7,132
8

18,713
20
212

23,031
27
4,455 .
5
9,292
13
36.778

li/i


10,576
lo
1,650
2
12.421
19
24.647
37
232

7,031
8
3.195
4
12,715
14

23.741
26
26^

18,407
24
4,045
6
25,136
33.
P. ^ ^ f (A
60
2'!^


9.60C
14
-
-
9.4CI-
I'l
.19.0CI,
2i>
I'M

5,^i
''
2.71U
U
11,131
1?

19,271
T.I
21.;

15,0:2:
21
2.71E:
J;
20,53V
2'i
*V^ *: i r •

lc^

Rcr,on 6

3,295
7
840
2
15,667
23
19.C02
b7
is;;

950
1
-
_
1,995
2
£ — .
, 2.915
3
T'
o/,

4,245
8
C-'iO
2
•17,662
30
22.7-17
••SKC „. ( . —K*
11?S

gct7 1 onr J[*«JJc™
42


3.330
8
_
.
878
2-
4,208
10
4%

330
1
-
_
-
-

330
1
IK

3,660
9
-
-
878
2
•1,530
mr" ^iV"*
2^


4,830
7
735
1
1,408
3
6^973
11
*>%

913
1
-
.
6,660
6

7,573
. 7
• G^

5.743
8
735
1
8.068
9
14.516
•"•"'— it)'™
7Ji

Grand
R!*gI^T TO .Jo'al

700 45,753
1 70
6.901
n
56.334
97-
700 109.076
i na
1% 100%

2,230 30,420
2 34
8.510
10
52,587
C6

2*>*>f\ « OI ^^T
T *.v>vl 7 I T \J«JiJ
2 * ICO
2* ICCtf

2.930 76.1C6
3 10-1
15.502
21
1C3.92)
] 11
•2,9-1 ?r"),(09
1C t/ j
2^\ 10C^

Percent
„ Distributfai

dh«;
23%

3*

20%

54%



15%

5%

26%


46%



30%

0%
,
54%
i
100%
r— -Js
f
1 '
1
JJ
42%

6%

52%

10*
.


333S

9%

50%


100%'
K0=t=


38%

8%.

54%

100%
«—*».


SOURCE:
5/72 FPC Printout of Utility Responses to FPC  Order  303-2

-------
u>
                                                 TABLE-20-
                 EXPECTED COVERAGE OF THERMAL EFFLUENT GUIDELINES; EPA RECOMMENDATON  (BEFORE EXEMPTIONS)
% Coverage by Required Compliance Date*


Capacity Placed in Service
Non-Nuclear
Prior to 1971
1971-1973
1974-1977
1978-1990
Nuclear
Prior to 1971
1971-1973
1974-1977
1978-1990


1977 1978 1979 1980 1983

25% 10% 5% 11,%
37 4 11
- 37 12 3
— — — — —

80%
67
67


Year of Initial
Operation

-
-
37
73%

-
_
33
100
Total
Cummulative
Coverage



89
73%

80%
67
100
100
    * Numbers represent

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                                             TABLE-21-

            EXEPECTED COVERAGE  OF  THERMAL  EFFLUENT  GUIDELINES:  EPA RECOMMENDATION (AFTER EXEMPTIONS)
                                            % Coverage by Required Compliance Date**
 Capacity Placed in Service

 Non-Nuclear
   Prior to 1970
   1971-1973
   1974-1977
   1978-1990
1977
1978
           5%
           7,1
           7,1
1979
           2%
           1,8
           2,3
1980
           1%
           2
          .6
1983
           22%
Year of Initial
   Operation
                        37%
                        38%
Total
Cummulative
Coverage
                                 10,2%
                                 10,0%
                                 40.0%
                                 38
 Nuclear
   Prior to 1970
   1971-1973
   1974-1977
   1978-1990
          16
          13
          13
                                          33
                                          44
                                                   16
                                                   13
                                                   46
                                                   44
 * After exemptions for Section 316(a)  of the Federal Water Pollution Control Act of 1972
** Numbers represent the incremental coverage in the indicated years.

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                               TABLE -22
        ESTIMATES OF CAPITAL  AND  OPERATING COSTS PER UNIT OF
          GENERATING CAPACITY - THERMAL EFFLUENT STANDARDS.*'


                                       Non-Nuclear Capacity   Nuclear Capacity
        Capital Costs                         C$/Kilowatt)         ($/Kilowatt)

1.  Cooling towers on new  plants—     .   $ 7.50                $10
2.  Cooling towers on existing plants—'     15                    18
3.  Replacement capacity
       - 1977 (peakers)                     90                    90
       - 1983 (baseload units)            170                   260


Annual Operating Expenses —'

1.  Replacement power
       - 1977                               42                    42
       - 1983                               15                    12


Capacity Losses

1.  Power to operating  cooling towers       1%                   1%
2.  Power to compensate for                  2%                   2%
     efficiency losses
_!/ Cost estimates  are  specified in 1970 prices and are based  on  data
   in EPA, Development  Document for Proposed Effluent Limitation
   Standards for the Steam Electric Power Generating Point  Source
   Category, Sept,  1973.
2j Capital costs include   only the cost of constructing and hooking-
   up the cooling  tower.
3_/ Total annual operating costs for a plant that  installs  a cooling
   tower equals  (capacity s£ p,lantX X (annual operating cost/kw) X
   C% capacity \®$$ per plant L,,
                                 n-38

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                             TABLE-23-


         ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT    .
       OF GENERATING CAPACITY - CHEMICAL EFFLUENT GUIDELINES-7


                           1977 Guidelines
                           Non-Nuclear Capacity—/   Nuclear Capacity—'
                               ($/Kilowatt)           ($/Kilowatt)
Capacity Placed in Service;

  Prior to 1971
    Capital Expenditures          $1.95                  $0.85
    Annual Operating               0.85                   0.50
      Expenses

  1971 - 1977
    Capital Expenditures           1.05                   0.85
    Annual Operating               0.55                   0.50
      Expenses


                           1983 Guidelines
                                               9 /                   3/
                           Non-Nuclear Capacity—7   Nuclear Capacity—
                                ($/Kilowatt)          ($/Kilowatt)

Capacity Placed in Service;

  Prior to 1971
    Additional Capital            $3.35                  $2.75
      Expenditures
    Annual Operating               0.65                   0.35
      Expenses

  1971-1977
    Additional Capital             2.75                   2.75
      Expenditures
    Annual Operating Expenses      0.35                   0.35

  1978-1983
    Capital Expenditures           2.60                   2.00
    Annual Operating Expenses      0.25                   0.20


_!/ Costs estimate are based on data in E-PA, Hevelopment Document for
   Proposed Effluent Limitation Guidelines and New Source Performance
   Standards for the Steam Electric Power Generating Point SourTT
   Category, Sept 1973.  All costs are specified at 1970 levels.
_2/ Cost estimates are based on an average plant size of 300 mwe for
   the pre-1971 capacity, a 800 mwe plant for the 1971-77 capacity
   and a 1,000 mwe plant for the ppst 1977 capacity.
_3/ Cost estimates are based on an average plant size of 1,000 mwe.

                                II-39

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                             TABLE -24-

        INCREMENTAL COSTS  OF APPLICATION OF MECHANICAL  DRAFT
         COOLING  TOWERS TO  EXISTING UNITS AND  NEW UNITS!'
Type  of  Unit
Price  Increase
ixeiuctj.uj.ug ijj-j-c
Fossil
A. Baseload
1. New Units
2. Existing
Units




B. Cycling
1. New Units
2. Existing
Units





C. Peaking
1. New Units
2. Existing
Units





Nuclear (All baseloadl
A. New Units
B. Existing Units





i. CO L. O


36

30-36
24-30
12-18
6-12
0-6

36

30-36
24-30
17-18
6-12
6-12
0-6

36

30-36
24-30
18-24
12-18
7-12
0-6

36
30-36
24-30
18-24
12-18
6-12
0-6
J. 11 11 JL J. K 9 / IX W 11
(1970 $)


.64

.82
.89
1.01
1.20
1.90

.92

1.17
1.25
1.34
1.50
1.67
2.50

3.50

5.00
5.00
5.62
6.25
7.50
12.50

.65
.85
.91
.98
1.04
1.24
1.95
I/ EPA, Development Document for proposed Effluent Limitation
New Source Performance
Source Category, March
standards
, 1974
duction Costs — '


10

13
14
16
19
30

11

14
15
16
18
20
30

28

40
40
45
50
60
100

10
13
14
15
16
19
30
Guidelines and
for the Steam Electric Power Generating roint


2J Estimates are based on production costs (in 1970 prices)  for baseload,cycling
   and peaking units of 6.34._8.35. and 12.50 mills/kwh.

                                  11-40

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                                 TABLE 25
         ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT OF GENERATING
         CAPACITY THAT THE UTILITY INDUSTRY WOULD HAVE INCURRED IN THE
         "     ~  AB SINCE OF FEDERAL ENVIRONMENTAL REGULATIONS-*?
                                            Non-Nuclear Capacity    Nuclear Capacity
            Capital Costsl/                    ($/Kilowatt)	     ($/Kilowatt)

1.  Cooling towers on new plants                   $3.70                 $4.50
2.  Cooling towers on existing plants
3.  Replacement capacity
      - 1977 and 1983 (baseload units)            170.00                260.00


Capacity Losses^/

1.  Average capacity loss on new plants              .7%                   .7%
2.  Incremental capacity loss on existing
    plants
_!/ The cost estimates are specified in 1970 prices and are based on the following
   assumptions:
          a.  In the absence of environmental regulations, the mix of cooling
              facilities installed between 1970 and 1990 would have been the
              same as the 1970 mix of cooling facilities - 74% once through, 7%
              cooling ponds, 13% cooling towers and 6% combination systems.  The
              capacity penalties for cooling towers, combination systems, cooling
              ponds, and once through cooling would be 3.0%, 2.5%, 2.0% and 0.0%
              respectively.

          b.  The capital costs for once through cooling are 38% and 42% of the
              capital cost of cooling towers for fossil and nuclear units.

          c.  The capital costs for cooling ponds are 77% and 79% of the cost of
              cooling towers for fossil and nuclear units.

          d.  The capital costs for combinations systems are 88% of the cost of
              cooling towers for nuclear and fossil units.

2J Figures are weighted averages based on the projected mix of cooling facilities
   and on the estimated capital costs and capacity losses for each type of facility.
                                    11-41

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                                TABLE -26

     ESTIMATES OF INCREMENTAL CAPITAL AND OPERATING COSTS PER UNIT OF
            GENERATING CAPACITY - THERMAL EFFLUENT STANDARDS^/
              Capital Costs

1.  Cooling towers on new plants!/
2.  Cooling towers on existing plants!/
3.  Replacement capacity
       - 1977 (peakers)
       - 1983 (baseload units)
Non-Nuclear Capacity   Nuclear Capacity
    ($/Kilowatt)         ($/Kilowatt)
      $ 3.90
       15.00

       90.00
      170.00
                                                                       $ 5.50
                                                                        18.00

                                                                        90.00
                                                                       260.00
Annual Operating Expenses —'

1.  Replacement power
       - 1977
       - 1983
                                                 42.00
                                                 15.00
                              42.00
                              12.00
Capacity Losses

1.  Average capacity loss on new plants
2.  Incremental capacity loss on
    existing plants
        2.3%
        3.1
                                                                         2.3%

                                                                         3.0%
I/ Cost estimates are specified in 1970 prices and were derived by subtracting
   the estimates of the expected costs in the absence of environmental regulations
   (e.g., Table 25) from the estimates of the total costs of the thermal
   guidelines (e.g., Table 22).
2J Capital costs includes only the cost of constructing and hookingup the cooling
   tower.
_3/ Total annual operating costs for a plant that installs a cooling tower equals
   (capacity of plant) X (annual operating cost/kw) X (capacity losses/plant).
                                     11-42

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V.  ECONOMIC IMPACT ANALYSIS METHODOLOGY

    A.   Introduction

        The following economic  impact  analysis  utilizes the
basic industry information developed  in Chapters  I-IV.   The
impacts examined include:

        1.  Financial Effects

        2.  Price Effects

        3.  Capacity and Energy Penalties

        4.  Production Effects

        5.  Employment Effects

        6.  Community Effects

        7.  Balance of Payments Effects

Each of these impacts will be discussed separately.

        The complexity of the calculations  required  to  estimate
the economic implications of the  guidelines dictated the develop-
ment and use of a policy testing  model (PTM)i' •  The computer
model also made feasible range  estimates and sensitivity testing
which are valuable in light of the uncertainity  inherent in the
available forecasts of the amount of  generating capacity to be
fitted with pollution control equipment, the costs of such pollu-
tion control equipment, and the impact of  such  equipment on
operating costs and the efficiency of  generating  capacity, etc.

        It is important to emphasize  several major assumptions
of the economic impact analysis.   First, all impacts are
estimated in current dollars.   A  summary of the rates of infla-
tion that were assumed for capital and operating  costs  is
presented in Part III, page 111-26 and 111-31,  Second  for the following
reasons, the cost of closed cycle cooling  systems for units
under actual or planned construction  were  included in the total
cost of the guidelines:

        1.  A number of utilities probably  planned to install
            closed cycle cooling  systems in anticipation of the
            water effluent guidelines.

        2.  It is impossible to determine  whether the utilities
            decided to install  closed  cycle cooling  systems for
            environmental reasons (e.g., state, local or
I/ The structure of the model  is  outlined  in Part III,  page III-152
                          11-43

-------
            federal requirements)  or  for  non-
            environmental reasons  (e.g.,  economic and
            geographic factors).

Third, the cost estimates emphasized  in  this report represent
the incremental cost due to  the Federal  Water Pollution Control
Act of 1972 (FWPCA).  Consequently,  the  costs that the utility
industry would have incurred  in the  absence  of federal legisla-
tion  (e.g., see Table 25) Were deducted  from the cost estimates
presented in Table 22.  Finally,  it  was  assumed that each
utility company could schedule the hook-up of the cooling towers
during off-peak periods and  could  obtain  the replacement power
by either     increasing the load factor on  other units in their
system or by purchasing  power  from  other  utilities.

    B.  Financial Effects.!/

        Under financial effects,  this report primarily considered
total capitalized expenditures and their  sources of financing.
The capital expenditures associated  with  the implementation of
the guidelines are of two kinds.—'   The  first consists of direct
expenditures on pollution control  equipment.   These expenditures
are a function of:

        1.  the effluent guidelines  for  1977 and 1983,

        2.  the time schedule for  moving  toward these goals,

        3.  the cost per unit of generating  capacity of
            installing pollution control  equipment in new
            plants and of retrofitting existing capacity,

        4.  the changes in these costs over  time,

        5.  the amount of each type  of generating capacity,

        6.  the dat.e of construction  of  that capacity..

JL/ See Part III,  p. III-158 detailed description of  the model's financial module.
2_l Another type of  capital  expenditure  that  could result would
   be for the  installation  of additional capacity to provide
   replacement power while  part of the  existing generating  capacity
   is taken off line to allow for  the tie-in of the cooling tower.
   For the purposes of this  analysis,  however, it was assumed that
   since  the replacement power needs were small  (e.g., less than 5%
   of capacity),  the utilities could provide this power  from  other
   operating units  in  their  system.   This assumption is  further
   discussed in Section
                           11-44

-------
        In order to estimate how the utilities would finance
the required investment the following assumptions were made:

        1.  The regulatory agencies would allow the utilities
            raise prices to the extent needed to maintain
            an adequate return on common equity—'

        2.  The capital structure of the investor-owned
            utilities would be up to 55% long-term debt, up to 10%
            preferred stock,  and at least 35% common quality.

        3.  The  publicly  owned utilities would finance
            35% of capital expenditures through internal
            financing and the remainder through external
            financing.

        While it was assumed that the utilities would be able
to obtain the required external financing, this assumption was
further evaluated by looking at the expected  converage ratios
both with and without expenditures for pollution control,—'

    C.  Price Effects

        The water effluent guidelines will effect prices
directly by increasing the price of electricity and indirectly
by increasing the prices of goods and services which utilize
electricity.  Specifically, the economic impact analysis
focused on the following direct and indirect  price effects:

        1.  Expected increase in the price of electricity
            in mills/kwh

        2.  Expected increase in the price of electricity as
            a percentage of production costs

        3.  Expected increase in the price of electricity as
            a percentage of the cost of power to the final
            user,

        4.  Total increase in the cost of electricity per year
            to the consumer,

        5,  Expected increase in the production costs for the
            major power intensive industries.

!_/ For the purposes of this analysis it was assumed that the
   utilities would earn an after tax return on common equity of  12%,
2^/ The two coverage ratios covered in this report are:
     a.  Interest = Income before income taxes and interest payments
                                Interest payments
     b.  Non-tax = Income before income taxes and interest payments
         adjusted  Interest payments plus preferred dividends,


                          11-45

-------
        The expected increase in the price of electricity
is primarily a function of the following factors:

        1.  Total capital expenditures

        2.  Sources of financing the capital expenditures

        3.  Total operating costs

        4.  Projected demand for electricity

        5,  Policy of the regulatory agencies

For the purposes of the analysis, it was assumed that the
utilities would obtain rate increase sufficient to maintain
an after tax return on common equity of 12%,  The expected
price of electricity, therefore, in any given year can be
calculated by estimating the total costs of the utility
industry and by calculating the price that the utility industry
would have to charge in order to maintain an after tax return
of 12%.I/

    D.   Capacity and Energy Penalty

        Because of the power requirements of closed cycle
cooling systems and the associated decrease in efficiency  (e.g.,
higher  heat rate), there will be a capacity and energy penalty.
The capacity and energy penalties were calculated based on
the following assumptions:

        1.  The power requirements of cooling towers would
            be 1% of capacity.

        2.  The efficiency losses would average 2% of capacity,

        3.  In the absence of federal legislation, the utilities
            would have installed cooling system with a total
            average energy penalty of 1%.

        4.  The utilities would replace the lost capacity
            with peakers through 1977 and with baseload units
            after 1977.

The importance of the resulting capacity and energy penalties
were evaluated by calculating their impact on the projected
increase in generating capacity and on the projected national
demand  for energy.
   A detailed explanation of the methodology for calculating
   the price of electricity is given in Part III, page III-162
                          11-46

-------
    E.  Production Effects

        Since the electric utility industry is regulated to
insure an adequate return on capital, it was assumed that
there would be no plant closures due to the guidelines.

    F.  Employment Effects

        It was assumed that the guidelines would have a
negligible impact on the general level of employment because:

        1.  The utility industry employs a very small per-
            centage of the total labor force .

        2.  The expected price increases would not cause
            plants to close or reduce their level of production.

    G.  Community Effects

        While the guidelines would certainly have an aesthetic
impact on the community, the only community effect that was
analyzed in this report was the expected increase in the cost
of living due to increases in the price of electricity.  Based
on the assumption that the per capita consumption of electricity
would grow by 5%-i.'  Pe* year, the report calculated the impact of
the guidelines on the monthly electricity bill for residential
and large industrial customers.

    H.  Balance of Payments Effects

        The guidelines will have a small effect on the balance
of payments because part of the increased fuel consumption
associated with closed cycle cooling systems will be met through
increased impacts of residual fuel oil.  In order to estimate
the balance of payments costs, the following assumptions were made;

        1.  Incremental demand for fossil fuel will be filled
            entirely by coal (50 %) and oil (50 %) .

        2.  100% of the additional demand for oil will be filled
            by impacts

        3.  The balance of payments cost will be $7 per barrel.
^/ Estimate was derived by assuming a total growth in demand for
   electricity of 7% per year and a 2% per year growth in
   total customers.
                         11-47

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VI.  BASELINE ECONOMIC  IMPACT  ANALYSIS

    A.  Introduction

        The impacts considered  in  this  analysis include the
following:

        1.  Financial Effects

        2.  Price Effects

        3.  Capacity and Fuel  Penalties

        4,  Production  Effects

        5.  Employment  Effects

        6.  Community Effects

        7.  Balance of  Payments  Effects

The expected coverage of the guidelines  was  estimated  in
Section IV and the methodology used  and  the  critical  assumptions
were described in Section V.   This  section will estimate the
incremental cost that the utility  industry will incur   both
before and after exemptions under  Section 316(a)  of  the FWPCA
in order to comply with EPA's  proposed  effluent guidelines for
steam electric powerplants  (see  Tables  18 and  19  for  a summary
of the guidelines).  Thus,  the costs  that the  utility  industry
would have incurred for thermal  cooling  systems,  primarily for
once through cooling system have been deducted from  the total
estimated costs of the  thermal guidelines.!'

        In view of the  fact that there  is a  considerable
difference in the economic  impact  before and after exemptions,
it is important to summarize the major  assumptions that were
used to estimate the impact of the  guidelines  after
exemptions :^./

        1.  68% of the  existing  units covered  by  the  guidelines
            will receive a  total exemption while  the  remaining
            32% will have to install  closed  cycle cooling systems
            on 50% of their capacity.   The cooling towers
            would only  have to be  operated during certain
            critical periods which  would in  the aggregate amount
            to 30% of the year.
!_/ See Tables 22, 25 and 26 for a comparison  of  the  total and
   incremental costs of the thermal guidelines for a. typical
   power plant.
2_/ The estimates are based on. a report bv KPA^P  Office  of Mater
   Programs,  entitled*  "A Preliminary Analysis of  Thermal Discharge in
   Relation to Water Quality Standards".
                              11-48

-------
2.   All new units that are planning  to  install
    cooling towers and 17% of all other units
    scheduled to come on line after  July  1,  1977
    will have to install closed cycle cooling
    systems on 100% of their capacity.  The  cooling
    towers for both categories of facilities will
    have to be operated whenever the unit  is
    generating electricity.
                  1149

-------
    B.  Financial Effects

        1.   Capital Requirements

            As shown in Table 27  the  total  capitalized
expenditure required to implement  the  guidelines  before
exemptions are 7.7 billion dollars  by  1977 and  23.2 billion
dollars by 1983.  Based on  the  estimate  of  projected utility
expenditures presented in the section  on financial profile
(page 11-21), it ran  be  concluded that  the guidelines will
increase the total  capital  expenditures  of  the electric
utility industry 8.1% by 1977 and 6.3% by 1983.   Approximately
72% of the cost of  the guidelines  by  1983 can  be  attributed
to the thermal guidelines.

            As indicated in Table 28 ,  New Source  Performance
Standards  (NSPS) will  increase  capital expenditures before
exemptions by 16.3  billion dollars  or by an additional 2.6%  between
1983 and 1990.  Approximately,  86 % of the  cost of meeting
NSPS can be attributed to the thermal  guidelines.

            It is important to  emphasize that  the actual impact
of the guidelines will be considerably less due to exemptions
under Section 316(a) of the FWPCA.   Specifically, as shown
in Table 28, after  exemptions the  guidelines will increase the
total capital expenditures  of, the  utility industry  2.1
billion or 2.2% by 1977 and  9.2  billion or  2.5%  by 1983.
The thermal guidelines will account for  only 30% of the capital
costs by 1983 after exemptions.

            Consideration of exemptions  has a  similar effect
on the cost of NSPS,   It is estimated  (see  Table  28) that
after exemptions the utilities  will have to spend an addition
5.2billion dollars  in  order to  comply with  NSPS between 1983
and 1990 which will increase the  utilities' capital requirements
over this  period by about  -8%.

        2 .  Sources of Financing

            The utilities will  finance the  expenditures for
pollution  control equipment through internal (e.g. depreciation,
retained earnings,  tax deferrals)  and external sources  (e.g.
long-term  debt, preferred  etroefc,  common  stock.!..  Based on
assumptions incorporated into the PTM model, the utilities could
finance 34% of the  (1973-1990)  capital expenditures through
internal financing  while the remainder would have to come
from external sources.  If  the  investor  owned  utilities were
to maintain the  same capital structure (e.g. 55% long-term
debt, 10%  preferred stock,  and  35% common equity) the external
financing  would be  obtained in  the following way:
                          11-50

-------
Before Exemptions
13.2
2.9
4.7
21.4
After Exemptions
4.8
.9
2.1
7.8
     Type  of                      Financial  Requirements  for Investor
External Financing               Owned  Utilities 1973-90  (Billion  $)!/

Long-term  debt
Preferred  Stock
Common Equity
   Total


             The key assumption of this analysis is  that the
utilities  will be able  to  obtain the required external  financing.
While it  is difficult  to  conclusively  prove that  the  capital
will be available, there  are several compelling arguments.  First,
the utilities were able to increase the level of  capital
investment by 11% per  year in the 1960's even though  the industry's
interest  coverage ratio fell from 5,11 in  1961 to 3.03  in 1971.

             Second, as  shown below, the investment  required before
exemptions to meet the  effluent guidelines will have  an insignifi-
cant effect on the industry's coverage ratios in  1977,  1983, and  1990

        Coverage Ratios                    1977         1983     1990

1) Interest?-/
    a.  without pollution control
          expenditures                       3.06         2.93     2.90
    b.  with pollution  control
          expenditures                       3.00         2.92     2.90

2) Non-Tax Adjusted?-/
    a.  without pollution control
          expenditures                       2.60         2.49     2.46
    b.  with pollution  control
          expenditures                       2.55         2,48     2.47


Finally,  if the utilities are going to be  able to finance
by 1990 over 900 billion dollars of investment for  transmission
and generation facilities, they should not experience major
problems  in financing  the  additional capital  (e,s<, 1.4.4  billion after
exemptions  by 1990) required for  pollution control equipment.   It can be
concluded,  therefore,  that  if the utility industry experiences problems
in securing long or short term capital, it will be  the result  of the large
capital expenditures required to  expand transmission and generation facilities.
_!/ Figures were derived by assuming that the composition of external financing
   for EPA's proposed guidelines (e.g., policy alternative-7 in Part III) was
   the same as in the case of the technological recommendation  (e.g., policy
   alternative 1 in Part III).
2J See p. 11-47 for a definition ofl the coverage ratios.
                            11-51

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        3.  Profitability

            As discussed in previous sections, the electric
utility industry has been regulated to insure an adequate
rate of return on its common equity.  This analysis assumes
that the regulatory agencies will allow the utilities to
raise the price of electricity in order to recover the increased
operating and fixed charges associated with the effluent guide-
lines.  Therefore, the profitability of the electric utility
industry (e.g. rate of return on common equity) should not be
affected by the implementation of the water effluent guidelines.
However, the total after-tax profits of the industry will
increase in order to realize a rate of return on the increased
investment in pollution control equipment.
                          II- 52

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     C.  Price Effects

        1 •  Direct Price Increase

            In order to finance the  operating  costs  and  the
fixed charges associated with the  capital  investment,  the
utilities will have to raise the price of  electricity.   Based
on the assumptions presented inthe previous  section,  the
total cost to the consumers of electricity before  exemptions
will increase 1.3 billion dollars  or 2.3%  by 1977  and  5.6  billion
dollars or 4.7% by 1983.  The comparable figures after exemptions
are: .9 billion dollars or 1.6% by 1977 and  3.1 billion  dollars
or 2.5% by 1983.  The price increase by 1983 needed  to generate
the additional revenues will be 1.5 mills/kwh  before  exemptions
and  .8 mills/kwh after exemptions.!.'

            As shown in Table 28, between 1983 and 1990, the
price effects New Source Performance Standards (NSPS) will be
negligible.  Specifically,  before exemptions NSPS  will increase
the price of electricity only .1 mills/kwh or  .2% by 1990.
After exemptions, however,  NSPS will not increase  the price of
electricity since the growth in the sales of electricity are
sufficient to generate the required increase in revenues.

        2.  Secondary Price Increases

            To the extent that commercial  and  industrial users
of electricity pass through to the final consumer  increases  in
production costs, an increase in the price of  electricity  will
have an effect on the prices of other goods  and  services.
However,  the average price increase  is expected  to be small
since purchases of electric power  account  for  only about .8%
of the total value of industrial shipments.—'  There will  be
a larger  impact on the price of products which are power
intensive.  However, as shown in Table 29  there  are  only 6
industrial classifications for which electric  power  costs
amounted  to 5 percent or more of the total value of  shipments.
Even if we assume that the increased power costs are completely
passed on to the final consumer, the final price of  the  most
power intensive products, will increase by less  than .5%,   It
can  be concluded, therefore, that  the secondary  price increases
associated with the guidelines will  be very  small.
JL/ Total price  increase by 1983.
"2j National Economic Research Associates,  Inc.,  Possible Impact
   of Costs of  Selected Pollution  Control  Equipment  on  the
   Electric Utility Industry and Certain Power  Intensive Consumer
   Industries,  1972.
                          11-53

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    D.  Capacity  and  Energy Penalty

        1.  Capacity  Penalty

            Installation of cooling towers  will  require the
construction of new capacity to generate power  to  run the
cooling towers and  to compensate for the loss of efficiency
due to the  increase in turbine back-pressure. The  baseline
case assumes that  in  1977 the utilities will provide this
increased capacity  through the construction of  gas-turbine
units.  However,  by 1983 the utilities will be  able to
construct large fossil and nuclear plants to replace the lost
capacity.

            Before  exemptions the total capacity penalty will
be  1,900 MWe by 1977  and 14 , 700 MWe by 1983.  The  comparative
figures after exemptions are   800 MWe by 1977  and 3 , 300 MWe
by 1983.  The composition of the capacity penalty  by type of
plant is  estimated  to be as follows:
                                        Capacity  Loss (in MWe)
Type of Plant                 1977                     1983
                       Before      After       Before     After
                       Exemptions  Exempt ions  Exemptions Exemptions

1. Peakers  (e.g.          1,900        800         1,900        800
   gas turbines)

2. Base Load                ---         ---        12,800      2,500
    CFossil and
    Nuclear )

       TOTAL              1,900        800        14,700      3,300

            The projected capacity loss before exemptions will increase
 the national demand for  generating capacity by only ,4% by  1977 and
1.7% by 1983. .V In view of the small increase in  the demand for
generating  capacity,  the utilities should not experience serious
problems  in replacing the projected loss in generating capacity.

