ORDES
       THE CURRENT STATUS OF




      THE ELECTRIC UTILITY INDUSTRY




          IN THE




    OHIO RfVER BASIN ENERGY STUDY STATES
          PHASE
OHIO RIVER DASIN ENERGY STUDY

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                                                              April, 1980
                          THE CURRENT STATUS OF

                      THE ELECTRIC UTILITY INDUSTRY

                                 IN THE

                  OHIO RJVER BASIN ENERGY STUDY STATES
                                 Editors

                   Jan L. Saper and James P. Hartnett
                University of Illinois at Chicago Circle
                        Chicago, Illinois  60680

                          Contributing Authors
        Vincent P. Cardi
          Thomas Sweet
    West Virginia University
Morgantown, West Virginia  26506
     Gary L. Fowler
      Rita Harmata
    James P. Hartnett
     Steven D. Jansen
      Boyd R. Keenan
       Jan L. Saper
 University of Illinois
    at Chicago Circle
Chicago, Illinois  60680
                              Prepared for
                 Ohio River Basin Energy Study (ORBES)

                    Grant Numbers R805585 and R805588

                   OFFICE OF RESEARCH AND DEVELOPMENT
                  U.S. EVNIRONMENTAL PROTECTION AGENCY
                         WASHINGTON, D.C.  20460

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                                  PREFACE






     Many authors contributed time and expertise to this report:  J.F. Hartnett




and Jan L. Saper, Energy Resources Center, University of Illinois at Chicago




Circle were responsible for those sections of Chapters II-IV dealing with the




organizational framework of the industry and Chapter VII, "Comparative Financial




and Operating Statistics for Investor-Owned Utilities."




     Gary L. Fowler, Department of Geography and Steven D. Jansen, Energy Re-



sources Center, University of Illinois at Chicago Circle wrote Chapter V,




"Electrical Generating Systems" and Chapter VI "Electrical Generating Capacity:




1976-1985."




     Boyd R. Keenan and Rita Harmata, Department of Political Science, University




of Illinois at Chicago Circle wrote those sections of Chapters II-IV defining the



institutional arrangements for each component of the industry.




     Tom Sweet and Vince Cardi, College of Law, West Virginia University wrote




Chapter VIII, "Regulation in the Electric Utility Industry."




     The preliminary organizational work of Kathleen M. Brennan, formerly wich




the Energy Resources Center, and the secretarial support of the Energy Resources




Center staff, especially the efforts of Claudette Eldridge and Marion B. Deloney,




are also appreciated.

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                                 CONTENTS

Figures 	     v

Tables	    vi

    I  Introduction 	     1

   II  Investor-Owned Utilities 	     4
          Organizational Framework  	     4
              Utilities in the ORBES States 	     4
              Power Consortia and Other Cooperative Ventures  	     8
              Reliability Councils  	    13
          Institutional Arrangements  	    18
              The Investor-Owned Electric Power Industry and the
                Federal Government  	    18
              Historical Growth of American Electric Power System ...    20
              The Allegheny Power System  	    22
              General Public Utilities  	    22

  III  Publicly-Owned Utilities and Power Agencies  	    24
          Organizational Framework  	    24
              Muncipal Utilities  	    24
              Regional Utilities  	    25
              Federal Power Agencies  	    25
          Institutional Arrangements  	    26
              Growth of the Municipal Electric Utility  	    26
              The Federally-Owned Power System  	    27

   IV  Rural Electric Cooperatives  	    29
          Organizational Framework  	    29
          Institutional Arrangements  	    30
              The Rural Electric Cooperative Movement  	    30
              Institutional Affiliations  	    32

    V  Electrical Generation Systems  	    33
          Electric Generation 	    33
              Generating Capacity 	    33
              Actual Generation 	    38
          Power Transmission	    40
              Transmission System 	    40
              Utility Interconnections  	    40
              Capacity Exchanges  	    42
          Power Resources:  Peak and Margin	    44
                                   iii

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   VI  Electric Generating Capacity:  1976-1985 	    47
          Growth in Generating Unit Size	    47
          Proposed Capacity Additions:  1976-1985 	    52
          Total Capacity - 1985	    59

  VII  Comparative Financial and Operating Statistics for Investor-Owned
         Utilities	    66
          Residential Customer Statistics 	    66
          Utility Performance Statistics  	    68
          Utility Ratings 	    70

 VIII  Regulation in the Electric Utility Industry  	    74
          Legal Basis for Regulation	    74
              Federal Regulation of the Electric Utility Industry  ...    76
              State Regulatory Commissions  	    79
                 Background	    79
                 Rate Regulation	    81
          Rate Structure Reform 	    83
          Adequacy of Service Regulations 	    85

   IX  Conclusion	    87

Appendixes

    A.  Glossary	    88

    B.  Investor-Owned Utilities in the Six ORBES States  	    93

    C.  Publicly-Owned Utilities in the Six ORBES States  	    97

    D.  Rural Electric Cooperatives in the Six ORBES States 	   102

    E.  Selected Operating Statistics for Major Investor-Owned
          Utilities in the Six ORBES States	   110
                                   IV

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                                   FIGURES

Number                                                                    Page

  1  The ORBES States .........................     3

  2  Utility Service Areas in the ORSES States  ............     7

  3  American Electric Power System ..................     9

  4  Allegheny Power Systems, Inc ...................    10

  5  General Public Utilities Corporation ...............    11

  6  Ownership of Ohio Valley Electric Corporation  ..........    12

  7  Regional Reliability Councils  ..................    16

  8  Total Installed Generating Capacity:  1975 ............    36

  9  Total Installed Coal-Fired Generating Capacity:  1975  ......    37

 10  Total Installed Nuclear Generating Capacity:  1975 ........    39

 11  Major Generating Units and Transmission Lines in the Six
       ORBES States  ..........................    41
 12  Average MWe Size of Generating Units in the Six States,
       by On-line Date
 13  Total Proposed Generating Capacity Additions:  1976-1985  .....    56

 14  Total Proposed Coal-Fired Generating Capacity
       Additions:  1976-1985  .....................    57

 15  Total Proposed Nuclear Generating Capacity
       Additions:  1976-1985  .....................    58

 16  Total Generating Capacity:  1985  .................    61

 17  Total Coal-Fired Generating Capacity:   1985   ...........    62

 18  Total Nuclear Generating Capacity:  1985  .............    64

 19  Changes  in  Scheduled On-Line Dates for  Electrical Generating
       Units  in  the Six ORBES States   .................    65

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                                  TABLES

Number                                                                    Page

  1  Investor-Owned Utilities in the ORBES States 	      5

  2  Power Pools with Member Systems Operating in the
       ORBES States	     14

  3  Reliability Council Membership in the ORBES States  	     17

  4  Generating Capac-ity Summary - 1975	     35

  5  Summary of Scheduled Capacity Exchanges Into or Out of
       ECAR and MAIN	     43

  6  Peak Loads and Reserve Margins:  1976-1977 	     45

  7  Unit Size, MWe	     50

  8  Sew Units and Existing Units	     51

  9  Mew Sites vs. Existing Site Expansion	     53

 10  Site Size, MWe	     54

 11  Capacity Additions:  1976-1985 	     55

 12  Electrical Generating Capacity - 1985  	     60

 13  Characteristics of the major Investor-Owned Utilitites
       in the Six ORBES States:  Summary Table	     67

 14  Selected Financial Statistics of the Major Investor-Owned
       Utilities in the Six ORBES States	     69

 15  Percentage Increases in Real Fuel Costs:  Average Cost Per
       Ton and Average Cost per Million Btu	     71
                                   vi

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                                 CHAPTER I








                               INTRODUCTION




     In the United States today, electricity is considered a necessity, relied




upon by all sectors of our society.  Except in those cases where an industry




generates its own power, the production and distribution of electricity is the



responsibility of the electric utility industry.  By definition, the industry




includes all enterprises involved in the production and/or distribution of




electric power for use by the public.  It is mandated,  both by customer demands




and by governmental regulation, to provide sufficient power with the greatest




possible economy to meet all present and future demands for electric power while




at the same time showing proper concern for the conservation of natural resources.




This mandate is complicated by the fact that electricity, for the most part, can-




not be stored and yet power must be available to the public at all times.  Thus,




to maintain adequate supplies of power, the industry must continually plan ahead,




anticipating electrical requirements many years in advance of the actual need




and ensuring that the necessary equipment is in place.   As a result, considera-




tion of the electric utility industry is an essential part of the Ohio River Basin




Energy Study (ORBES).



     ORBES was organized by the U.S. Environmental Protection Agency to "...identify




and evaluate the potential consequences of levels, rates, and patterns of future




energy development..."1  In particular, the study was in part directed to focus



on "...considerations of the environmental, public health, economic, institutional,




and social impacts associated with possible future extension or modification of




energy conversion facilities..."2
        io River Basin Energy Study, "Phase II Work Plan" 2 August 1978, p. 1-3.



     2Ibid.

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     The electric utility industry is essentially a vast conversion and distri-




bution operation, converting primary fuels such as coal, uranium, oil and natural




gas into electricity through an interlocking network of generating plants, dis-




tribution facilities, and transmission lines.  Because of its importance to ORBES,




it is necessary to understand how the industry operates.  This report is intended




to provide the "baseline data" needed to place the various facets of the industry




in perspective and to offer a starting point for further evaluation.  Thus, the




report covers the institutional, technological, financial, and regulatory consid-




erations within which the industry must operate.




     In general, the ORBES study region includes those portions of Illinois,




Indiana, Kentucky, Ohio, Pennsylvania, and West Virginia shown in Figure 1.  This




region contains the bulk of the Ohio River drainage area (excluding the portion




located in Tennessee, Virginia, Hew York and Maryland) as well as those coal pro-




ducing counties in Illinois outside the drainage area.  Thus, the ORBES region in-




cludes a large portion of the Appalachian Basin Coal Fields and all of the coal in




the Illinois Basin.  However, for the purpose of this report, the entire six-state



area is considered.  This approach takes into account the nature of the electric



utility industry.  Utility service areas and generating facilities do not coin-




cide with the ORBES region boundaries.  Furthermore, many institutional and legal




relationships may be described only in the context of the state and federal laws.




     There is no single "baseline" year.  Rather, data are gathered for a base




period in the Lnid-1970's.  It was done here, as in all ORBES research, because



there is no single year in which complete information is available for all data




categories.  This is particularly true of the  institutional and regulatory data




where rules and  interpretations are constantly altered.

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                                 Fig.  1       The   ORBES  States
         ILLINOIS
                                                                                    WEST
                                                                                    VIRGINIA
LEGEND
Counties outside tlie ORBES study region

Ohio River Drainage Basin (excluding the Tennessee River Drainage Basin)

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                                CHAPTER II








                         INVESTOR-OWNED UTILITIES








                         Organizational Framework




                       Utilities in the ORBES States




     The investor-owned utilities in the ORBES states produce approximately 90




percent of the electric power, both for direct consumer use and for sales to




all classes of electric utilities.  Such a utility is a tax-paying business,




usually financed by the sale of securities in the free market, whose properties




are managed by representatives regularly elected by their shareholders.  Inves-




tor-owned electric utilities, which may be owned by an individual proprietor or




small group of people, are usually corporations open to ownership by the general




public.  There are a number of investor-owned utilities in the ORBES states




(Table 1,  A detailed description of each utility appears in Appendix B).  Thirty-




four large generating and transmission companies produce most of the power gener-




ated by investor-owned utilities.  Of these, 26 operate completely within the




six-state region and four more (Indiana-Michigan Electric Company, Monogahela




Power Company, Potomac Edison Company, and Appalachian Power Company) operate




largely within these states.  The remaining companies  (Union Electric Company,




Interstate Power Company, Iowa-Illinois Power Company and Virginia Electric



Company) have only small amounts of service territory in Che ORBES states: the




bulk of their areas are in adjacent states.



     The small investor-owned utilities tend to fall into one of three categories:




generating and transmission companies serving a limited number of customers;  sub-



sidiary companies set up to operate a generating station for the parent company,

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                                    TABLE 1
                INVESTOR-OWED UTILITIES IN THE ORBES STATES
Illinois
Ind iana
Kentucky
Ohio
Pennsylvania
West Virginia
Large Utilities

Central Illinois Light Co.
Central Illinois Public Service Co.
Commonwealth Edison Co.
Illinois Power Co.
Interstate Power Co.
Iowa-Illinois Gas and Electric Co.
Union Electric Co.