        2.  Fuel  Penalty

            There is a fuel penalty associated  with the water
effluent  guidelines.   This penalty results  primarily from
the following factors:
iy The comparable figures after exemptions are .2% by 1977 and .4% by 1983.
                          II- 54

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            a.  Additional fuel required  to  operate  the
                closed cycle cooling  systems.

            b.  Additional fuel required  per  kwh  of  electricity
                (e.g. higher heat rate) due  to  the  increase
                in turbine back pressure.

The fuel penalty before exemptions will be approximately  4
million tons equivalent of coal per year  by  1977  and 33 million
tons per year by 1983.    The comparable  figures  after  exemptions
are 2 million tons by 1977 and 7 million  tons by  1983.i'

            In view of the current shortage  of  energy it is
important to evaluate the effect of the fuel  penalty on the
national demand for energy, especially on the demand for oil.

            Based on the Department of the Interior's estimates,—'
the fuel penalty after exemptions will increase the  national
demand for energy   .05% by 1977 and  .2%  by  1983.   Also, if one
assumes that the fossil fuel penalty  will be  evenly  divided
between coal and oil ,3_/  the guidelines after exemptions would
increase the national demand for oil  4 million barrels per
year or ,06%by 1977 and 14 million barrels per  year  or  ,Z£ by
1983.  It can be concluded, therefore, that  the effluent guide-
lines will have an insignificant effect on both the nation's
ability to satisfy the projected demand for  energy and the country's
dependency on foreign sources.
iy The fuel penalty was  converted  to  a  coal  equivalency by taking
   the total increase  in demand  for nuclear  and  fossil fuel
   expressed in million  BTU,  and dividing  by the average BTU per
   ton of coal  (e.g. 24  million  BTU/ton).
2y Dupree, Walter G. and West, James  A., United  States Energy
   Through the Year 2,000, U.S.  Department of  the Interior,
   December, 1972.
3_/ This is probably a  conservative assumption  since if the fossil
   fuel penalty was distributed  according  to the projected
   utility demand for  coal and oil, the energy penalty would be
   65% coal and 35% oil.
                         11-55

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    E .   Production Effects

        Because electric utilities are regulated to  insure  an
adequate return on their capital base, it is expected  that
the utilities will be able to obtain rate increases  to  cover
the increased costs due to pollution control.  Even  if  there
are delays in obtaining rate increases, it is unlikely  that any
power plant will shut-down because of the higher costs  associated
with the water effluent guidelines.

        The one production effect of the guidelines  may be  to
force certain utilities to prematurely retire some older units
in order to avoid spending large amounts for pollution  control
equipment.  Such an option will probably be used only  after 1977
when it would be possible to replace the retired unit  with  new,
large fossil or nuclear units.

        However, the guidelines will not significantly  affect
the growth of the electric utility industry for  several reasons.
First, since the electric utility industry is regulated  to insure
an adequate rate of return on its equity, investment in the
industry will not be significantly affected.  Second,  the expected
increase in the price of electricity is not expected to have a
noticeable impact on the demand for electricity.

    F.   Employment Effects
        Since the price increases associated with  the  guide-
 lines are not  expected to have a significant effect on the
 growth in demand for electricity, the overall level of employ-
 ment in the  electric utility industry will increase in order
 to meet the  projected  increase in demand for electricity.  Also
 as discussed in the previous section, the guidelines  are not
 expected to  cause any  plant  closures  and any employment effects
 due to the early retirement  of inefficient generating units  will
 probably be  offset by  the projected  expansion  in  generating
 capacity.  Furthermore,  if  the increased demand for generating
 capacity due to capacity penalties  (e.g.,  .4%  after exemptions  by
 1983), is greater than the  reduction  due to  the projected  price
 increase the guidelines  will increase the  level of  employment.

     G.   Community rtiffants

          The  water  effluent  guidelines will  impact  the community
  directly through  increased  prices for electricity  and indirectly
  through  price  increases  for final goods and services-£s shown
  in Table 30   the  guidelines after exemptions!/  will increase the
  average  resident'!  monthly electricity bill $.39    or  1.6 A by
  1977  and $1-08 (2.5%)  by 1983.  The average monthly bill  for
  large industrial  users would increase $43   (1,6%)  by  1977 and
  
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    H.  Balance of Trade

        The guidelines will have a small effect on the balance
of trade because part of the increased fuel consumption
associated with closed cycle cooling systems will be met by
increased imports of residual fuel oil.  Based on the assumptions
used to estimate the fuel penalty, the guidelines before
exemptions will increase oil imports by 8  million barrels per
year or 1.2% by 1977 and 66 million barrels per year or 1.5% by
1983.   The comparable figures after exemptions are  4 million
barrels or  .6% by 1977 and 14 million barrels or ,,4 % by 1983.

        It is difficult to estimate the total balance of payments
costs  of the guidelines since there is considerable uncertainty
concerning the future price of imported oil.  If one assumes
a net  out-flow of $7'per barrel of oil, however, the balance
Of payments costs before exemptions would be 256 million dollars
per year by 1977 and 462 million dollars per year by 1983.
The comparable figures after exemptions are 28 million dollars
by 1977 and 98 million dollars by 1983.  Since the level
of imports in 1973 was approximately 70 billion dollars, it can he
concluded that the guidelines will have an insignificant impact
on the nation's balance of trade.
                        11-57

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                                              TABLE 27

                                SUMMARY OF THE ECONOMIC IMPACT OF  TH
                                    EFFLUENT LIMITATION GUIDELINES L
                                                          Level  I
                                                       1977 Standards
                  Impact
    Financial Effects
      1. Capital  Investment  (billion $)
      2. % Increase  over  baseline
    Price Effects
      1. Increased  revenues per year
      2. Price  increase  in mills/kwh
      3.  Price increase (% cost to final user)
(billions)
             Before
           Exempt ions
               7.7
               8,1%
1,3
 ,5
2,3%
           After
         ExemDtions
             2.1
             2.2%
 .9
 .4
1,63
                                             Level II
                                           1983 Standards!/
            Before
          ExemDt ions
             23.2
              6.3%
                                                                            5.6
                                                                            1.5
                                                                            4.7%
                                                                                       After
                                                                                     Exemptions
                                                                                          9.2
                                                                                          2.5%
3.1
 .8
2.5%
Oi
00
Capacity Penalty            „.
  1. Total capacity  penalty—
  2. % of national capacity

Fuel Penalty
  1, Total fuel penalty  (million  tons
     coal equivalent)—'
  2. % of national demand  for  energy
                                                    1,900 mwe
                                                      .,4%
                                                       4

                                                      ,1%
                            SOOmwe
                             .2%


                             2

                            ,05%
                         14,700 mwe
                          1.7%
                          33
                           .7%
                           3,SOOmwe
                            .4%
                             7

                            .2%
    I/ Figures represent  the incremental cost of the guidelines
    "2J Total replacement  capacity needed to run the cooling towers  and  to compensate for
       capacity  lost  due  to  increased turbine back pressure.
    3/ Total increase in  demand for nuclear and fossil fuel expressed  in million BTU and
    ~~  divided by  the average BTU per ton of .coal (e.g., 24 million BTU)
    kj FigureSshown for Level II represent the cumulative effect  of 1977 and 1983 standards.

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                            TABLE 28

      SUMMARY OF THE  ECONOMIC  IMPACT OF NEW SOURCE PERFORMANCE
                        STANDARDS.  3.983-1990
            Impact
Financial Effects

1.  Capital Investment
2.  % increase over baseline
                                           Cost  of  New Source Performance
                                               Standards - 1983-199Q.3-/
                                             Before
                                           Exemptions
                                           16.3 billion
                                            2,6%
  After
Exemptions
 5,2 billion
Price Effects

1.  Increased revenues per year
2.  Price increase
3.  Percentage increase in price  to
    final user
                                            3,5
                                             .1  mills/kwh
                                             .2%
 1.7         .,
  ,0 mills/kwhA'
Capacity Penalty

1.  Total capacity penalty!.'
2.  % of national capacity
                                           10,400 MWe
                                             .8%
 3,100 MWe
  .25%
Fuel Penalty

1.  Total fuel penalty
    (million tons coal equivalent)^/
2.  % of national demand of  energy
                                           26  million tons
                                             .4%
 8  million tons
   127
  . A ^ fo
I/ Total replacement capacity  needed  to run the cooling towers
   and to compensate for  capacity  lost due to increased turbine
   back pressure.
2y Total increase in demand  for  nuclear and fossil fuel expressed
   in million BTU and divided  by the  average BTU per ton of coal
   (e.g. , 24 million BTU)
3_/ Figures represent the  incremental  effect of New Source Performance
   Standards between 1983  and  1990.

~                                            between 1984 and 1990  is

                                               *»
                              °*
                               11-59

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                                          TABLE 29

                SELECTED ELECTRICITY  INTENSIVE  INDUSTRIES  IN THE UNITED STATES

                                             1967
              Industry
  All  Manufacturing

  Atomic  Energy  Commission  Plants 2
  Primary Production of  Aluminum
  Electrometallurgical Products
  Alkalies  and Chlorine
  Industrial  Gases
  Cement,  Hydraulic

  Six-Industry Total

  All  Other Industry
2819
33-34
3313
2812
2813
3241
  Electric Power
    Costs As A
    Per Cent of
Value of Shipments^l
    (Per Cent)

       0.79%

      IS.25
      11.40
      11.01
       9.35
       9.10
       5,94

      10 .34

       0.69
  Total Electric
  Poxver .Purchased
Plus Net Generation
    (Million Kwh)

     505,820.9

      29,827.7
      53,604.9
      11,205.7
      12,319.0
       7,050.4
       8,413.2

     122,425.9

     383,395.0
OS
O
       1  Self-generated  power  is evaluated  for each  industry at  the  same  cost  per  Kwh
         as  that  industry's electric power  purchases.

       2  These plants constitute only  a  part  of  industry  2819  (Industrial Inorganic
         Chemicals,  N.E.C.).   The  Census does permit isolating  the value  of shipments
         by  these plants.   Electric power purchases  are based on FPC data.
    Source:   U.S.  Bureau  of  the Census; Census^ pf Manufactures,  1967  (Washington,  D.C.:  U.S.
             Government Printing Office,~T971); Volume II, Industry Statistics,  Part  1,
             pp.  28-42; Volume II, Industry Statistics , Part  2,  p. 28A-9  and  Fuels  and Energy
             Consumed, Special Series MC  (67)"S~4, p. 18-SR4.  U.S. Federal Power  Commission,
             "Electric Energy Purchased,  Generated and Used and  Maximum Demands  at  Major
             Atomic  Energy Commission Installations by Months  for  1967"  (unpublished  table),
             July  1968.

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                             TABLE 30

         IMPACT OF THE WATER EFFLUENT GUIDELINES ON TflE CONSUMERS
                     OF ELECTRICITY. 1977 and 1983
YEAR
1977
1983
     FINANCIAL DATA

Actual monthly electricity
bill

Projected monthly  bill  with-
out effluent guidelines
      TYPE OF  CUSTOMER
RESIDENTIAL  LARGE  INDUSTRIAL
                                           2/
Projected increase  due  to the tl
effluent guidelines
   - before  exemptions
   - after exemptions

Percent increase
   - before  exemptions
   - after exemptions

Projected monthly bill
without effluent guidelines

Projected increase  due  to^/
the effluent  guidelines

   - before  exemptions
   - after exemptions

Percent increase

   - before  exemptions
   - after exemptions
                                               $13.33l/
    24.20
                                                   ,56
                                                   .39

                                                  2.3 %
                                                  1.6%
                                                43.25
                                                 2.03
                                                 1.08
                                                 4.7%
                                                 2.5%
$l,416l/


 2,712
                       62
                       43

                     2.3%
                     1.6%
                    4,830
                      227
                      120
                     4.7%
                     2.5%
I/ Edison Electric  Institute, Statistical Yearbook  of  the Electric
   Utility Industry for  1971

2J Temple, Barket  & Slone,  Economic Impact of Water  Effluent Guide-
   lines on  the  Electric Utility Industry. March, 1974.
   In addition the following assumptions ivere made.
       a. 7%  per year  growth in demand for electricity and a 2%
          per  year  growth in total customers.
       b. The  price increase due to the guidelines  would  be
          passed on uniformly to all types of customers.
                                11-61

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VII.   LIMITS TO THE ANALYSIS

     A.   Uncertainty of Cost Estimates

          1.   Capital Costs

              Section VI estimated  the economic impact of  the
guidelines  based on estimates  of  the most likely costs  of
complying with the effluent guidelines.   The data, however,
indicates that there is considerable variability in  several
of  the cost  parameters.  For example, estimates of the  cost
of  installing cooling towers.on  existing plants!' vary  from
$3.8  per  kilowatt of capacity^-' to  over ?100 per kilowatt  (kw)
of  capacity^.'.  Since  there will  be more variability in cost
estimates for individual plants  than in estimates for average
national cost,additional computer  runs were made with the  cost
of  retrofitting existing plant varying from $10/kw to $38/kw_L'«
The  analysis indicates that the  capital requirements  reauired
before exemptions to meet  the  1983 thermal standards  could be  reduced
by  as  mach  as 16% or increased as  much as 35%.A/  It  is in.terest-
ing  to note  however, that  the  high estimates for capital
costs  would  raise the expected price increase in 1983 before
exemptions  by only 20% (e.g.,  from   5 % to 6%).

              Similarly, as  indicated in Table 32, there is
consideralle uncertainty in the  capital cost required to
comply with the chemical guidelines. While it is EPA's  judgment
that the actual costs of the chemical guidelines will correspond
to  those specified in the  development document !/, a  separate
computer run was made to determine the impact of the  highest
industrial  estimate.—'  The analysis indicates that the investment
 17  Only the capital required  to  build and hook-up  the  cooling
    tower will be included  in  the following estimates.
 27  Woodson, R.D. "Cooling  Towers for Large Steam-Electric
    Generating Units,"  in Eisenbad, M and Gleason,  G.,,  editors,
    New York, 1969, pp.  364-365
 3/  Estimated costs for  Indian Point Nuclear Station  (Consolidated
 ~  Ed.)
 4/  A breakdown of the  maximum and minimum capital  costs by type
 ~~  of unit is given in Table  31,
 5/  The figures are only estimates since it was  assumed that the
 ~  percent variation in 1983  for the technological option  (e.g.
    Policy Alternative -0- in Part III would be the same as the percent
    variation for EPA's proposed guidelines (e.g. Policy Alternative 7
    in Part III).
 6/  EPA,  Development Document for Proposed Effluent Limitation Guidelines
    and New Source Performance  Standards for the Steam Electric Power
    Generating Point Source Category,  March 1973.
 1_J  Corresponds to Policy Alternatives <-l"(b-) and -l(d) in Part III,
                             11-62

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 required to comply with  the 1983 chemical  guidel-lnes  could increase
 from 5,5 billion to 18.4 billion dollars.  ¥his  would  increase   ease
 the total capital requirements of  the utility industry
 another 3.5% by 1983.

          2.  Operating Costs

              The principal uncertainties concerning the
 estimates of operating costs are the cost  of replacing the power
 losses associated with closed cycle cooling  systems,  and  the
 magnitude of the loss in efficiency due  to the  increase  in turbine
 back pressure. In order  to determine the importance of varying
 these parameters, additional computer runs were made  for  what
 could be considered maximum and minimum values  (see Table 31  for
 cost estimates).  The analysis indicated that the  expected price
 increase in 1983 before  exemptions could be  reduced by 2Q% or
 increased by 13%.

          3.  Conclusions

              Although a  similar analysis was not undertaken to
 estimate the effect of cost uncertainties  on the impact  after
 exemptions, it is expected that the variability could be  of the
 same order of magnitude.  Thus, if one assumes  the worst  set  of
 assumptions for both the chemical  and thermal standards,  the guide-
 lines after exemptions would  require an incremental, investment Q£  2_4 vl
 fcillion dollars by 1983.i'lt can be concluded,  therefore,  that
 even under the most conservative set of assumptions,  the
 effluent guidelines will not increase the  capital  requirements
 of the electric utility  industry more than 6V5£ by 1983.
!_/ Estimate can be broken down as follows:
     - cost of guidelines after exemptions      	 9,2 billion
     - adjustment for higher capital            	  2^0 billion
         costs for thermal guidelines
     - adjustment for higher capital costs      	12.9 billion
         for chemical guidelines
                         11-63

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     B.  Critical Assumptions

         While the previous  section analyzed the variability
in the cost estimates,  this  section will focus on several criti-
cal assumptions that were  the  basis of the economic impact metho-
dology.  The first assumption  was  that the price increase granted
by the regulatory agencies will  be sufficient to maintain an adequ-
ate rate of return on  the  utility  industry's common equity.  Speci-
fically,  EPA's analysis assumes that the price increases would
enable the utility industry  to realize a 12% return on common
equity.  Although this  is  probably a good long-run assumption,  in
the short-run some utilities could experience delays in obtaining
the necessary rate increases.  To  the extent to which delays
occur, the utility's rate  of return could fall below the level
assumed in this analysis.  A decline in the utility's rate of
return could also affect its ability to finance the required
capital expenditures.   However,  given the available data there
is no way to predict the exact impact that delays in obtaining
rate increases will have on  the  overall level of profitability
of the utility industry or on  the  industry's ability to finance
pollution control expenditures.

         The second critical assumption was that the utilities
will be able to finance the  incremental expenditures for
pollution control equipment.  The  principal counter arguments
seem to be as follows:

         1.  Since the utility industry's ability to finance capital expendi-
             tures is already  stretched to its upper limit, there will
             be considerable problems in obtaining additional capital.

         2.  Delays in obtaining rate increases could result in
             a derating of the utility's bond issues, thus
             further reducing  the  utility's ability to finance
             capital expenditures.

         While it is not possible  to conclusively prove that
the required capital will  be available, there are several reasons
why the utilities should be  able to obtain financing.  First,
since  the utility industry is  regulated to insure an adequate
rate of return on common equity, it will be able to obtain rate
increases to finance expenditures  for pollution control equipment.
Second, the utility industry is  already planning to spend about
360 billion dollars between  1973 and 1983 in order to construct
generation and transmission  facilities.  The guidelines  after
exemptions will increase the utilities'  capital requirements only 2.5% by
1983.  Third, the industry was  able  to increase investment by 11% per year
in the 1960's despite a rapid decline  in   the  industry's  coverage
                             11-64

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ratios.  As noted in previous Section VI, the guidelines will have
an insignificant effect on the industry's coverage ratios.  It
can be concluded that any financial problems that the utility
industry will encounter will be caused primarily by the industry's
need to rapidly expand its generation and transmission facilities.
Consequently >  a.n     effective way for the utility industry to
insure the availability of capital for pollution control equipment
would be to support an extensive energy conservation program.

         The third major assumption was that the cooling tower
industry will be able to expand in order to meet the projected
demand for cooling towers.  This assumption  appears to be
valid for the following reasons:

         1.  Cooling systems are not generally factory limited.
             That is, the bulk of the labor and material is
             supplied by construction in the field.  The only
             components supplied from off-site sources are fans,
             spray modules, tower packing and small quantities
             of piping and control equipment.  None of these
             items are sophisticated to manufacture and large
             increases in the supply of these materials can be
             obtained through subcontractors who specialize in
             similar items.  The major limitation in increasing
             the volume may be in obtaining competent engineering
             and design forces to support the increased demand.
             However, since most of the increased demand for
             cooling towers will occur after 1977, adequate lead
             time Is available for the industry to train qualified
             personnel.

         2.  Several types of cooling systems do not require
             any type of factory support and can be engineered
             and constructed by the utilities or their agents.
             This is the case with any cooling pond (spray
             pond excluded).  The potential of this type of
             system  for  those   plants which have surplus
             land is significant.

         3.  There are several recent entrants into the cooling
             tower industry and several others are anticipat-
             ing entry.

         Another critical assumption was that each utility
company could schedule the hook-up of the cooling towers during
off-peak periods and use either the company's or another system's
excess capacity as replacement power.  Assuming that it took 3
months to hook-up a cooling tower to an existing power plant
(one month of which was for normal maintenance), and that the
utilities could schedule the outages during 54 of the months
                            11-65

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between  1978  and 1983, an additional•6%  of the nation's
generating  capacity would have  to  be used to supply  the
required  power.i'   Although  the  incremental capacity
requirements  will vary by utility  system, the regional
disparities probably could be alleviated by purchasing
power  from  other systems which  were less impacted.

          There are several potential problems concerning
the above assumptions.  First,  if  the demand curve for many
utility  systems is peaked, there will be considerably  less
time  in  which to schedule outages.   Second, if all a utility's
excess     capacity during non-peak periods is firmly committed
to either necessary maintenance  or to required reserve  capacity,
it may be extremely difficult to make available an additional .6%
of tne  system's generating capacity.  Finally, since all
utility  systems are required  to  comply with the guidelines
at approximately the same time,  it also may be difficult to
purchase  power from another  utility system.

          If the above problems  prove to be significant  the
utilities would have to provide  the replacement power  by
constructing  additional capacity.   If it is assumed  that ^6%
of generating capacity would  have  to be replaced,  the  capacity
expenditures  to meet the 1983 guidelines would increase  by
approximately 1.1 billion dollars.

          Despite the problems just cited, it is the  conclusion
of this  analysis that since  most utilities will not  have to begin
to comply with the thermal guidelines until July,  1978,  there
is adequate time to schedule the construction and  hook-up of
cooling  towers without having to construct additional  capacity
to supply replacement power.

          The fifth critical  assumption was that in  the absence
of feueral  environmental regulations, the mix of cooling facilities
in the 1973-1983 period would correspond to the 1970 mix of
cooling  facilities.  Therefore,  for new power plants the incre-
mental cost of the thermal guideline's would equal  the  cost of
cooling  towers minus the cost of the basic cooling  facility
that  the utility would have  installed (e.g., once  through
cooling  in  most cases and cooling  ponds, combination systems
or cooling  towers in the remaining cases).  For existing power
plants,  however, the incremental cost and the total  cost of the
thermal guidelines would both be equal to the cost  of  cooling
towers.

17 Estimate was based on the following consumptions:
  - All power plants that were planning  to install cooling towers  before the
    publication of the guidelines have already planned to build additional capacity
    to replace the capacity losses associated with cooling towers.
  - After  exemptions, an additional 88,000 mwe of capacity will have to install
    cooling  towers by 1983.
  - The outages will be scheduled at  3 months intervals over 54 months between
    1978 and 1983.
  - The total generating capacity in 1983  will be 790,000 mwe.
                               11-66

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         There are a number of problems concerning this
assumption.  First, it is extremely difficult to forecast
what mix of cooling facilities would have been installed
in the absence of federal environmental regulation.   Second,  a
certain percentage of the new power plants have already incurred
costs for the construction of cooling facilities.  Thus,the
incremental costs presented in Table-26 which were calculated
based on the assumption that no costs had been incurred for  alter-
native cooling facilities, actually under estimate the impact of
the guidelines.  Finally, there was a computational  error  in the
computer run that calculated the incremental cost of  the guidelines
after exemptions (e.g., policy alternative 7(e) in Part III).
Specifically, the costs that the utility industry would have
incurred for cooling systems in the absence of federal legislation
(e.g., Table-25) were not included for that fraction  of new  capacity
which will not be covered under the guidelines.  In  order  to
accurately predict the incremental costs of the guidelines after
exemptions, these costs would have to be added to the estimates
which were presented in Tables 27 and 29.

         It can be concluded, therefore, that the actual incre-
mental costs of the guidelines fall in between the total cost
estimates  (Table -22 ) and the incremental cost estimates (Table
26).  If one assumes the worst case, namely that the  incremental
cost actually equals the total cost, the capital requirements of  the
guidelines would increase 5.3 billion dollars by 1983-—'   Since
this would increase the utility industry's capital requirements only
an additional 1.4% by 1983, there is no  reason to question  the
validity of the analyses'  major conclusions.

         The final crucial assumption was that the report  analyzed
the impact of the guidelines based on a single set of assumptions
about the growth in demand for electricity.  Consequently, another
computer run was made using a low forecast for the growth  in demand.
The analysis indicates that the projected expenditures between  1974
and 1983 for generation and transmission facilities  is reduced
about 31% — from 364 to 250 billion dollars.!'  Since the projected
impact of the guidelines after exemptions is reduced  by only about
20%,the percent increase in the utility industry's capital require-
ments by 1983 will increase from 2.5% to about 3%.-'  It can be
concluded, that even tfnder assumptions of low demand, the  utility
industry should be able to comply with the guidelines without
experiencing serious problems in financing the required expenditures,
I/ Tables 33 and 34 summarize estimates  of  the  total  cost  of  the
   guidelines before and after exemptions.
2y See Part III, p. III-122 for a description of  the  low demand
   case.
_3_/ Estimate assumes that the percent variation  in Policy Alternative
   1-E (low demand) is the same as  the percent  variation in  EPA's
   proposed guidelines.
                           11-67

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    C.  Remaining  Questions

        Probably  the  most important area that hasn't  been
discussed  is  how  the  economic impact will vary by region and
by utility  system.  The major determinants of the variation
in economic impact  are:

        1.  Percentage of existing and planned capacity
            without closed cycle cooling systems,

        2.  Percentage of existing capacity that is baseload.

        3.  Cost  of installing cooling towers on existing
            and planned capacity.

        4.  Cost  of replacement power.

        5.  Percentage of existing and planned capacity which
            will   receive exemptions.

        6.  Projected demand for electricity.

        7.  Projected efficiency losses due to increased
            tubine  track-pressure.

        While there was not sufficient time to collect and
analyze data  on the above variables, the regional variation
in economic impact  should correspond to the results of a pre-
vious study of  the  economic impact of  pollution control
expenditures.L'   This study found that the relative impact
would vary  as follows:

        Region                       Relative Impact—/

      l.New England                   Average
      2.Middle Atlantic               Average
      3.East  North  Central            High
      4.West  North  Central            Average
        (except Nebraska)
      S.Nebraska                       Low
      6.South Atlantic                High
      7.East  South  Central            High
         except TVA)
      S.Tennessee Valley Authority    High
      9.West  South  Central            Low
      10.Rocky Mountain                Average
      11.Far West                       Low
      12.California                     Low

iyNational  Economic Research Associates, Possible Impact on Costs of
  Selected Pollution Control Equipment on the mectric utility industry
  and Certain Power Intensive Consumer Industries,  Jan. 1972.
^/Impact relative to the  averaged national impact.

                          11-68

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                           TABLE 31


MINIMUM AND MAXIMUM ESTIMATES OF CAPITAL AND OPERATING COSTS PER UNIT
OF GENERATING CAPACITY ASSOCIATED WITH THERMAL EFFLUENT GUIDELINES^/
                                Non-Nuclear Capacity        Nuclear Capacity
                                Minimum    Maximum         Minimum    Maximum
Capital Expenditures ($/kw)
 for Back-Fitted Units          $10.00      $28.00          $12,00     $38,00
 for New Units                    7.50        7.50           10.00      10.00
Annual Operating Expena«s
  ($/kw)l>

  for 1977 Guidelines             21.00       84.00           21.00      84,00
  for 1983 Guidelines             12.00       18.00            6.00      24.00
Capacity Losses

 due to Running Cooling Units      1%          1%              1%         1%
 due to Increased Back Pressure    15               15
I/ All costs are specified at 1970 levels.
2J Total annual operating costs for a plant that installs a cooling tower
   equals  (capacity of plant) X (annual operating costs/kw) X (% capacity
   losses  per plant)
                                11-69

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                                   TABLE 32
            ESTIMATES OF CAPITAL ANfl OPERATING COSTS PER UNIT OF GENERATING
                CAPACITY ASSOCIATED WITH CHEMICAL EFFLUENT GUIDELINES^/
Capacity Placed in Service;

Prior to 1971
 Capital Expenditures
 Annual Operating Expenses

1971-1977
 Capital Expenditures
 Annual Operating Expenses
1977 Guidelines

  Non-Nuclear Capacity
      ($/Kilowatt)

             Maximum
    EPA      Industry
  Estimate   Estimate
    $1.95
      .85
     1.05
      .55
$17.00
  1.35
 11.00
  0.90
               Nuclear Capacity
                 $/Kilowatt)

                        Maximum
               EPA      Industry
             Estimate   Estimate
$.85
 ,50
 ,.85
 .,50
$7.00
 1.15
 4.50
 0.75
Capacity Placed in Service:
1983 Guidelines^

  Non-Nuclear Capacity
      ($/Kilowatt)
             Maximum
    EPA      Industry
  Estimate   Estimate
Prior to 1971
 Additional Capital                $3.35      $5.00
  Expenditures
 Annual Operating Expenses           .65       0.25

1971-1977
 Additional Capital Expenditures    2,75       3.30
 Annual Operating Expenses           .35       0.15

1978-1983
 Capital Expenditures               2.60      14.30
 Annual Operating Expenses           .25       1.05
               Nuclear Capacity
                 ($ Kilowatt)
                        Maximum
               EPA      Industry
             Estimate   Estimate
                             $2.75

                               .35
                              2,75
                               ,35
                              2.00
                                .20
                          $3,00

                           0.25
                           2,00
                           0,15
                           6.50
                           0.90
I/ All costs are specified at 1970 levels.
2J Estimates represent the incremental costs of the 1983 standards.
                                        11-70

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M
M
I
                                                TABLE 33

                    SUMMARY OF  THE  TOTAL  COST  OF THE  EFFLUENT  LIMITATION  GUIDELINES

Level
I
1977 Standards

Impact
Financial Effects
1. Capital investment (billion $)
2. % increase over baseline
Price Effects
1. Increased revenues per year (billions)
2, Price increase in mills/kwh
3. Price increase (% cost to final user)
Capacity Penalty
1. Total capacity penalty i/
2. % o£ national capacity
Fuel Penalty
1. Total fuel penalty (million tons
coal equivalent )?-'
2. % of national demand for energy
Before
Exemptions

9.4
10.0%

1.4
.5
2.4

2,800
.5

6

.15%
After
Exemptions

3.8
4.0%

1.0
.4
1.7%

1,700
,3%

4

,1%
Level
II
1983 Standards!/
Before
Exemptions

28.5
7". 8%

6.2
1.7
5.5%

17,300
2,2%

38

.9%
After
Exemptions

14.5
4.0%

3.7
1.0
3.3%

5,900
.7%

13

.4%
      17 Total replacement  capacity needed to run the cooling towers and to compensate for
         capacity lost  due  to  increased turbine back pressure.
      2] Total increase in  demand for nuclear and fossil fuel expressed in million BTU and
         divided by the average BTU per ton of coal (e.g., 24 million BTU).
      3_/ Figures shown  for  Level II represent the cumulative effect of 1977 and 1983 standards.

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                           TABLE 34
       SUMMARY OF THE TOTAL COST OF NEW SOURCE PERFORMANCE
                      STANDARDS. 1983-1990
                                       Cost of New  Source Performance
                                            Standards - 1983-1990
        Impact
Financial Effects
  1.  Capital Investment
  2.  % increase over baseline

Price Effects
  1.  Increased revenues per year
  2.  Price increase
  3.  Percentage increase in price

Capital Penalty
  1.  Total capacity penalty—'
  2.  % of national capacity

Fuel Penalty
  1.  Total fuel penalty
      (million tons coal equivalent)—'
  2,  % of national demand of energy
  Before
Exemptions
23.2 billion
 3.8%
 4.5 billion
  .2 mills/kwh
  .5%
13,600 JJWe
 1.1%
 30 million tons

  .5%
  After
Exemptions
12.1 billion
 2.0%
 2.7 billion
  .1 mills/kwh
  .25%
6,300
  .5%
  14 million
   tons
  .2%
_!_/ Total replacement capacity needed to run the cooling towers
   and to compensate for capacity lost due to increased turbine
   back pressure.
2_l Total increase in demand for nuclear and fossil fuel expressed
   in million BTU and divided by the average BTU per  ton of  coal
   (e.g., 24 million BTU).
3_/ Figures represent the incremental effect of New Source  Performance
   Standards between 1983 and 1990.
                            11-72

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                          PART III
                      TECHNICAL APPENDIX-/
I/ The technical appendix is reproduced in full from a report
   entitled,  "The Economic Impact of Alternative Water
   Effluent Guidelines on the Electric Utility Industry,"
   which was  submitted to EPA in March, 1974 by Temple,
   Barker,  and Sloane, Inc.  in fulfillment of Contract
   No.  68-01-2418.

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             1,  PURPOSE AND SCOPE
          This report focuses on the economic and
financial implications of the water effluent guidelines

established pursuant to the Federal Water Pollution Control

Act of 1972 (the Act) for the electric utility industry.


          The economic consequences of the Act

include:

          •    capital expenditures for pollution
               control equipment;

          •    the costs of operating that pollution
               control equipment;

          •    capital expenditures for the added
               generating capacity needed to offset
               the reduced efficiency of generating
               plants resulting from the operation
               of cooling equipment; and

          •    the costs of operating these additional
               generating units.


          The magnitude of these direct and induced

economic costs is primarily  a function of:


          •    the industry's future demand;

          •    the industry's future reserve
               margins and load factors;

          •    the mix of nuclear and fossil-fueled
               capacity brought into service in
               each year;
                    III - 1 -

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          •    the percentage of each type of
               generating capacity affected by
               the Act;

          •    the time  phasing of these pollution
               control requirements;

          •    the capital costs associated with the
               installation of pollution control
               equipment in new plants;

          •    the capital costs of retro-fitting
               existing  capacity;

          •    the direct operating costs of this
               equipment; and

          •    the impact of cooling towers on the
               generating efficiencies of the plants
               affected by the Act.

          The foregoing direct and induced economic
costs will in the long run be borne by the consumers

of electrical energy,  but the impact in the shorter
run will largely be absorbed by the capital markets.
The distribution of the financial burden between
consumers and the capital markets as of any particular

time is a function of:
               the proportions of operating costs and
               capital expenditures associated with
               the Act's standards ;

               tax and regulatory policies with
               respect to the depreciation of the
               pollution control equipment ;

               the industry's dividend and capital
               structure policies; and

               capital market conditions.
                        III-2-

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          This study projects the economic and

financial consequences of a number of assumptions

supplied by the Environmental Protection Agency

(EPA) concerning the percentage of each type of

generating capacity affected by the Act.  These al-

ternative coverage policies include:


          •    a baseline assumption of no
               limitations on chemical and thermal
               effluent;

          •    the coverage implicit in existing federal,
               state and local thermal pollution
               control regulations;

          •    the assumption that only the Act's
               chemical pollution control standards
               are in force;

          •    the maximum percentages of existing
               and new nuclear and fossil-fueled
               generating capacity potentially
               affected by the Act; and

          •    the reductions in this maximum
               coverage possibly afforded by
               exemptions from the Act's standards
               that are available in Section 316(a)
               of the Act.


          This study also projects the impact of the
latter two issues above under various assumptions

with respect to the time phasing of the Act's thermal
pollution control requirements.  Considered are a
variety of different time schedules for:

          •    the completion date for the retro-
               fitting of the water cooling equipment
               required on existing nuclear and
               fossil-fueled plants; and
                        III-3-

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               the  date  after  which  all  plants
               coming  into  service must  be  fitted
               with thermal pollution  control
               equipment.
          To take account of technical uncertainties

concerning the equipment required to control chemical

and thermal water pollution, this study also reviews

the impact of various combinations of maximum,  most-

likely,  and minimum estimates for:

          •    the capital costs of the chemical
               and thermal pollution control equip-
               ment required per unit of generating
               capacity;

          •    the operating costs of such equipment;
               and
               the impact of the thermal equipment
               on generating efficiencies.
          Finally, the study examines the implications

of the Act under two different sets of assumptions

concerning rates of growth in the demand for electrical

energy :


          •    a most-likely projection consistent
               with that of the 1973-1974 National
               Power Survey; and

          •    a low-growth projection intended to
               reflect the potential impact on de-
               mand of energy conservation policies
               and escalating costs per kilowatt
               hour (kwh) of energy.
                        III-4-

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          The impact of the Act is described in terms
of the following financial and physical variables:

          •    changes in the industry's capital-
               ized expenditures, i.e., expenditures
               for in-service generating capacity,
               for construction work in progress,
               and for allowances on funds used
               during construction;
          •    changes in external financing require-
               ments;
          •    changes in yearly operating revenues
               and operations and maintenance
               expenses;
          •    average cost per kwh of electricity;
               and
          •    capacity and energy penalties.
          These major industry variables are projected
for each of five time periods:
          •    1974-1977
          •    1978-1983
          •    1974-1983
          •    1984-1990
          •    1974-1990
          The scale of the calculations required to
project the magnitude of  the economic consequences
of the Act and the distribution of the financial burden
between consumers and the capital markets over time
for a wide variety of technical assumptions and policy
alternatives dictated the use of a computer model
of the electric utility industry.  The model used in
this study, PTm, is an extension of a model developed
                      III-5-

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by Dr. Howard W. Pifer of Temple, Barker & Sloane,
Inc.,  and Professor Michael L. Tennican of Harvard
University, Graduate School of Business Administration,
to provide projections for the Technical Advisory Com-
mittee on Finance (TAC-Finance) to the 1973-1974
National Power Survey.  A brief overview of PTm is
provided in the Appendix to this report.
                           III-6-

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            2,  SUMMARY CONCLUSIONS
2.1  Introduction
          Section 2 summarizes the analysis of Sections
3 through 8 by focusing on the two policy options, la-
belled Policy Alternatives 1 and 3, at the ends of the
spectrum considered by the EPA and on the option, Policy
Alternative 7, proposed by the EPA.  Each of these policy
alternatives is examined both before and after consid-
eration of the exemptions from required closed-cycle
cooling systems estimated by the EPA to be available
under Section 316(a) of the Act.  In addition, Section 2
briefly reviews the economic and financial implications
of the Act under the assumption of reduced rates of
industry demand growth such as may stem from a contin-
uation of recent price and non-price induced energy con-
servation efforts.  Finally, this section presents a brief
summary of an earlier report submitted by TBS to the EPA
concerning the effects of technological uncertainties
about the capital costs, operating costs, and generating
plant efficiency losses of pollution control equipment.

          A brief overview of the policy alternatives
and alternative technological assumptions is as follows:
          •    Policy Alternative 0:  A base for
               reference which assumes no thermal
               or chemical effluent controls.
                     Ill - 7 -

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•    Policy Alternative 1:  An alternative
     calling for increasingly strict limi-
     tations on chemical effluents by 1977 and
     by 1983 and for closed-cycle cooling
     systems by 1977 on all but cyclic and
     peaking generating capacity built prior
     to 1978.  These cyclic plants are required
     to be fitted with closed-cycle cooling
     systems by 1983 while peaking units are
     not covered by the guidelines.  The chemical
     and thermal pollution control aspects of
     Policy Alternative 1 are also discussed
     separately as Policy Alternatives 1-C and
     1-T.   The impact on Policy Alternative 1
     of the thermal equipment exemptions esti-
     mated to be available under Section 316(a)
     of the Act is discussed as Policy Alternative 1-E,

•    Policy Alternative 3:  An alternative which
     assumes that generating plants began after
     publication of the EPA regulations (estimated
     to be those fossil and nuclear plants coming
     into service after 1978 and 1981, respec-
     tively) have closed-cycle cooling systems
     as of their in-service dates and which
     assumes that all other capacity is brought
     into compliance with the Act's standards
     by 1983.  Policy Alternative 3's eventual
     coverage of generating capacity is iden-
     tical to that of Policy Alternative 1;
     the two differ only in their time schedules
     for the installation of thermal pollution
     control equipment.  The effect of exemptions
     estimated to be available under Section
     316(a) of the Act is discussed as Policy
     Alternative 3-E.

•    Policy Alternative 7:  The policy alter-
     native being proposed by the EPA.  This
     policy option assumes that pre-1971 peak-
     ing capacity is retro-fitted with closed-
     cycle cooling systems by 1983, but otherwise
     calls for the same eventual coverage as Policy
     Alternatives 1 and 3.  The time schedule
     for the imposition of these requirements
     is an intermediate one, however, calling
     for a time phasing that depends, among
     other things, on the size of any given
     plant.  Policy Alternative 7 with Section
     316(a) exemptions is labelled Policy Alter-
     native 7-E.

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Policy Alternatives l(a)-(g):   Policy
Alternative 1 for the 1974-1983 period
under different assumptions with respect
to:

    the capital and operating costs of
    chemical pollution control equipment;

    the capital costs of retro-fitting
    thermal pollution control equipment;
    and

    the operating costs and efficiency
    losses associated with closed-cycle
    cooling systems.
          III-9-

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2.2   The Impact  of Selected  EPA Policy Alternatives
      Before Exemptions
           Before  consideration of the  impact of  pollution
control  requirements, the  electric utility industry is
projected to have the capitalized expenditures,  operations
and maintenance expenses,  and average  consumer charges
per kilowatt hour summarized  in Table  2.2-1.
                         Table 2.2-1

        BASELINE  INDUSTRY PROJECTION, EPA POLICY ALTERNATIVE 0:
                         SUMMARY DATA
       1974-1977
       1974-1983
       1974-1990
                    Capitalized
                    Expenditures
                   During Period
              Operating
               Expenses
             During Period
                     (billions of current dollars)
$93.8
$364.0
$968.1
$90.8
$322.3
$832.6
             Average Consumer
             Charges at End
              of Period	
             (cents per kwh)
2.40?
3.19?
4.32?
           Policy  Alternative  1,  which  calls for  rapid
compliance with the Act's effluent guidelines, results
in the  added capitalized expenditures  and operating
expenses shown in Table 2.2-2 below.
                            111-10-

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Table 2.2-2
THE IMPACT OF EPA POLICY ALTERNATIVE
SUMMARY DATA

1974-1977
1974-1983
1974-1990

(billions
Thermal
$11.2
$20.6
$41.5
Capitalized
Expenditures
of current dollars)
Chemical Total
$ 2.2 $ 13.4
$ 6.5 $ 27.1
$ 8.8 $ 50.3
1:

Operating
Expenses
(billions
Thermal
$ 1.4
$ 6.9
$17.6
of current
Chemical
$ 1.0
$ 5.9
$16.8
dollars)
Total
$ 2.4
$12.8
$34.4
The short-run and long-run impacts of Policy Alternative 1
can be highlighted via an inspection of the projections for
the 1974-1977 and 1974-1990 periods.  Capitalized expendi-
tures are increased relative to the baseline by 14.3 percent
in the 1974-1977 period, but only by 5.2 percent over the
1974-1990 period.  As is discussed further in Sections 3
and 4 of this report, these expenditures for pollution con-
trol equipment are financed in the short run largely via
new issues of debt, preferred stock, and common stock.  The
external financing associated with Policy Alternative 1's
pollution control expenditures is $11.0 billion in 1974-1977
and $33.5 billion over the entire 1974-1990 period.  As is
shown in Table 2.2-2, operations and maintenance expenses are
2.6 percent and  4.1 percent higher than the baseline in the
1974-1977 and 1974-1990 periods.

          Policy Alternative 3 assumes a time schedule
for the installation of closed-cycle cooling systems that
is substantially delayed relative to that of Policy Alterna-
tive 1.  As a consequence of inflation and of the greater
technical difficulties inherent in retro-fitting, the capital
costs per unit of capacity rise relative to those in Policy
Alternative 1.   On the other hand, the EPA has assumed
                      III-ll-

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technological improvements over time that result in lower
operating costs for units installed after 1977.  Summary
data on capitalized expenditures and operating costs for
Policy Alternative 3 are shown in Table 2.2-3.
Table 2.2-3

THE IMPACT OF EPA
POLICY
ALTERNATIVE 3:

SUMMARY DATA

1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
(billions of current
Thermal Chemical
$ 2.7 $ 2.2
$30.2 $ 6.5
$47.4 $ 8.8

dollars)
Total
$ 4.9
$36.7
$56.2
Operating
Expenses
(billions of current
Thermal Chemical
$ 0.3 $ 1.0
$ 2.3 $ 5.9
$ 9.5 $16.8

dollars)
Total
$ 1.3
$ 8.2
$26.3
Capitalized expenditures for Policy Alternative 3 are
substantially below those of Policy Alternative 1 in
1974-1977, being only 5.2 percent above the baseline in-
dustry projection.  On the other hand, despite the major
differences assumed in the timing of thermal pollution
controls, Policy Alternative 3's capitalized expenditures
over the full 1974-1990 period are only $5.9 billion higher
than those of Policy Alternative 1, or 5.8 percent
above the baseline.  Operating expenses for Policy Alterna-
tive 3 are lower over all time periods than for Policy
Alternative 1.  The 1974-1977 expenses are 1.4 percent
above baseline; the 1974-1990 expenses are 3.2 percent
above baseline.
                        111-12-

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          Policy Alternative 7 stipulates that pre-1971
peaking capacity have closed-cycle cooling for 1983, result-
ing in $0.5 billion of capitalized expenditures for these
peaking plants in the 1978-1983 period and in small amounts
of related operating expenses in subsequent years.  However,
as is suggested in Table 2.2-4, Policy Alternative 7 is in
other respects an intermediate position between Policy Al-
ternatives 1 and 3.  Policy Alternative 7 results in 1974-
1977 capitalized expenditures for pollution control that
are 10.0 percent above the baseline and in 1974-1990 totals
that are 5.3 percent higher than the baseline. In sum,
Policy Alternative 7, like Policy Alternative 3, entails
much lower capitalized expenditures  and  external financing
requirements in the 1974-1977 period than does Policy  Alternative
1.  Furthermore, Policy Alternative 7's thermal pollution
equipment is installed early enough in the 1974-1990
period so as to entail only slightly higher total capitalized
expenditures than Policy Alternative 1.  However, this in-
stallation schedule also means that much of the equipment is
installed too early to capture the reduction in operating
costs assumed by the EPA to take place in 1977.
Table 2.2-4
THE IMPACT OF EPA POLICY ALTERNATIVE 7:
SUMMARY DATA

1974-1977
1974-1983
1974-1990
Capitalized
Expenditures
(billions of current
Thermal Chemical
$ 7.2 $ 2.2
$22.0 $ 6.5
$42.9 $ 8.8
Operating
Expenses
dollars)
Total
$ 9.4
$28.5
$51.7
(billions
Thermal
$ 0.4
$ 6.4
$17.4
of current
Chemical
$ 1.0
$ 5.9
$16.8
dollars)
Total
$ 1.4
$12.3
$34.2
                         111-13-

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2.3  The Impact of Selected EPA
     Policy Alternatives After Exemptions
          The  potential  economic  and  financial impact of
the Act may be reduced  dramatically by  the exemptions
from thermal  control requirements available in Section 316(a)
of the Act.   The EPA has estimated that the retro-fitting
of pre-1978 capacity will be  reduced  to approximately 20
percent of the levels assumed in  the  preceding discussion
and that capacity  coming into service in 1978 or later will
have coverages roughly  half that  assumed before consideration
of exemptions.
          Tables 2.3-1 and 2.3-2 below,  which present summary
data on Policy Alternatives 1-E and 3-E, clearly show the
impact of exemptions from the Act's thermal effluent  guidelines
Table 2.3-1
THE IMPACT OF EPA POLICY ALTERNATIVE 1-E
SUMMARY DATA
Capitalized
Expenditures

1974-1977
1974-1983
1974-1990
(billions
Thermal
$ 3.2
$ 7.3
$17.1
of current
Chemical
$ 2.2
$ 6.5
$ 8.8
dollars)
Total
$ 5.4
$13.8
$25.9
(billions
Thermal
$ 0.3
$ 1.7
$ 5.1
Operating
Expenses
of current
Chemical
$ 1.0
$ 5.9
$16 . 8

dollars)
Total
$ 1.3
$ 7.6
$21.9
                           111-14-

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Table 2.3-2
THE IMPACT OF EPA POLICY ALTERNATIVE 3-E
SUMMARY DATA
Capitalized Operating
Expenditures Expenses
(billions
Thermal
1974-1977 $ 1.7
1974-1983 $ 9.8
1974-1990 $18.8
of current dollars) (billions of current dollars)
Chemical Total Thermal Chemical Total
$ 2.2 $ 3.9 - $ 1.0 $ 1.0
$ 6.5 $16.3 $ 0.7 $ 5.9 $ 6.6
$ 8.8 $27.6 $ 3.6 $16.8 $20.4
The sharp reduction in retro-fitting requirements assumed
to occur as a result of 316(a) exemptions means that capital-
ized expenditures for thermal equipment drops sharply in
the 1974-1977 period for Policy Alternative 1-E relative to
Policy Alternative 1; the decline is from $11.2 billion to
$3.2 billion, or 71.4 percent.  The impact of the reduced
retro-fitting requirements is, of course, spread out over
longer time periods for the other policy options.  The per-
centage declines in the post-1977 period are also reduced
by less dramatic amounts because the EPA has assumed that
exemptions will have less impact on new source coverages
than on the retro-fitting of existing generating capacity.
          Policy Alternative 3-E provides an analysis of the
impact of exemptions whenever the installation of closed-
cycle cooling systems is delayed substantially.  Once again,
Policy Alternative 7-E yields an intermediate position.
                        111-15-

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   2.4   The  Impact of Reduced Industry Growth
              A  baseline projection for  the  electric utility
   industry assuming  approximately a 25  percent reduction in
   future  rate  of demand growth  is summarized in Table  2.4-1.
                               Table 2.4-1

           BASELINE INDUSTRY PROJECTION,  EPA POLICY ALTERNATIVE  0
                       (LOW DEMAND): SUMMARY DATA
  1974-1977
  1974-1983
  1974-1990
              Capitalized
              Expenditures
              During Period
                  Operating
                  Expenses
                During Period
               (billions of current dollars)
$63.8
$249.0
$585.1
$ 85.9
$293.3
$708.2
                Average Consumer
                 Charges at End
                   of Period
              (cents per kilowatt  hr .)
2.35'?
3.08'?
4 .09'?
             The  economic and  financial consequences  of
  Policy  Alternative  1  under such  demand assumptions  are
  summarized in  Table 2.4-2.
                              Table 2.4-2

                   THE  IMPACT OF EPA POLICY ALTERNATIVE 1
                       (LOW DEMAND) : SU»UAi1Y DATA
                     Total
                  Capitalized
                  Expenditures
                                 Total
                                Operating
                                Expenses
            (billions of current dollars)   (billions of current dollars)
1974-1977
1974-1983
1974-1990
     $11.4
     $21.4
     $34.3
               $ 1.9
               $11.4
               $30.3
                                 IH-16-

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          As is evident in these data, the effect of approxi-
mately a 25 percent reduction in the industry's future demand
growth is to reduce the total dollars of capitalized expendi-
tures and operating expenses substantially relative to those
projected for higher demand growth, from $13.4 billion to
$11.4 billion (14.9 percent) in the 1974-1977 period and
from $50.3 billion to $34.3 billion (31.8 percent) in the
1974-1990 period.  Note, however, that the industry's baseline
capitalized expenditures decline even more rapidly, from $93.8
billion to $63.4 billion (32.4 percent) and from $968.1 billion
to $585.1 billion (39.6 percent) in the same periods.  Thus,
expenditures for pollution control equipment represent an
increased share of total expenditures, rising to 17.7 percent
for the 1974-1977 period and to 5.9 percent for the 1974-1990
period.  These figures contrast with 14.3 percent and 5.2
percent pollution equipment increases relative to the baseline
under the most-likely demand growth forecast.
          Unfortunately, these significant reductions in
expenditures are not passed through to the consumer.  The
above-mentioned reduction in peak load demand would reduce
1990 consumer charges from 4.32£/kwh to 4.09£/kwh (5.3 percent)
                       111-17-

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2.5  The Impact of Alternative
     Technological Assumptions
           Alternative assumptions about  the capital  and
operating  costs of chemical  and thermal  pollution control
equipment  and about the  impact on generating efficiencies
of closed-cycle cooling  systems may have a substantial
impact on  the projected  consequences of  the Act.  In  addition
to the "most-likely" estimates used in the analyses  sum-
marized  above, the EPA has  estimated "maximum" capital  and
operating  costs for chemical equipment,  "maximum" and "mini-
mum" capital costs for retro-fitted thermal equipment,  and
"maximum"  and "minimum"  operating costs  and efficiency
losses  for thermal equipment.  The effects over the  1974-
1984 period of these technological uncertainties are sum-
marized  in Table 2.5-1.   The costs shown are the impact of
each assumption relative to the baseline "most-likely"
assumptions incorporated in Policy Alternative l(a).
                          Table 2.5-1

           THE IMPACT OF POLICY ALTERNATIVES l(b)-l(g) RELATIVE
            TO POLICY ALTERNATIVE l(a): SUMMARY DATA
                          Capitalized         Operating
                          Expenditures        Expenses
                           (billions of current dollars)
   Chemical Cost Factors
      Maximum
   Thermal Retro-Fitting
      Capital Costs
      Maximum
      Minimum
   Thermal Operating Costs
   and Efficiency Losses
      Maximum
      Minimum
  $12.9
+ $ 6.1
- $ 2.8
+ $ 6.6
- $ 1.3
+ $ 2.9
+ $18.9
- $ 3.1
                            111-18-

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2.6   Guide to  the Remainder of the Report
         Further discussions of the policy alternatives
mentioned in this section and of other policy options sub-
mitted by the EPA for analysis by TBS are contained in
Sections 3 through 8.  Section 3 projects and discusses
the major economic and financial variables for the electric
utility industry through 1990 under the assumption of no
chemical or thermal effluent controls either at the federal
level or at the state and local level.  With this baseline
forecast as background, Section 4 turns to a detailed pro-
jection and analysis of Policy Alternative 1, the option
from which the EPA's final policy proposal evolved.  Section
5 describes the economic and financial impact of each of
the EPA's seven primary policy options before consideration
of exemptions.  Section 6 then discusses the impact of
exemptions on a selected subset of the seven primary policy
alternatives.  Section 7 analyzes the implications of
pollution control requirements under a different set of
assumptions about the industry's future demand growth.
Section 8 concludes the report with a review of the impact
of alternative technological assumptions.  Appended to the
report is a brief description of PTm, the computer model
used to generate the economic and financial projections
discussed in this report.
                    111-19-

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  3,   BASELINE ELECTRIC UTILITY INDUSTRY PROJECTIONS:
               EPA POLICY ALTERNATIVE 0


3.1   Introduction
          In order to discuss the economic and the
financial implications of the Act's proposed guidelines,
it is important to establish a point of reference from
which comparisons can be made.  In doing so, the un-
certainties inherent in forecasting conditions within
the electric utility industry which are unrelated to
the Act can be segmented from those associated with
the Act.  This reference point requires the establish-
ment of a set of baseline conditions, which will be
referred to as Policy Alternative 0 in later sections
wherein comparisons of specific policy alternatives
will be made.  These baseline conditions exclude any
impact associated with existing state and local en-
vironmental standards, as well as federal standards
as specified in the Act and the Clean Air Act of 1970.
Thus, Policy Alternative 0 represents what utilities
would expend in the absence of environmental regula-
tions .

          In the absence of the Act, existing thermal
and chemical pollution standards would remain in force.
Section 4.5 evaluates the economic impact of these
existing standards.  While some might argue that these
federal, state and local standards should be included
                   III - 20 -

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in the baseline conditions, TBS believes that these
standards do not adequately reflect the water quality
standards which would be imposed in the absence of the
Act.  Recent concern with environmental integrity sug-
gests that more stringent standards would have been en-
acted in some areas if federal legislation had not been
passed.   On the other hand, the more recent "energy
crisis"  has perhaps changed the balance between environ-
ment and energy conservation.

          This analysis does not deal with the
economic impact and financial implications associated
with the Clean Air Act of 1970 due to a current lack
of detailed engineering and economic assessments.  It
is anticipated that future analyses will include these
impacts.
                        111-21-

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3.2   Policy Alternative 0 Assumptions

          Because the electric utility industry com-
prises both investor-owned ("private") and other ("public")
firms and because there are fundamental cash-flow dif-
ferences between those private firms allowed by their
regulatory commissions to normalize income tax expenses
and those private firms required to flow through the
benefits of accelerated depreciation and other tax
shields, PTm in fact arrives at industry estimates via
summation of the estimates for three separate industry
segments:

          •    publicly-owned        20 percent
          •    investor-owned,       48 percent
               normalized accounting
          •    investor-owned,  flow  32 percent
               through accounting

Given t-he relative  importance of the two types of
firms in the private  sector and the  paucity of cogent
information on the  financial characteristics of the
public  sector, the  two segments of the private sector
are  modelled  in  detail and  together  serve  as  a basis
for  estimating certain characteristics of  the public
sector.
 "''These assumptions are those used in the preliminary
  analysis provided to the TAC-Finance,  National Power
  Survey.
                     111-22-

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     3.2.1  Growth in  Generating Capacity.  Perhaps
the most critical set of assumptions relate to the
rate of growth assumed for the electric utility in-
dustry in the period through 1990.  Until the recent
"energy crisis." industry spokesmen assumed that the
current rate of growth which implied a doubling in
size each decade would continue through the 1970's
with a gradual decline during the 1980's.  These assump-
tions have been incorporated into the baseline conditions
and the policy alternatives defined in Sections 4 and
  2
5.   Specifically, the growth in peak load demand as
measured in kilowatts is assumed to grow in the follow-
ing way:
          •    1971 - 1980  7.2 percent per year
          •    1981 - 1985  6.7 percent per year
          •    1986 - 1990  6.6 percent per year

In addition to the growth in peak load demand, the
ensuing analyses assume that reserve margins will be
maintained at 20 percent and capacity load factors
at 51.4 percent.
2
 The EPA recognized the need to assess the economic and
 financial impact implicit in energy conservation;
 therefore, Section 7 provides analysis of policy
 alternatives in which peak load demand growth has
 been limited to:
          •   1971 - 1975    6.2 percent per year
          •   1976 - 1980    5.7 percent per year
          •   1981 - 1985    5.1 percent per year
          »   1986 - 1990    4.4 percent per year
                        IH-23-

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          In terms of industry growth, the above load
growth implies that generating capacity in the period
1970 through 1990 will be:

          •    1970   324.6 million kilowatts
          •    1975   459.6 million kilowatts
          •    1980   650.6 million kilowatts
          •    1985   899.8 million kilowatts
          •    1990  1238.6 million kilowatts

          The construction of new generating capacity
implicit in the above growth in peak load demand fore-
casts must also include the retirement of obsolete
fossil  gene
the rate of:
      3
fossil  generating capacity assumed to be retired at
          •    1971-1975  0.4 percent per year
          •    1976-1980  0.7 percent per year
          •    1981-1990  1.2 percent per year

          While much publicity has preceded the con-
struction of nuclear-fueled generating plants, less
than 2.2 percent of the generating capacity in service
prior to 1971 was nuclear-fueled.  Although environ-
mental and technical issues have delayed the conversion
to a nuclear-based electric utility industry, industry
spokesmen have assumed that the mix of generating
capacity additions will be:
_
 Throughout the analysis based upon PTm, "fossil-fueled"
 and "non-nuclear" will be used interchangeably to de-
 scribe generating capacity which is not "nuclear-fueled,
 In this context, hydro-electric generating capacity
 would be defined as "fossil-fueled."
                   111-24-

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               1971-1975  30 percent nuclear/70
                          percent non-nuclear
               1976-1980  40 percent nuclear/60
                          percent non-nuclear
               1981-1985  50 percent nuclear/50
                          percent non-nuclear
               1986-1990  60 percent nuclear/40
                          percent non-nuclear
     3.2.2  Growth in Cost Factors.  In an effort to assess
the cost escalation facing the electric utility indus-
try, the TAC-Finance conducted an informal, industry-
wide survey of existing utility construction plans
through 1980.  On the basis of this survey,  the TAC-Finance
                                 4
developed the cost growth factors  detailed in Table
3.2-1.  The post-1980 inflation rate of 5 percent was
then used as the basis for cost growth in other plant
and equipment, including nuclear fuel, as detailed in
Table 3.2-2.