Indiana-Michigan Electric Co.
Indianapolis Power and Light Co.
Northern Indiana Public Service Co.
Public Service Company of Indiana
Southern Indiana Gas and Electric

Kentucky Power Co.
Kentucky Utilities Co.
Louisville Gas and Electric Co.

Cincinnati Gas'and Electric Co.
Cleveland Electric Illuminating Co.
Columbus and Southern Ohio Electric Co.
Dayton Power and Light Co.
Ohio Edison Co.
Ohio Power Co.
Toledo Edison Co.

Duquesne Light Co.
Metropolitan Edison Co.
Pennsylvania Electric Co.
Pennsylvania Power Co.
Pennsylvania Power and Light Co.
Philadelphia Electric Co.
United Gas Improvement Corp.
West Penn Power Co.

Appalachian Power Co.
Monongahela Power Co.
Potomac Edison Co.
Virginia Electric Power Co.
Small Utilities

Electric Energy Inc.
Sherrard Power System
South Beloit Water, Gas
Commonwealth Edison of
   Indiana
Indiana-Kentucky Electric
   Corporation
Union Light, Heat and Power
   Company
Cardinal Operating Co.
Miami Power Corporation
Ohio Electric Co.
Ohio Valley Electric Corp.
Conowingo  Power Co.
Hershey  Electric  Co.
Philadelphia Electric
    Power Co.
Safe Harbor Water Power Corp.
Susquehanna Electric Co.
 Beech Bottom  Power  Co.
 Central  Operating Station
 Kanawha  Valley  Power  Co.
 Wheeling Electric Co.

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or non-generating utilities which distribute power purchased from neighboring

companies.

     Eight utilities in the ORBES states are incorporated to operate individual

plants for the parent company.1  These include:   Commonwealth Edison of Indiana,

the Cardinal Operating Company and the Ohio Electric Company in Ohio,  the Cono-

wingo Power Company and the Philadelphia Electric Power Company in Pennsylvania

and the Beech Bottom Power Company, Central Operating Station, and the Kanawha

Valley Power Company, all in West Virginia.

     Non-generating utilities purchase power from a neighboring power generating

utility and distribute it to their own customers.  There are five such utilities

in the six-state area - Miami Power Corporation, Hershey Electric Company, Sher-

rard Power System, Union Light, Heat and Power Company and Wheeling Electric Com-
               2
pany.  Figure 2  shows the location of the service territories for many of these

utilities in the ORBES states.

     Another type of investor-owned utility is the holding company.  By defini-

tion, a holding company is a. corporation chat directly or indirectly owns a

majority or all of the voting securities of one or more utility companies -which
     lfThis is frequently done because many states do not permit a foreign
utility (one which is only chartered to operate in another state) to operate
within their boundaries.

     2Figure 2 is a composite drawn from the following map sources:
        Electric Light & Power, Investor-Owned Electric Utility Service Areas.
          Technical Publishing Company. Barrington, Illinois, February, 1977.
        Illinois Commerce Commission, Electric Utilities In Illinois,
          Springfield, January, 1975.
        Ohio Electric Utility Institute, Service Areas of Ohio Electric Utility
          Institute Members, Revised 1967.
        General Public Utilities Corp., General Public Utilities Corporation
          System Map, Hagerstrom Co., New York, June, 1976.

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              Fig.  2     Utility  Service Areas  in  the
                            ORBES  States
                                                                  SCALE (miles)
                                                                  100      2OO
                                                                                    3OO
                                        LEGEND
—— STATE BOUNDARIES
	 CUBES PHASE II BOUNDARY
	 UTILITY SERVICE AREA

        UTILITY CODES
IL  1 Central Illinois  Light
    2 Central Illinois  Public
       Service Co.
    3 Commonwealth Edison
    4 Electric Energy Inc.
    5 Illinois Power Co.
    6 Interstate Power  Co.
    7 Iowa-Illinois Gas &
       Electric Co.
    8 Mt. Cannel Public
       Utility Co.
    9 Sherrard Power System
   10 South Beloit Water, Gas
       & Electric Co.
   11 Union Electric Co.
IN 12 Indiana-Michigan
       Electric Co.
   13 Indianapolis Power &
       Light Co.
   14 Northern Indiana  Public
       Service Co.
   15 Public Service Company
       of Indiana, Inc.
   16 Southern Indiana  Gas &
       Electric Co.

n 17 Kentucky Power Co.
   18 Kentucky Utilities
   19 Louisville Gas &
       Electric Co.
   20 Union Light, Heat, &
       Power Co.
   21 Tennessee Valley Auth.

OH 22 Cincinnati Gas &
       Electric Co.
   23 Cleveland Electric
       Illuminating Co.
   24 Columbus & Southern
       Ohio Electric Co.
   25 Dayton Power & Light
   26 Ohio Edison Co.
   27 Ohio Power Co.
   28 Monongahela Power  Co.
   29 Toledo Edison Co.

PA 30 Duquesne Light Co.
   31 Metropolitan Edison
       Co.
   32 Pennsylvania Electric
       Co.
   33 Pennsylvania Power Co.
   34 Pennsylvania Power &
       Light Co.
   35 Philadelphia Electric  Co.
   36 Potomac Edison Co.
   37 United Gas Improve-
       ment Co.
   38 West Penn Power Co.

WV 39 Appalachian Power Co.
   28 Monongahela Power Co.
   36 Potomac Edison Co.
   40 Virginia Electric Power
       Co.
   41 Wheeling Electric Co.
   SOURCE:   See previous page

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are located in the same or contiguous states.  Three holding companies control




utilities in the ORBES states:




                    American Electric Power System (AEPS)




                    Allegheny Power Systems (APSI)




                    General Public Utilities (GPU)




AEPS brings eight companies, including two not in the ORBES states, into a




single system (Figure 3).  In addition, the company indirectly controls




eight additional utilities.  APSI and GPU each directly control three companies




(Figures 4 and 5), while APSI controls two more companies indirectly.








             Power Consortia and Other Cooperative Ventures




     A number of electric power consortia and other cooperative ventures oper-




ate in the ORBES states.  One of the most structured is the Ohio Valley Electric




Corporation (OHVC), which was created in the aid-1950's under the leadership of




AEPS (Figure 6).  Its purpose was to allow fifteen investor-owned utilities in




the Ohio Valley area to jointly produce  electric power for the U.S. Atomic



Energy Commission (now Department of Energy) uranium enrichment plant near




Portsmouth, Ohio.  Today, OHVC and its subsidiary, the Indiana-Kentucky Electric



Corporation, operate two generating stations primarily to serve the enrichment



plant.




     A similar arrangement provides power to DOE's enrichment plant in Paducah,



Kentucky.  Approximately half of the necessary power is supplied by Electric



Energy Inc.'s Joppa Plant.  The company is owned by four utilities - Illinois



Power (20%), Central Illinois Public Service Company (20%), Kentucky Utilities



(20%) and Union Electric Company (40%).  The Tennessee Valley Authority sup-



plies the remaining power to the enrichment plant.

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       Fig. 3  AMERICAN ELECTRIC POWER SYSTEM (AEPS)
  ELECTRIC POWER COMPANIES DIRECTLY OR INDIRECTLY CONTROLLED
APPALACHIAN POWER CO.
         CENTRAL OPERATING CO. (50%).
         KANAWHA VALLEY POWER CO.
         WEST VIRGINIA POWER CO.
INDIANA AND MICHIGAN ELECTRIC CO. —- INDIANA AND MICHIGAN POWER. CO
                                        (NOT IN ORBES STATES)
KENTUCKY POWER CO.
K1NGSPGRT POWER CO.(NOT IN OfiBfcS STATES)
MICHIGAN POWER CO. {NOT IN ORfttS STATES}
OHIO POWER CO.
CENTRAL OPERATING CO. (60%)
OHIO ELECTRIC CO.
BEECH BOTTOM POWER CO. (50%)
CARDINAL OPERATING CO. (50%]
WHEELING ELECTRIC CO.
OHtO VALLEY ELECTRIC CORP. (37.8%)

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            Fig. 4         ALLEGHENY POWER SYSTEMS INC. (APSI)
            ELECTRIC POWER COMPANIES CONTROLLED DIRECTLY OR INDIRECTLY
               MONONGAHELA POWER CO. 	•- OHIO VALLEY ELECTRIC CORP. (3.5%)


APSI 1	*- POTOMAC EDISON CO. 	•- OHIO VALLEY ELECTRIC CORP. (2.0%)



               WEST PENNSYLVANIA POWER CO. ^*~ BEECH BOTTOM POWER CO. (60%)

                                                  OHIO VALLEY ELECTRIC CORP. (7.0%)

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Fig. 5 GENERAL PUBLIC UTILITIES CORPORATION (GPU).








                      METROPOLITAN EDISON CO.







  GPU}	^" PENNSYLVANIA ELECTRIC CO







                      JERSEY CENTRAL POWER AND LIGHT CO.

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                                   Fig. 6     OWNERSHIP OF
                                   OHIO VALLEY ELECTRIC CORPORATION
TOLEDO EDISON (4.0 %)
CINCINNATI GAS AND ELECTRIC (9.0%)

COLUMBUS AND SOUTHERN (4.3%)

DAYTON POWER AND LIGHT (4.9%)

KENTUCKY UTILITIES CO. (2.6%)

LOUISVILLE GAS AND ELECTRIC  (7.0%)

SOUTHERN INDIANA GAS AND ELECTRIC (1.6%)

INDIANA AND MICHIGAN - AEPS (7.6%)
OHIO POWER CO. - AEPS (16.0%)
APPALACHIAN POWER CO.-AEPS (16.2%)

MONONGAHELA POWER - APSI (3.6%)

POTOMAC EDISON- APSI (2.0%) 	
 WEST PENNSYLVANIA POWER CO. - APSI (7.0%)
OHIO EDISON (14.6%)  -   -

 PENNSYLVANIA POWER CO. - (OHEC) (2.0%)
• 16.6%
                                   OHIO VALLEY ELECTRIQ
                                      CORPORATION
                                            1
                                    ( INDIANA  -KENTUCKY
                                   ELECTRIC CORPORATION)

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     Power sharing occurs frequently among utilities in the ORBES states.  The

most common arrangement is the "power pool."  A power pool consist of two or

more utilities which are interconnected on a formal contractual basis to plan

and operate their combined power supply in the most reliable and economical

manner for their combined load and maintenance requirements.  There are three

pools in the ORBES states (Table 2).

     Power sharing also extends down to the level of individual generating

plants.  Many plants, particularly the new larger ones are jointly owned,

thus easing the financial burden for all owners and providing smaller utili-

ties with an economical source of new generating capacity.3



                           Reliability Councils

     The National Electric Reliability Council  (NERC) was  formed voluntarily

by  the electric utility  industry in 1968 following  blackouts in the Northeast

in  1965 and 1967; it was  incorporated in 1975.  NERC directs the efforts  to

augment the reliability  and  adequacy of bulk power  supply  of the electric util-

ity systems in North America.  NESC consists of nine regional councils whose

memberships comprise essentially all of the electric utility systems  in  the

United States and the  Canadian systems in  the  provinces of Ontario, British

Columbia,  Manitoba, and  New  Brunswick.

     The  governing  board of  MERC is a Board of Trustees which consists of two

representatives of  each  regional council,  plus  such additional members as nec-

essary to  assure at least two  representatives  of  each segment of  the  electric

utility industry:   investor-owned,  federal, rural electric cooperative and
     3Such plants are identified in:  Steven D. Jansen, Electrical Generating
Unit Inventory 1976-1986, prepared for the Ohio River Basin Energy Study, Novem-
ber, 1978,
                                     13

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                                  TABLE 2


      POWER POOLS WITH MEMBER SYSTEMS OPERATING IN THE ORBES STATES
                          (As of April 1, 1979)

      Central Area Power Coordinating Group (CAPCO)
            Cleveland Electric Illumination Co.
            Duquesne Light Co.
            Ohio Edison Co.
            Pennsylvania Power Co.
            Toledo Edison Co.

      PJM Interconnection (PJM)
            General Public Utilities
              Metropolitian Edison Co.
              Pennsylvania Electric Co.
            Pennsylvania Power and Light Co.
            Philadelphia Electric Co.
            United Gas Improvement Corporation

      Illinois-Missouri Pool (IMP)
            Central Illinois Public Service Co.
            Illinois Power Co.
            Union Electric Co.

     SOURCES:  East Central Area Reliability Coordination Agreement.  Regional
Reliability Council Coordinated Bulk Power Supply Program, Volume II. April 1, L979
p. 1-ii.

     Mid-Atlantic Area Council.  Regional Reliability Council Coordinated
Bulk Power Supply Program. April 1, 1979.

     Mid-America Interpool Network.  Regional Reliability Council Coordinated
Bulk Power Supply Program.  April 1, 1979 p. 1.

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municipal/state.



     As one of its major activities, NERC makes an annual appraisal of the bulk




power supply in North America for  the upcoming ten years and issues an annual




report detailing national and regional plans.  In addition, NERC conducts spec-




ial studies on  factors affecting the electric power supply.




     The regional reliability council is basically an administrative body repre-




senting a group of utilities from a specific region.   Member utilities work




together to ensure a higher degree of reliability than any one utility could




provide alone.  Not all utilities are members of a reliability council although



all major companies are represented in one of the nine regional councils.  The




reliability councils differ from power pools in two important ways.  Councils



are essentially voluntary organizations governed by informal agreements.




Furthermore, the councils do not own nor operate generation or transmission




facilities as do power pools.   Instead, they coordinate  the needs  and plans of



their members in order to provide an overall plan for adequate, reliable elec-




tric service.  The regional councils are also responsible  for preparing an



annual report to the Economic Regulatory Administration, based on  the operations



and projections of its member systems for the succeeding ten years.  The six




ORBES states include sections of five reliability council  regions  (Figure 7):








     East Central Area Reliability  Coordination Agreement  (ECAR)




     Mid-Atlantic Area Council  (MAAC)



     Mid-America  Interpool Network  (MAIN)



     Mid  Continent Area Reliability Coordination Agreement (MARCA)



     Southeastern Electric Reliability Council  (SERC)



A complete  listing of  reliability council members in  the ORBES states  is  shown




 in Table  3.
                                     15

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            Fig.  7     Regional  Reliability  Councils
            East Centra i Araa

       ECAR "«»'»6iMtY Coorttirvlfo*
      EHCOT
Electric

Council of
            Mid Atlantic Ar*«
                                       Imwpool Network
                                        Mid—Continent Aree
                                       Coordinating Council
     South«a«t»rn Electric

            Council
                                                SERC
SPP  Southweet Potver Pool
                                                WSCC "*••'•"*
                                                     Coordin«1ina Council
SOURCE: National B«otrlc IMIabilltY Council. 1977  Annual Report { March, 1978 } p. 2
                                       16

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                                                                      TABLE  3

                                      RELIABILITY  COUNCIL  MEMBERSHIP  IN THE  ORBES  STATES
                                    (Auction  Electric rover Syeten)
                                    (Ohio  Valley Electric Corp.)
bit Central Area Bel lability Coordination Agreement  (EGAS)
     Bulk Henber Systems
          Appalachian Power Co.  (American Electric  rawer System)
          The Cincinnati Gas and Electric Co.
          Tim Cleveland Electric Illuminating,  Co.
          Columbia and Southern Ohio Electric  Co .
          The Dsytoa  Power and Light Co.
          Duaueene Light Co.
          bet  Kentucky Power Cooperative
          Indiana 4 Hlchlgan Electric Co.
          Indiana-Kentucky Electric Corp.
          Indianapolis Power and Light Co
          Kentucky Power Co.  (American Electric Power)
          Kentucky Utilities Co.
          Loulavllla  Can and Electric Co.
          Honogetiela  Power Co.  (Allegheny Power System)
          Northern Indiana Public Service Co.
          Olilo  Edition Co.
          Ohio  Power  Co.   (American Electric  Power  Syatta)
          (Mito  Valley Electric Corp.
          r«*naylvanla Power CD.  (Ohio Ml ton Co.]
          Faunae  Edison Co.  {fclleg'tienj lava System}
          Full lie  StmlCB Co, of Indiana. Inc.
          Southern Indian*. Caa end Etectrlc Co.
          Toledo  Ed lean Co
          Heat  Penn Power Co.  (Allegheny Power Syaten)
     Liaison  Member Syaten*!
          Richmond  (IN) Power and Light
          Heoaler Energy Dlvlelon
          llenderaon  (KV> Municipal Power and light
          Owenaboro  (KV) Municipal Utilities
          Big Rivera  Electric Corp.
          Dlvlaloii of Light end Power - City of Cleveland
          City of Hamilton  (Oil) - Department of Pbullc Utilities -
             Electric Division
          Buckeye Power  Incorporated
          Uabaah Valley  Power Aeaoclallon



     SOURCES:  East Central area  Reliability Coordination Agreement.  Heal«i*l  Rell.blUtr Council Coordinated Bali. Paver Supply Program Voluae II.  a|UU  I.  l»79.  p.  1-n.

     Htd-Atlaatlc Area  Council.   Regional  Kellahlllty Council Coordinated Bulk  power Supply  Program.  April 1, 1979.

     Hld-Anerlca Interpool  Network.  Benlonol  Reliability Council Coordinated Bulk Power  Supply Program.  April 1, 1979, p. 1.

     Kid-Continent Area  Reliability CootJIn.tion Agreeaent.  Bealonal Hc\lebllltT Council Bulk Power Supply Program.  April 1. 1979, p. 1-6.

     National Electric  Reliability Council.   I9T7 Annual Report.  March 1*7B. p.  28.
Mid-Atlantic Area Council (MAC)
     negulai Heater a
          Metropolitan Edlaon Co.  (General Public Utllltlea)
          Pennsylvania Electric Co.  (General Public Ucllltloa)
          Pennaylvanla Power • Light Co*
          Philadelphia Electric Co.
          IIGI Corp.
     Aaaoclate Member1
          Allegheny Electric Cooperative

Hid-America Interpool Network (HAM)
     Regular Meabera
          Commonwealth Ed 1 aim Co.
          Illlnola Croup
               Central Illtnola Light Co.
               Central Illinois Public Service Co.
               Illinois Power Co.
               Southern Illinois Power Cooperative
               Sprlngtleld-Clty Water Light aod power
          Klaaourl Croup
               Union Elect tic Co-.
     •aaacUte Hambeca1
          Asaoclaclaai 41! [Hindi* EJecCclc CcoparatliHS
          Seylend Pouec CoopecatU*
          Western Illlnola Power Cooperative

Hid Continent Area Reliability Coordination Agreement (HAHCA)
     Interstate Power Co.
     Iowa-IllInols Caa and Electric Co.

Southeastern Electric Reliability Council (SBRC)
     Southessterti Power Admin la tret Ion
     Tennessee Valley Authority
Llaaon and associate maabera Include municipal and cooperative  utilities which do not have a significant effect on system reliability.

-------
     The question of reliability provisions were addressed again in the Public

Utility Regulatory Policies Act of 1978.  However, to date, there has been

no clear and consistent interpretation of this act.  The relationships be-

tween reliability councils may also need examining.  On March 13, 1979, in

testimony before the Senate Energy Committee, former Energy Secretary, James

Schlesinger reminded the group that the Public Utility Regulatory Policies

Act permitted "wheeling" of electric power from regions where it is generated

by coal-burning plants to regions where oil is the primary generating fuel.

If such were to occur, linkages between reliability councils would likely need

strengthening.  Furthermore, the institutional impacts must be examined by both

the government and the utility industry.  For example, Governor John D. Rocke-

feller of West Virginia was reportedly seeking the support of the Department

of Energy to encourage utilities in the East to locate new power plants in the

Ohio Valley and in Appalachia, close to coal reserves.  Such a development

would exacerbate the energy-environment conflicts which gave rise to the ORBES

study.  In addition, the new institutional arrangements resulting from such a

development would have major significance for the ORBES states.



                       Institutional Arrangements

               The Investor-Owned Electric Power Industry
                       and the Federal Government

     The national government first became involved in energy regulation and

management through water power.  Under its authority to regulate interstate

commerce, Congress vested in the War Department (now the Department of Defense)

supervisory control over all structures, including water-power plants, insofar

as they affected navigation.  Because the Federal government was a major land

holder in the western states, ic also became  necessary to formulate a policy
                                     18

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with regard to the use of power sites on the public lands.  Through the pro-




motion of irrigation, the government became interested in the generation of




power as a by-product of its water supply units as well.  Federal activity




increased further during World War I, when the government constructed a hydro-




electric project at Muscle Shoals in northern Alabama to provide power for the




production of synthetic nitrate.




     Finally, with the growth of great companies engaged in transmitting across




state boundaries, problems in the regulation of interstate commerce were pre-




sented to Congress.  Amid such circumstances, federal control over the develop-




ment of electric power became a major political and economic issue.   In the




1920's, the industry began to construct and operate local plants to serve




single cities or communities.  Increasingly, however, local plants expanded




their service territories and consolidated their holdings to take advantage of




load diversity between  differing areas, to realize economies of scale in gen-




erating stations,  and to introduce  some degree of standardization in equipment




and methods.1*  In an era when formation of "trusts" was common, the business




of corporate consolidation posed few problems.  This extreme concentration of




utility firms was accomplished by use of the holding company.




     Generally, such holding companies were beyond the control of the various




state commissions.  As a result, it  was widely felt that  the values of the




holding company techniques were offset by  its abuses.  Concern over inflated




valuations, watered stock and feverish speculation in securities of companies




often several steps removed  from the actual operating level led, in 1928, to




a  Federal Trade Commission investigation.
      'Electrical  World:   100th Anniversary  Issue  (June  1,  1974) p.44
                                     19

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     That study and others revealed that by 1930 the country was covered by




networks of gigantic electrical companies owning and operating plants in many




localities.  In the meantime, by mergers, these companies had apparently




achieved remarkable economies in operation.  Yet these reports emphasized that




these developments were accompanied by popular resentment.  Protests were




heard frequently against high rates, the issuance of stocks and bonds that




became worthless or of  little value, propaganda against public control and




ownership, and lobbying scandals.



     These massive power networks made the electric power industry largely




interstate in character, as electricity was transmitted across state boundaries




and holding companies  operated virtually all over the country.  Ouc of chis




situation and the accompanying studies grew popular demands for the federal




regulation of holding companies and of interstate operations of electric power



firms.  As a result, the Federal Power Act was passed in 1935.  This Act, also




called the Public Utility Holding Company Act of 1935, is discussed in greater




detail in Chapter VIII.








           Historical Growth of American Electric Power System



     American Electric Power (A£PS) began in 1906, when it was incorporated in



New York as the holding company American Gas and Electric Company  (AGEC).  It



was re-incorporated in 1925, as a   consolidation of American Gas and Electric



Company and Appalachian Securities  Corporation.  (In turn, AGEC was a subsidiary



of the registered holding company of Electric Bond and Share Company of America,



until 1945).  At this time, AGEC's  twelve electric utility companies operating



in Ohio, Indiana, Michigan, Virginia, West Virginia, Kentucky, Tennessee, New



Jersey and Pennsylvania were divided into three sectional groups,  none of which



was connected with any other.
                                     20

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     The Central System of AGEC was retained as the principal completely inte-




grated system when the Public Utility Holding Company Act forced the dissolution




of the large holding companies.  It became the  American Electric Power System




in May 1958.



     Today, the AEPS system is easily the largest investor-owned power system




in the ORBES study region, both  from the standpoint of electric generation and




electricity sales.  It  serves nearly 2 million customers in  2,940 communities.




Moreover,  at the  present  time AEPS  owns, controls or has surface rights  to more




than 3.3 billion  tons  of  recoverable coal.



      AEPS  serves  a  sizeable  portion of Kentucky, Ohio  and West  Virginia.   A




bid  to  purchase Columbus   and  Southern Ohio  Electric Company (COSO),  made while




they were  still AGEC,  would  have greatly expanded  their influence  in  the ORBES




states.  The  initial  application requested  approval from the FPC  to bid  on the




purchase of 99 percent of common stock of  COSO (then  a subsidiary of  United




Light and  Railways  Company).  The area of  COSO was contiguous with Ohio  Power




Company,  a subsidiary of  AGEC.   However, the FPC concluded  that this purchase




would represent a major extension into  new territory,  and denied its permission.




      In 1968,  AEPS   again proposed the  acquisition through an exchange of 1.3




 shares of  AEPS common stock for each share of COSO.  Both AEPS and COSQ filed




 motions with SEC, which must approve the sale, urging it to expedite a decision




 concerning the acquisition.   COSO has emphasized that the prolonged delay of




 the proceedings has restricted its financing plans over the past years and that




 these restrictions would be expected in the future until the matter is resolved.