          Although the generating capacity, related
transmission/distribution equipment and nuclear fuel
placed in service in any given year is determined by
the load growth requirements, the construction work
begins several years prior to the in-service date.
Moreover, the cash flow associated with generating
plant additions generally precedes the completion of
construction.  Changes in the related construction
4
 It should be noted that throughout this report, all
 dollar amounts will be specified in current dollars.
                      111-25-

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                              TABLE 3.2-1
                    GENERATING CAPACITY COST GROWTH
                     (expressed  in  current dollars)
                            1970       1975       1980       1985	     1990

Nuclear Generating
Capacity
  $ per kilowatt           $ 150      $ 308      $ 457      $ 584       $ 745
  % cost escalation
      Inflation               -        5.75%      5.65%         5%         5%
      Other                   -        9.20%      2.40%
Non-Nuclear Generating
Capacity
  $ per kilowatt           $ 120      $ 199      $ 292      $ 372       $ 475
  % cost escalation
      Inflation               -        5.60%      5.50%         5%         5%
      Other                   -        4.70%      2.40%
Gas Turbine Generating
Capacity
  $ per kilowatt           $  90      $ 118      $ 154      $ 197       $ 252
  % cost escalation
      Inflation               -        5.60%      5.50%         5%         5%
      Other                   -                                 -
                              111-26-

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                              TABLE 3.2-2

                 OTHER PLANT AND EQUIPMENT COST GROWTH
                    (expressed in current dollars)
                            1970      1975
Nuclear Fuel
  $ per kilowatt          $  38      $  48
 1980       1985        1990
$  62      $  79       $ 101
  % cost escalation
     Inflation                -  ,        \5%         5%         5%          £
     Other                    -

Transmission &
Distribution Equipment
  $ per kilowatt          $ 180      $ 230      $ 293      $  374       $173
  % cost escalation
     Inflation                -          5%         5%         5%        5%
     Other                    _____
                                  111-27-

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work in progress account historically constituted
a substantial portion of capital expenditures by the
electric utility industry.

          In order to approximate the cash progress
payments related to construction requirements, the
TAC-Finance assumed the payment schedules outlined
in Table 3.2-3.  For example, a $100 million nuclear-
fueled generating unit (with an additional $15 million
for nuclear fuel) placed in service in 1980 would re-
quire cash payments of:

                         Nuclear            Nuclear
                          Plant               Fuel
         1976         $25 million
         1977          25 million
         1978          25 million
         1979          25 million        $15 million
         1980

Likewise, a $100 million fossil-fueled generating
unit placed in service in 1980 and $100 million in
related transmission/distribution equipment would
require cash payments of:
                                 Transmission/
              Fossil Plant       Distribution
   1977       $ 25 million
   1978         25 million
   1979         25 million       050 million
   1980         25 million        50 million

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                 - 29  -


                     TABLE 3.2-3

SCHEDULE OF CONSTRUCTION WORK IN PROGRESS CASH PAYMENTS
       Capital Expenditures for Nuclear Generating
       Capacity (and related pollution control equipment)
       placed ir. service during Period T incurred by:
            •  Period T-l            100  Percent

            •  Period T-.2             75  Percent

            •  Period T-3             50  Percent

            •  Period T-4             25  Percent


       Capital Expenditures for Non-Nuclear Generating
       Capacity (and related pollution control equipment)
       placed  in service during Period T incurred by:

           •  Period T              100 Percent

           •  Period T-l             75 Percent

           •  Period T-2             50 Percent

           •  Period T-3             25 Percent
       Capital Expenditures for Nuclear Fuel placed
       in service during Period T incurred by:

           •  Period T-l            100 Percent
       Capital Expenditures incurred for Transmission and
       Distribution Equipment placed in-service during
       Period T incurred by:

           •  Period T              100 Percent

           •  Period T-l             50 Percent
                      111-29-

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          Regulatory agencies in the past have required
electric utilities to capitalize a portion of the fi-
nancing charges associated with the funds tied-up in
construction work in progress.  In 1970, this allowance
for funds used during construction (AFDC) approximated
5.25 percent of construction work in progress (CWIP).5

          In addition to capital expenditures, a pri-
mary target of cost inflation is the operations and
maintenance expenses which include expenditures for
fossil fuels.  Prior to the recent "energy crisis,"
the cost growth for fossil fuels approximated 10
percent while operations and maintenance expenditures
for nuclear generation (excluding fuel) were relatively
stable.  These patterns were expected to continue
through 1975 at which time cost escalation was assumed
to follow the industry level of 5 percent.  Table 3.2-4
details those assumptions.^

     3.2.3  Financial Policy Parameters.  The instruments
employed to finance the expansion of the electric
utility industry depend largely upon the financial
policies of the electric utilities and the policies
of the governing regulatory agencies.
51972 Federal Power Commission data suggests that the
 AFDC should be 7 percent of CWIP.
6Recent events within the oil industry suggest that the
 cost of fossil fuels will greatly exceed those assumed
 in this analysis.
                      Hi-30-

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                               TABLE 3.2-4


                   OPERATIONS AND MAINTENANCE GROWTH
                      (expressed in current dollars)



                        1970       1975       1980      1985      1990


Operations and
Maintenance Expenses:
Non-Nuclear Generating
Capacity

  $ per kilowatt hour    .70?     1.13?      1.44?     1.84?     2.34?

  % cost escalation

     Inflation            -         10%         5%        5%       5%
     Other                -          -          -


Operations and
Maintenance Expenses:
Nuclear Generating
Capacity (excluding
fuel)

   ? per kilowatt hour  .38?       .38?       .48?     .61?       .78?

   % cost escalation

      Inflation           -          -          5%       5%         5%
      Other               -          -          _
                                 Hl-31-

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          Throughout this analysis TBS has assumed

that the past policies of agencies which regulate the

electric utility industry will remain in force — specifi-
cally,  the overall structure of the industry with respect

to the mix of public and private firms as well as the

proportion of states which require private firms to

employ flow through accounting procedures.


          In addition, it is assumed that average

consumer charges per kilowatt hour will be set at
                                                        •7
levels which yield a 12 percent return on common equity.


          Likewise, the future capital structure of

electric utilities has been assumed to remain relatively

stable.  The mix of financing instruments for investor-

owned utilities is determined within PTm by the follow-

ing constraints upon their capital structure:

          •    long-term debt       no  more  than  55  percent

          •    preferred stock      no  more  than  10  percent


          •    common equity        at  least 35 percent
7It should be noted that this assumption is consistent
 either with a target 12 percent return and no regula-
 tory lag or a target rate in excess of 12 percent with
 time lags in the regulatory process.  In recent years
 the actual return on common equity has been between
 11 and 12 percent.  Previous analysis by Drs. Pifer
 and Tennican for the TAC-Finance has shown that vary-
 ing the required rate of return on common equity, while
 perhaps affecting the ease with which additional fi-
 nancing can be obtained, has minimal impact upon the
 amount of additional financing required.
                     111-32-

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In addition, a dividend policy which results in a
70 percent dividend payout ratio has been employed.

          Historically, the average rate of interest
on long-term debt and the dividend rate on preferred
stock have been approximately the same.  At the end
of 1970,the embedded rate for each was approximately
4.8 percent, a rate significantly below the existing
long-term rate of interest.  Acknowledging this fact,
TBS has assumed a 7.5 percent interest rate and dividend
rate for preferred stock.  Without a significant change
in the mix of financing instruments, the return on
common equity and/or the common stock dividend payout
ratio, these conditions wherein the marginal debts
rates exceed the embedded rates will result in lower
interest and preferred dividend coverage ratios.^

          For the public sector, it is simply assumed
that 65 percent of total financing requirements will
be met from external sources.

     3.2.4  Tax and Accounting Relationships.  Internal
cash generation in an industry as capital intensive
as the electric utilities depends heavily upon the
accounting procedures employed.  As previously men-
tioned, this analysis assumes that the electric
utility industry is segmented into public and investor-

 8'For example,  the assumptions implicit in Policy Al-
 ternative 0 result in the interest coverage ratio,
 defined as Earnings Before Interest Charges and In-
 come Taxes divided by Interest Charges, declining from
 3.335 in 1973 to 2.902 in 1990.  The marginal impact
 of the Act's effluent guidelines are insignificant.
                        111-33-

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owned firms with the latter group of utilities further
segmented into those which are required to use normal-
izing techniques and those which use flow through account-
ing procedures.  While these alternative accounting practices
change significantly both the timing of cash flows resulting
from generating capacity additions and the revenues required,
the actual liberalized depreciation policies and investment
tax credits need not differ.

          PTtn assumes straight-line depreciation
over 30 years for regulatory and financial accounting
purposes.  Tax depreciation figures are the maximum
allowed and make use of the asset depreciation range
(ADR) and the double-declining balance depreciation
provisions within the tax code.  An exception to the
above is nuclear fuel which is depreciation on a 3-
year, straight-line basis for both tax and regulatory
purposes.  In addition, a 4 percent investment tax
credit is permitted on 80 percent of capital expenditures.

          Taxes within PTm have been segmented into
federal (48 percent) and state (4 percent) income
taxes as well as additional taxes other than on in-
come which are assumed to approximate 11 percent of
revenue.9
  An example of the reconciliation of taxes within
  PTm is provided in Table 3.3-5.
                     111-34-

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3.3   Economic and Financial Consequences
     of Policy Alternative 0
          The assumptions  detailed in Section 3.2
define the baseline  conditions for the electric utility
industry and  are not  varied  in Policy Alternatives 1
through 7 which also  incorporate  different sets of
proposed thermal and  chemical  effluent guidelines.

          Table 3.3-1 provides selected summary
data obtained from the Policy  Alternative 0 baseline
assumptions.  Detailed PTm results for these same
baseline conditions  can be found  in Appendix A of
Economic and Financial Implications  of the Federal Water
Pollution Control Act of 1972 for the Electric Utility
Industry, a TBS report  submitted to the EPA on Sep-
tember 7, 1973 in fulfillment of Contract # 61-01-1582.
Tables 3.3-2 through  3.3-5 provide an example
of the level  of detail within  the investor-owned
sector which  is captured by  PTm.
          Table 3.3-1 displays the detail which will
be presented  for each policy alternative.  In order
to better understand  the specific definitions used,
a brief discussion of each variable follows:

     •    Capitalized Expenditures are the
          sum of capital expenditures (in-
          cluding the change in construction
          work in progress ( A CWIP)  and  the
          allowance for  funds  used during con-
          struction  (AFDC) in  any  given year.
          For example,  the 1977 capitalized
          expenditures  of  $28.2 billion can be
          segmented into:

          •    Private Sector              $23.0 billion
               -Capital Expenditures
                for  in-service plant  $17.1
               - A CWIP                 4.2
               -AFDC                    1.7
                         111-35-

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                                                           Table 3,3-1

                                                   POLICY ALTERNATIVE 0

                                 ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                          (dollar  figures in billions of current dollars)
                                                                         1973
                                                                                              1977
                                                             1983
                                                                                                                         1990
 Capitalized Expenditures:
                                                 Total for the Year
                                                 Total since 1973
                                                                        $15.4
                                            $28.2
                                             93.8
                                                                                                       $ 58.4
                                                                                                        364.0
                              $121.1
                               968.1
H    External Financing:
I
Total for the Year
Total since 1973
                                                                         $9. 5
                                                                                        $19.1
                                                                                         64.1
              $ 38.3
               244.4
$ 76.5
 624.8
Operating Revenues:
Operations & Maintenance Expenses:*
                                            Total for the Year
                                                 Total for the Year
                            $34.4


                            $16.0
                                                                                        $57.0


                                                                                        $26.6
              $113.6


               $48.6
$240.9


 $95.4
Consumer Charges:
(cents/kwh)
                                            Average for the Year
                                                                              1. 91
2.40
                                                             3.19
                                                                                                                              4.32
*Excludes nuclear fuel expense

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                              TABLE 3.3-2
                           POLICY ALTERNATIVE 0

         INVESTOR-OWNED ELECTRIC UTILITIES COMBINED INCOME  STATEMENT
                     (billions of current dollars)
Operating Revenue                                       $  90.9

  -Operating and Maintenance Expenses        $38.9
   (excluding nuclear fuel)

  -Taxes other than Income                    10.0

  -Depreciation (including nuclear fuel)      11.1

  ^Allowance for Interest on Construction
   Work in Progress                            3.7         56.3

Earnings Before Interest and Income Taxes               $  34.6
  -Interest Charges                                        11.8

Earnings Before Income Taxes                            $  22.8

  -Income Taxes (State and Federal)         $  9.4
  +Investment Tax Credits                      0.8          8.6
Net Income                                                 14.2

  -Dividends on Preferred Stock             $  2.1

  -Dividends on Common Stock                   8.5         10.6
Retained Earnings                                       $   3.6
                                111-37-

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                                TABLE 3.3-3
                           POLICY ALTERNATIVE 0
         INVESTOR-OWNED ELECTRIC UTILITIES COMBINED BALANCE SHEET
                        BASELINE CONDITIONS - 1983
                       (billions of current dollars)
Asset Accounts
   Gross Plant in Service                     $ 328.5
   -Accumulated Depreciation                     80.7
   Net Plant in Service                                      $247.8
   Net Nuclear Fuel                                             4.0
   Construction Work in Progress                           	71.0
   Net Electric Plant                                       $ 322.9
   Net Working Capital (assumed to be constant)                (0.5)
Total Assets                                                $ 322.4

Liability and Equity Accounts
   Deferred Tax Items                                       $  17.7
   Long-Term Debt-outstanding prior to 1971    $ 27.0
                 -issued after 1970             140.6
   Long-Term Debt - Total                                  $  167.6
   Preferred Stock -outstanding prior to 1971  $  6.9
                   -issued after 1970            23.6
   Preferred Stock - Total                                 $   30.5
   Owners' Equity  -outstanding prior to 1971  $ 24.7
                   -cash issues after 1970       56.7
                   -retained earnings after
                     1970                        25.2
'Owners' Equity - Total                                     $ 106.6
Total Liabilities and  Owners' Equity                       $ 322.4
                                 111-38-

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                                TABLE  3.3-4
                            POLICY ALTERNATIVE 0
        INVESTOR-OWNED  ELECTRIC  UTILITIES  COMBINED APPLICATIONS AND
                              SOURCES  OF FUNDS
                         BASELINE CONDITIONS  - 1983
                        (billions of current  dollars)

Applications of Funds
Capitalized Expenditures
   Non-Nuclear Generating  Plant               $7.6
   Nuclear Generating  Plant                   11.9
   Nuclear Fuel                                 1.6
   Transmission and Distribution Equipment     15.3
   Pollution Control Equipment                  0.0
   Increase in Construction Work in Progress    7.6
Total                                                         44.0
Capitalization of Allowance for
   Interest on Construction Work
   in Progress during  1982                                    3.3
Refundings of Long-Term Debt                                  0.8
Total Applications                                          $ 48.1
Sources of Funds
Internal Cash  Generation   ,
     Retained Earnings                      $ 3.6
     Depreciation (including
       nuclear fuel)                          11.1
     Deferred Tax Items                       2.1
Total                                                      $ 16.8
External Financing
     Long-Term Debt                         $19.6
     Preferred Stock  Issues                   3.4
     Common Stock Issues                      8.3
Total                                                      $ 31.3
Total Sources                                              $ 48.1

                                  111-39-

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                               TABLE 3,3-5
                           POLICY ALTERNATIVE 0
     INVESTOR-OWNED ELECTRIC UTILITIES COMBINED RECONCILIATION OF TAXES
                        BASELINE CONDITIONS - 1983
                       (billions of current dollars)
Earnings Before Income Taxes:   Reported
       -Accelerated Depreciation
       -Allowance for Interest on Construction
         Work in Progress
Earnings Before Income Taxes:  Tax Base

Income Taxes:  Paid
       -Investment Tax Credits (Actual)
       +Deferred Tax Items
       +Investment Tax Credits (Amortized)
Income Taxes: Reported
$   4.6
    3.7
              $ 22.8
                 8.3
    0.4
    2.1
    0.1
              $14.5
              $  7.6
1.8
              $  9.4

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             Public  Sector
             -Capital  Expenditures
              for in-service plant

             - £ CWIP
    $ 5.2 billion
$ 4.3

  0.9
        External  Financing Requirements are the
        sum of  long-term debt,  preferred stock
        and common equity stock issues in any
        given year,  including the refinancing
        of maturing long-term debt.10 pOr ex-
        ample,  the 1977 external financing
        requirements of $19.1 billion can be
        segmented into:
             Private  Sector

             -New Long-Term
              Debt              $9.1

             -Maturing Long-
              Term Debt          1.0

             -Preferred Stock
              Issues             1.6

             -Common Stock
              Issues             4.0

             Public Sector
   $15.7 billion
   $  3.4 billion
              The  difference  between  capitalized
              expenditures  and  external  financing
              requirements  in any  given  year  is
              the  amount  of funds  generated in-
              ternally  in the form of retained
              earnings, depreciation  and tax
              deferrals.
        Operating Revenues are those required
        to yield a 12 percent rate of return
        on common equity.  For example, the
        1977 operating revenues are estimated
        to be $57.0 billion.
10
  A schedule of long-term debt refundings through 1990
  has been estimated from published sources and in no
  year exceeds $1.7 billion.   Further,  PTm assumes
  that no new long-term debt  issues will mature prior
  to 1990.
                         111-41-

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Operations and Maintenance Expenses
include those items so defined by the
Federal Power Commission in its
Statistics of Pr-jvately Owned Eleotr-i-o
Utilities in the United States with  the
exception of nuclear fuel.  For example,
the 1977 operations and maintenance
expenses are estimated to be $26.6
billion.

Consumer Charges are the average amount
per kilowatt hour which is being paid
in any given year.  The amount of elec-
trical energy consumed is based upon
the growth in peak load demand,, the re-
serve margin and the capacity load factor
For example, the 1977 electrical energy
amount of 2378.0 billion kilowatt hours
is obtained from

     •   1970 peak load demand of
         270.5 million kilowatts;

     •   Growth in peak load demand
         1970-1977 of 7.2 percent per
         year;

     •   Reserve margin of 20 percent;

     •   Capacity  load factor of 51.4
         percent;  and

     •   8760 hours per year.
The actual numerical  calculation  is  (270.5
million kw)*  (1.072)7 *  (1.20)  *  (0.514)  *
(8,760 h) = 2378 billion  kwh.

The average consumer  charge  per kilowatt
hour  is obtained by dividing operating
revenues by the total electrical  energy
consumed.  For example,  the  average  con-
sumer charge  for 1977 is  estimated to be:

      $57.0 billion    =  2.40?/kwh
    2378 billion kwh         Y/
              111-42-

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          The summary data for Policy Alternative 0
indicate the magnitude of growth which the electrical
utility industry will undergo during the period 1974-
1990.   Even without the added expenditures required
to meet the Act's effluent guidelines, the industry
is expected on an annual basis to expand:

          •    Capitalized Expenditures     13 percent
          •    External Financing Re-
               quirements                   13 percent
          •    Operating Revenues           12 percent
          •    Operations and Maintenance
               Expenditures                 11 percent
          •    Consumer Charges              5 percent

          The rapid growth in both capitalized expen-
ditures and external financing requirements reflects the
effects of the assumed growth in peak load and cost
factors.  The slightly lower rate of growth in opera-
ting revenues results from the time lag between capital
outlays and the associated cost burden passed on to the
consumer.   The industry's conversion to nuclear-based
generation is the primary factor in holding down the
rate of growth in operations and maintenance expendi-
tures to 11 percent.  Finally, the relatively small
increase in the average consumer charge per kilowatt
hour closely parallels the underlying long-run rate
of inflation.
                     111-43-

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     4,  ELECTRIC UTILITY  INDUSTRY PROJECTIONS:
              EPA POLICY ALTERNATIVE 1
4.1  Introduction


          Section 3 of this  report  specified a set
of baseline conditions which do  not include the costs
associated with the Act's effluent  guidelines;  the remaining
analyses deal with alternative sets of proposed effluent
guidelines.   Section 4 concentrates upon Policy Alternative

1, a set of conditions which were referenced in a  previous
TBS report to the EPA as combining:


          "...the "most-likely"  estimates of the
          capital and operating  costs for both
          thermal and chemical pollution control
          equipment and their impact upon opera-
          ting efficiencies with the "maximum"
          coverage levels anticipated to repre-
          sent the "most-likely" set of circum-
          stances with environmental-related
          costs."1
  Eoonomic and Financial Implications of the Federal Water Pollution
  Control Aat of 1972 for the Eleetrie Utility Industry (September 1973);
  page4-2, Policy Alternative 1 is identical to  Case X  in
  the previous report and differs  from  Case  I only  by in-
  cluding the addition of new source pollution control
  equipment during the 1984-1990 period.  TBS has described
  Policy Alternative 1 in greater  detail than other policy
  alternatives in order to provide continuity between re-
  ports.   This extensive coverage, therefore, should not
  imply that Policy Alternative 1  is the preferred  option.
                        Ill -  44  -

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4.2   Policy Alternative 1 Assumptions


          To estimate the operational impacts of com-
pliance with the Act, the EPA has specified water  effluent
guidelines for both thermal and chemical pollutants.   In

order to provide a basis from which to properly eval-

uate the alternative policies proposed for effluent

guidelines, TBS has divided Policy Alternative 1 into

its two components:


          •    Policy Alternative 1-T which
               provides the economic and financial
               implications for only the thermal
               standards; and

          •    Policy Alternative 1-C which sum-
               marizes the consequences for only
               the chemical standards.


     4.2.1 Thermal Assumptions.  The thermal requirements

specified by the EPA stipulate that:

          •    All fossil or nuclear-fueled base-
               load generating plants (defined as
               those plants with a capacity load
               factor in excess of 60 percent)
               which will not be retired prior to
               July 1983 , must have closed-cycle
               cooling systems installed by July
               1977.

          •    All fossil or nuclear-fueled
               cyclic generating plants (defined
               as those plants with a capacity
               load factor between 20 and 60 per-
               cent ) which will not be retired
               prior to July 1989 , must have closed-
               cycle cooling systems by July 1983 •
                       111-45-

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          •    All fossil or nuclear-fueled
               generating plants placed in
               service after July 1977 must
               have closed cycle cooling systems.
          The standards applicable to generating units
placed in service prior to 1971 have been estimated by
the EPA to require 40 percent of the fossil capacity and
80 percent of the nuclear capacity to be retro-fitted
with pollution control equipment by 1977.  These existing
source standards also require that 52 percent of the
fossil capacity and 67 percent of the nuclear capacity
brought in service during the 1971-1973 period will be
retro-fitted by 1977.  The installation schedule for this
retro-fitted equipment is:

          •    1974           15 percent
          •    1975           20 percent
          •    1976           25 percent
          •    1977           40 percent

          The EPA has further estimated that an additional
9 percent of total pre-1971 fossil capacity is cyclic and
will need to be retro-fitted by  1983.  The installation
schedule for the pollution control equipment required on
these  existing cyclic plants is:
          •    1978           10 percent
          •    1979           10 percent
          •    1980           20 percent
                    111-46-

-------
          •    1981          20 percent
          •    1982          20 percent
          •    1983          20 percent

          Of fossil and nuclear plants brought in
service during the 1974-1977 period,  89 and 100 per-
cent,  respectively, are required to be fitted with
closed-cycle cooling systems.  In the case of fossil
plants, 52 percent of capacity will be retro-fitted
by 1977 in accordance with the installation schedule
described above for existing base-load plants; the
other 37 percent will be incorporated in new plants
during their construction at lower costs and will in-
volve cash outlays on the same time schedule.  In the
case of nuclear plants, 67 percent of those brought
in service for the 1974-1977 period will be retro-
fitted, and 33 percent will have pollution control
equipment incorporated during the plant construction
process.

          Standards applicable to plants brought  in
service after 1977 are assumed by the EPA to affect
73 percent of fossil capacity and 100 percent of  nuclear
capacity.  All required pollution control equipment
will be incorporated during the plant construction
process.

          The coverage and time phasing of pollution
controls assumed in Policy Alternative 1 are repro-
duced in Table 4.2-1.
                       111-47-

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                                                                                      Table 4.2-1

                                                                             POLICY ALTERNATIVE 1

                                                       COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
           Generating Capacity
             In-S'*rvioe Date
Pollution Control Equipment
      In-Service Date
________ .__
PCE Incorporated
  in New Plants
 __ _________
PCE Retro-Fitted
in Existing Plants
 _______   ___
PCE Incorporated
  in New Plants
___   __ ___
PCE KctroFitted
in Existing Plants
              Before 1P7I
                                             Hy 1377*
                                             Hv 10(13**
                                                                   40%
                                                                    9%
                                                         80%
              1971-1973
              1974-1977
                                             Hy 1977*


                                             liv 1SI77*
                                                                                37%
                                                                                                         52%
                                                                                                         52%
                                                                                                                                  33%
                                                                                                                     67%


                                                                                                                     67%
oo
              1973-UH>0
                                             1078-1990***
                                                                                73%
                                                                                                                                  1007.
           •T e in-t.iH.itton srhrdulr for equipment ri-quirod by 1977 is:  1974 - 15%: 1975 - 20%; 1976 - 25%; and 1977 - 40%.
          •••'• o in-tJH.itu.r-. scli-dulo for equipment required by 1983 Is:  1978 - 10%; 1979 - 10%; 1980 - 20%;  1981 - 20%; 1982 - 20%; and 1983 - 20%.
          *M' >!luiiop control equipment to he functioning a.s of the plant's in service date; cash outlays for this pollution control equipment follow the
            s.irie  schedule  as those for the cener.itin.F rapacity.  See Section 3 for details.

-------
          These guidelines will impact more than one
billion kilowatts of generating capacity during 1974-
1990.  The 1977 guidelines will affect 235 million
kilowatts of fossil-fueled and 70 million kilowatts
of nuclear-fueled generation.  Thus, nearly 58 per-
cent of the generating capacity placed into service
by 1977 will require cooling facilities.

          By 1983, an additional 145 million kilowatts
of fossil-fueled and 132 million kilowatts of nuclear-
fueled generating capacity will require cooling facil-
ities, increasing the level of coverage to nearly 74
percent.  The remainder of the capacity impacted is
that brought in service during 1984-1990 and brings
the overall coverage to more than 80 percent.

          The installation of cooling facilities
will require the construction of additional capacity
to generate power to operate the cooling towers and to
make up for the loss of efficiency due to the increase
in turbine back-pressure.  This capacity loss, based
upon a 1 percent loss for running the cooling units
and an additional 2 percent due to increased back-
pressure, will approximate 9.1 million kilowatts
by 1977, an additional 8.4 million kilowatts by 1983.
and an additional 13.2 million kilowatts by 1990.  To
meet these added generating requirements, the EPA
has assumed that the 1977 guidelines will be met
through the construction of gas-turbine peaking units
                         111-49-

-------
at a 1970 cost of $90 per kilowatt.   The EPA further
assumes that the electric utilities should be able to
construct base-load generating plants to replace addi-
tional capacity losses by 1978.

          In order to meet the thermal standards in-
cluded in Policy Alternative 1, the EPA has estimated
that nearly 1,614 trillions of Btu's will be expended
to operate the cooling facilities.  This estimate is
based upon the following assumptions:
                                              2
          •    60 percent average load factor;
          •    8,760 hours per year; and
          •    10,000 Btu's burn  per hour of
               operation•

          In addition to the above-mentioned levels
of thermal coverage, the EPA has provided detailed cost
estimates for construction and operation of the cooling
facilities.  These estimates, summarized in Table 4.2-2,
specify different capital expenditures for new source
and back-fitted units as well as varying operating ex-
penses between the 1977 and 1983 guidelines.

          The thermal effluent guidelines outlined
herein do not include the additional capital expen-
ditures which might be required to maintain adequate
capacity reserve margins while generating capacity is
removed from service for installation of cooling units.

 2The  60  percent  load  factor was  used in  place of  the EPA
  assumptions  of  a 30  percent  load factor for  retro-fitted
  capacity,  and  a 60 percent load factor  for fossil-fueled
  and  a 70  percent load  factor for nuclear-fueled  capacity
  additions which are  required to have a  closed-cycle
  cooling system.

                       111-50-

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                                        Table 4.2-2

                            CAPITAL AND OPERATING COSTS
                                  THERMAL GUIDELINES
Capital Expenditures ($/kw)

     for Back-Fitted Units
     for New Units

Annual Operating Expenses ($/kw)
     installed by  1978
     installed by  1978-1990
                                                     Non-Nuclear
                                                      Capacity
15.00s
 7.50
42.00
15.00
                              Nuclear
                             Capacity
18.00
10.00
42.00
12.00
Capacity Losses
      due to Running Cooling Units
      due to Increased Back Pressure
 1%
 2
 1%
 2
 *A11 costs are specified at 1970 levels.  Cost escalation occurs at the inflation rates
 projected for each type of generating capacity in Table 3. 2-1.
 **Annual operating expenses associated with the Act will be incurred only by tnose
 plants required to install cooling facilities and only in amounts to offset operating
 inefficiencies.