      In 1978, the SEC approved the acquisition in principle.  This tentative




 approval was subject  to  the resolution of two remaining issues:  (1) objections




 by  several local municipal systems and  (2) "fairness" in exchange offers involv-




 ing stockholders of the  two corporations.  After the necessary substantiating
                                       21

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materials were submitted to the SEC in 1979, proceedings were closed.  However,

the Commission has not yet released its decision.5
                       The Allegheny Power System

     The second holding company with operating utilities in the ORBES  states

is the Allegheny Power Systems, Inc. (APSI).  Two of its three operating  com-

panies — the West Penn Power Company and the Monongahela Power Company —  are

located squarely in  the ORSES region.  The  third, the Potomac Edison  Company,

is located on  the periphery of the region.

     APSI was  established  in  Maryland  nearly sixty  (60)  years ago as the  West

 Penn Electric  Company.   The company was formed  to  acquire  control of the  elec-

 tric,  gas,  transportation  and certain  other  subsidiaries of American Water

 Works  and  Electric Company (AWWEC)  which had electric  utility operations  in

 West Virginia, Pennsylvania,  Ohio,  Virginia  and Maryland.   AWWEC also supplied

 gas to users in West Virginia,  Pennsylvania  and Maryland,  but gas operations

 were small compared to the electric operations.

      West  Penn Electric Company adopted its  present name,  Allegheny Power Sys-

 tem, Inc.,  in November of  1960.   By 1976, the APSI system served customers

 in Pennsylvania, West Virginia,  Maryland, Ohio and Virginia, with a generating

 capacity of 6,429 megawatts.



                         General Public Utilities

      General Public Utilities (GPU) is the third holding company in the ORBES

 states providing electric service co customers in New Jersey and Pennsylvania.
     5In February 1980, the Securities and Exchange Commission approved American
Electric Power's request to acquire Columbus and Southern Ohio Electric Company,
subject to approval by at least 80 percent of the shareholders of Columbus  and
Southern Ohio Electric Company.
                                      22

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At the end of 1977, the three subsidiaries which make up GPU owned 44 genera-




ting stations with a net effective capability of 7,190 MWe.




     Metropolitan Edison Company, Pennsylvania Electric Company, and Jersey




Central Power and Light Company jointly own Three-Mile Island nuclear station.




Metropolitan Edison, the operator, owns 50 percent of the plant, while Jersey




Central and Pennsylvania Electric each own 25 percent.  The 1979 accident at




the Three-Mile Island facility caused extensive physical damage to the reactor




and heightened public concern about the safety of nuclear facilities.  The




estimated cost of  repair of Three-Mile Island is of the order of 500 million



dollars, and this  factor coupled with the uncertainty in the scheduling of the




repairs has created financial problems for all three companies.  These have




yet to be fully  resolved and the full impacts of the accident have not yet




been evaluated.
                                      23

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                               CHAPTER III



               PUBLICLY-OWNED UTILITIES AND POWER AGENCIES



                        Organizational Framework

     Another class of utilities is the publicly-owned utilities and power

agencies.  There are three levels of public ownership found in the ORBES states:

     Municipal utility (village, town, or city)

     Regional utility (county or district)

     Federal Power Agency

The state power agency is another level of publicly-owned utility.  However,

none of the six ORBES states operate any generating or distribution facilities,

although some state institutions such as state universities may generate their

own power.



                            Municipal Utilities

     Municipal utilities are owned and/or operated by a municipal government

to serve customers within the corporate limits.  Today, municipals outnumber

the major investor-owned utilities in the ORBES states approximately  7  to  1;

264 such companies are located  in the six-state region.   Eighty-three are  in

Ohio,  followed by Indiana with  74, Illinois with 41, Pennsylvania with  34,

Kentucky with 30 and West Virginia with 2.  (A listing of  the  larger  publicly-

owned  utilities is included  in  Appendix C).   Despite the  numerical advantage,

the municipal utilities supplied only one percent of the  six-state region's

electrical  power in  1978.1
      ^.S.  Department  of  Energy,  Energy  Information Administration,  "EIA  Report
 on  Preliminary  Power Production,  Fuel  Consumption  and  Installed  Capacity  for
 1978" Energy  Data  Report,  May  1979,  p. 37.

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     Fifty-three municipals in the ORBES states have some generating capability




which is used to produce all or a portion of the power needed for the community.




Nearly 66 percent of these generating utilities have annual operating revenues




in excess of $1 million.  However, in some cases, such as Fort Wayne City Util-




ities, the utility's generating capacity is leased to a private utility for use




within the system.




     The remaining municipal utilities have no generating capability.  They




rely solely on purchased power to meet their customer demands.








                           Regional Utilities




     The Chicago Metropolitan Sanitary District  (MSD) is the only special dis-




trict in the six-state region which maintains generating capacity.  The MSD is




responsible for solid waste disposal operations  in and around Chicago.  Thus,




its 41 Mwe capacity is used to provide power for its various functions.








                          Federal Power Agencies





      The Tennessee Valley Authority and the U.S. Army Corps of Engineers are




  the only federal power agencies operating in the ORBES states.  The three TVA




  plants and three Army Corps plants, all in Kentucky, produce approximately four




  percent of the total power generated in the ORBES states.2  Of all  Che ORBES




  states, Kentucky is  the only one using substantial amounts of federally-generated




  power.  This power is either marketed directly  to the consumer by  che Depart-




  ment of the Interior, Southeastern Power Administration or purchased by indi-




  vidual utilities or  cooperatives for distribution along their own  transmission




  lines.
       2"EIA  Report  on  Preliminary Power  Production,"  p.  37.
                                     25

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                        Institutional Arrangements

                                Growth of the
                        Municipal Electric Utility

     Municipal ownership of electric utilities grew during the first three

decades of the electric utility industry primarily in areas where private elec-

tric services were not available.  In addition, municipal ownership was an al-

ternative to state regulation.  The public was supposed to benefit from publicly-

owned utilities in two ways:  (1) those served by the city electrical system

enjoyed the low price directly; and (2) those not served, enjoyed the benefits

of having a yardstick against which to measure their own prices.  Occasionally,

the competition between the public and private sector was direct.  For example,

in such cities as Cleveland, Ohio; Columbus, Ohio; and Los Angeles, California

residents had a choice of hooking up with either municipal or private electricity.

Proponents of the municipal approach argue that as a result, these cities (for

a time) had some of the cheapest power in the country.


     During the 1920s, the trend toward municipal ownership reversed as more

areas were integrated into the private sector.  This trend was reversed in the

1930s (although private ownership has always predominated) when the development

of new technology apparently made small operations economic for a time and per-

ceived abuses in the private sector soured the public on privately-owned electric

utilities.

     Opponents of the municipal power approach cite at least four basic obstacles,

aside from charter limitations, which inhibit a return to municipal ownership:

     1)  Damages and severance charges may have to be paid to an existing

         private firm.

     2)  A financing problem may arise.  Public funds must be available to

         pay for seizure or severance, and on-going capital investment will

         be necessary.
                                     26

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     3)  The municipal boundary limits may not constitute an efficient unit




         of distribution or production; thus, prices may not be as low as




         anticipated.




     4)  Where alternative sources of power supply are not available, the




         city may become a captive customer of the private utility which




         previously owned its distribution system.




Apparently, the obstacles to municipal ownership are great enough that few




cities today embark on this route.  The number of municipal power enterprises




nationwide has declined from a high of 3,084 cities in 1923 to less than 2,000




at the present time.  Most of those that remain, purchase power from the investor-




owned utilities.  As a result, they are confronted with institutional problems




of trying to keep prices as low as possible while having to pay the utility at




the rates set by the state.








                     The Federally-Owned Power System




     As indicated earlier, the Federal government constructed a dam on the Tenn-




essee River in northern Alabama at Muscle Shoals to aid in the manufacture of



synthetic nitrates for explosives.  When the construction of the dam and the




nitrates plant ended in 1925, the logic of government ownership of a war-born




production dam and plant disappeared.  For a time, the dam moved into private




hands.  However, after several false starts in attempting to regain ownership




of the dam, the Congress finally acquired the facility for the federal govern-




ment in 1933, the same year President Franklin D. Roosevelt signed the Tennessee



Valley Authority Act.



     This new legislation provided for the total development of the valley.  One




major objective was to generate electric power for residents of the TVA region.




At first such power was provided totally by the Muscle Shoals installation, later
                                    27

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renamed the Wilson Dam, and others which followed it.  Slowly, however, coal-




fired steam plants were built, and today more power is generated in these plants




than by hydro-electric power.




     Because of its institutional importance, the TVA can have a considerable




impact in the ORBES states.  In fact, the TVA may be changing its traditional




stance as a champion of energy growth.  According to the Wall Street Journal,




a recent TVA report to President Carter recommended that further expansion of




existing energy companies be opposed.  Coal and uranium markets "aren't only




dangerously concentrated, but are also dominated by companies with other energy




interests."  The report which was prepared by the TVA general counsel also ar-




gued that "the high concentration in these markets is likely to lead to collusion




among energy suppliers, as well as higher prices and smaller supplies."3




     The report by the huge government-owned electric utility urged that mergers




leading to a further concentration in the industry be prevented mainly through




litigation and legislation.  It pushes for legislation that would prevent energy




companies from acquiring interests in more than one of what the report calls



the three primary fuels — petroleum, coal and uranium.




     It also suggests  that the government provide assistance to small coal and




uranium producers to allow them to compete more effectively with larger energy




companies.  If federal agencies fail to take legal action to prevent anticom-




petitive merges in the energy industry, the report asserts, then TVA itself



should file suit to prevent them.  If the leadership of TVA is fully behind




these suggestions, it  seems probable that a shift in overall TVA policy could



have an impact on the broad electric utility industry in the ORBES states and




elsewhere.
      3Wall Street Journal. March 26, 1979.
                                     28

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                               CHAPTER IV








                       RURAL ELECTRIC COOPERATIVES








                        Organizational Framework




    The rural electric cooperatives (REC) are the third component in the




structure of the electric utility industry, providing power to farms and rural




areas not otherwise served by investor-owned or public utilities.  The six-




state region supports 145 cooperatives ranging from 44 in Indiana to 1 in West



Virginia.  Appendix C contains a complete listing.




    There are three  levels of REC.  The basic unit is the distribution co-




operative, which predominates in the ORBES states.  Such a cooperative must




purchase power from a nearby investor-owned utility, a federal power agency,




or from a generating cooperative.  On the average, each one has a service area




of one or two counties.



    In some states, the REC's are affiliated into a "super-cooperative" which




acts as a purchasing agent for all its associated cooperatives.  Two such or-




ganizations are Buckeye Power, Inc., which distributes power to all the REC's




in Ohio and Allegheny Electric Power Cooperative in Pennsylvania.  Moreover,




Allegheny owns 10 percent of the Susquehanna Nuclear Plant under construction.




     Other rural electric cooperatives also currently own or are  planning to




own generating capacity, usually in conjunction with an investor-owned utility.




Like the "super-cooperative," they  supply power to a network of  affiliated




distribution cooperatives.   The seven generating cooperatives in  the ORBES



states are:




     Southern Illinois Power Cooperative




     Soyland Power Cooperative (Illinois)
                                    29

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    Western Illinois Power Cooperative




    Wabash Valley Power Association (Indiana)




    Hoosier Energy Division; Indiana Statewide Rural Electric Corp.




    Big Rivers Electric Corporation (Kentucky)




    East Kentucky Power Cooperative




Western Illinois Power Cooperative and Hoosier Energy Division, do not generate




enough power to supply all their customers.  Therefore, they purchase additional




power,  for distribution through their systems.




                       Institutional Arrangements




                 The Rural Electric Cooperative Movement




    About 2 percent of all electric power in the ORBES states is generated by




the rural electric cooperatives.1  However, as in the case of municipal utili-




ties, this figure is not indicative of the importance of the rural electric




cooperative in the broad electric power industry.




    The institutional development of the electric cooperative began in 1932




with the election of President Franklin D. Roosevelt.  At that time, private




and municipal utilities service was confined to the cities and towns where




many customers per mile of line could be connected.  However, Roosevelt de-




cided to extend the power policies he had developed while governor of New




York.  His ideas were supported by other innovators with similar goals. In May




of 1935, Roosevelt signed an executive order creating the Rural Electrifica-




tion Administration (REA).  Congress incorporated the program into the Emer-




gency Relief Act of 1935, and Roosevelt named Morris Cooke, a vocal supporter




of Roosevelt's energy policy and a critic of the existing utilities, to head
      "EIA Report on Preliminary Power Production" p. 37.
                                    30

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the agency.  The initial efforts made by Roosevelt  and  Coote  to bring  electric
service to the individual  farmer through the REA were not  successful.   They
attempted to arrange  for farmers to buy power  from  the  private companies,
because they felt that  the well established investor-owned utilities had  the
knowledge and equipment to do  the  job.  However, the privately-owned  utili-
ties refused to supply  the power and so they turned to  the municipally-owned
utilities.  The municipal  company  option proved unsatisfactory as well, because
they had  little enthusiasm for extensions  that would neither  serve  their  own
residents nor return  much  profit.  Also, a series of adverse  court  decisians
cast doubt on their legal  right to provide electricity  beyond their city
boundaries.