-------
Assuming that historical capacity reserve margins can-
not be reduced, the ability of the industry to absorb
these capacity losses without the purchase of additional
generating equipment depends upon, among other things,
the seasonal patterns of demand.  Under the best of
circumstances, highly seasonal patterns of demand, per-
haps no additional capacity would be required.  Because
information not available to TBS would be required to
assess the economic impact of these downtime periods,
estimates of outage have been excluded from this report
and are an area of possible further analysis.

     4.2-2  Economic and Financial Consequences of
           Thermal  Assumptions.  The economic impact of
these coverage levels and the costs associated with
the thermal guidelines can be obtained from Table
4.2-3.  This exhibit captures the level of detail
which will be presented for each policy alternative
that includes thermal pollution standards.  In addition
to the summary data detailed in Section 3.3, operating
inefficiencies are provided in the form of energy and
capacity losses.

          The actual consequences of the previously
specified assumptions can be directly obtained by com-
paring Tables 3.3-1 and 4.2-3 and recording the dif-
ferences.  For  example, the capitalized expenditures
between 1974-1990  increased by $41.5 billion ($1,009.6
minus $968.1) as a direct result of the addition of
cooling facilities as prescribed in Policy Alternative
1.  These added expenditures will be partly financed
                      111-52.

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                                                  Table 4.2-3

                                           POLICY ALTERNATIVE 1-T

                        ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                   (dollar figures in billions of current dollars)
                                                                         1977
                                            1983
                                1990
 Capitalized Expenditures;
 External Financing:
 Operating Revenues;
 Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$ 31.4
105.0
$21.7
73.4
$58.9
$27.3
$ 60.6
384.6
$ 39.7
259.9
$117.3
$49.8
$ 125.4
1.009.6
$ 79.3
652.9
$248.2
$97.4
 Consumer Charges:
 (cents /kwh)
Average for the Year
 2.48
 3.30
                                4.45
 Energy Losses:
(trillions  of  Btu's)
Total for the Year
478.3
919.8
                                                        1.613.6
 Capacity Losses:
 (millions of kw )
Total since 1973
  9. 1
 17.5
                                                           30.7
 *Excludes nuclear fuel expense

-------
by $28.1 billion in external financing with the
remainder generated internally.  The additional require-
ments will increase operating revenues by $7.3 billion
and operations and maintenance expenses by $2.0 billion in
1990.  Finally, the consumer will be required to share
the burden in the form of higher charges for the use of
electricity:

          •    in 1977  0.08£/kwh (3.3 percent)
          •    in 1983  0.11£/kwh (3.4 percent)
          •    in 1990  0.13£/kwh (3.0 percent)

While the relative increase is only 3 percent in 1990,
these incremental charges result in an increase in
revenues required by the previously mentioned $7.3
billion in 1990.

     4.2-3  Chemical Assumptions.  The Act specifies stan-
dards for both chemical and thermal water pollution; how-
ever, the EPA has requested that TBS place primary focus
upon the thermal guidelines.  The following set of
assumptions for chemical effluent standards have been
utilized in each policy alternative analyzed in Section
5.  Limited analysis of alternative capital and operating
cost assumptions for chemical effluent standards is pro-
vided in Section 8.

          The chemical requirements as stipulated
by the EPA differ somewhat in concept from the pre-
vious specification of thermal guidelines.  The 1977
guidelines require compliance by 1977 and cover:
                       111-54-

-------
          •    81.5 percent of pre-1971  fossil-
               fueled capacity;
          •    88.8 percent of fossil-fueled
               additions placed  in  service  during
               1971-1977; and
          •    100 percent of nuclear-fueled
               generating capacity  placed in
               service by 1977.

The capital and operating costs  associated  with  these
chemical guidelines are summarized  in  Table 4.2-4.
         By 1983, more  stringent  chemical  pollution
control has been stipulated.  For example,  nuclear
capacity operating by 1977 will require  $.85  in  capital
expenditures and $.50 per year  in operating costs
per kilowatt to meet the 1977 guidelines.   By 1983
additional controls will require  that another $2.75 per
kilowatt be expended in capital expenditures  while
annual operating expenses are increased  to  $.85  per
kilowatt.  All of the above  chemical capital  and
operating cost estimates are specified at  1970 levels
and must be inflated at the  relevant rates  provided
in Section 3.2.  The coverage levels remain the  same
for pre-1978 capacity and closed-cycle requirements
are imposed upon 73.3 percent of  fossil-fueled addi-
tions and all nuclear units  placed in service after
1977.

     4.2-4.  Economic  and Financial Consequences of
            Chemical  Assumptions.  The economic impact
associated solely with  the chemical guidelines stip-
ulated by the EPA can be obtained from Table  4.2-5.
                      111-55-

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                                       Table 4. 2-4

                            CAPITAL AND OPERATING COSTS
                                CHEMICAL GUIDELINES
                                    1977 Guidelines
H
H
H
I

I
Capacity Placed in Service:
     Prior to 1971
           Capital Expenditures
           Annual Operating Expenses
      1971-1977
           Capital Expenditures
           Annual Operating Expenses
                                                   Non-Nuclear
                                                    Capacity
                                                               1.95*
                                                               0.85


                                                               1.05
                                                               0.55
                                                                                           Nuclear
                                                                                           Capacity
                                                                                            ($/kw)
0.85
0.50


0.85
0.50
                                      (continued)

-------
         Table 4 .2-4 (continued)
                                              1983 Guidelines
M
M
H
I
Oi
         Capacity Placed in Service:

              Prior to 1971
                    Additional Capital Expenditures
                    Additional Annual Operating Expenses
1971-1977
      Additional  Capital Expenditures
     Additional Annual Operating Expenses
              1978-1983
                    Capital Expenditures
                    Annual Operating Expenses
                                                             Non-Nuclear
                                                              Capacity
                                                                <$/kw)
3.35
0.65


2.75
0.35


2.60
0.25
                                                                              Nuclear
                                                                              Capacity
                                                                               <$/kw)
2.75
0.35


2.75
0.35
                                                                                2.00
                                                                                0.20
         *A11 costs are specified at 1970 levels.  Cost escalation occurs at the inflation rates projected
          for each type of generating capacity in Table 3. 2-1.

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                                                                   Table 4. 2-5

                                                            POLICY ALTERNATIVE  1-C

                                         ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA

                                                     (dollar figures in billions of current dollars)
                                                                                          1977
                                             1983
                                                                                                                          1990
Ln
03
                  Capitalized Expenditures:
                 F-xtorru'l Financing:
 Total for the Year
 Total since 1973
Total for the Year
Total since  1973
$28.9
 96.0
$19.7
 65.8
$ 59.3
 370.5
$ 38.8
 249.0
$121.7
 976.9
$ 76.7
 630.2
                 Operating He-venues:
Total for the Year
$57.6
$115.8
$244.1
                 Operations & Maintenance Expenses:*
Total for the Year
$27.1
 $49.8
                                                          $97.3
                 Consumer Charges:
                 (cents/kwh)
Average for the Year
 2.42
  3.25
  4.38
                 *Fxcludes nuclear fuel expense

-------
A comparison of Tables  3.3-1 a.nd 4.2-5 shows  that  the  cap-
italized expenditures between  1974-1990 will  increase  by
$8.8 billion as a direct result of  the chemical  guidelines.
These expenditures will be  financed by $5.4 billion  in ex-
ternal  financing and an incremental $3.4 billion generated
internally. These additional internal funds result in  part  from
an increase in retained earnings,  in part from increased
depreciation and tax deferrals.  The net effect  of these
chemical guidelines  on the consumer results in the
following increases in average charges for electricity:

          •    in 1977   0.02£/kwh  (0.8 percent)
          •    in 1983   0.06£/kwh  (1.9 percent)
          •    in 1990   0.06£/kwh  (1.4 percent)
                       111-59-

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4.3  Economic and Financial Consequences
     of Policy Alternative 1

          Table 4.3-1 provides selected summary data
obtained from an evaluation of Policy Alternative  1
and combines the economic consequences of both thermal
and chemical effluent guidelines implicit in Tables
4. 2-3 and 4.2-5 .

          The short-term impact of the Act's thermal
and chemical water pollution control requirements
through 1977 is a 14 percent increase in capitalized
expenditures and requires a more than proportionate
increase of 17 percent in external financing require-
ments.  In the long run, the overall impact  for both
of these measures ranges from 5 to 5i percent.  Through-
out the period 1974-1990 operating revenues, operations
and maintenance expenses and consumer charges increase
at approximately 4 to 44 percent with a peak in the
early 1980's of 5 to 54 percent.  This intermediate
peak in the burden passed on to the consumer results
from the rapid increase in capitalized expenditures
and external  financing required to meet the 1977
guidelines.

          Tables 4.3-2 through 4.3-4 summarize for
1977, 1983 and 1990 the relative impact due to thermal
and chemical standards.  During the 1974-1990 period,
more than 80 percent of the related capitalized ex-
penditures ($41.5 billion out of $50.3) and external
financing requirements ($28.1 billion out of $33.5)
can be attributed to cooling equipment.  On the other
hand, chemical standards account for nearly 50 percent

                   111-60-

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                                              Table 4.3-1

                                          POLICY ALTERNATIVE 1

                       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA
                                  (dollar figures  in billions of current  dollars)
                                                                        1977
                                                                                         1033
                                                            3900
M
M
M
I

M
       .R lie venues:
       >!,.••: & ?.i.'iintenr>ncc Expenses:
                                            Total for the Year
                                            Total since 1973
                                            Total for the Year
                                            Total since 1073
Total for the Year
Total for the Year
                          $  32. 1
                           107.2
                           $22. 3
                            73. 1
$59.5
$27.8
                $  61.5
                391. 1
                $  40.2
                2G4. 5
$119.5


 $51.0
             $   126.0
              1, 01S.4
               $  70. 5
                638. 3
                                                                                                                  $251.4
                                                                                                                   $99. 3
        r Charges:
Average for the Year
 2.50
  3.36
                                 4.51
   i ! ! u>n:, <>l lit u's)
                                            Total for the Year
                          478.3
                919.8
              1,613.6
   i:on.'-: of k\v
                                            Total since 1973
                             9.1
                 17.5
                 30. 7
KxH-i''"<- nuclear fuel c:-:pcnR
-------
                                                             Table 4. 3-2

                                                 POLICY ALTERNATIVES 0 AND 1

                                   ECONOMIC AND FINANCIAL CONSEQUENCES: 1977 SUMMARY

                                             (dollar figures in billions of current dollars)
Capitalized Expenditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses;*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
Policy
Alternative
0
$28.2
93.8
$19.1
64.1
$57.0
$26.6
Added
Thermal
Requirements
+3.2
+ 11.2
+2.6
+9.3
+1.9
+0.7
Added
Chemical
Requirements
+0.7
+2.2
+0.6
+1.7
+0.6
+0.5
Policy
Alternative
1
$ 32.1
107.2
$22.3
75.1
$59.5
$27.8
Consumer Charges:
(cents /kwh)
Average for the Year       2.40
 +0.08
+0.02
2.50
Energy Losses:
(trillions of Btu's)
Total for the Year
+478.3
                                                                                478.3
Capacity Losses:
(millions of kw  )
Total since 1973
                                             + 9.1
                                        9.1
*Excludes nuclear fuel expense

-------
                                                                       Table 4.3-3

                                                          POLICY ALTERNATIVES 0 AND 1

                                             ECONOMIC AND FINANCIAL CONSEQUENCES:  1983 SUMMARY
                                                        (dollar figures in billions of current dollars)
U>
I
('amtn Ii7.«'d Kxpcnditurcs :
         Ext-.-rr.nl Financing:
         Operating
         Opi-r.itinns & Maintenance Expenses:*
                                                   Total for the Year
                                                   Total since 1973
                                          Total for the Year
                                          Total since  1973
                                          Total for the Year
                                          Total for the Year
Policy
Alternative
0
$ 58.4
364.0
$ 38.3
244.4
$113.6
$48.6
Added
Thermal
Requirements
+2.2
+20.6
+ 1.4
+ 15.5
+3. 7
+ 1.2
Added
Chemical
Requirements
10.9
+6.5
+0.5
+4.6
+2.2
+ 1.2
Policy
Alternative
1
$ 61.5
391. 1
$ 40.2
264.5
$119.5
$51.0
         Consumer Charge's:
         (cr-nt-i/kwh)
                                          Average for the Year       3. 19
  +0.11
+0.06
3.36
         Knerpy Losses:
        I c i-1 1 I t • > n s "I  Utu's)
                                          Total for the Year
+919.8
                 919.8
         Capacity l.onsi'S:
         (millions of kw  )
                                          Total since 1973
 + 17.5
                   17.5
                S nuclear fuel expense

-------
                                                             Table 4. 3-4

                                                 POLICY ALTERNATIVES 0 AND 1

                                    ECONOMIC AND FINANCIAL CONSEQUENCES: 1990 SUMMARY

                                            (dollar figures in billions of current dollars)
                                                                   Policy
                                                                 Alternative
                                                                     0
                                            Added
                                           Thermal
                                         Requirements
                                      Added
                                     Chemical
                                   Requirements
                                    Policy
                                  Alternative
                                       1
M
l-l
M
I
                 Kxpcnditures:
1      External Financing:
                                          Total for the Year       $121.1
                                          Total since 1973          968.1
                                          Total for the Year        $  76. 5
                                          Total since 1973         624. 8
                                             +4.3
                                            +41.5
                                             +2.8
                                            +28.1
                                       +0.6
                                       +8.8
                                       +0.2
                                       +5.4
                                 $  126.0
                                  1.018.4
                                   $ 79.5
                                    658.3
Oppr.-iting Revenues:
Total for the Year
$240.9
+7.3
                                                                                                                +3.2
$251.4
Op«'rations A Maintenance Expenses:
Total for the Year
$95.4
+2.0
                                                                                                               +1.9
 $99.3
Cnns'imor Charges;
(centrf/kwh) .
Average for the Year       4. 32
                    +0. 13
                   +0.06
                                                                                                                                 4.51
Energy Losses:
( l r i ! 1 11 n'.s o i  [it u s)
Total for the Year
                +1.613.6
                                  1.613,6
Cap.'icitv Losses:
(millions of kw  )
Total since 1973
                   +30.7
                                                                                  30.7
 Kxr!u:i<>< nuclear fuel expense

-------
of the increase in operations and maintenance expenses
($1.9 billion out of $3.9 billion).  About 30 percent of the
incremental charges passed on to the consumer (.06£/kwh
out of .19£/kwh) are directly related to chemical pollu-
tion control.  These chemical guidelines will remain
unchanged throughout Policy Alternatives 1 through 7.
                       111-65-

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4.4   Financing  Implications of Policy
     Alternative 1

          Policy Alternative 1 assumptions imply that
the electric utility industry will spend $84.7 billion
during the period 1974-1990 to comply with the chemical
and thermal effluent guidelines of the Act.  Of this
amount, 69.8 percent ($59.1 billion) corresponds to
the thermal guidelines; the remainder ($25.6 billion)
represents costs associated with the chemical guide-
lines.  During the period 1974-1990, 59.4 percent of
the expenditures ($50.3 billion) have been capitalized;
the remainder ($34.4 billion) is the operating expenses
incurred during the 1974-1990 period.

          The financial burdens associated with
meeting the proposed effluent guidelines are shared
among the following:
          •    capital markets in the form of
               increased external financing require-
               ments — long-term debt, preferred
               stock, and common stock issues;
          •    consumers in the form of increased
               charges for electrical power; and
          •    government in the form of reduced
               tax receipts because of reductions
               in taxable income.

          Of  the total capitalized expenditures
of $50.3 billion, $41.2 billion (81.9 percent) are
attributable  to the investor-owned utilities and $9.1
billion to the public sector.  Of the investor-owned
expenditures;
                         UI-66-

-------
          •    $16.9 billion (41.0 percent) will
               be financed by long-term debt,

          •    $3.1 billion (7.5 percent) by
               preferred stock issues;

          •    $7.3 billion (17.7 percent) by
               common stock issues,

          •    $3.3 billion (8.0 percent) by
               retained earnings; and

          •    $10.6 billion (25.7 percent) by
               non-cash charges against income.


Of the publicly owned financing requirements,  35
percent are assumed to be generated internally ($3.1

billion) with the remainder obtained from external

sources ($6.2 billion).
                      111-67-

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4.5   Pol icy Alternative 0-T

          The analysis of the economic impact and
financial implications resulting from the thermal and
chemical pollution control assumptions contained in
Policy Alternative 1 ignores the effect of existing
standards.  If one desired to measure the incremental
impact due solely to the Water Pollution Control Act
of 1972, one would need to reduce the impacts detailed
for Policy Alternative 1 by the amounts that would be
spent on pollution control equipment to meet existing
federal, state and local standards.

          In order to assess the impact of these
existing standards, the EPA has requested the analysis
of Policy Alternative 0-T which corresponds to Policy
Alternative 0 with the addition of existing thermal
standards.  Therein, the EPA has assumed that the coverage
levels associated with existing pollution control
standards would be:

          •    prior to 1974   no coverage
          •    1974 to 1977    89 percent (fossil)
                              100 percent (nuclear)
          •    1978 to 1990    73 percent (fossil)
                              100 percent (nuclear)

These post-1973 coverage levels correspond to those
assumed  to be effective with the Act.
           While  the  coverage  levels  may be  identical,  the
capital  costs and  generating  inefficiencies  required to
comply  with  existing  legislation are significantly  lower
than  those associated with  the  Act.
                      Hl-68-

-------
          The capital expenditures required for fossil-
fueled equipment would have been $3.90 per kilowatt and
$5.50 per kilowatt for nuclear-fueled generating capacity.
These expenditures compare with $7.50 and $10.00 per
kilowatt required by the Art for fossil and nuclear-
fueled additions, respectively.  In addition, no retro-
fitting of generating capacity installed prior to 1974
would be required.

          The inefficiencies associated with operating
the cooling equipment specified by the Act was esti-
mated to lower generating capacity by 3 percent.  The
capacity losses associated with the existing standards
have been estimated by the EPA to reduce operating efficiency
by 0.7 percent.  The cost of operating these cooling
facilities is the same as the cost of the new units installed
as a response to the Act's guidelines.

          Table 4.5-1 provides the selected summary
data obtained from an evaluation of existing thermal
pollution control requirements.  These requirements
when compared to Policy Alternative 1 provide an es-
timate of the incremental impact of the Act's standards.
Table 4.5-2 provides a 1990 summary of the relative
impacts due to thermal and chemical standards when
Policy Alternative 0-T replaces Policy Alternative 0
as the baseline.
                      111-69-

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                                                               Table 4.5-1

                                                        POLICY ALTERNATIVE 0-T

                                      ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA

                                                (dollar figures in billions of current dollars)
                                                                                     1977
                                            1983
                                                          1990
               Capitalized Kxpcnditures:
Total for the Year
Total since  1973
                          $28.8
                           95.5
$ 59.3
 369.3
$122.6
 980.3
O
              External Financing:
              Operating Revenues:
              Operations &. Maintenance Expenses:*
              Consumer Charges:
              (cents/kwh)
Total for the Year          $19.4
Total since 1973            65.3
Total for the Year         $57.1
Total for the Year         $26.6
Average for the Year        2.40
                                         $  38.8
                                          248.4
                                         $114.3


                                          $48.8


                                           3.21
               $  77.5
               633.7
               $242.5


               $95.6


                4.35
              Kncrgy Losses:
              ( I ri 11 ions ol  Btu's )
Total for the Year
                           47.3
 136.7
 304.9
              Capacity Losses:
              (millions of kw /
Total since 1973
                            0.9
   2.6
   5.8
              ''KxrhxU'S nuclear fuel expense

-------
                                                    Table 4. 5-2
                                        POLICY ALTERNATIVES 0-T AND 1
                           ECONOMIC AND FINANCIAL CONSEQUENCES:  1990 SUMMARY
                                    (dollar figures in billions of current dollars)
C 'a nit.nl 17 rd !• xpenditures:
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
Consumer Charges:
(ccnts/kwh)
Knercv Losses:
(trill nm.s of IH u 's>
Cnpnoitv Losses:
(millions of kw )
Policy
Alternative
0-T
Total for the Year $122.6
Total since 1973 980. 3
Total for the Year $ 77. 5
Total since 1973 633.7
Total for the Year $242. 5
Total for the Year $95. 6
Average for the Year 4. 35
Total for the Year 304. 9
Total since 1973 5.8
Added
Thermal
Requirements
+2.8
+29.3
+ 1.8
+19.2
+5.7
+1.8
+0.10
+ 1.308.7
+24.9
Added
Chemical
Requirements
+0.6
+8.8
+0,2
+ 5.4
+3.2
+ 1.9
+0.06
Policy
Alternative
1
$ 126.0
1.018.4
$ 79.5
658.3
$251.4
$99.3
4.51
1.613.6
30.7
*K>
nuclear fuel expense

-------
      5,   OVERVIEW OF EPA POLICY ALTERNATIVES
                 BEFORE EXEMPTIONS

 5.1  Introduction
          Analyses paralleling that of Policy Alter-
native 1, which was described in detail in Section 4,
were performed for a total of seven major policy al-
ternatives.  Section 5 is an overview of the results
of these analyses.  As in Section 4, each policy alter-
native is examined in terms of its potential impact
before consideration of exemptions possibly available
under Section 316(a) of the Act.  The effects of ex-
emptions are discussed in Section 6 of this report.

          The primary policy alternatives differ from
one another only in the coverage and time phasing of
thermal pollution control requirements; all seven pol-
icy options presume the same chemical pollution stan-
dards and costs.  Section 5, therefore, focuses on the
different thermal effluent guidelines assumed in each
of the seven primary policy options and on the overall
economic and financial implications for each of the
policy alternatives.  The chemical pollution control
requirements assumed in each alternative are those
that were discussed in detail for Policy Alternative 1,

           It should be emphasized that, because the
purchase cost per kilowatt of cooling equipment is
assumed  to  increase over time, delays in the imple-
mentation  of any given level of  coverage increase  the


                    III- 72  -

-------
total capital expenditures associated with the coverage
policy.  Moreover, because there are differences between
the costs of new and retro-fitted equipment, whether a
particular unit of capacity is required to meet standards
as of its in-service date or as of a later date affects the
eventual total amount of capital expenditures for cooling
equipment.

          Policy Alternative 1 can be viewed as the
base from which emerged all the other policy alterna-
tives submitted by the EPA for economic and financial anal-
ysis by TBS.  Each of these alternative policies for
controlling thermal water pollution differs somewhat in:

          •    the time schedule for retro-fitting
               cooling equipment on existing source
               generating units;
          •    the first year (or years,  if fossil
               and nuclear are treated differently)
               that plants newly coming into service
               are required to have closed-cycle
               cooling systems;  and
          •    the requirement that all peaking units
               brought into service prior to 1971 have
               closed-cycle cooling systems.

          The date at which new source standards are in
effect imposed is one key difference between the various
policy alternatives.   The Act states that plants on
which construction is begun after the publication of EPA
regulations must have closed-cycle cooling  systems  in  operation
as of their in-service dates.   These new source standards
are assumed in all policy options to be applicable to
fossil capacity coming into service in 1979 or later and
to nuclear plants coming into service in 1982 or later.
In addition,  Policy Alternative  1 requires  closed-cycle
cooling equipment on  all generating capacity  placed in
service in 1978 or later.
                      Hl-73-

-------
          Some other policy alternatives assume that the
installation of the thermal pollution control equipment
on capacity other than that defined as new source by the
Act,  i.e., that capacity on which construction is begun
after the publication of regulations, is delayed until
1983.

          The pre-1974 plants which are currently oper-
ating without closed-cycle cooling systems and the
plants which will come into service in 1974 or later
without such systems are also treated in significantly
different ways in the seven primary policy options.
Policy Alternative 1 specifies that the vast majority of
these plants be fitted with pollution control equipment
by 1977.  Most of the other policy alternatives delay
the  bulk  of the retro-fitting until 1983.  Some policy
alternatives assume that plants coming into service in the
1974-1977 period which have been designed to incorporate
closed-cycle cooling systems will have such systems completed
by 1977.
                   111-74-

-------
 5.2  Policy Alternative 1
          Briefly to recapitulate the thermal require-
ments discussed in Section 4, Policy Alternative 1
stipulates that :
               All fossil or nuclear-fueled base gener-
               ating plants (defined as those plants
               with a capacity load factor in excess
               of 60 percent), which will not be retired
               prior to July 1983, must have closed-cycle
               cooling systems installed by July 1977.
               All fossil or nuclear-fueled cyclic gener-
               ating plants (defined as those plants with
               a capacity load factor between 20 and 60
               percent), which will not be retired prior
               to July  1989, must have closed-cycle
               cooling  systems by July 1983.
               All fossil or nuclear-fueled generating
               plants coming into service  in 1978 or
               later must have closed-cycle cooling
               systems.
          The  coverage  and  time phasing of pollution

 controls  assumed  in Policy  Alternative 1  are  reproduced

 below  as  Table 5.2-1.


          A  summary of  the  economic  and financial  con-

 sequences of Policy Alternative 1  is set  out  below in
 Table  5.2-2.   As  discussed  in  Section 4,  except  for the
 energy and capacity loss  figures,  the data in Table 5.2-2
 are  the industry's total  capitalized expenditures,  exter-
 nal  financing,  etc.   The  level of  each of these  figures
 relative  to  the baseline  assumption  of no water  pollution

 control requirements, Policy Alternative  0, is summar-
 ized for  Policy Alternatives 1 through 7  in Section 5.9.
                      IH-75-

-------
                                                                 Table  5.2-1


                                                                 POLICY ALTERNATIVE 1

                                          COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS



                                                             	___F_9_5_5.i_i_c_nj3a^jitjy	         	?i.4_^.L? a.JL
    •ti-i: Capacity         Pollution Control Equipment        PCElncorporated        PCE~Rctro-Kitted         PCE Incorporated"        1'CK ""Retro-Kitted
    , .-...(, ,. D.I'..'                 In-Servlce D:ite                  in New Plants           in Existing Plants           in New Plants           in Existing Plants
                                Ily  1D77*                             -                        40%                        -                        80T»
                                ]ty  1HB3**                                                      0%
 1?T1-1?73                      I3v 1977*                             -                       52%                       -                        67%


 :>n • < hcdulr for fT«-nt ti> br fimriltir.inK :>H of tin- plant's In  service date; cash outlays for this pollution control equipment follow the
,..,c «,',,..! ]'.,. as tf'.nsr fi>r '.lie RI-U'ratine capacity.  See Section 3 for details.

-------
                                                 Table 5.2-2

                                           POLICY ALTERNATIVE 1

                        ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA

                                   (dollar figures in billions of current dollars)
                                                                         1977
                                            1983
                                 1990
 Capitalized Fxpenditures:
Total for the Year
Total since 1973
$ 32.1
 107.2
$ 61.5
 391. 1
$  126.0
 1.018.4
 External Financing:
Total for the Year
Total since 1973
 $22.3
  75. 1
$ 40.2
 264.5
  $ 79.5
   658.3
 Operating Revenues:
 Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
 $59.5
 $27.8
$119.5
 $51.0
  $251.4
   $99.3
 Consumer Charges:
 (cents /kwh)
Average for the Year
  2.50
  3.36
    4.51
        Losses:
( t r i 1 ! ions of Btu 's)
                                             Total for the Year
                          478.3
                 919.8
              1,613.6
Capacity Losses:
(millions of kw )
Total since 1973
   9.1
  17.5
    30.7
' K'xfhidrs nuclear fuel expense

-------
5.3   Policy Alternative 2
          Policy Alternative 2 is identical to Policy
Alternative 1 with the exception of the added require-
ment that all peaking units brought into service prior
to 1971 have closed-cycle cooling systems by 1983.  As
shown in Table 5.3-1, the  EPA  has  estimated  that  the effect
of this requirement is to boost the retro-fitting of
pre-1971 fossil capacity by 1983 from 9 percent to  11
percent.

          The economic and financial consequences of
Policy Alternative 2 are summarized in Table 5.3-2.
          As mentioned earlier, a comparison of the con-
sequences of Policy Alternative 2 with those of the
other policy options is presented in Section 5.9.
                       "1-78-

-------
                                                                                 Tuble 5. 3-1

                                                                         POLICY ALTERNATIVE 2

                                                  COVEaAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Generating Capacity
  In -Service Date
Pollution Control Equipment
_ In-Service Date
________ fossil  S:J!J?J?.£.iLy. __   ____
PCE Incorporated ~      PCE Retro-Kitted
  in New Plants          in Existing Plants
                                                                                                                   _____   N_UILL?-? r—
                                                                                                                 PCE Incorporated  ~
                                                                                                                    in New Plants
                                                                                                                                                        ______
                                                                                                                                                 PCE~Retro-Fitted
                                                                                                                                                 in Existing Plants
           Be/ore 1971
                                         By 1977*
                                         By 1983**
                                                                                              40%
                                                                                              11%
                                                                                  80%
           1971-1973
           1974-1977
                                         By 1977*
                                         By 1977*
                                                                            37%
                                                                                               52%
                                                                                                     52%
                                                                                                                              33%
                                                                                  67*


                                                                                  67%
           1978-1990
                                         1978-1990***
                                                                            73%
                                                                                                                             100%
VO
 I
  *The installation schedule for equipment required by  1977 is:  1374 - IS'li; 1975 - 20%; 1976 - 25%; and  1977 - 40%.
 **The installation schedule for equipment required by  1983 is:  1978 - 10%; 1979 - 107.; 1980 - 20%; U>81 - 20",,; l'J82 - 20°',,; and 1983 - 20%.
"**Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
   same schedule as those for the generating capacity.  St;e Section 3 for details.