     Finally, Cooke turned to the concept of a cooperative  for farmers  as a
solution.   One model he used was a pioneering venture begun in Alcorn County,
Mississippi,  where a group of farmers known as Alcorn Associates, had formed
a cooperative to buy power from the Tennessee Valley Authority (TVA).   The
cooperative strung one-hundred miles of wire,  charged rates no higher than
those being charged in the surrounding towns  and  made enough profit  in one
year to repay half of the  funds that TVA had  loaned in the previous year to
establish  the service.
     Gooke  proposed  that local  cooperatives such as  Alcorn  Associates be or-
ganized to seek funds from the Federal  Rural Electrification  Administration
 (REA).  This  required that ElEA be   strengthened as  a loan  agency and  its  orig-
inal mission as a  relief  agency be phased  out. The enabling  legislation  became
known  as  the Rural  Electrification Act  (Norris-Rayburn  Act).  Under the Act,
farmers had  a clear incentive  to work  for  speedy  electrification.   Thus,  the
rural  electric  cooperative became  the  chief vehicle of  rural  electrification,
                                     31

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serving all farms in the community, not just the most profitable ones.

     By 1974, $64 billion on federally backed long term, low interest loans

had been extended to 1,000 borrowers serving 5.8 million customers in 46 states.2

As a result, rural electrification was extended to 94 percent of the farms in

the United States in the first twenty years following passage of the REA Act,

and now exceeds 98 percent of all farms.


                        Institutional Affiliations

     Institutionally, the rural cooperative is a legal  form of business similar

to a corporation, except that ownership is vested in members'rather  than stock-

holders.  All benefits are in the  form of products or services rather than profits.

     Most cooperatives in the ORBES states are affiliated with the National

Rural Electric Cooperative (MEGA), a non-profit organization serving rural

electric systems.  NERCA coordinates a variety of services for its members,  in-

cluding management training, insurance and safety programs, legislative repre-

sentation, and public relations.

     Each state also maintains a state-wide association of cooperatives.  These

state organizations have similar goals — providing to  its members the advantage

of larger utility operation, while  retaining local control and ownership.

     The National Rural Utilities  Cooperative Finance Corporation  (CFC) is

another non-profit organization serving member cooperatives (including nearly

all those in the ORBES states).  It was created in 1969 to provide private

capital to  the rural electric cooperatives to supplement the government financing

available through the Rural  Electrification Administration (REA) loan program,

particularly for generation  and transmission facilities.
     2Martin J. Farris and Roy J. Sampson, Regulation, Management and Ownership,
 (Boston:  Houghton Mifflen Co.,  1968; reprint ed., 1976).
                                     32

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                                CHAPTER V






                      ELECTRICAL GENERATION SYSTEMS


     Because of the large number of utilities serving the ORBES states it is


more useful to analyze the industry in terms of a regional system rather than


at the level of the individual utility.  This approach is appropriate too, be-


cause the high degree of interconnection among the utilities in the six states


allows power to be sent to any area in need of additional electricity.  Such


ties are stimulated by the independent power pools and power consortia as well


as by the national and regional reliability councils.




                           Electric Generation


                           Generating Capacity


     The total installed capacity represents the maximum amount of power in-


stantaneously available, assuming every generating unit in the system is oper-


ating at full capacity.  However, in a system as large as the one encompassing


the ORBES states, it is highly unlikely that any utility will be operating at


full capacity in any given instant.  On a yearly basis, coal planes operate


with a capacity factor of about 50 percent while nuclear plants operate at a


60-65 percent capacity factor.1  However, these factors vary widely from plant


to plant as well as from company to company.  Thus,  the system usually operates


at some percentage of capacity, depending on the generating unit availability


and  the customer demand for electricity.
      .          ,          ,  ..         Actual Mwh generated per year
      1 Capacity  factor is defined as:  	
                                      Unit Capacity  (MW) x 8760 hours/year
                                     33

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     In most ORBES states, there is a strong correlation between the amount of




installed capacity and the state population.  Thus, most of the capacity in




the six-state region is found in Pennsylvania, Ohio and Illinois (Table 4).




West Virginia is the exception.  The state, which has only 4 percent of the




area's population, contains nearly 11 percent of the installed capacity.  As




a result, West Virginia exports nearly twice as much power as is used in the




state.  This is largely due to the fact that the American Electric Power System




(AEPS) owns the majority of the generating facilities in the state.  Because




AEPS is a totally integrated system, power required at one location may be gen-




erated many miles away.  State lines are meaningless within the AEPS system.




     Power plants must be located near a good supply of water.  Therefore, most




of the capacity is located along major rivers and  the Great Lakes, with clusters




adjacent to the metropolitan areas which constitute the utilities' major load




centers  (Figure 8).  More specifically, more than  60 percent of the six-state




capacity is within the Ohio River drainage system; 28.7 percent is located on




the main stem of  the  Ohio River and 31.8 percent  is located on its tributaries.



   Coal, oil, and nuclear power provide most of the capacity in the six-state




area, however, coal is the single most important fuel in the region.  Coal fired




capacity is found in all six states, but nearly 60 percent of it is sited in



Ohio, Illinois and Pennsylvania.  About 32 percent of the coal-fired capacity




is found along the main stem  (Figure 9).  Ohio-based utilities, in particular,



have  located extensively along the Ohio River.  In other states, primarily West



Virginia, Pennsylvania and Kentucky, the majority  of coal-fired capacity is




located  on  the tributaries of  the Ohio River.





     Historically, nuclear capacity had been increasing in the ORBES states.



The uncertainties associated with public acceptability and regulatory constraints




have resulted in a slowdown in orders for new nuclear units.   In 1975,  ten com-



mercial-sized reactors were in operation in the six-state region:   seven were

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                                                    TABLE 4


                                       GENERATING CAPACITY SUMMARY  - 1975
                                               SIX-STATE REGION

1975 Capacity MWe
Illinois
Indiana
Kentucky
Olilo
Pennsylvania
West Virginia
TOTAL
%
1985 Capacity MWe
1975-1985 MWe Change,
1975-1985, % Change
SOURCE: Steven D
COAL

15,801
13,104
10,948
21,266
15,517
11,966
88,602
75.9
118,572
Net 29,970
+ 33.8
NUCLEAR PETROLEUM

5,717 4
1
-
2
2,904 5
-
8,621 13
7.4
33,240 14
24,619
+ 285.6 +
. Jdiisen, Electrical Generating

,058
,166
121
,700
,818
12
,875
11.9
,087
212
1.5
Unit
NATURAL
GAS

204
110
128
71
19
-
532
0.4
456
76
- 14.3
Inventory,
HYDRO*

34
114
679
1
1,717
205
2,750
2.4
3,037
387
+ '10. '4
prepared
OTHERb

19-7
324
-
626
815
387
2,349
2.0
3,493
1,144
+ 32.8
for the Ohio
TOTAL
MWe

26,011
14,818
11,876
24,664
26,790
12,570
116,729
100
172,885
56,156
-1- 48.1
River Basin
%

22.3
12.7
L0.2
21.1
22.9
10.8
100.0




Energy
Study (November 1978).

     a
      Includes hydro and  pumped  storage.


      Includes refuse,  waste heat,  multi-fueled  and  unknown  fuel  types.

-------
                        Fig. 8  Total Installed Generating  Capacity:  1975
                                                                                    3000.  -  5400.
                                                                                    2000.  -  3000.
                                                                                  §| 1000.    2000.
                                                                                  §] 500.  -  1000.
                                                                                  3 250.  -  500.
                                                                                  3 100.  -  250.
                                                                                  3 1 .    100.
                                                                                  DO.    o.


                                                                                 MEGflWRTTS
     SOURCE:  Steven  I). Jansen, Electrical Generating  Unit  Inventory, Prepared for the Ohio River Basin
Energy .Study  (November,  1978)

-------
                   Fig. 9  Total Installed Coal-Fired  Generating Capacity:  1975
                                                                                     3000.  - 5400.
                                                                                     2000.  - 3000.
                                                                                     1000.  - 2000.
                                                                                     500.  - 1000.
                                                                                     250.    500.
                                                                                     100.  - 250.
                                                                                     1.  -  100.
                                                                                     0.  -  0.
                                                                                  MEGflWRTTS
     SOURCE:  Steven I). Jaiisun, Electrical Generating Unit  Inventory, Prepared for the Ohio River  Basin
Energy Study  (November,  1978)

-------
Located at three sites in northern Illinois and three reactors were Located

at two sites in eastern Pennsylvania (Figure 10).  In addition, there was a 60

MWe reactor near Shippingport, Pennsylvania.  This reactor was operated by

Duquesne Electric Company for the federal government, primarily as an experi-

mental plant, although it did provide power to the surrounding community, and

was thus classified as a commercial reactor.
     By 1978, four additional units, totaling 2778 MWe of capacity, were on-


line, including a new 60 MWe experimental breeder reactor built on the site of
                                                               2
the earlier experimental station at Shippingport, Pennsylvania.  Because it


was constructed as an experimental plant, consideration is now being given to


its decommissioning.  Additional commercial nuclear plants are under construc-


tion in all ORBES states, except Kentucky and West Virginia.



                            Actual Generation

     The amount of electricity actually generated during the year is based on


demand from both the final consumer  and inter-utility bulk sales.  In 1975,

nearly one half billion MWh of electricity were generated in the six-state re-

gion, of this, 86.5 percent came from coal, 8.0 percent from nuclear power, 3.2

percent from  petroleum, 1.3 percent from hydro and 1.0 percent from natural gas.

These percentages do not coincide with breakdown of capacity by  fuel types.  Nu-

clear and coal-fired plants are base-loaded units.  They are used whenever possi-

ble,  thus providing a  relatively constant level of generation.   As a result, these

two  fuel types provide a greater percentage of the generated electricity than  in-


dicated by  their contribution  to the installed capacity.
      2This  figure includes  the capacity contributed  by both  units  at  Metropoli-
 tan Edison's Three Mile Island Station, which  was  shut down  following the acci-
 dent in March 1979.

-------
                    Fig. 10  Total Installed  Nuclear Generating Capacity: 1975
                                                                                    3000.  -  5400.
                                                                                    2000.  -  3000.
                                                                                    1000.  -  2000.
                                                                                    500.  -  1000.
                                                                                    250.    500.
                                                                                    100.    250.
                                                                                    1.    100.
                                                                                    0.  -  0.
                                                                                 MEGRWOT7S
     SOUKCE:  Steven 1). Jansen,  Electrical  Generating Unit Inventory, Prepared for the  Ohio  River
Basin Energy  Study (November, 1978)

-------
                           Power Transmission




                           Transmission  System




     The bulk electric power produced at the generating plant is transported




to other portions of the system through the transmission network.  This net-




work consists of the transformers,  which change the voltage of the electricity




and the transmission lines which carry the power.




     The transmission lines are the most extensive aspect of this system.




They form a network of high voltage (69-161 KV) and extra high voltage (230-




765 KV) lines which connect the generating stations to the load centers.   The




system includes substantial intra-system, intra-regional, and inter-regional




transmission ties, thus creating a well interconnected power grid which allows




power to be sent by numerous, redundant pathways to the final user (Figure 11).






                        Utility Interconnections




     A utility interconnection is defined as a transmission link between two




individual utilities.  These connections are most important in the context of




the regional reliability councils.   Member utilities are highly interconnected




in order to stabilize the regional system and provide for a more economical




power supply.  Thus, in the event of an accidental breakdown at a key genera-



ting plant or transmission line, or an unexpectedly high level of demand, power




from other plants in the system can be used to make up the deficiency, de-



creasing the chances of a blackout or brownout.  Connections are made between



regional reliability councils for the same purpose.




     Such a transmission is mandated by the National Electric Reliability Coun-



cil.  Each regional council is responsible for planning a network with a high




degree of reliability, and testing it under a variety of simulated conditions.