-------
                                                                   Table 5. 3-2

                                                           POLICY ALTERNATIVE 2

                                         ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA
                                                    (dollar figures  in billions of current dollars)
                                                                                         1977
                                            1983
                                 1990
oo
o
I
                 ('npita 1 i?c'd Kxpenditures:
                 External Financing:
                 Operating Revenues:
                 Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$ 32. 1
107.2
$22.4
75.2
$59. 5
$27.8
$ 61.5
391.6
$ 40.3
264.7
$119.5
$51.0
$ 126.0
1.018.9
$ 79.5
658.4
$251.4
$99.3
                 Consumer Charges:
                 (ccnts/kwh)
Average for the Year
 2.50
 3.36
   4.51
                 Energy Losses:
                 (t ri1 I ions o(  Btu's)
Total for the Year
478.3
925.1
1.624.1
                Cnpacity Losses:
                (millions of kvr >
Total since 1973
  9.1
 17.6
   30.9
                < Kxrludes nuclear fuel expense

-------
 5• 4  Pollcy A1 te ma t i v e 3
          Policy Alternative 3 calls for the same generating.
capacity coverage levels  as  Policy  Alternative  1,  but  assumes
substantial delays  in the time phasing of the portion
of these coverage  requirements to be met by retro-fitting.
New source standards are assumed to apply to fossil plants
coming into service after 1978 and to nuclear plants coming
into service after 1981.   As in Policy Alternatives 1
and 2, the equipment required by the new source standards
is installed during the construction of the generating
plants and comes into service simultaneously with the
plants.

           The installation  of closed-cycle  cooling  systems
on capacity that is not new source (i.e., that capacity
on which  construction  started before publication  of EPA
regulations) is in Policy Alternative 3 assumed to be
delayed until 1983.  As  in  Policy  Alternatives  1  and  2,
it  is assumed that  some  plants  currently under  construc-
tion  have already been designed to include  closed-cycle
cooling systems.  Specifically, the EPA has assumed in Policy
Alternative 3,  as in Policy Alternatives 1  and  2, that
37 percent of the fossil  capacity  brought  into  service  in
the  1974-1977 period and 33 percent of  the  nuclear  capacity
brought into service in  the 1974-1981 period will have
been  designed to include pollution control  equipment.   In
Policy Alternative  3,  it  is assumed that these  units  will
be  completed by 1983.  These  units are  assumed  to come
 in  at the new unit  costs, appropriate to their  installa-
 tion  dates.  The remaining  52 percent fossil and  67 per-
 cent  nuclear coverages are  to be met by retro-fitting
 by  1983.   Policy Alternative  3  also assumes that  31
 percent of the  fossil  plant brought into service  in  1978
 will  have been  designed  to  incorporate  pollution  control

                          111-81-

-------
equipment and will be fitted by 1983 at new unit costs;
the remaining 42 percent coverage requirement will be
retro-fitted by 1983.
          The pollution control equipment required by
1983 is assumed to be installed in accordance with the
following schedule:

          •    1981  10 percent
          •    1982  40 percent
          •    1983  50 percent

          The coverage and time phasing assumptions of
Policy 3 are presented in Table 5.4-1;  the projected
economic and financial implications of these assump-
tions are presented in Table 5.4-2.
                    111-82-

-------
                                                                                      Tatle 5.4.-1


                                                                              POLICY ALTERNATIVE 3


                                                        COVERAGE AND TIME PHASING OP THERMAL POLLUTION CONTROLS
                                                                           _ ____ _.----   ____   ___         ________    .--____    _______
             Generating Capacity        Pollution Control Equipment         PCE~inco"rporat<7f        PCE Retrofitted         PCfcfincorporaFed     ~  PCE~Retro-Fitted
               In-Service Date          _ In-Service Date _           in Now Plants           in Existing Plants           in New Plants          in Existing Plants
Before 1971
                1971-1973
                              By 1983>



                              By 1983*
                                                                                          49%
                                                                                                          52%
                                                                                                                                                            80%



                                                                                                                                                            67%
                 1974-1977
                                              Bv 1983*
                                                                                 37%
                                                                                                                                   33%
                                                                                                                                                            67%
 H
 M
 I
oo
00
1978
                1979-1981
                              By 1983*
                                               1979-1981**
                                               By 1983-1'
                                                                 31%
                                                                                 73%
                                                                                                          42%
                                                                                                                                   33%
                                                                                                                                    33%
                                                                                                                                                            67%
                                                                                                                                            67%
                1982-1990
                                               1982-1990-**
                                                                                                                                   100%
              'The installation schedule for equipment required by 1983 is:  1981 - 10''«;  1982 - 40%; and 1983 -  50%.
             **Pollutlon control i'qmpm<• functioning as of the plant's m-scrvicc date; cj.-.h outlays for this pollution control equipment follow the

               same schedule as those for the generating capacity.  Sec Section 3 for details.

-------
                                                                  Table 5. 4-2

                                                         POLICY ALTERNATIVE 3

                                       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                    (dollar figures in billions of current dollars)
                                                                                        1977
                                                                                         1983
                                                                                                                       1990
H
I
00
               Capitalized !• xpcnditures:
External  Financing:
               Operating Revenues:
               Operations & Maintenance Expenses;*
               Consumer Charges:
               (conts/kwh)
                                             Total for the Year
                                             Total since 1973
Total for the Year
Total since 1973
                                                            Total for the Year
                                             Total for the Year
                                             Average for the Year
$30.2
98.7
$20.8
68.1
$57.9
$27.3
2.43
$ 66. 1
400.7
$ 44.1
274.3
$119.8
$50.4
3.36
$ 126.0
1.024.3
$123.4
663.2
$251.6
$98.6
4.51
               Energy Losses:
               ( i n 1 1 KIMS  (iI  Btu's)
                                                            Total for the Year
                                                                         78.8
                                                                                                       919.8
                                                         1.613.6
               Capacity Losses:
               (millions of kw  )
                                                            Total since 1973
                                                                          1.5
                                            17.5
                                                                                                                       30.7
                Kxcluclos nuclear fuel expense

-------
5.5   Policy Alternative 4
          The fourth policy alternative specified by  the
EPA calls in effect for the imposition of new source
standards as of 1977.  That is, it is assumed that all
capacity coming into service after 1976 must have closed-
cycle cooling, irrespective of the date on which con-
struction of any particular plant began.  Policy Alter-
native 4 secondly calls for a delay until 1983 in retro-
fitting the pre-1977 capacity that has not been designed
to have closed-cycle cooling systems.  Policy Alternative
4 thirdly assumes that the capacity coming into service
in the 1974-1976 period that has been designed to have
such systems will have them completed by 1977.

          The coverage of Policy Alternative 3's
retro-fitting requirements is the same as in Policy Al-
ternatives 1 and 3.  The installation schedules for
the pollution control equipment retrp-fitted by 1983
are the same as that in Policy Alternative 3.  The
schedule for the equipment already planned in 1974-1977
capacity additions is the same as that of Policy Alternatives
1 and 2.  The coverage and time phasing of Policy Alter-
native 4's requirements are set out in Table 5.5-1.

          The economic and financial impact of these
assumptions is summarized in Table 5.5-2
                        111-85-

-------
                                                                                   Tab c 5. 5-1

                                                                           POLICY ALTERNATIVE 4

                                                     COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS



                                                                       	Fo£8i l_jC_a_p_a_c_H£	        	..	—
           Generating Capacity        Pollution Control Equipment        PCE~l7icorpbraFc:i         PCK Metro-Fitted        PC E Incorporated  ~"     PCE Retro-Fitted
             In-Servlee Date          	In-Service Pate	          in New Plants           in Existing Plants          in New Plants         in Existing Plants


              Before 1971                   By 1983**                          -                       49%                      -                       80%


              1971-1973                    By 1983**                          -                       527.                      -                       67%


              1974-1976                    By 1977*                          37%                       -                       33%
                                           By 1983**                          -                       52%                      -                       67%

M
H            19?7                         1977***                           37%                       -                       33%
 I                                          Ry 1977*                           -                       52%                      -                       67%
00
O\
I
              1978-1990                     l'J7B-10»0***                      73%                       -                       100%
                                                                                                                control equipment follow the

-------
                                                                Table 5. 5-2

                                                        POLICY ALTERNATIVE 4

                                      ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA

                                               (dollar figures in billions of current dollars)
                                                                                       1977
                                             1983
                                 1990
oo
                         Kxpenditures:
              Kxtcrnal Financing:
              Operating Hevonuos:
             Operations & Maintenance Expenses:*
Total for the Year
Total since  1973
Total for the Year
Total since  1973
Total for the Year
Total for the Year
$30.5
99.8
$20.9
68.9
$58.0
$27.3
$ 65.5
397.6
$ 43.6
271.3
$119.3
$50.4
$ 126.0
1.022.3
$ 79.3
661.6
$251.3
$98.4
             Gons'.irnfr Charges:
             (cents/kwh)
Average for the Year
 2.44
 3.35
   4.50
             Knorgy Losses:
             (trill mns o I Btu ' s)
Total for the Year
105.1
904.0
1.613.6
             Capacity Losses:
             (millions of kw )
Total since 1973
  2.0
 17.2
   30.7
              Kxfl'id-"-' nuclear fuel expense

-------
 5.6   Policy Alternative 5

           Policy Alternative 5 differs from Policy Alter-
native 4 only in assuming that all existing source plants
requiring retro-fitting and having a capacity of 500 megawatts
or above will have such retro-fitting completed by 1977,
instead of by 1983.  The "by 1977" timetable is the same
15-20-25-40 schedule used in other policy options. The  EPA's
estimate of the coverage and time phasing implied by
Policy Alternative 5 is shown in Table 5.6-1.

          The projected economic and financial consequences
of this policy option are shown in Table 5.6-2.
                      111-88-

-------
                                                                                Table  5.6-1

                                                                        POLICY ALTERNATIVE 5

                                                 COVERAGE AND TIME PHASING OF THERMAL POLLUTION CONTROLS
Generating Capacity
  In -Service Date
Pollution Control Equipment
      In-Service Date
________ ..
PCE Incorporated
  in New Plants
..   _________
PCK Retro-Kitted
in Existing Plants
                                            ________    __
                                            PCE Incorporated
                                              in New Plants
                                                                                                                                                 _     _____ _
                                                                                                                                               PCE Retrofitted
                                                                                                                                               In Existing Planta
          Before 1971
                                        By 1977*
                                        By 1983**
                         25%
                         24%
                                                        80%
          1971-1973
                                        By 1977*
                                        By 1983**
                         37%
                         15%
                                                        67%
00
          1974-1976
          1977
                                        By 1977*
                                        By 1983**
                                        1977-;.**
                                        By 1977*
37%
37%
                         37%
                         15%
                                                                                                   52%
                               33%
                                                  33%
                                                        67%
                                                                           67%
          1978-1990
                                        1978-1990***
                                                                          73%
                                                                                                                           100%
       *The installation schedule for equipment required by 1977 is:  1974 -  15%;  1975 - 2('%; 1976 - 25%; and 1977 - 40%.
      **Thr installation schedule for equipment required hv 1!1R3 is;  19B1 -  10%;  1082 - 1('%: rind 19H3  - 50%.
     ***Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
        same schedule as those for the generating capacity.  Sec Section  3 for details.

-------
                                                                    Table 5.6-2

                                                            POLICY ALTERNATIVE 5

                                         ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                   (dollar figures in billions of current dollars)
                                                                                          1977
                                                                                         1983
                               1990
 H
\O
O
                  Capitalized Kxpcnditures:
                  Kxtornal Financing:
Operating Revenues;
                 Operations & Maintenance Expenses;*
                                             Total for the Year
                                             Total since 1973
                                             Total for the Year
                                             Total since 1973
                                             Total for the Year
                                             Total for the Year
$ 31.9
106.2
$22.0
74.0
$58.6
$27.1
$ 62.1
393.3
$ 40.7
266.4
$119.4
$50.8
$ 126.0
1.020.3
$ 79.5
659.8
$251.3
$99.0
                 C.'onsurnor Charges:
                 (cents/kwh)
                                             Average for the Year
                                                                                          2.47
                3.35
               4.51
                 Kncrgy Losses:
                 (trill ions ol Btu's)
                                                              Total for the Year
                                                                       410.0
              977.6
            1.613.6
                 Caparity Losses:
                 (millions of kw)
                                             Total since 1973
7.8
18.6
                                                                                                                         30.7
                 '; Kxc-luclos nuclear fuel expense

-------
5.7   Policy Alternative 6

          Policy Alternative 6 is identical to Policy
Alternative 5 except in assuming that all existing source
plants having a capacity of 300 megawatts or above will
be retro-fitted by 1977, instead of partly by 1977 (plants
having a capacity of 500 megawatts or above) and partly
by 1983 (plants having a capacity of under 500 megawatts)
as is assumed in Policy Alternative 5.  The coverages and
time phasing estimated by the EPA for Policy Alternative 6
are shown in Table 5.7-1.
          The economic and financial projections made
by TBS for Policy Alternative 6 are summarized in Table
5.7-2.
                         111-91-

-------
                                                                                  Taole 5.7-1

                                                                          POLICY ALTERNATIVE 6

                                                    COVERAGE AND TIME PHASING OK THERMAL POLLUTION CONTROLS
Generating Capacity
  In -Service Date
Pollution Control Equipment
_ In-Service Date _
__  ___   .__
PCtTlncorporated
  in Now Plants
     _________
PCE Retrofitted
in Existing Plants
                                                                              PCE Incorporated
                                                                                in New Plants
                                                                                                                                                    .
                                                                                                                                                 PCE Retroitted
                                                                                                                                                 in Existing Plants
             Before 1971
By 1977*
By 1983**
      35%
      14%
                                                                                                                                                        80%
             1971-1973
By 1977*
By 1983**
      41%
      11%
                                                                                                                                                        67%
             1974-1976
liy 1977*
By 1983**
                                                                             377
      49%
       3%
                                                                                                                               33%
                                                                                                             67%
NJ
             1977
                                           1977***
                                           By 1977*
                                                                             37%
                                                                                                                               33%
                                                           52%
                                                                                                             67%
             1978-1990
                                           1978-1990***
                                                                             73%
                                                                                                                              100%
           *The installation schedule for equipment required by 1977 is:  1974 -  15%; 1975 - 20%; 1976  - 25%; and 1977 - 40%.
         **The installation schedule for equipment required by 1083 is:  1981 -  lOTo, 1982 - 40%; and 1983 - 50%.
        ***Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for this pollution control equipment follow the
           same schedule as those for the generating capacity.  See Section 3 for details.

-------
                                                                 Table 5. 7-2

                                                         POLICY ALTERNATIVE 6

                                       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                   (dollar figures in billions of current dollars)
                                                                                       1977
                                            1983
                                 1990
                Capitalized Kxpenditures:
Total for the Year
Total since 1973
$ 32.0
 106.5
$ 61.7
 391.5
$  126.0
 1.018.7
               External Financing:
Total for the Year
Total since 1973
 $22. 1
  74.3
$ 40.4
 264.7
  $ 79.5
   658.4
 I
vo
               Operating Revenues;
Total for the Year
 $59.4
$119.5
  $251.4
               Operations & Maintenance Expenses:*
Total for the Year
 $27.8
 $50.9
   $99.1
               Consumer Charges:
               (conts/kwh)
Average for the Year
  2.50
  3.36
    4.51
               Energy Losses:
               (trill ions  <>t  Btu's)
Total for the Year
 441.5
 914.5
 1.613.6
               Capacity Losses:
               (millions of kw)
Total since 1973
   8.4
  17.4
    30.7
               *KxrIut|ps nuclear fuel expense

-------
5.8  Policy Alternative 7
          Policy Alternative 7 is similar to Policy
Alternatives 5 and 6.  It differs in requiring that
pre-1971 .peaking capacity be retro-fitted by 1983, a
requirement which adds 2 percent to the pre-1971 fossil
coverages assumed in the two related policy options.
Policy Alternative 7 also differs slightly in the as-
sumed time schedule for the retro-fitting of existing sources,

          As shown in Table 5.8-1, capacity brought into
service prior to 1971 is retro-fitted by dates that de-
pend on the type and size of the generating plants.
Nuclear plants are retro-fitted by 1978 in accordance
with the time schedule:
               15 percent of total retro-fitting
               completed as of 1975;
          •    another 20 percent completed as of 1976;

          •    another 25 percent as of 1977 ; and

          •    the remaining 40 percent as of 1978.

Fossil capacity brought into service prior to 1971 is
retro-fitted as follows:

          •    plants of 500 megawatts and above in 1978 ;
          •    plants of 300 megawatts to 500 megawatts
               in 1979 ;
               other base capacity in 1980 I and
                      111-94-

-------
                                                                                 Table 5.8-1

                                                                         POLICY ALTERNATIVE 7

                                                   COVERAGE AND TIMK PHASING OK THERMAL POLLUTION CONTROLS
         Generating Capacity
           In-Service Date
                       Pollution Control Equipment
                             In-Service Date
____  __ ____ _
PCE Incorporated
  in New Plants
.._ __  _____
PCE Retro-Fitted
in Existing Plants
________ _____
PCElncorporated
  in New Plants
 ___ __  _  __
PCE Retrofitted
in Existing Plants
            Before 1971
                             By 1978*
                             1978
                             1979
                             1980
                             By 1983**
                                                                                                    25%
                                                                                                    10%
                                                                                                     5%
                                                                                                                                                      80%
            1971-1973
H
H
 I
VO
Ui
1974-1976
                                         By 1977***
                                         By 1978*
                                         1978
                                         1979
                                         1980
                             By 1978*
                             1978
                             1979
                             1UDO
                                                                           37?
                                                                                                                 33%
                                                                                        37%
                                                                                         4%
                                                                                        11%
      37%
      12",
        3%
                                                                                                                                          67%
                                                        67%
            1977
                                         1977****
                                         By 1978*
                                                                37%
                                                                                        52%
                                                                                                                 33%
                                                                                                                                          67%
            1978-1990
                                         1978-1990****
                                                                           73"
                                                                                                                            100%
         *The installation schedule for equipment required by 1978 is:  1975 - 15%; 1976 - 20%; 1977 - 25%; and 1978 - 40%.
        **The installation schedule for equipment required by 1983 is:  1981 - 10%; 1982 - -10%; and 1983  - 507..
       ***The installation schedule for equipment required by 1977 is:  1974 - 15%; 1975 - ->0%; 1976 - 25%; and 1977 - 40%.
      ****Pollution control equipment to be functioning as of the plant's in-service date; cash outlays for  this pollution control equipment follow the
          same schedule as those for the generating capacity.  See Section 3 for details.

-------
               the remaining coverage, including cyclic
               and peaking capacity, by 1983.
The capacity to be retro-fitted by 1983 is done in accor-
dance with the same 10-40-50 installation schedule used
in Policy Alternatives 3 through 6.

          Capacity brought into service in the 1971-1973
period is phased according to a schedule similar to that
for the pre-1971 capacity, specifically:

          •    nuclear capacity by 1978;

          •    fossil capacity of 500 megawatts and
               above in 1978;
          •    fossil capacity of 300 megawatts to 500
               megawatts in 1979; and
          •    the remaining fossil coverage in 1980.

          Policy Alternative 7 further assumes that 37
percent of the fossil capacity and 33 percent of the
nuclear capacity brought into service in the 1974-1976
period has been designed to incorporate closed-cycle
cooling systems and is  fitted by  1977 with  such equipment,
as was also assumed in  Policy Alternatives  4, 5, and 6.
Policy Alternative 7 assumes that the retro-fitting of the
other  1974-1976 capacity additions  is spread as follows:

          •    nuclear  capacity by 1978;
          •    fossil capacity of 500 megawatts and
               above in 1978;
                       Hl-96-

-------
          •    fossil capacity of 300 megawatts to 500
               megawatts in 1979; and
          •    the remaining coverage in 1980.

          Capacity brought into service in 1977 and sub-
sequent years is treated the same in Policy Alternative
7 as in the two related options.

          The coverage and time phasing requirements
assumed in Policy Alternative 7 are shown in Table 5.8-1,

          The economic and financial implications of
Policy Alternative 7 are shown in Table 5.8-2.
                         111-97-

-------
                                                                Table 5. 8-2

                                                        POLICY ALTERNATIVE 7

                                      ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA

                                                (dollar figures in billions of current dollars)
                                                                                      1977
                                            1983
                                  1990
              Capitalized Kxpendi tares;
 Total for the Year
 Total since 1973
$ 31.2
 103.2
$ 61.6
 392.5
$  126.0
 1,019.8
 I
vo
oo
 I
              Kxterrml Finnnrin":
              Operating Revenues:
Total for the Year
Total since  1973
Total for the Year
 $21.5
  71.9
 $58.4
$ 40.4
 265.7
$119.8
  $ 79.4
   659.1
  $251.6
              Operations & Maintenance Expenses:*
Total for the Year
 $27.4
 $50.9
   $99.3
              Consumer Charges:
              (ccnts/kwh)
Average for the Year
  2.45
  3.36
    4.51
              Kr.orgy Losses:
              (trill ions ol  Btu's)
Total for the Year
 147.2
 909.3
 1.624.1
              Capacity Losses:
              (millions of kw>
Total since 1973
   2.8
  17.3
                                                          30.9
              *Kxcluiles nuclear fuel expense

-------
5.9 Summary Comparisons of Policy
    Alternatives 1 Through 7
          Selected summary data on the total economic and
financial impacts of Policy Alternatives 1 through 7 and
on their impacts relative to the baseline industry fore-
cast are presented in Tables 5.9-1 through 5.9-4.  These
tables focus on:
     •    capitalized expenditures;
     •    external financing;
     •    operations and maintenance expenses; and
     •    average consumer charges per kilowatt hour.
          Two central results are clearly evident in the
data on capitalized expenditures in Table 5.9-1.  First,
as is perhaps most easily seen in the figures for each of
the policy options relative to the baseline, delays in
the implementation of thermal pollution control require-
ments result in significant increases in the total amount
of capitalized expenditures over the 1974-1990 period.
Consider the data for Policy Alternatives 1, 3, 4, 5 and
6.   All of these policy options call for the same eventual
coverage of each type of capacity brought into service as
of any particular date, but vary in the dates by which
compliance is mandatory.  Policy Alternative 1, which
assumes the most rapid installation schedule, results in
capitalized expenditures for pollution control equipment
of $50.3 billion in the 1974-1990 period.  Policy Alternative
3,  which assumes the latest compliance, is estimated to
require pollution control expenditures of $56.2 billion.
Policy Alternatives 4, 5, and 6, which assume compliance
schedules in between those of Policy Alternatives 1 and 3,
result in the intermediate amounts displayed in Table 5.9-1.
                          111-99-

-------
                                     Table 5.9-1


                       IMPACT OF EPA POLICY ALTERNATIVES

                            ON CAPITALIZED EXPENDITURES:
                             SELECTED SUMMARY DATA
 Capitalized  Expenditures
(Ml I Ion H of <• urn-lit il o I I a r -i )
Capitalized  Expenditures Relative to  Baseline
                    iH of current  dollaru)





H
H
1— 1
O
O
Policy Alternative
0
1
2
3
4
5
6
7
1974-1977
93.8
107.2
107.2
98.7
99.8
106.2
106.5
103.2
1978-1983
270.2
283.9
284.4
302.0
297.8
287. 1
285.0
289.3
1974 -1983
364.0
391.1
391.6
400.7
397.6
393.3
391." 5
392.5
1984-1990
604. 1
627.3
627.3
623.6
624.7
627.0
627.2
627.3
1974-1990
£'68. 1
1.C18.4
1,018.9
1,024.3
1.C22.3
1,020.3
1,018.7
1,019.8
1974-1977
-
13.4
13.4
4.9
6.0
12.4
12.7
9.4
1978-1983
-
13.7
14.2
31.8
27.6
16.9
14.8
19. 1
1974-1983
.
27.1
27.6
36.7
33.6
29.3
27.5
28.5
1984-1990
.
23.2
23.2
19.5
20.6
22.9
23.1
23.2
1974-1990

50.3
50.8
56.2
54.2
52.2
50.6
51.7

-------
                                    Table 5. 9-2

                      IMPACT OF EPA POLICY ALTERNATIVES
                            ON EXTERNAL FINANCING:
                            SELECTED SUMMARY DATA
     Kxternal Financing
(billions  of current  dollars)
External Financing Relative to Baseline
        (billions  of current dollars )
P.'I:






H
t— 1
H
1
r-1
O
1
:ov Alternative
0
1
*>
3
4
5

6

7

I!'74-l
-------
                              Tab e 5. U-3

             IMPACT OF EPA POLICY ALTERNATIVES
           ON OPERATIONS AND MA INT liNANCi'J EXPENSES:
                    SELECTED SUMMARY DATA
Operations and Maintenance Expense 3
    (billions of current dollars)
Operations and Maintenance Expenses Relative to Baseline
                (billions of current dollars)





H
H
H
I
Policy Alternative
0
1
2
3
4
5
6
7
1977
26.6
27.8
27.8
27.3
27.3
27.3
27.8
27.4
1983
48.6
51.0
51.0
50.4
50.6
50.8
50.9
50.9
1990
95.4
99.3
99.3
98.6
98.8
99.0
99.1
99.3
1977
1.2
1.2
0.7
0.7
0.7
1.2
0.8
1983
2.4
2.4
1.8
2.0
2.2
2.3
2.3
1990
-
3.9
3.9
3.2
3.4
3.6
3.7
3.7

-------
                             Table 5.9-4

             IMPACT OF HPA I'OMCY AI.TKUNATIVKS
           ON AVKJIACJK C'ON.Sl'MKK CIIAKUKS 1'Klt MV1I
                    SELECTED Sl'MMAKY DATA
Avernge Consumor Charges por
      (current cents)
Average Consumer Charges per kwh Relative to Baseline
                  (current cents)








M
H
i_j
i^^
O
1
Policy Alternative
0
1
2
3
4
5
6

7



1977
2.
2.
2.
2.
2.
2.
2.

2.



40
50
50
43
44
47
50

45



1983
3.
3.
3.
3.
3.
3.
3.

3.



19
36
36
36
36
35
36

36



1990
4.
4.
4.
4.
4.
4.
4.

4.



32
51
51
51
51
51
51

51



1977
-
0. 10
0. 10
0.03
0.04
0.07
0. 10

0.05



1983

0.
0.
0.
0.
0.
0.

0.



-
17
17
17
17
16
17

17



1990
-
0. 19
0. 19
0. 19
0.19
0.19
0. 19

0. 19




-------
          Consider next the figures for Policy Alternatives
2 and 7.  Policy Alternative 2 differs from Policy
Alternative 1 only in its coverage by 1983 of pre-1971
peaking capacity, adding $0.5 billion to capitalized expen-
ditures in the 1978-1983 period.   Policy Alternative 7, in
contrast,  calls for some lags in compliance relative to
Policy Alternative 2 that increase capitalized expenditures
by $0.9 billion, to $51.7 billion relative to the baseline,
over the 1974-1990 period.
          The second major conclusion that emerges clearly
from the summary table is that the EPA's various  policy alter-
natives result in widely disparate patterns of capitalized
expenditures over time.  Capitalized expenditures attrib-
utable to pollution control equipment over the
1974-1977 period, range from a maximum of $13.4 billion
for Policy Alternatives 1 and 2 to a minimum of $4.9
billion for Policy Alternative 3.  These relationships
are sharply reversed in the subsequent sub-period.  To
cite figures for two policy options having the same eventual
coverages, Policy Alternative 1 results in capitalized
expenditures of $13.7 billion from 1978-1983; Policy
Alternative 3 results in pollution control expenditures of
$31.8 billion.  Policy Alternative 7's capitalized expendi-
tures are $9.4 billion and $19.1 billion in the respective
1974-1977 and 1978-1983 sub-periods.
          The costs of any capital expenditures by the
electric utility industry are passed on to consumers over
the life of the equipment and are reflected only gradually
in depreciation tax shields, but the relationships between
Policy Alternatives 1 through 7 manifest in the
capitalized expenditure data are evident also in the
external financing figures summarized in Table 5.9-2,
especially.in the data for the earlier sub-periods.  The


                      Hl-lOA-

-------
1974-1977 external financing requirements for Policy
Alternative 1 comprise $11.0 billion for pollution con-
trol equipment; for Policy Alternative 3, the industry's
total external financing includes $4.0 billion for
pollution control.  For Policy Alternative 7, the incre-
mental financing is $7.8 billion.
          The 1974-1977 relationships for external financ-
ing reverse sharply in the 1978-1983 period, as was true
of capitalized expenditures.  Policy Alternative 1 results
in external financing requirements during the period of
$9.1 billion.  Policy Alternative 3 requirements, in contrast,
are projected at $25.9 billion.  Policy Alternative 7's
1978-1983 requirements are $13.5 billion.
          The magnitude of the external financing require-
ments associated with pollution control equipment should
also be viewed relative to the industry's total external
financing activities.  The 1974-1977 pollution control
requirements increase the industry's baseline external
financings of $64.1 by a minimum of 6.2 percent for Policy
Alternative 3 to 17.2 percent for Policy Alternative 1 and
to a maximum of 17.3 percent for Policy Alternative 2.
The 1978-1983 pollution control requirements increase external
financing relative to a baseline of $180.3 billion by a
minimum of 5.0 percent for Policy Alternative 1 to a maximum
of 14.4 percent for Policy Alternative 3.
          The relative impacts of Policy Alternatives 1
through 7 on operating expenses is somewhat different from
their impacts on capitalized expenditures and external
financing.  As shown in Table 4.2-2, annual operating expenses
for thermal equipment installed after 1977 are assumed by
the EPA to be much lower than for equipment installed in
1977 or earlier.  Thus, as is evident in Table 5.9-3,
Policy Alternative 1 results in higher operations and

                           III-105-

-------
maintenance expenses,  both in 1977 and in later years, than
Policy Alternative 3.   As before, the policy options having
pollution control equipment installation schedules in
between those of Policy Alternatives 1 and 3 have operating
costs that are also in between those of Policy Alternatives
1 and 3.  To cite some illustrative numbers, the 1977
operations and maintenance expenses are $1.2 billion,
$0.8 billion and $0.7 billion for Policy Alternatives 1,
7, and 3, respectively.  The 1990 figures are $3.9 billion,
$3.7 billion and $3.2 billion for Policy Alternatives 1,
7, and 3.
           Table 5,9-4 displays the combined impact of the
capital and operating factors associated with each policy
option on average consumer charges per kilowatt hour.  The
various policy options result in incremental charges in
1977 ranging from 0.10 cents per kilowatt hour for Policy
Alternatives 1, 2 and 6 to 0.03 per kilowatt hour for the
chemical  equipment requirements of Policy Alternative 3.
However, what is striking in Table 5.9-4 is how little the
various policy alternatives differ from one another in the
long run.  In 1990, for example, all seven primary policy
options result in a projected increase of 0.19 cents per
kilowatt hour, or 4.4 percent, relative to a baseline charge
of 4.32 cents.
          In summary, the different thermal phasing assump-
tions in Policy Alternatives 1 through 7 result in sub-
stantially different time profiles and somewhat different
total amounts of capitalized expenditures and external
financing.  However, the lower operating expenses per unit
assumed by the EPA to apply to thermal equipment installed after
1977 by coincidence almost exactly offset the interest,
dividends, and other expenses associated with the higher total
capital expenditures of the alternatives having relatively
slow  installation schedules for  thermal equipment.

                      III-106-

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       6,  OVERVIEW OF EPA POLICY ALTERNATIVES
                  AFTER  EXEMPTIONS
6.1  Introduction

          Section 6 of this Report discusses the
implications of the EPA assumptions with respect to
exemptions potentially available under Section 316(a)
of the Act.  Such exemptions have the effect of reducing
the coverages assumed in the primary policy alternatives
by substantial amounts.  The coverages of pre-1978
capacity assumed in Policy Alternatives 1 through 7 to be
retro-fitted are reduced by approximately 80 percent.
Only the 1974-1977 capacity designed to be fitted with
closed-cycle cooling systems is assumed not to be affected
by assumptions.  Capacity coming into service in 1978 or
later is assumed to have coverages reduced by roughly a
half,  specifically to 38 percent for non-nuclear capacity
and 44 percent for nuclear capacity.
          Because the impact of exemptions is similar
across the seven policy alternatives considered in
Section 5, Section 6 focuses on their impact on only
three of the EPA options, namely,  Policy Alternatives 1,
3, and 7.
                    Ill - 107 -

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6.2  Policy Alternative 1-E.
          Policy Alternative 1-E  incorporates  the EPA's
estimate of the potential impact  of exemptions on the
coverages assumed in Policy Alternative  1.   The resultant
coverages and time phasings are shown  in  Table 6.2-1.
          The economic and financial consequences of
Policy Alternative 1-E are summarized  in  Table 6.2-2.
                          III-108-

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                                                                                Table 6.2-1

                                                                        POLICY A I/I KKNATIVK 1-K

                                                 COVKItAGE AND TIMING PHASING OK TIIEHMAI POLLUTION CONTROLS
                                                                          \\ITI1 KXKMl'llONS
Generating Capacity
  In-Service Date
Pollution Control Equipment
      In-Service Date _
________   ._
PCE Incorporated
  in New Plants
_^   _________
PCE Retro-Fitted
in Existing Plants
                                                                                                            PCE Incorporated
                                                                                                              in New Plants
                                                                                                                                               ---    _______
                                                                                                                                               PCE Retro-Fitted
                                                                                                                                               in Existing Plants
          Before 1971
                              By 1977*
                              By 1983**
       8% .
       1.8%
                                                                                                                                                     16%
          1971-1973
                                        By 1977*
                                                                                                    10%
                                                                                                                                                     13°;
M
M
 I
M
O
VO
 I
          1974-1977
1978-1990
                                        By 1977*
                              1978-1990***
                                                                37%
                                                                38%
                                                                                                   10 To
                                                                                                                             33%
                                                                                                                  44%
                                                                                                                                                     1?%
       •The installation schedule for equipment required by 1077 is:  1074 - 15%; 1975 - 20%: 1976 - 25%; and 1977 - 40%.
      **The installation schedule for equipment required by 1983 is:  1978 - 10%; 1979 - 10%; 1980 - 20%; 1981 - 20%; 1982 - 20%; and 1983 - 20%.
     ***Pollution control equipment to be functioning as of the plant's in-service date; catth outlays for this pollution control equipment follow the
        same schedule as those for the generating capacity. Sec Section 3 for details.

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                                                                  Table 6.2-2

                                                          POLICY ALTERNATIVE 1-E

                                       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                   (dollar figures in billions of current dollars)
                                                                                        1977
                                            1983
                                 1990
o
               Capitalized Expenditures;
                External Financing:
                Operating Revenues:
                Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$29.9
99.2.
$20.5
68.6
$58. 1
$27.3
$ 60.2
377.8
$ 39.4
255.0
$117.0
$50.0
$123.7
994.0
$ 78.1
642.5
$246.9
$97.4
                Consumer Charges:
                (cents/kwh)
Average for the Year
 2.44
 3.29
                                 4.43
                Energy Losses:
                (trillions of Btu's)
Total for the Year
157.7
352.2
                                                          683.3
                Capacity Losses:
                (millions of kw )
Total since 1973
  3.0
  6.7
                                                           13.0
                       lr.i nuclear fuel expense

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6.3  Policy Alternative 3-E
         The EPA's estimated impact of exemptions  on  Policy
Alternative 3 is incorporated  in Policy  Alternative
3-E.  The coverage and time phasing assumptions  are
summarized in Table  6.3-1.  The economic and financial
consequences of Policy Alternative 3-E are  displayed  in
Table 6.3-2.
                       III-lll-

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                                                                               Table 6. 3-1

                                                                       I'OI.ICY AI.TI.HNATIVK 3-K

                                                 COVERAGE AND TIME 1'IIASING OF THERMAL POLLUTION CONTROLS
                                                                          "WT1II EXEMPTIONS
      Generating Capacity
        In-Service Date
Pollution Control Equipment
      In-Service Date
________   .
PCE Incorporated
  in New Plants
     _________
PCE Retro-Fitted
in Existing Plants
__ ___    .
PCE Incorporated
  in New Plants
 --     ____ _
PCE ReTro-Fitted
in Existing Plants
         Before 1971
                                       By 1983'-
                                                                   9. 8%
         1971-1973
                                       Bv 1983-
                                                                                                   10™
                                                                                                                                                      13".
         1974-1977
                                       By 1983
                                                                                                   10"-
KJ
I
1978
1979-1981
1982-1990
1978**
By 1983*
1979-1981**
By 1983*
1982-1990**
31%
38%
387o
                                                                                                                            33%
                                                                                                                            33%
                                                                                                                            44%
                                                                                                                                                     11%
                                                                                                                    11%
      The installation schedule for equipment required by  1983 is:  1981 - 10%; 1982 - 4
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                                                                Table 6.3-2

                                                        POLICY ALTERNATIVE 3-E

                                      ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                 (dollar figures in billions of current dollars/
                                                                                      1977
                                            1983
                                1990
to
I
              Capitalized Expenditures;
              External Financing;
              Operating Revenues:
              Operations & Maintenance Expenses:*
Total for the Year
Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$29.4
97.7
$20.1
67.2
$57.8
$27.1
$ 61.3
380.3
$ 40.2
256.8
$117'.0
$50.0
$123.7
995.7
$ 78.0
643.5
$247.0
$97.9
              Consumer Charges;
              (cents /kwh)
Average for the Year
2.43
 3.29
 4.43
              Energy Losses:
              (trillions of Btu's)
Total for the Year
78.8
357.4
683.3
              Capacity Losses:
              (millions of kw )
Total since 1973
 1.5
  6.8
 13.0
             *Excludes nuclear fuel expense

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6.4   Policy Alternative 7-E

          Policy Alternative 7-E  incorporates  the  EPA's
estimate of the impact of exemptions on  the  coverages
assumed in Policy Alternative  7.  The  coverages  and
time phasings assumed in Policy Alternative  7-E  are
displayed in Table 6.4-1.

          The economic and financial consequences
of Policy Alternative 7-E are  presented  in Table
6.4-2.
                       III-114-

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                                                                                      Table 6.4-1

                                                                              POLICY ALTERNATIVE 7-E

                                                        COVERAGE AND TIME PHASING Of THERMAL POLLUTION CONTROLS
                                                                                  WITH EXEMPTIONS


                                                                           	F_o_sfc_il_Caj?J(.£_itjy	          	     Nuclear  Capacity	
              Generating Capacity        Pollution Control Equipment         PCE  Incorporated~PCE~Retrc)~Pitted         PCE~lncorporated         PCE Retro^Fitted
             '  In-Service Date          	In-Service Date	           in New Plants        '  in Existing Plants           in New Plants           in Existing Plants
                 Before 1971
                              By 1978*
                              1978
                              1979
                              11)80
                              1983*»
                                                                                                           5%
                                                                                                           2!'.
                                                                                                           1%
                                                                                                           2.2%
 M
 I
Ul
1971-1973
                              By 1978*
                              1978
                              107'J
                              IftflO
7.1%
0.8%
2. 1%
                                                  13%
                 1974-1976
                                               Hy 1977***
                                               By 1978*
                                               1978
                                               1079
                                               1980
                                                                 37%
                                                                                         7. 1%
                                                                                         2.3%
                                                                                         0.6%
                                                                                                                  33%
                                                                                                                                           13%
                 1977
                                               1077****
                                               By 1978
                                                                37%
                                                                                                                  33%
                                                                                                                                                            13%
                 1978-1990
                                               1978-1990****
                                                                                                                                   44%
              *The installation schedule for equipment required by 1978 is:  1975 -  15%; 1976 - 20%; 1977 - 25%; and 1978 - 40%.
             **The installation schedule for equipment required by 1983 is:  1981 -  10%; 1982 - 49%; and 1983 - 50%.
            ***The installation schedule for equipment required by 1977 is:  1974 -  15%; 1975 - 20%; 1976 - 25%; and 1977 - 40%.
           ****Pollution control equipment to be functioning as of the plant's in-servire date; cash outlays for this pollution control equipment follow the
               same schedule as those for the gonrrntinjj capacity.  Spr Section  3 for clrtnil.s.

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                                                   Table 6.4-2

                                           POLICY ALTERNATIVE 7-E

                        ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                    (dollar figures in billions of current dollars)
                                                                         1977
                                            1983
                                 1900
 Capitalized Expenditures;
Total for the Year
Total since 1973
$ 29.4
  97.6
$ 60. 3
 378. 5
123.8
994.7
 External Financing:
Total for the Year
Total since  1973
  20.1
  67.3
  39.5
 255.6
 78. 1
642.9
Operating Revenues:
Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
                                                                         58.0
                                                                         27. 2
                                          117'. 3
                                           50.0
                                247.3


                                 97. 7
Consumer Charges:
(cents/kwh)
Average for the Year
                                                                        2. 44
                 3.29
                 4.43
Energy Losses:
(trillions Btu's)
Total for the Year
                                                                         98.4
                 310.1
                 641.?
Capacity Losses;
(millions of kw)
Total since 1973
   1.7
                                             5.9
                                  12.?
* Excludes nuclear fuel expense

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6.5 Summary Comments on the Impact of Exemptions
          Selected summary data on the total economic and
financial impact of Policy Alternatives 1-E, 3-E, and 7-E
are shown in Tables 6.5-1 through 6.5-4.  As is evident
in all these tables, the impact of each of the policy
options before exemptions is substantially reduced by
316(a) exemptions.
          As shown in Tables 6.5-1 and 6.5-2, the effects
of exemptions on capitalized expenditures and external
financing requirements in any given period depends on
the proportion of retro-fitted versus new equipment in
the total capitalized expenditure figure.  Thus, the large
amount of 1978-1983 retro-fitting assumed in Policy
Alternative 3 is substantially reduced in Policy Alternative
3-E, from $31.8 billion to $11.9 billion.
          As is evident in Tables 6.5-3 and 6.5-4, the
effect of exemptions in the long run depends more on the
reduced requirements applicable to new sources than on the
reductions in retro-fitting requirements.  Thus, by 1990,
average consumer charges relative to the baseline are 0.11
cents per kilowatt hour, a decline of about 40 percent from
the 0.19 cents per kilowatt hour associated with the EPA
policy alternatives before exemptions.
                     III-117-

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                                     Table 6.5-1

            IMPACT OF EPA POLICY ALTERNATIVES WITH EXEMPTIONS
                        ON CAPITALIZED EXPENDITURES:
                           SELECTED SUMMARY DATA



Capitalized Expenditures                                Capitalized  Expenditures  Relative  to  Baseline
   (l)illions of rnrrcnt dollars)	                             (billions of current dollars)
                                                       1974-1977       1978-1983      1974-1083      1984-1990       1974-19SC



                                                           5.4            8.4           13.8           12.1            25.9

                                                           3.9           11.9           15.8           11.4            27.2

                                                           3.8           10.7           14.5           12.1             26.6
PMicv Altorn.itive
0
l-K
3-E
7-E
H
H
H
M
CD
1974-1977 1978-1983 1974-19113 1984-1990 1974-1990
93.8 270.2 364.0 604.1 968.1
99.2 278.6 377.8 616.2 994.0
97.7 282.1 379.8 615.5 995.3
P7.6 280.9 378.5 616.2 994.7



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 I
I-1
VO
 I
                                                                           Table 6.5-2



                                                   IMPACT OP EPA POLICY ALTERNATIVES WITH EXEMPTIONS

                                                                  ON EXTERNAL FINANCING:

                                                                  SELECTED SUMMARY DATA
                                            External  Financing                                     External Financing Relative to Baseline

                                            (billions of current dollars)                                              (billions of current dollars)
Po'icv .Mtornntive
0
1-E
3-K
7-K
1974-1977
64.1
68.6
67.2
67.3
1978-1983
180.3
186.4
109.6
188.3
1974-1983
244.4
255. 0
256.8
255.8
1984-1990
380.4
387.5
306.7
387.3
1974-1990
624.8
642.5
643.5
642.9
1973-1977
-
4.5
3.1
3.2
1978-1983
-
6.1
9.3
8.0
1974-1983
-
10.6
12.4
11.2
1984-1990
-
7.1
6.3
6.9
1974-1990
-
17.7
18.7
18.1

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                             Table 6. 5-3

    IMPACT OF EPA POLICY ALTERNATIVES WITH EXEMPTIONS
         ON OPERATIONS AND MAINTENANCE EXPENSES:
                    SELECTED SUMMARY DATA
Operations and Maintenance Expenses
     (billions of mi-rent dollars)
Operations and Maintenance Expenses Relative to  Baseline
              (billionH of current dollars)
IVHcv




• Alternative
0
1-K
3-K
7-E
1977
26.6
27.3
27.1
27.2
1083
48.6
50.0
50.0
50.0
1990
95. 4
97.4
97.9
97.7
1977
-
0.7
0.5
0.6
1983
-
1.4
1.4
1.4
1990
-
2.0
2.5
2.3

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M
 I
to
M
                                                                            Table 6. 5-4

                                                    IMPACT OF KPA POLICY ALTERNATIVES WITH EXEMPTIONS
                                                           ON AVERAGE CONSUMER CHARGES PER KWH
                                                                   SELECTED SUMMARY DATA
                                                Average Consumer Charges per kwh
                                                         (current cents)
Poliev Alternative

1
3
7
0
-E
-K
-E
1977
2.40
2.44
2.43
2.44
1983
3.19
3.29
3.29
3.29
1990
4.32
4.43
4.43
4.43
Average Consumer Charges per kwh Relative to Baseline
                  (current cents)
1977
0.04
0.03
0.04
1983
0.10
0.10
0.10
1990
0.11
0.11
0.11

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        7,   IMPACT OF REDUCED INDUSTRY GROWTH
7.1   Introduction
          The preceding analyses all employed the most-
likely projection of peak load demand growth which implied
that the doubling in size of the electric utility industry
each decade would continue through the 1970's with a
gradual decline during the 1980's.  While many conserva-
tionists have long preached the need for energy conserva-
tions, the recent Arab oil embargo has demonstrated not
only the need for conservation, but also the economic
realities associated with a rapid curtailment in the in-
dustry's growth.

          In an effort to assess the economic and financial
impacts implicit with a gradual shift to conservation of
electrical energy, the EPA requested a comparison of Policy
Alternatives 0, 1 and 1-E with a projection of relatively
low growth in peak load demand.  It should be noted that
these assumptions are also consistent with a slackening
of demand due to escalating electrical energy costs.
                         Ill-  122 -

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7.2    Low Demand Assumptions

           The low demand growth assumptions are consistent
 with the minimum growth scenarios employed by the TAC-
 Finance.  Specifically, peak load growth in kilowatts has
 been limited to:
           •    1971-1975  6.2 percent per year
           •    1976-1980  5.7 percent per year
           •    1981-1985  5.1 percent per year
           •    1986-1990  4.4 percent per year.

           In terms of industry growth, the above load
 growth implies that generating capacity in the period
 1970 through 1990 will be:
           •    1970  324.6 million kilowatts
           •    1975  438.5 million kilowatts
           •    1980  578.6 million kilowatts
           •    1985  741.9 million kilowatts
           «    1990  920.2 million kilowatts
 These projections of industry growth during the 1970's
 and 1980's represent more than a 25 percent decrease in
 generating capacity and a decline in the average growth
 rate from 6.9 to 5.3 percent.
                           III-123-

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7.3   Economic Consequences of Low Demand
          The assumptions outlined in Section 7.2 define
the low demand growth conditions for the electric utility
industry and were the only modifications to Policy
Alternatives 0, 1, and 1-E.  Tables 7.3-1 through 7.3-3
provide selected summary data for these three alternatives.

     7.3.1  Prior to Exemptions.  A comparison of Tables 7.3-1
and 3.3-1  yields the overall impact of low demand growth
upon the baseline conditions within the electric utility
industry.  In general, the 1970-1990 reduction in peak load
demand of 25 percent results in an overall reduction in
1974-1990 capitalized expenditures by 40 percent and exter-
nal financing requirements by 45 percent.  Unfortunately,
these significant reductions in construction and financing
are not passed through to the consumer.  The above-mentioned
reduction in peak load demand would reduce consumer charges
by only 5 percent.  These observations are consistent with
the rate adjustments being requested and the generating addi-
tions being delayed by those electric utilities undergoing
significant conservation during the current "energy crisis."

          In terms of the Act's impact, the results
are the same for Policy Alternative 1 although the mag-
nitude of the benefits are reduced.  For example, the pre-
viously determined $50.3 billion increase in capitalized
expenditures would be reduced by 32 percent to $34.3 billion.
The reduction in external financing requirements would
be 38 percent  ($33.5  to $20.9 billion).  In addition, the
differential impact in consumer charges of 0.19£/kwh would  not
                       III-124-

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                                                              Table 7.3-1

                                                 POLICY ALTERNATIVE 0 (LOW DEMAND)

                                   • ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                                (dollar figures in billions "o/'current dollars)
                                                                                      1977
                                            1983
                                 1990
Ni

-------
be changed at all.  Thus, the overall impact of reduced
industry growth yields:

          •    a more than proportionate reduction
               in construction requirements and
               their related financing requirements;
          •    a slight  decrease in the charges borne
               by the consumer; and
          •    an increasing share of total expen-
               ditures being related to pollution
               control equipment.

     7.3.2  After Exemptions.  The foregoing conclusions
continue to hold after consideration of exemptions poten-
tially available under Section 316(a) of the Act.  Under
the industry growth assumptions employed in Sections 3-6,
Policy Alternative 1 requires $50.3 billion in capitalized
expenditures without exemptions and $25.9 billion after
exemptions — a reduction in the Act's impact by nearly
50 percent.  With low demand growth assumptions, the
required capitalized expenditures is reduced to $34.3
billion without exemptions and $17.7 with exemptions.  Once
again, the percentage reduction is nearly 50 percent.
Similar relative changes in external financing requirements
and consumer charges result  from consideration of
exemptions under the conditions of most-likely and low
demand growth.
                     III-126-

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                                                  Table 7.3-2

                                    POLICY ALTERNATIVE 1 (LOW DEMAND)

                       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                                    (dollar figures in billions of current dollars'
                                                                        1977
                                            1983
                                1990
 Capitalized Expenditures;
External Financing:
Operating Revenues:
Operations & Maintenance Expenses:*
                                             Total for the Year
                                             Total since 1973
Total for the Year
Total since 1973
Total for the Year
Total for the Year
$24.3
75.2
$16.1
49.0
$54.3
$26.0
$ 40.3
270.4
$ 24.6
171.5
$98.1
$44.4
$ 65.7
619.4
$ 37.6
368.2
$177.5
$77.4
Consumer Charges:
(cents/kwh)
Average for the Year
 2.46
 3.24
   4.28
Energy Losses:
(trillions  ol  Btu's)
Total for the Year
431.0
762. 1
1.166.8
Capacity Losses;
(millions of k\v  j
Total since 1973
  8.2
 14.5
   22.2
-'•Excludes nuclear fuel expense

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                                                              Table 7. 3-3

                                                POLICY ALTERNATIVE 1-E (LOW DEMAND)

                                   ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED  DATA
                                                (dollar figures in billions of current dollars)
                                                                                    1977
                                           1983
                                1990
             Capitalized Expenditures;
Total for the Year
Total since 1973
$22.4
 68.3
$ 39.5
 260.0
                                                                                                                 $ 64.6
                                                                                                                  602.8
oo
I
             External Financing:
Total for the Year
Total since 1973
$14.5
 43.3
$ 24.1
 164.1
$ 37.0
 358.2
             Operating Revenues:
             Operations & Maintenance Expenses:*
Total for the Year
Total for the Year
$53.0
$25.6
                                             .0
 $43.8
$174.1


 $76.1
             Consumer Charges:
             (cents /kwh)
Average for the Year
 2.40
  3.17
                                4.20
             Energy Losses:
             (trillions of Btu's)
Total for the Year
131.4
 273.3
                                                         467.8
             Capacity Losses:
             (millions of lew )
Total since 1973
  2.5
   5.2
   8.9
             "•Excludes nuclear fuel expense

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      8,  REVIEW OF ALTERNATIVE  TECHNOLOGICAL
                   ASSUMPTIONS
8.1   Introduction
          Section 8 reviews  the  economic and financial
consequences of alternative  assumptions about;

          •    the capital costs per kilowatt
               of generating capacity of thermal
               and chemical  pollution control equip-
               ment;
          •    the operating costs of such pollution
               control  equipment,  and
          •    the impact of closed-cycle cooling
               systems  on operating efficiency of the
               generating capacity on which such equip-
               ment is  installed.

          Section 8 thus  considers the effect of
uncertainties  in the  "most-likely" capital costs and
operating characteristics discussed in Section 4 and
assumed in the economic and  financial projections
presented in the other  sections  of this report.  As
mentioned earlier, Section 8 is  based on a report sub-
mitted to the  EPA by  TBS  on  September 7, 1973.
 Economic and Financial Implications of the Federal Water
 Pollution Control Act of 1972 for the Electric Utility
 Industry.
                     Ill - 129 -

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                       - 130 -
          The coverage and time phasing of pollution
control requirements assumed in Section 8 are the same
as those in Policy Alternative 1.  However, because TBS's
earlier report focused only on the 1974-1983 period, the post-
1983 requirements of Policy Alternative 1 are excluded
from consideration in the analysis reviewed in Section
8.  As a consequence, this section's figures for capital-
ized expenditures, external financing, etc. in the years
preceding 1983 do not reflect any cash outlays for the
construction of polluti6n control equipment that is
assumed in either sections of this report to come into
                                     2
service in 1984 and subsequent years.
          The alternative technological assumptions
proposed by the EPA for analysis by TBS differ only in
their assumed costs and in their assumed impact on gen-
erating efficiencies.  Section 8 therefore focuses on
these different assumptions and on their economic and
financial consequences.  The percentages of each type
of capacity affected by the Act's pollution control
requirements and the timing of installation of pollution
control equipment are those that were discussed in
detail for Policy Alternative 1 in Section 4.  An
overview of the alternative technological assumptions
considered by TBS is perhaps best conveyed graphically.
Such an overview is presented in Figure 8.1-1.
     magnitude of construction work in progress for
 post-1983 pollution control equipment can be seen by
 comparing capitalized expenditures through 1983 for
 Policy Alternatives 1 and l(a).
                           III-130-

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-------
8.2  Alternative Technological Assumptions
          The cost assumptions considered  in various
combinations in this section can be presented  in  five
tables.  Table 8.2-1, which displays the so-called
"most-likely" costs associated with the chemical  effluent
guidelines,  is simply a reproduction of Table 4.2-4,
which was discussed in Section 4.  As shown in Figure
8.1-1, these chemical costs are employed in all but
Policy Alternatives l(f) and (g) below.  These two
cases consider the impact of some "maximum" estimates
of chemical pollution control costs.  The  maximum cost
figures specified by the EPA are set out in Table 8.2-2.

          Tables 8.2-3 through 8.2-5 present the
alternative assumptions with respect to thermal pollution
control equipment.  Table 8.2-3 is a reproduction of the
"most-likely" cost assumptions discussed in Section 4.
Tables 8.2-4 and 8.2-5 present the EPA's "maximum" and
"minimum" estimates for the same cost and  operating
variables.
                        HI-132-

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                                           Table 8:2-1


                              MOST-LIKELY  CAPITAL AND OPERATING COSTS
                                          CHEMICAL GUIDELINES
                                           1977 Guidelines
M
to
I
Capacity Placed in Service;
     Prior to 1971
                  Capital Expenditures
                  Annual Operating Expenses
             1971-1977
                  Capital Expenditures
                  Annual Operating Expenses
                                                           Non-Nuclear
                                                            Capacity
                                                              ($/kw)
                                                      1.95*
                                                      0.85


                                                      1.05
                                                      0.55
                                                                                 Nuclear
                                                                                 Capacity
                                                                                  ($/kw)
0.85
0.50


0.85
0.50
                                              (continued)

-------
Table  8.2-1  (Cont.)
                                     1983 Guidelines
 Capacity Placed in Service;
      Prior to 1971
            Additional Capital Expenditures
           Additional Annual Operating Expenses
      1971-1977
            Additional Capital Expenditures
           Additional Annual Operating Expenses
      1978-1983
            Capital Expenditures
            Annual Operating Expenses
                                                     Non-Nuclear
                                                      Capacity
                                                        ($/kw)
3.35
0.65


2. 75
0.35


2.60
0.25
                           . Nuclear
                            Capacity
                             ($/kw)
2.75
0.35


2. 75
0.35
2.00
0.20
*All costs are specified at 1970 levels.  Cost escalation occurs at the inflation rates projected
  for each type of generating capacity in Table 3. 2-1.

-------
                                               Table 8.2-2

                             MAXIMUM CAPITAL AND OPERATING COSTS
                                        CHEMICAL GUIDELINES
                                            1977 Guidelines

        Capacity Placed in Service:
        - - -
             Prior to 1971
                                                            Non-Nuclear                   Nuclear
                                                             Capacity                      Capacity
                                                              ($/kw)                       ($/kw)
                  Capital Expenditures                        17.00*                         7.00
V                 Annual Operating Expenses                   1.35                          1. 15
              1971-1977
                   Capital Expenditures                       11.00                          4.50
                  Annual Operating Expenses                   0. 90                          0. 75
                                               (continued)

-------
Table 8.2-2 (continued)
                                     1983 Guidelines
Capacity Placed in Service:

      Prior to 1971
            Additional Capital Expenditures
            Additional Annual Operating Expenses
      1971-1977
            Additional Capital Expenditures
            Additional Annual Operating Expenses
      1978-1983
            Capital Expenditures
            Annual Operating Expenses
                                                      Non-Nuclear
                                                       Capacity
                                                        ($/kw)
 5.00
 0.25


 3. 30
 0. 15


14.30
 1.05
                              Nuclear
                              Capacity
                               ($/kw)
3.00
2. 00
0. 15


6. 50
0.90
*A11 costs are specified at 1970 levels.

-------
                                                Table 8.2-3

                                    CAPITAL AND OPERATING COSTS -
                                          THERMAL GUIDELINES
M
M
I
Capital Expenditures ($/kw)

      for Back-Fitted Units
      for New Units

Annual Operating Expenses ($/kw)
      installed by  1978
      installed by  1978-1990
                                                             Non-Nuclear
                                                               Capacity
                                                               15.00*
                                                                7.50
**
                                                               42.00
                                                               15.00
                                                                                    Nuclear
                                                                                    Capacity
                          18.00
                          10.00
                          42.00
                          12.00
        Capacity Losses
              due to Running Cooling Units
              due to Increased Back Pressure
                                                        1%
                                                        2
                           1%
                           2
         *A11 costs are specified at 1970 levels.  Cost escalation occurs at the inflation rates
         projected for each type of generating capacity in Table 3. 2-1.

         **Annual operating expenses associated with the Act will be incurred only by tnose
         plants required to install cooling facilities and only in amounts to offset operating
         inefficiencies.