As with generation capacity, transmission line additions must be planned well
                                     40

-------
              Fig. 11     Major  Generating  Units  and
I        Transmission Lines in the Six ORBES States
I
             Illinois
                                                               Pennsylvania
                             Kentucky
  LEGEND

  TRANSMISSION LINE CAPACITY
      	 345 Kilovorts and Over
      	230 Kilovolts
  GENERATING PLANTS
       A Capacity  Greater than 1000 MWe
       A Capacity  250-999 MWe


  Miles
                     LOCATOR MAP
      50    100
                    200
                            300
                                     400
 I
500
  SOWC& Congressional Research Service for the US. Senate Committee on Natml Resomea. National Energy Transportation; Volume I.
        Current Systems and Movements., Map 14 ( Washington D.C.; May 1977 ) Publication 95—15
        and Staven 0. Janaen, Electric Generating Unit Inventory, Prepared for the Ohio River Basin Energy Study  (November 1978)
                                           41

-------
in advance of demand.  New lines are needed for a variety of reasons:  to re-

lieve overloads, to provide area protection, to increase interchange capability,

for stability considerations, or to deliver generation output.3



                           Capacity Exchanges'4

     The system's interconnections are also used to maintain day-to-day

service through the' use of "capacity exchanges."  The utilities depend on the

grid to help meet the demand for power because no single utility can exactly

predict the amount of electricity required to supply the demand.  Excess elec-

tricity from one company is routinely sold to another utility in need of

additional power.  Many utilities have firm commitments to purchase power if

their available capacity is not sufficient, such as during times of peak demand.

     Capacity exchanges usually occur between power pool affiliates or among

neighboring utilities.  This also takes place between regional  reliability

councils.  This capability is used  in power "wheeling," where the transmission

facilities of one system is used to transmit power of and for another system.

     In terms of firm commitments for capacity exchanges,  MAIN is neither a

net exporter nor a net importer of  power (Table 5).   The projections of  the

reliability councils for 1977-1986  indicate that MAIM,  as  a  whole,  will  be a

net importer of power during the summer for the entire  reporting period  and

a net exporter of power during  the winter, except for  1979  through 1982  when

winter exports nearly balance winter imports.
     ^Detailed plans for proposed new lines are included in the annual reports
issued by each reliability council.

     ^Detailed data on exchanges by individual companies can be found in the
company's annual report or in the yearly report from the Reliability Council
to which it belongs.

-------
                               TABLE  5

 SUMMARY  OF  SCHEDULED  CAPACITY  EXCHANGES  INTO OR OUT OF  ECAR AND  MAIN

                               1977-1986


 Scheduled Imports
                            ECAR                    MAIN

1977
1978
1979
19SO
1981
1982
1983
1984
1985
1986
Summer
704
594
493
483
728
921
872
1,013
957
894
Winter
1,112
902
801
989
1,228
1,229
1,372
1,321
1,265
1,202
Summer
2,074
1,832
1,522
1,522
1,552
1,552
1,240
1,240
1,240
1,240
Winter
1,114
1,072
1,262
1,262
1,292
1,292
780
980
980
980
 Scheduled Exports
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
2,479
2,424
1,940
2,006
2,128
2,264
2,317
2,069
2,128
2,207
2,052
2,094
2,217
2,469
2,328
2,518
2,311
2,418
2,545
2,671
880
1,264
1,036
1,037
1,037
1,038
1,039
1,040
1,040
1,041
1,729
1,540
1,294
1,295
1,295
1,296
1,297
1,297
1,298
1,298
     SOURCES:  East Central Area Reliability Council(ECAR),  Load Projactions
and Resource Planning. (April 1977)  Exhibit I-C p.  42

     Mid-America Interpool Network (MAIN),  Reply Co Appendix A-l of Order No.  383-4,
(April,  1977)  Item 2-C p.  2-49
                                     43

-------
     In contrast,  the projections  indicate  that  ECAR,  as  a  whole,  will export




approximately  twice as much  power  as  it will  import  over  the same  reporting




period  (Table  5).  Planned exports will exceed planned imports  in  all summers




and winters  through 1986.







                    Power Resources:   Peak and Margin




     Through capacity exchanges and other load sharing mechanisms,  the utilities




try to keep up with the demand for power.   The demand is cyclical,  increasing




at certain times of the day or year.   All utilities experience increased demand




(i.e.  peaks) during the day and evening, diminishing at night.  The yearly peak




is not as predictable.  Most utilities in the six-state region are summer peak-




ing, while others are winter peaking  (Table 6).  In the next ten years, utili-




ties in the ECAR region are expected  to  experience only slightly more demand




in the summer  than in the winter.  On the other hand, MAIN utilities are ex-




pected to experience a definite summer peaking schedule.  The timing of peak




demand is an important consideration  in load management and planning since stag-




gered peaks can reduce the overall capacity needed to maintain reliable power.







     The difference between  the  system capacity  and  the peak load  is  the




"margin of capability" or "reserve margin."   This  is essentially the  power




available to provide for scheduled maintenance,  emergency outages, system



operating requirements, and  unforeseen loads.    The reserve margins  for util-



ities in the ORBES states ranged from 44.8  percent to  -24.0 percent in 1976




and from 38.7  to -17.0 in 1977.  The  higher margins generally belong  to the




largest utilities, those with the  greatest amount  of generating capacity.  The



negative reserve margins are generally associated with the smaller utilities,



which may find it more economical  to  purchase power than to construct new
                                     44

-------
                                                   TABLE 6
                              PEAK LOADS AMD  RESERVE MARGINS:  1976-1977
STATE   COUPANY"
                                      1976
                                                                                            1977


1L CEIL
CB1P
COEC
ILPC
IOIC
VXSLC
IN IHPL
NO1P
PS1K
SOIC
n KEUC
LQCIL
OU C1CE
CU!I
coso
DAPO
OllhC
TOEC
Pi DULC
HI! EC
PMC
rePC
PEI*L
MlEC
uv roec
ACFS
nrSl
C*n«raclao, r»k
Capacity LoaJ Date of B0tterva Margin
(KUe) (Mile) Peak Load .t Peak
MUe Z
1.397 965 Sumuer 432 44.8
1.809 1.665 	 144 8.6
15.909 12.907 — 1.002 23.1
3.412 2.570 	 842 32.8
1.166 811 Sunnier 155 43.8
6.361 5.5B2 7/26 779 14.0
2.013
1.8SS
4.370
750
1.706
2.162
3.424
3.906
2.111
2.361
	
	
2.964
1.811*
2. 172*
4OO
1.717
7.742
i,OI3
.671 7/23 141 20. S
.997 7/27 -142 - 7.1
.138 11/29 1.240 39.5
593 7/23 137 26.5
.641 12/21 65 4.0
.585 	 579 36.6
.598 7/IS 826 31.8
.065 — 841 27.4
.776 Su««r 135 18.9
.793 	 56fl 31.]
	 	 	 	
	 	 	 	
.260 — 704 31.2
.410 	 4OI 28.3
.994 — 178 8.9
526 11/21 -126 -24 0
.425 Winter 1.292 29.2
.346 — 2.196 44.8
.500 — 1.S1J 43.2
17.661 13.539 Winter 3.699 27.3
6.429 4.6M 1/22 1.779 38.1
Generating Paak
Capacity Load Data of kacrvc Martin
(We) (HUc) P«.k Lo.d .t Peak
Hit _«_
1.244 97} 7/14 269 27.
1.819 1.811 July 6 0.
16.409 11.932 7/15 2.477 17.





















.412 2.846 7/1} 566 19.
.104 872 	 232 26.
.671
.013
.286
.378
750
.228
.137
.308
.611
.480
.361
.961
.665
.289
.837 7/IS 836 14.
.802 7/li 211 11.
.211 7/IS 71 1.
.386 December 990 29.
669 7/18 81 12.
.797 1/18 431 24.
.705 7/15 432 25.
.841 7/20 467 16.
.350 July 281 8.
.932 7/20 548 28.
.954 7/20 407 20.
.114 7/01 827 20.
.191 7/15 272 19.
.171 7/21 918 38.
.698 1.428 Winter 270 18.
.158 2.022 January 336 16.
496 S5I 7/18 -9S -17.
.726 4.411 Ulnur 1.295 29.
.198 5.888 7/21 2,110 39.
	 	 	 	 	
12.611 Winter 3.950 31.
6.429 S.OJ1 1/17 1.294 27.
•Include* fIrn purcheBeb
"See Cloeadry. Appendix A. lor company abkreulatIons
 SOUBCE:  *'"""•' H-Kurt 197b and 1977 for each cuapuny atmun

-------
generating facilities.  Each utility or power pool is responsible for main-



taining the margins suggested by the regional reliability council.  In gen-



eral, it is recommended that a utility maintain reserves equivalent of 15%-



20% of the total peak demand or 50% of the capability of the largest generating



unit, whichever is greater.

-------
                               CHAPTER VI








                ELECTRIC GENERATING CAPACITY:  1976-1985




     To maintain a reliable level of generating capacity, utilities constantly




plan for the future.  To do this, they must  formulate long range forecasts of




expected demand and adjust capacity to meet these demands.  Basically this in-




volves projecting load growth ten or more years into the future.  The required




capacity additions must account for the projected load, capacity retirements,




and an adequate reserve margin.  The utility must then consider the trade-offs




between purchasing increasing amounts of electricity or constructing a new fa-




cility.  If the latter is chosen, options regarding the fuel sources and the




location of the new plant must be assessed.






                     Growth in Generating Unit Size



     Current plans indicate that the new units will primarily be fueled by




coal or uranium.  Nuclear power, expected to replace petroleum as the second



largest fuel source for the installed capacity in the six-state region by 1985,




will experience a greater relative increase than the coal-fired capacity.  How-




ever, in absolute terms, coal should remain the major source of fuel in all six



states.





       The  average  size  of new  electric generating units  increased raoidlv between




1960 and 1975  (Figure 12).  This was due, in part, to the introduction of nuclear




units which tended  to be large  and, in part, to the increasing size of new coal




units  to realize economies of  scale.  In 1960, the average size of coal capacity

-------
Figure  12.   Average MWe Size of Generating  Units in the Six ORBES  States
                              By On-Line  Date*
                                                                            1986
       Wlin20m*MW»1MOlM>1MO  1965  1960  1966  1970  1975  1980  1385
     SOURCE:  Steven  D.  Janscn,  Electrical Generating Unit  Inventory.   Prepared
for the Ohio River Basin Energy Study, (November, 1973).

     *Future figures  are based on announced utility plans
                                      48

-------
additions was 190 MWe and the maximum was about 600 MWe.  By 1975, the average




new coal-fired unit had increased to 750 MWe and the maximum size was 1300 (We.




It now appears that at least for the near future, utilities have reached the




limit of increasing economy of scale with larger coal-fired units.  Over 60




percent of scheduled coal-fired additions between 1976 and 1985 are in the




range of 400 to 650 MWe.




     Nuclear units have shown a much more stable size distribution history.




With the exception of the first prototype reactors at Shippingport, Pennsylvania




and Dresden Unit 1 in Illinois, which was the first privately financed reactor




in the United States, all of the reactors in the ORBES six-state region have




been built or are planned through 1985 in the size range between 684 MWe and




1205 MWe.  Table 7 illustrates some elements of this growth; new coal units




will be, on the average, more than twice as large as existing coal units.  New




nuclear units are expected to be about 20 percent larger than those now in opera-



tion.  Furthermore, the average nuclear unit additions are expected to be almost




twice the size of coal-fired unit additions.  This size differential is reflected




in Figure 12, which shows the growth in the average size of generating unit




additions as a function of on-line date in the six-state region.




     As a result of the significant increases in the generating unit size, the




number of on-line units is expected  to decline between 1976 and 1985 (Table 8)




while the total installed capacity will continue to increase.  The new plants



will allow utilities  to retire the older, smaller, less efficient and conse-




quently, less economical generating unit.  These retirements will primarily




affect coal and oil burning planes; no commercial sized nuclear plants are



scheduled for retirement before 1985.
                                     49

-------
                                  TABLE 7

                              UNIT SIZE, MWe

                         ORBES Six-State Region
                            (steam units only)

Mean
Maximum
MiiyLmum
*
OPERATING UNITS
1975
COAL
190
1,300
1
NUCLEAR
862
1,098
209
NEW UNITS
1976-1985
COAL
549
1,300
20
NUCLEAR
l,023a
1,205
60b
     SOURCE:   Steven D. Jansen,  Electrical Generating Unit Inventory.  Prepared
for the Ohio  River Basin Energy Study (November,  1978).
           size calculated excluding experimental Shippingport Light Water
Breeder Reactor.