-------
oo
I
                                                Table 8.2-4

                             MAXIMUM CAPITAL AND OPERATING COSTS
                                        THERMAL GUIDELINES
        Capital Expenditures ($/kw)
                                                            Non-Nuclear                  Nuclear
                                                             Capacity                     Capacity
     for Back-Fitted Units                            28.00*                         38.00
     for New Units                                    7.50                          10.00

Annual Operating Expenses ($/kw)

     for 1977 Guidelines                              84.00                          84.00
     for 1983 Guidelines                              18.00                          24.00

Capacity Losses

     due to Running  Cooling Units                       1%                             1%
     due to Increased Back Pressure                    5                              5
        *A11 costs are specified at  1970 levels .

-------
                                       Table 8.2-5

                     MINIMUM CAPITAL AND OPERATING COSTS
                                THERMAL GUIDELINES
                                                   Non-Nuclear                    Nuclear
                                                     Capacity                      Capacity

Capital Expenditures ($/kw)
     for Back-Fitted Units                            10.00*                         12.00
     for New Units                                    7.50                          10.00

Annual Operating Expenses ($/kw)

     for 1977 Guidelines                              21.00                          21.00
     for 1983 Guidelines                              12.00                           6.00

Capacity Losses

     due to Running Cooling Units                       1%                             1%
     due to Increased Back Pressure                   1                              1
*A11 costs are specified at 1970 levels.

-------
8.3   Policy Alternative 1 (a)
          As mentioned above, Policy Alternative l(a)
presumes the EPA's most-likely estimates of capital and
operating costs for both chemical and thermal pollution
control equipment and of the impact of closed-cycle
cooling systems on generating efficiencies.  A brief
summary of the projected economic and financial im-
plications of Policy Alternative l(a) is presented in
Table 8.3-1.3

          As shown in Table 8.3-1, the assumptions
behind Policy Alternative l(a) imply that  the electric
utility industry will spend $35.5 billion  dollars dur-
ing the period 1974-1983 to comply with the chemical
and thermal effluent guidelines of the Act.  Of this
amount, 68.2 percent  ($24.2 billion) corresponds to
the thermal guidelines; the remainder ($11.4 billion)
represents costs associated with the chemical guide-
lines.  During the period 1974-1983, 64.2 percent of the
expenditures ($22.8 billion) have been capitalized;
the remainder  ($12.7 billion) are the operating ex-
penses incurred during  the 1974-1983 period.

          Table 8.3-1 also shows how Policy Alternative
l(a)'s capitalized expenditures and operating costs vary
over  the  1974-1977 and  1978-1983 periods.  Operations
 See Economic and Financial Implications . . . ,  Case I for
 further detail.
                          III-140-

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                                   TABLE 8,3-1

                             POLICY ALTERNATIVE  KA)

              ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA
                           (billions of current  dollars)
                               Capitalized         Operating
                               Expenditures         Expenses           Total
                               Relative to        Relative  to       Relative  to
                                 Baseline           Baseline          Baseline
1974-1983
     Chemical Guidelines            5,5             $  5.9           $  11.4
     Thermal Guidelines            17.4                6.8              24.2
     Total Impact*              $  22.8             $12.7           $  35.5
1974-1977
     Chemical Guidelines         $   2.1              $ 1.0
     Thermal Guidelines            10.9                1.4
     Total Impact*              $  13.0              $ 2.3
1978-1983
     Chemical Guidelines         $3.4               $4.9            $8.3
     Thermal Guidelines             6.5                5.4              11.9
     Total Impact*               $  9.8              $10.3            $  20.1
*Totals may not equal the sum of  components  due  to rounding.
                                 III-141-

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and maintenance expenses for both chemical and
thermal pollution control increase substantialy
from the 1974-1977 period to the 1978-1983 period
as the amount of equipment in service increases.  The
time schedule for installing chemical equipment is
such that capitalized expenditures in this category
take place at roughly equal average yearly rates
during the two periods.  Capitalized expenditures
for cooling equipment are, however, much higher in
the early period.  This latter relationship would
of course be modified substantially under the thermal
equipment time phasing assumptions used in other of
the major policy alternatives.

         Policy Alternative l(a)'s external financing
requirements and 1983 average consumer charges per kilo-
watt are presented in the summary tables in Section 8.10
                         III-142-

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8.4   Policy Alternative  l (b)

           Policy Alternative  l(b) differs from Policy

Alternative  l(a) only in using the EPA's estimated maximum

capital costs for the retro-fitting  of closed-cycle

cooling systems.  The impact  of Policy Alternative l(b)'s

assumptions  is described in part in  Table 8.4-1.  Further
                                                 4
summary data are presented in Section 8.10.
                        TABLE 8,4-1

                   POLICY ALTERNATIVE 1 (B)
        ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA
                 (billions of current dollars)
  1974-1983

  Chemical Guidelines

  Thermal Guidelines

      Total
                      Capitalized
                      Expenditures
                      Relative to
                      Baseline
 $5.5

 23.4
             Operating
              Expenses
             Relative to
               Baseline
$ 5.9

  6.8
$28.9
$12.7
              Total
            Relative  too
             Baseline
$ 11.4

  30.2
 $41.6
 NOTE:  Totals may not equal the sum of components due to rounding. .
  See also  Economic and Financial Implications  . . . ,  Case V,
  for further detail.
                         III-143-

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8.5   Policy Alternative 1 (c)

            Policy  Alternative l(c)  adds maximum  thermal

operating  costs and efficiency  losses to  the maximum

thermal retro-fitting costs assumed in Policy Alter-

native l(b).   Policy  Alternative l(c)'s capitalized

expenditures and  operations and maintenance expenses
are  shown  in Table  8.5-1.5
                         TABLE 8.5-1

                   POLICY ALTERNATIVE 1 (c)
          ECONOMIC AND FINANCIAL CONSEQUENCES:   SELECTED  DATA
                  (billions of current  dollars)
                         Capitalized   Operating
                        Expenditures   Expenses
                         Relative to   Relative to
                           Baseline    Baseline
                          Total
                        Relative to
                         Baseline
    1974-1983


    Chemical Guidelines

    Thermal Guidelines

    Total Impact
 $5.5

 30.1

$35.5
 $5.9

 25.7

$31.6
$11.4

 55.8

$67.1
    NOTE:  Totals may not equal the sum of components due to
          rounding.
 See also  Economic and Financial Implications
 for further detail.
                          Case III,
                           III-144-

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8.6   Policy Alternative  1 (d)

           Policy Alternative  l(d) assumes most-likely

thermal operating costs and efficiency  losses,  as in

Policy Alternatives l(a) and  l(b),  and  minimum  thermal

retro-fitting  costs.   As holds  for all  Policy Alterna-

tives l(a) through l(e), chemical costs are assumed

to  be the EPA's most-likely estimate.   The consequent

capitalized  expenditures and  operating  expenses are

shown in Table 8.6-1.6
                        TABLE 8.6-1

                  POLICY ALTERNATIVE 1 (D)

          ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA

                 (billions of current dollars)


                       Capitalized    Operating
                       Expenditures    Expenses       Total
                       Relative to    Relative to   Relative to>
                        Baseline      Baseline       Baseline -
   1974-1983


   Chemical Guidelines       $5.5        $5.9        $11.4

   Thermal Guidelines        14.5          6.8          21.3

   Total Impact             $20.0        $12.7        $ 32.7
   NOTE:  Totals may not equal che sum of components due to
         rounding.
c
 See  also Economic and Financial  Implications  . . . ,  Case  IV,
 for  further detail.
                       III-145-

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8.7   Policy Alternative 1 (e)
           Policy Alternative l(e)  incorporates the EPA's
minimum estimates both for  thermal  retro-fitting  costs
and  for thermal operating costs and efficiency losses.
Policy Alternative  l(e)'s projected capitalized expen-
ditures and  operations and  maintenance expenses are
shown in Table 8.7-1.7
                       TABLE 8.7-1
                 POLICY ALTERNATIVE 1 (E)
        ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
                  (billions of current dollars)

                       Capitalized    Operating
                       Expenditures     Expenses       Total
                       Relative to    Relative to   Relative to
                        Baseline       Baseline      Baseline
    1974-1983            	
   Chemical Guidelines      $5.5         $5.9        $11.4
   Thermal Guidelines        13.3          3.7          17.6
   Total Impact            $18.7         $ 9.6        $ 28.3
  NOTE:  Totals may not equal the sum of components due to rounding.
7
 See  also Economic and Financial Implications . . . ,  Case  II,
 for  further  detail.
                          "1-146-

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8.8   Policy Alternative I(f)

           Policy Alternative l(f)  assumes  that all
thermal costs are at the EPA's  most-likely levels,  as
Policy Alternative  l(a), but that  chemical costs
are  at the estimated maximum levels  shown  in Table
8.2-2.  The  implications of  these  assumptions for
capitalized  expenditures and operating costs are
shown in Table 8.8-1.8
                      TABLE 8,8-1
                   POLICY ALTERNATIVE  1 (F)
       ECONOMIC AND FINANCIAL CONSEQUENCES:  SELECTED DATA
                (billions of current dollars)

                     Capitalized    Operating
                     Expenditures     Expenses         Total
                     Relative to    Relative to     Relative to
                      Baseline       Baseline        Baseline
    1974-1983          	    	     	
   Chemical Guidelines  $28.4         $8.8          $27.2
   Thermal Guidelines     17.4           6.8            24.2
   Total Impact        $ 35.7         $15.6          $ 51.3
   MOTE:   Totals may not equal the sum of components due to rounding.
o
 See also Economic and Financial Implications .  . . ,  Case VII,
 for further  detail.
                          III-147-

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8.9   Policy Alternative 1 (g)

           Policy Alternative l(g)  incorporates  the
maximum assumptions both  for chemical  and for  thermal
costs and efficiency losses.  The  capitalized  expen-
ditures and  operating costs associated with this
                                                        g
"worst case" alternative  are shown in  Table 8.9-1.
                        TABLE 8,9-1
                   POLICY ALTERNATIVE 1 (G)
        ECONOMIC AND FINANCIAL CONSEQUENCES: SELECTED DATA
                    (billions of current dollars)
   1974-1983
   Chemical Guidelines
   Thermal Guidelines
   Total Impact
Capitalized   Operating
Expenditures    Expenses
Relative to   Relative to
 Baseline      Baseline

  $ 18.4
    30.1
              Total
            Relative to
             Baseline

              $ 27.2
                55.8
  $48.5
$34.5
$83.0
   NOTE:  Totals may not equal the sum of components due to rounding.
9
 See  also Economic and Financial Implications
 for  further  detail.
                       .., Case IX,
                             III-148-

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8.10  Summary Conclusions About the Alternative
cy_
5T
     Technological Assumptions

         Table 8.10-1 summarizes the total  impact
of the chemical and thermal assumptions on  capitalized
expenditures and operating expenses during  the 1974-
1983 period for Policy Alternative l(a) through Policy
Alternative l(g).  It also presents projected external
financing requirements during the 1974-1983 period  rel-
ative to the baseline Policy Alternative 0.  Table
8.10-1 also includes 1983 coverage consumer charges
per kilowatt hour relative to a baseline price of 3.19
cents per kilowatt hour.

          The consequences of the range of  the un-
certainties associated with technological factors can
be seen by comparing the summary data for Policy
Alternatives l(a), l(e), and l(g).  Capitalized expen-
ditures for pollution control equipment under most-
likely assumptions are $22.8 billion during the 1974-
1983 period, but range from $18.7 billion to $48.5
billion.  Operating expenses attributable to pollution
control during the period are $12.7 billion under
most-likely assumptions, but range from $9.6 billion
to $34.5 billion.  Incremental external financing
requirements are $16.4 billion during the period
under most-likely assumptions, but range from $13.6
billion to $49.7 billion.  The increased average
consumer charges per kilowatt hour in 1983  due to
pollution control equipment are 0.16 cents  under
most-likely assumptions, but range from 0.13 cents
to 0.54 cents.
                      HI-149-

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                                                     TABLE 8,10-1
                                   IMPACT OF ALTERNATIVE TECHNOLOGICAL ASSUMPTIONS:
                                                 SELECTED SUMMARY DATA1
              Capitalized Expenditures
External Financing
   Operations and
Maintenance Expenses
     Average Consumer
Charges Per Kilowatt Hour
Policy
Alternative
1974-1983
Relative to Baseline
(billions of dollars)



M
M
I
M
Ui
O


0
1
1
1
1

1
1
1

(a)
(b)
(c)
(d)

(e)
(f)
(g)
-
22.
28.
35.
20.

18.
35.
48.

8
9
5
0

7
7
5
1974-1983
Relative to Baseline
(billions of dollars)
-
16.
21.
24.
15.

13.
25.
49.

4
0
4
0

6
3
7
1974-1983
Relative to Baseline
(billions of dollars)
-
12.
12.
31.
12.

9,
15.
34.

7
7
6
7

6
6
5
1983
Relative to Baseline
(cents)

0.
0.
0.
0.

0.
0.
0.
-
16
19
21
16

13
23
54
Expressed in current dollars.

-------
          The impact of changing individual elements
in the sets of assumptions can also readily be seen
in Table 8.10-1.  As is evident from Figure 8.10-1,
the impact of most-likely versus maximum versus minimum
assumptions for thermal retro-fitting costs can be seen
by comparing Policy Alternatives l(a), l(b) and l(d).
The impact of most-likely versus maximum thermal
operating costs and efficiency losses can be seen
by comparing Policy Alternatives l(b) and l(c); the
most-likely versus minimum comparisons can be seen in
Policy Alternatives l(d) and l(e).   Finally, the
impact of most-likely versus maximum chemical cost
assumptions can be seen by comparing Policy Alternatives
l(a) and l(f).  A commentary on such comparisons is
presented in the September 7, 1973 TBS report to the EPA
and thus is not reproduced in detail here.
                       III-151-

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         APPENDIX:  RESEARCH METHODOLOGY
A.I   Introduction
         This appendix on research methodology
consists of a non-technical overview of the logical
structure of the computer model used to derive the
projections discussed and analyzed in the text of this
report.  The model, called PTm, is an extension of a
model developed by Dr. Howard W. Pifer of Temple, Barker &
Sloane and Professor Michael L. Tennican of Harvard University ,
Graduate School of Business Administration, to pro-
vide projections for the Technical Advisory Committee
on Finance to the 1973-1974 National Power Survey.
         In broad terms, PTm has three main logical
components, which may conveniently be labeled the en-
vironmental, physical, and financial modules.  As
shown in Figure A.1-1, it is assumed that general eco-
nomic conditions and other factors outside the model
determine the demand for electricity.  Consumers' peak
and average demand, the industry's policy with respect
to reserve margins, and the equipment, power drain, and
generating efficiency implications of pollution control
requirements combine to determine the industry's physical
plant, equipment, fuel, and labor requirements.  These

 Drs. Pifer and Tennican gratefully acknowledge the
 counsel and assistance of a number of individuals
 from industry, the Federal Power Commission, and
 various financial institutions — especially Messrs.
 John Childs, Gordon Corey, Fred Eggerstedt, Robert
 Fortune, Rene Males, John O'Connor,  and Robert Uhler.
                    III-152-

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                                                                           KNVIUUNMK.NTAL
H
H
it

3

3
It
a
                                                                                                             z
                                                                                                             H
                                                                                                             W
                                                                                                             n

                                                                                                            a!
                                                                                                            IS
                                                                                                            K M
                                                                                                            S M
                                                                                                            H!  s
                                                                                                            •< z
                                                                                                             D
                                                                                                             >

-------
physical requirements and the relevant factor costs,
which are also influenced by economic considerations
external to PTm, combine to determine the consequences
of building and operating the capacity needed to meet
consumer demand.

          These capital asset and operating cash require-
ments are met in part by revenues collected from the users
of electrical energy and in part by external financing.
The amount of cash provided by operations at any given
point in time is influenced by regulatory policy (in
effect via the allowed revenue per kilowatt hour), by
tax policy (via the effective rate of taxation after con-
sideration of depreciation tax shields, investment tax
credits, etc.), and by the cost of capital raised in prior
periods.  Any shortfall between cash needs and the cash
provided by operations is met by recourse to the capital
markets.

          Figure A.1-1  omits  a  number  of  interactions
and  feedbacks,  two of which might be noted  explicitly.
First,  if  external financing  is to be  available,
regulatory policy must  be  such  as to allow  revenues
per  kilowatt  hour sufficient  to yield  returns to
capital  that  are adequate  in  light of  prevailing capital
market  conditions, tax  policy,  and pollution control
requirements,  all of which may  have an impact on the cost
of electrical power and hence on demand.  As a second
illustration, because the  financial characteristics of
the  electric  utility industry and of individual utilities
may  be considerations in the drafting  and administration of
pollution control legislation, pollution control policy in
part  determines and in  part is determined by the industry's
financial profile.

                        III-154-

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A.2  PTm's Environmental Module

          The model's environmental module has  as  its
primary function the inputting of assumptions concern-
ing future growth in the demand for power, current  and
future pollution control requirements, equipment and
operating costs, etc.  The implications of these policy,
economic, and technical assumptions are then determined
in the physical and financial modules of PTm.   PTm  is
programmed so as to be able to test a wide variety  of
policy alternatives via changes in input data.  In
testing alternative policies with respect to the coverage
and time phasing of water pollution control requirements,
however, modifications to the logical structure of  the
model itself were required, so that a series of slightly
different models were actually used to make the projec-
tions set out in the body of the report.  Nonetheless,
for simplicity we shall in the following speak  of PTm as a
single model rather than a set of related models.

A.3  PTm's Physical Plant and Equipment Module

          The primary relationships determining the
industry's physical plant and equipment requirements
are shown in Figure A.3-1.  Consistent with the assump-
tion that demand will be met, the industry's gross  gen-
erating capacity in service as of any point in  time is
determined by the level of demand, the industry's policy
with respect to capacity reserves, and the efficiency
                         III-155-

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                                                                                KiRiiro A.:t-l
                                                               DETERMINANTS OK PI.AI.T AND EQUIPMENT IN SERVICE
                                                           ANU IN CONSTRUCTION KOR THE ELECTRIC UTILITY INDUSTRY
  Impact of Kuturr Pollution
  Equipment on Generating
      Plant Efficiency
K-"
in
 I
Impact of Current Pollution
 Equipment on Generating
    Plant Efficiency
Current Required
 Gross Capacity
                                                                               Future Retirements
                                       Construction for
                                     Future Requirements
                                                                               Additions to Plant and
                                                                             Equipment in Service and
                                                                                 in Construction
                                                                                  Pollution Control Equipment
                                                                                        Requirements
                                                                                  Construction for
                                                                              Current Requirements
                                                                              Current 1cvircments

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impact and operating power drain of pollution control
equipment.  These current capacity requirements and the
rate of retirement of old generating units together
determine the amount of generating capacity additions
necessary for meeting current demand.  With the inclu-
sion of the pollution control equipment required for
generating capacity currently in service, the additions
to in-service plant and related equipment are fully
specified in physical terms.

          Given the long time lags involved in con-
structing new generating capacity, the industry's
plant and equipment construction as of any point in
time typically includes significant amounts of work in
progress so as to meet future demand as it materializes.
As is shown in Figure A.3-1, future demand,  future reserve
factors, future pollution control requirements,  and future
retirements — together with the lags in construction —
determine the plant and equipment additions that are
related to future demand, i.e., construction in progress.
It should be noted that because the time span between
ordering and placing generating capacity in service
is radically different for peaking units, fossil-fueled
base load plants, and nuclear units, PTm computes con-
struction work in progress for nuclear and for non-nuclear
plants via two different time schedules.  Thus,  average
construction lags are themselves a function of the
assumed future mix of these various types of generating
plants.  It might also be noted that PTm is designed to
accept assumptions with respect to the relative propor-
tions of nuclear and fossil additions that change over
time.
                         HI-IS?-

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A.4  PTm's Financial Module
         For expositional purposes it is convenient
to divide PTm's financial module into three segments,
dealing with :
         •   uses of funds;
         •   sources of funds; and
         •   revenues, expenses, and profits.

     A.4.1  Uses of Funds.  The industry's uses of
funds, depicted in Figure A.4-1, are determined pri-
marily by the physical plant and equipment required
to meet current and future demand and by the cost
per unit of this equipment.   A second use is the
allowance on funds tied up in plant and equipment in
the process of construction.  For simplicity, PTm
assumes that the industry's net working capital remains
constant, so that changes in working capital appear
neither as a use nor as a source of funds.  Given the
miniscule size of such working capital changes relative
to the industry's major sources and uses of funds,
such a simplifying assumption is unlikely to introduce
appreciable error absent fundamental structural changes
in the industry's current assets and payables accounts
or in its usage of short-term debt.

         As may be clear from Figure A.4-1, once the
total physical amounts of plant and equipment required
to meet current and future demand and the proportions
of those amounts accounted for by nuclear and fossil-fueled
plants are determined, the crucial input assumptions
required to convert these physical quantities into

                     III-158-

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            Figure  A.4-1

    DETERMINANTS OF USES OF FUNDS
 FOR THE ELECTRIC UTILITY INDUSTRY
         Cost Per Unit of Plant
             and Equipment

.Plant & Equipment
Construction for Current
Requirements

Plant & Equipment
Construction for
Future Requirements
	

Capitalized Expenditures !
t M/ !


>

>
Expenditures for In-
Service Plant and Equipment

Allowance for ' Funds
Used for Construction
in Progress
T
Expenditures for Increasing
Plant and Equipment
in Construction





>
f
Total Uses of Funds
/

\
	t	
          Cost Per Unit of Plant
             and Equipment
                III-159-

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financial terras are the cost per unit of each type of
asset and the schedule of payments required by con-
tractors while such plant and equipment are under con-
struction.

     A.4.2  Sources  of Funds.  In the case of the private
sector of the electric utility industry, sources of
funds consist of two major elements, namely:
         •   funds provided by operations and
         •   external financing.

Funds provided by operations in turn are the sum
of three internal sources, namely:
         •   depreciation;
         •   tax deferrals; and
         •   retained earnings.

For the public sector, it is simply assumed that 35
percent of total funds uses are met for internal
sources.  As is shown in Figure A.4-2(a), any short-
fall between total uses and internal sources is met
via external financing.

         Figure A.4-2(b) shows these same relation-
ships in a format that is slightly different and that
shows how the private sector's total required external
financing and capital structure and dividend policies
combine to determine:
         •   cash issues of preferred  stock'
         •   gross cash offerings of debt; and
         •   cash issues of common stock.
                     III-160-

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                                                                    Figures  A.4-2


                                                               DETERMINANTS AND COMPOSITION

                                           OF TOTAL SOURCES OF FUNDS FOR THE ELECTRIC UTILITY INDUSTRY
                                                                                         U>

Total


V
^

External


*


Fund* Provided




                                                                                                             TOTAL SOURCES OP FUNDS
H
H
H
                                                    Depreciation
                                                       Initial
                                                   Capital Structure
                                                                                   Total Uses of Funds
                                                                                                               TOTAL SOUIICES OF FUNDS
                                                                                    Additions to Capital
   Ending
Capital Structure
                                                                                 3    Cash Issues of Preferred
                                                                                       Caah laaura of Debt
                                                                                      Cash Isauea of Common
                                                                                                                      Debt Retirements
                                                                                                                       Retained Earnings
                                                                                                                        Profit Available for
                                                                                                                         Common Stock

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     A.4.3  Revenues and Related Variables.  The third
segment of the financial module determines total in-
dustry revenues, expenses, profits, and related sta-
tistics such as price per kilowatt hour and interest
coverage ratios.  The output variables of this revenue
segment serve in many instances as inputs to other
segments (e.g., the depreciation expense figure com-
puted in the revenue segment is an input to the sources
of funds segment.)  Conversely, certain of the input
variables to the revenue segment are based on the
output from the sources and uses segment of the fi-
nancial module (e.g., plant and equipment expenditures
provide the base for computing depreciation expense).
The structure of the revenue segment and the inter-
actions between this segment and other parts of the
total model are depicted in Figure A.4-3.

         As shown at the top of Figure A.4-3, profits
available for common stockholders are assumed to be
determined completely by the amounts of the industry's
common equity capital and by a rate of return on equity
set by regulatory policy.2  As a consequence of this
assumption, revenues and prices per kilowatt hour of
electricity are determined by required profits, other
capital charges, and operating expenses.
  It  should be  noted  that  "policy"  is  a  term  intended
  to  comprise the  effect of  both  the target rates  of
  return  set by individual regulatory  bodies  and the
  administrative lags involved  in adjusting prices per
  kilowatt hour so as to achieve  such  target  returns.
                     III-162-

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                                                                  Figure  A.4-3
                                  DETERMINANTS OF REVENUES, EXPENSES,  AND PROFITS FOR THE
                                                         ELECTRIC UTILITY INDUSTRY
H
M
OJ
 I
                                                       Depreciation &
                                                       Amortization of
                                                      Plant and Equipment

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         Earnings before interest and taxes (EDIT)
is simply the sum of EBT and interest expense and is com-
puted by the same general process used for preferred
dividends.  The resultant EBIT figure constitutes one
of the five main determinants of revenues.

         The second determinant of revenues, deprecia-
tion and  amortization of plant and equipment, is a vari-
able related to the amount of plant and equipment in
service.  Presuming taxes other than on income consist
primarily of property taxes, a third determinant of
revenue,  namely other taxes, is also related to the
amount of plant and equipment in service.  Plant and
equipment requirements are in turn determined by both
current demand and pollution control policy.

          Current consumer demand and the  power drains
and operating efficiency losses associated with pollution
control equipment combine to determine the  level of
operating and maintenance expenses.  This latter expense
figure  is the fourth determinant of revenues.

          Future consumer demand and pollution control
requirements also determine  future in-service plant and
equipment requirements and hence determine  the amount
of  construction currently in progress.  The amount of
construction in progress in  turn determines the allow-
ance  for  funds used during construction,  which is another
non-cash  item, but which also affects  —  this time
diminishes  -- the  level of revenues  required to achieve
a given level of profit as determined  by  regulatory
accounting  procedures.  This allowance on construction
funds variable  is  the  fifth  and  last major  determinant
of  revenues.
                        III-164-

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         Net profit is simply the sum of profits
available for common stock and preferred dividends.
The amounts of preferred dividends are determined
by the amounts of preferred equity capital and the
average dividend rate on the industry's outstanding
preferred stock.  The dividend yield on new pre-
ferred stock issues -- and hence the average yield—
is in turn determined over time by the reaction of
the capital market to the industry's offerings.

         Earnings before income taxes (EBT) are then
set at a level such that EBT minus taxes will be equal
to the required net profit figure.  The tax expense
figures (or equivalently,  the effective tax rate) is
itself a function of the EBT figure, which is computed
in accordance with regulatory accounting procedures,
and several other factors.  The calculations are some-
what complicated first of all because various special
features of the tax code (e.g., provisions allowing
investment tax credits and accelerated depreciation) and
of regulatory accounting (e.g., the creation of allow-
ances for funds used during construction as non-cash
credits to income) must be taken into account.  As a
consequence of these differing provisions, taxable EBT
and regulatory EBT may — and typically do -- differ.
Secondly, as mentioned earlier, there exist two sub-
stantially different regulatory methods for determin-
ing the tax expense figure to be associated with EBT.
Normalizing accounting gives rise to deferred taxes,
which is a non-cash charge against income, but which
nonetheless constitutes an accounting expense to be
covered by revenues if accounting profits to stock-
holders are to reach prescribed levels.

                    III-165-

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 A.5  A Concluding Comment

           As has been outlined above, the operating,
 financial, tax, regulatory, and accounting relationships
 and constraints relevant to making economic and financial
 projections for the industry are individually rather
 simple.  However, the number of these relationships and

 constraints are so great as to dictate the use of a com-
 puter model such as PTm.  Moreover, because of inter-
 actions between the various industry relationships and
 constraints, attempts to reduce the number of factors

 through shortcut approximations are hazardous.'1  Further-
 more, such shortcuts, even if based on careful econo-
 metric analyses of historical data, would tend to pre-
 clude an examination of the implications of structural
 and policy changes.
3
 To  illustrate  the  point  concretely,  consider the industry's
 effective  tax  rate as  it appears  in  regulatory and shareholder
 financial  reports.   This rate  is,  in fact,  a complex function
 of  (among  other  things):   the  actual federal,  state,  and local
 income  tax rates;  the  industry's  plant  and  equipment expendi-
 tures  in the current and past  years;  and, the reduced asset
 lifetimes,  the accelerated methods of depreciation,  the invest-
 ment credits,  and  the  other income statement items allowed for
 tax purposes,  but  not  for regulatory purposes.  These current
 and past expenditures  are themselves a  function of:   demand
 growth;  the mix  of nuclear and non-nuclear  capacity built to
 meet this  demand;  and  the costs per  unit  of such generating
 capacity and the related transmission and distribution equipment
 Clearly, to assess the industry's future  effective tax rate
 directly is a  formidable task;  even  more  clearly,  simply to
 assume  the future  rate will be the same as  the current rate or
 some average of  recent rates is unlikely  to be an adequate
 approximation  of the outcome of the  detailed calculations or
 actual  events.
                        III-166-

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            PTm was designed not only to  compute  rapidly
the implications of any given set of assumptions  about
the future, but also to facilitate the examination  of
structural and policy changes.  Thus, the model is
able conveniently to accept input assumptions  for over
100 variables, such as the current level  of  and future
changes in:  the industry's peak demand;  reserve  margins;
the mix of nuclear and non-nuclear capacity  additions;
unit costs of generating plants, transmission  and distri-
bution capacity, thermal and chemical pollution equip-
ment;  etc.  As is discussed briefly in Section 4, PTm then
generates projections for a variety of physical and fi-
nancial variables, including: capacity figures for  each
of the major segments of the industry; energy  losses
resulting from thermal water pollution control standards;
income statements, balance sheets, funds  flows, and re-
conciliations of regulatory and Internal  Revenue  Service
income tax expense figures; and summary statistics  such
as interest coverage figures.
                           III-167-
                                U. S. GOVERNMENT PRINTING OFFICE : 1974 732-430/428

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