      Shippingport experimental Light Water Breeder Reactor.
                                      50

-------
                                                     TABLE  8

                                          NEW UNITS AND  EXISTING UNITS

                                             ORBES Six-State  Region
                                                (steam units  only)

Tocal Units, 1975
New Units, 1976-1985*
Retired Units, 1976-1985*
Total Units, 1985*
COAL
456
67
-114
409
OIL
102
8
-70
40
NUCLEAR
10
25
0
35
OTHER
44
2
-35
11
     SOURCE:  Steven D. Jansen,  Electrical Generating Unit  Inventory,  Prepared for the Ohio River Basin
Energy Study, (November, 1978).
     *Based on announced utility plans.

-------
                  Proposed Capacity Additions 1976-1985






     As indicated earlier, nearly all new generating units planned by the elec-




trical utilities will utilize either coal or nuclear fuel.  Sixty percent of




the coal-fired unit additions and 96 percent of the nuclear-powered unit addi-




tions are scheduled to be  constructed on new sites, while the remainder will




be built on sites which already support some generating capacity (Table 9).  In




terms of total megawattage, the new coal-fired sites will be 2.5 times larger




than existing coal sites.  The size of nuclear-powered sites, however, is not




expected to change significantly (Table 10).




     Nearly half of the 67,714 MWe capacity additions scheduled by the utilities




for the 1976-1985 period, are expected to be in Illinois and Pennsylvania (Table




11}.  This is primarily due to the large increases in nuclear capacity slated




for these states.  However, coal-fired units account for all of the total sched-




uled capacity additions in Kentucky and West Virginia, and three-quarters of the



total in Indiana.  The majority of all these scheduled additions are along the




Ohio River and its tributaries (Figure 13).




     In the six-state region, 58 percent of the scheduled coal-fired capacity




additions are sited along the Ohio River main stem (Figure 14).  Three states




in particular, West Virginia, Kentucky and Ohio, have the majority of their




new coal capacity along this river.  Another 30 percent of the coal-fired capac-



ity will be located on tributaries of the Ohio River.  Nearly half of Indiana's



new capacity will be on these tributaries, especially the Wabash and White rivers.




     Nuclear-powered units comprise a large percentage of the total scheduled



capacity additions in Illinois, Ohio and Pennsylvania.  Eighty percent of the




total 24,619 MWe of new nuclear capacity are scheduled to be located outside of



the Ohio River drainage basin (Figure 15).  Although Indiana and Ohio have sched-



uled nuclear capacity additions for the first time,  the majority of the nuclear
                                     52

-------
                                            TABLE 9

                             NEW SITES vs. EXISTING SITE EXPANSION

                                    ORBES Six-state Region
                                      (steam sites only)

Total Sites, 1975b
New Sites, 1976-1985
Retired Sites, 1976-1985
Total Sites, 1985
1976-1985 Capacity Added to:
Existing Sites, MWe
New Sites, MWe
Unslted, MWe
COAL
159
15
-18
156
COAL
11,969
22,934
2,940
OIL
41
2
-11
32
OIL
1,540
2,535
—
NUCLEAR
5
15e
0
20
NUCLEAR
927C
23,692C
_
OTHERa
34
It
-23
15
OTHERa
_
90
690
      SOURCE:   Steven D.  Jansen,  Electric Generating Unit Inventory, Prepared for the Ohio River Basin
Energy Study (November 1978).

       Includes gas,  multi-fueled,  refuse,  undetermined and unknown fuel types.

       Same site may be counted  more than once under different fuel types except for nuclear.

       Bailey nuclear facility is considered a new  site although presently there is coal and oil capacity at
       the site.

-------
                                 TABLE 10

                             SITE SIZE, MWe

                         ORBES Six-state Region
                           (steam sites only)

Mean
Maximum
Minimum
OPERATING SITES
1975
COAL
546
2,932
2
NUCLEAR
1,724
2,196
818
NEW SITES
1976-1985
COAL
1,349
2,751
480
NUCLEAR
l,688a
2,410
810
     SOURCE:  Steven D. Jansen,  Electrical Generating Unit Inventory.  Prepared
for the Ohio River Basin Energy Study.  (November,  1978).
           site size calculated excluding 60 MWe Shippingport experimental
Light Water Breeder Reactor.
                                     54

-------
                                      TABLE 11



                                CAPACITY ADDITIONS


                                      1976-1985
State


Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total
Total
MWe % Total
18,558
12,061
11,061
9,190
14,351
2,552
67,714
27.4
17.8
16.2
13.6
21.2
3.8
100.0
Coal
MWe
4,989
8,951
10,680
3,952
6,134
2,552
37,258
% Coal
13.4
24.0
28.7
10.6
16.5
6.8
100.0
Nuclear
MWe
9,656
2,944
-
5,032
6,987
-
24,619
Nuclear
39.2
12.0
-
20.4
28.4
-
100.0
Other2
MWe
3,913
166
322
206
1,230
-
5,837
% Other
67.0
2.8
5.5
3.5
21.2
-
100.0
     SOURCE:  Steven D. Jansen, Electric Generating Unit Inventory, prepared for the
Ohio River Basin Energy Study, (November, 1978)


      Does not include MWe reductions due to unit retirements

     2
      Includes oil, natural gas, hydropower, and other miscellaneous fuels
                                          55

-------
                 Fig.  13  Total Proposed Generating Capacity Additions:  1976-1985
                                                                                     3000.  - 5400.
                                                                                     2000.  - 3000.
                                                                                  gg 1000.  - 2000.
                                                                                  §J500.  - 1000.
                                                                                  gj 250.    500.
                                                                                  .3 100.    250.
                                                                                  I] 1 .    100.
                                                                                  ^] 0.  -  0.


                                                                                  MEGRWRTTS
     SOURCE:  Steven  I). .Jansen, Electrical Generating Unit  Inventory,  Prepared  for  the  Ohio  River  Basin
Knergy Study  (November,  I97K)

-------
                                   Fig.  14  Total Proposed  Coal-Fired Generating Capacity Additions
                                                         1976-1985
Oi
                                                                                                   3000
                                                                                                   2000
                                                                                                   1000
                                                                                                   500.
                                                                                                   250.
                                                                                                   100.
                                                                                                 0i.
                                                                                                 DO.  -
 - 5400.
 - 3000.
 - 2000.
- 1000.
  500.
- 250.
100.
0.
                                                                                                 MEGRWflTTS
                    SOURCK: Steven IK .lansen,  Klectrical Cenerating Unit  Inventory, Prepared for the Ohio River
               Basin Energy Study (November,  1978)

-------
              Fig. 15  Total  Proposed Nuclear Generating Capacity Additions:  1976-1985
                                                                                 I 3000.  - 5MOO.
                                                                                 §2000.  - 3000.
                                                                                 | 1000.  - 2000
                                                                                 | 500.     1000.
                                                                                 9 250.  -  500.
                                                                                 3 100.     250.
                                                                                 vj i•  - io°-
                                               f
MECOWOTTS
     SOURCE: Steven D. .lansen,  Klectricai Generating Unit Inventory,  Prepared  for  the  Ohio  River
Basin Energy Study (November,  1978)

-------
expansion is in parts of the region which had nuclear capacity in 1975.  In gen-




eral, nuclear plants are located away from major coal producing areas.  Neither




Kentucky nor West Virginia have scheduled nuclear-powered electric generating




units through 1985.










                         Total Capacity - 1985




     By 1985, 61 percent of the total coal and  nuclear powered generating




capacity is expected to be located in Illinois, Pennsylvania and Ohio  (Table



12).  The most significant growth is projected to be along the Ohio River main




stem, where the concentration of generating capacity would increase to 34.5




percent of the six-state total and along the Ohio's tributaries where the capac-




ity would increase to 26.5 percent of the total.  This is primarily due to new




coal-fired capacity additions being located in these areas (Figure 16).



     Ohio, Indiana and Pennsylvania are expected to contain 54 percent of the




total 118,572 MWe of coal-fired generating capacity (Figure 17).  Almost three-




quarters will be in the Ohio River drainage basin, with 40 percent located on




the main stem, (as compared to 32 percent located there in 1975) and 34 percent




on the tributaries.  This projected growth would significantly increase the con-




centration of electric generating capacity along the  main stem of the Ohio River



between Portsmouth, Ohio and Louisville, Kentucky.




     Most of the nuclear electric generating capacity projected for 1985 will




be located in Illinois and Pennsylvania.  These two states are expected to have



76% of the total 33,240 MWe nuclear capacity.  Only three sites (Zimmer in Ohio,




Marble Hill in Indiana, and Beaver Valley in Pennsylvania) will be along the Ohio




River main stem.  These three sites would constitute 15 percent of the total nuclear
                                     59

-------
                                    TABLE 12



                     ELECTRICAL  GENERATING CAPACITY  - 1985

                              SIX-STATE  REGION
                        Coal
             Nuclear
             Other*
               Total
     Illinois

     Indiana

     Kentucky

     Ohio

     Pennsylvania

     West Virginia
     Total 1985
     Capacity-MWe
19,742
20,881
20,791
22,379
20,843
13,936
15,373
2,944
-
5,032
9,891
-
7,206
925
1,575
1,981
9,039
347
42,321
24,750
22,366
29,392
39,773
14,283
118,572
33,240
21,073
172,885
     SOURCES:   Steven D. Jansen, Electrical Generating Unit Inventory.
prepared for the Ohio River Basin Energy Study (November 1978).

      Other  includes  petroleum,  natural  gas,  hydropower, .multifueled, refuse,
undetermined and unknown fuel types.
                                       60

-------
                               Fig. 16  Total Generating Capacity: 1985
                                                                                     3000.  - 5400.
                                                                                     2000.  - 3000.
                                                                                     1000.  - 2000.
                                                                                     500.  - 1000.
                                                                                     250.  - 500.
                                                                                     100.    250.
                                                                                          100.
01.
DO.  - o.
                                                                                  MEGRWRTTS
     SOURCE:  Steven D. .lansen, Electrical Generating Unit Inventory.  Prepared  for  the Ohio River
Basin Energy  Study (November, 1978)

-------
                         Fig.  17  Total Coal-Fired Generating Capacity:  1985

                                                                                        3000.  - 5400.
                                                                                        2000.    3000.
                                                                                        1000.    2000.
                                                                                        500.  - 1000.
                                                                                        250.  - 500.
                                                                                        100.    250.
                                                                                        I.  -  100.
                                                                                        0.  -  0.
                                                                                     MEGflWflTTS
     SOURCE: Steven D.  Jansen,  FJectrical Generating Unit  Inventory, Prepared for the Ohio River
Basin Energy Study, (November,  1978)

-------
capacity.  The remainder is expected to "be located outside of the Ohio River

drainage basin (Figure 18).

     These announced plans are constantly revised by the utilities.  Since 1976,

numerous changes have occurred in the capacity additions scheduled through

1985 (Figure 19)-    The  net  effect  of  these  changes  over a one year  period

was  to  reduce  the  expected 1985  installed capacity by  1,926 MWe.   While the

MWe  of  postponed coal units  was  approximately  equal  to the megawattage of newly-

announced plants,  the expected nuclear capacity had  a  net reduction  of 2,158

MWe  because postponements were not  compensated for by  newly announced  units.

The  changes in scheduled capacity additions  in the six-state region  follow

the  general national slowdown in new power plant construction.   Additional

regulatory and public acceptability uncertainties resulting from the Three

Mile Island accident have placed a.  disproportional amount of this slowdown

on the  nuclear industry.
      1Changes  (including postponements, cancellations, deratings, aratings,
and additions) are calculated by comparing  the Electrical Generating Unit
Inventory  for  1976 with an unpublished undate for 1977.
                                      63

-------
                           Fig.  18  Total Nuclear Generating Capacity:  1985
                                                                                     3000.  -  5400.
                                                                                     2000.  -  3000.
                                                                                  i$ 1000.    2000.
                                                                                  |§500.   -  1000.
                                                                                  £§] 250.   - 500.
                                                                                  0 100.    250.
                                                                                  HI I.  -   100.
                                                                                  Do.    o.


                                                                                  MEGRWflTTS
     SOURCE:  Steven I). Jan.sen, Electrical Cenerating Unit  Inventory, Prepared for the Ohio River
Basin Energy  Study  (November, 1978)

-------
             Klg.  19  Changes  Jn Scheduled On-Llne  Dates for  Electrical Generating  Units in  the Six ORBES States
tn
                                          (lull
                                          SIM
                                          |MRA|
 1200


 1110


 10W


 • 0


 8 0


 7 0


 tOO
>

 600
31
21
1(
10
10 •
0
• Nuclear
• Coal
• Oil

1 n
' 12 ' 10 ' i ' i ' i ' i ' ! ' i ' '. ' ' ' i 	 I 1 1 1 1 1 I 1 1 1 1 1 1 1 1 1 1 1 1 ll | | | | ' \i— |
12 10 ' 8 * 2 ° 2 4 • • 10 12 14 16 18 20 22 24 28 28 30 3X ft M 38 4|
Months Advanced Pfcatponed
^ Monlnt)
                                           'Clianges based on comparison ol announced plans between
                                            31 December. 1976 and 31 Decorr.bur. 1977
                  SOUKCli:  Steven !).  .lanson, F.lectrlcnl Cenerdiing Unit  Inventory,  Prepared  for the Ohio River
              lias in Energy  Study (Novemhur, 1978)  unii an unpublished  1977 update

-------
                                CHAPTER VII



              COMPARATIVE FINANCIAL AND OPERATING STATISTICS
                       FOR INVESTOR-OWNED UTILITIES

     The investor-owned utilities in the ORBES  states  vary widely in the size

 and  scope  of their operations.   These variations,  summarized in Table 13,

 illustrate the very significant differences  which exist  among the utilities

 with respect to service areas,  number of customers, annual sales and total

 generation.

                      Residential Customer Statistics


     Residential customer statistics are a convenient means of comparing utili-

ties throughout the ORBES states.  These can be used as indicators to identify

differences in residential costs and usage throughout the ORBES states.  The

average rate per Kwh for residential customers, which includes such costs as

rate base,  transmission costs, and fixed service charges, shows the differences

in electric costs across the six-state region.   In the ORBES states, resi-

dential users make up the majority of the investor-owned utility's customers.

If the rates charged by each single system utility are averaged for each state,

Kentucky appears to have the lowest rate, averaging 2.71 cents/Kwh, while

Pennsylvania has the highest—4.30 cents/Kwh.  Charges to customers of the

two large holding companies fall within this range:  AEPS customers average

2.96 cents/Kwh while APSI customers pay an average of 3.45 cents/Kwh.  Average
                                    66

-------
                                                                            TABLE 13
                                    CHAKACTEKISTJCS  Of THE  MAJOK  INVESTOR-OWNED  UTILITIES  IN THE  SIX ORBES  STATES
                                                                        SUMMARY  TABLE
                                                                                          1

Slat.

OH.UVA.VA.MD
HU.VA.UVA
PA

1H.VA.UVA.JPA
IB .Ml
IL1
OB

PA
*•
IL
IL
IL
IL
IL.IA
IL.IA.HO
IH
IH
IH
IH
KT
JLI
tm
em
OH
oa
IM
OH
OH
PA
PA
PA

Utility Code*
MfSl
HOPC
POKC
UEPP
Airs
UftC
IVttt.
IEPC
OIIPC
GPU
HE EC
PCEC
CEIL
CILIP
coec
ILK
I01C
IIHBC
IMPL
Half
mu
SOIC
CKUC
LOOK
cice
O.EI
LJOSO
DAPQ
Ml EC
PEPC
IUEC
Hl\£
PEH.
HIIKC
Sarvlca
Arae
(aq oUlee)
-
11.900
7,266
9,900
-
19,260
5.140
5,100
1.174
11.5JO
3.114
11.600
1.100
10,000
11,515
15,000
-
14.000
528
12.000
-
2.25D
10,000
700
3.000
1.700
6,200
6,000
7,500
1.500
1.150
800
1O.OOO
2.475
Popul etlon
Served
(Tliouaeiwle)
-
6*8
561
1.186
6.19&
2.151
1.599
396
1.698
4,076
827
1.500
439
760
a. ooo
1.160
596
1. 110
«sa
1.114
-
241
dM
«0>
1.700
1.121
1.290
1,300
1.3HO
J24
750
1,600
2,400
1.900

(Thau mind a)
1.0 J9
280
261
49 S
1.918
671
427
I2B
SB 7
1.481
337
4BB
172
191
1.791
489
159
924
909
345
499
91
HI
283
461
491
431
401
>96
116
254
535
926
1.261

S.1..1
(I01 Mwll>
».46I
7,62f
8,815
13.014
84.913
16,037
20,0(7
4,159
14.956
28.617
7,089
10 ,054
4.211
7.760
58,111
12.0)6
1.419
21. in
7.906
11.511
15. ill
1,451
10.814)
7.591
11,419
li.OM
8.111
9,121
IB, 16 3
1.015
1.122
12,516
10,114
26,111
St ( t
do*3 doiutd)
725.274
216.645
2Q7.S82
316.905
1.817.309
610.184
417, J4S
B4.J40
712.747
1.066.176
26J.SOJ
117.919
144,727
747.128
1,908,188
301.066
99.974
Ali.OOO
184 .OSS
323.182
397.742
IS. 174
229.156
154.117
35J.4I9
S 13. 100
280.185>
771.671
356.166
BB.SU6
119.119
418.118
611,417
1.024. BOO

Generation3
(103 tbh)
29.461
7.618
9.508
11.034
91.329
18.322
11.337
4.309
37.098
11.702
7.J94
lO.lii
4.542
S.429
61,274
12.076
_
23.10*
8. 406
« .660
16.858
3.611
10. aio
1.914
13. 4U
18.111
a. 1:1
10.065
10.101
1.2S4
7.814
12.516
20.354
28.437
CuaicaHr S
Ave.rate/Ewti
(unta)
1.45
1.90
1.40
1.21
-
1.09
1.16
1.45
l.ll
-
4.41
. .*-
            'Oclftllail d»ln kvatlable In AppaodLft E.

            2S«e gludimry. AppendlK A. tor  utility «nbr*vlatlona.

            2rtunbarB roundcil to n*»rii[ thoufand.

            '•All utllltlca Identified In thli tabla »r« under th« Jurlldlctloa of the Vederel Energy ««gul«tory Caaulaltaa ee well » the regulatory eKencle« ahown.

            aOURCE;  Hjudy'a Public Utility JUnuei. 1916.

-------
annual residential usage also varies among the utilities, ranging from 6,659

Kwh/residential customer in Illinois to 8,450 Kwh/residential customer in

Indiana.1  Use by AEPS customers was higher, averaging 9,735 Kwh/residential

customer.  APSI users averaged 8,197 Kwh/residential customer.  These figures,

however, do not indicate the extent to which electricity is used for home

heating.  Data such as the availability of oil and natural gas for heating

purposes and the number of degree days in the region are needed for further

interpretation.

    Despite the fact that the residential segment represents the largest

number of customers, megawatt-hour sales to commercial and industrial firms

are substantially larger throughout the six-state region.  This is primarily

a result of the concentration of heavy industry in the six-ORBES states.

However, no statistics comparable to the residential customer statistics are

available.

                     Utility Performance Statistics

     Between 1971 and 1976, the percent of revenues devoted to fuel cost in-

creased between 50 percent and 100 percent in most utilities reporting the sta-

tistic.  This general rise in fuel costs was accompanied by a general decrease,

on the order of 10-40 percent, in the percent of revenues going for labor.

Clearly, fuel costs have risen more dramatically than labor costs (Table 14).

    The heat rate is a measure of overall thermal efficiency; thus a lower

figure indicates greater efficiency in burning fuels.  The rates reported

by utilities in the ORBES states have fluctuated, creating no clear trend

over the six years.  Factors such as average unit efficiency, plant age, and
     iThe Illinois figure is calculated from statistics for the four major util-
ities in the state:  Central Illinois Light Co., Central Illinois Public Ser-
vice Co., Commonwealth Eidson Co., and Illinois Power Company.  Data for
Iowa-Illinois Gas and Electric and Union Electric Company are not included.
                                    68

-------
                                                   TABLK U
SELECTED FINANCIAL STATISTICS OF  THE MAJOR INVESTOR-OWNUL) UTILITIES  IN THE  SIX ORBES STATES
                                                 SUMMARY TAHLli
Utility
cude
mi
tore
POEC
UKW
A* PS
APPC
1KMK
»EPC
OIII-C
HEEC
PEEC
CEIL
CE1P
COEC
1LPC
101C
UNEC
1HPL
NO1P
rsiM
SOIC
IKUC
LUCE
CI(Z
CLCI
COM
OAPO
UUEL
rare
TotC
OULC
ft. PL
PUEC
I net opar
revenue lo
net utility
plant
_
9.5
8.1
7.3
-
a. a
6.1
9.5
10.4
6.3
6.7
5.9
3.1
6. 1
6.1
6.82
7.8
5.5
6.5
7.35
8 0
6.3
7.5
6 6
-
6.8
6. 87
6.0
4.7
10.0
5.34
3.B
1.4



For fuel
1971
.
-
-
-
-
.
-
-
-
-
-
12 4
-
21.5
11.0
20 >9
16.6
19.1
7.4
1) 1
9.7
17.5
11.9
12. B
-
17.8
16.1
18.4
_
20.7
21.09
_
31.2
1976
.
-
_
-
.
_
-
-
-
.
-
22 2
-
25 6
26 B
-
19.6
15 0
II. 1
30. a
-
27.1
21.1
25.0
-
30.1
24.9
32.9
_
27.4
32 85
_
39.1

For Labor
1971
-
-
-
-
-
_
-
-
-
_
-
9.B
-
-
11.9
12.56
-
12.7
12 B
18.4
14.2
11.6
14 5
11.4
-
19.2
18.2
15.3
_
17.2
13 64
_
17.9
1976
.
.
-
-
-
-
-
-
-
.
-
6.B
-
13.3
10.4
8.38
-
12.2
10.5
14.5
9 4
10.2
12.9
9.6
-
14.6
II 9
12.3
_
10 B
A. 82
_
13.1
Meat Sat.

1971
10,511
-
_
-
-
9.220
9.671
9.476
-
-
-
10.614
-
10.911
10.320
12.199
10.967
10.100
10.204
10.569
11.280
11.106
10.259
10.108
10,236
10.900
10.120
10.246
_
10.0)7
11.204
_
9,114
1976
9. BOB
.
-
-
-
9.489
10. 190
9.302
-
_
-
10.713
-
11.094
10.041
11.437
1O.393
10.401
10.329
10.193
10.556
10.745
10.053
10.251
10.122
10.600
10.106
10.346
_
9.963
10.628
_
9.639
Fuel
Ave. Coat/ton
1971
_
_
_
-
.
.
.
-
-
-
-
• $ 6.32
-
$ 8.02
$ 3.27
$ 8.46
$ 6.42
$ 3.94
$ 7.41
$ 5.59
$ 4.68
$ 8.32
$16.65
$ 7.58
$ 9.03
$ 6.38
$ 9.06
$ 7.16
_
$10.12
$ 7.61
_
$10. 06
1976
_
-
_
-
_
_
-
-
-
-
-
$19.99
-
$11.90
$15.04
$17.33
$13.29
$14.68
$16.29
$14.17
$11.78
$ 3.87
$13.80
$20.14
$23.98
$19.85
$21.96
$20 65
_
$23.40
$22.78
_
$23.81
Ave Coat/lo'Btu
1971
1
* 0.28
-
-
-
-
_
-
-
-
-
.
$ 0.30
.
$ 0.40
$ 0.27
$ 0.38
$ 0.10
$ 0.269
$ 0.342
$ 0.255
$ 0.26
$ 0.52
$ 0.27
$ 0.37
$ 0.4051
$ 0.32
$ 0.43
_
_
$ 0 44
$ 0.34
.
$ 0 59
1976 -
S 0.97
-
-
-
-
-
-
-
-
-
-
$ 1.04
-
$ 0.72
$ 0.7A
$ 0.59
$ 0.71
$ 0.675
S O.R06
$ 0.636
$ 0.37
$ 0.74
$ 0.61
$ 1.009
$ I.Q55
$ 0.95
$ 1.03
-
-
« 1.12
$ 1.03
-
$ 1.24
t 1 Hill Ion S.ven.ia
1
1971
-
-
-
-
-
-
-
-
-
-
-
14.7
-
14.8
13.7
11.7
17.1
18.0
16.0
17.0
14.6
17.10
22. B
16
-
22.1
16.6
19.0
-
17.4
21
-
17.1
1976
-
-
-
-
-
-
-
-
-
-
-
7.1
-
7.9
7.44
6.3
8.9
10.3
8.7
9.14
7.4
7.25
14.4
8
-
10.3
7.9
9.21
-
8.9
10
-
7.7
1976
Poor
Rat log
I
A- !
A
AA
-
BBB-
BBB
-
BBB
-
-
A
AA
AA
AA
A
BBB
At
AA
AA
AA
A
AA
A
A
BBB
BBB
A-
A-
BBB
AA
BBB
BBB
     NOTb: AJdlcloilal data and data AOurcva In Appendix E of tills report.

-------
environmental control equipment contribute to the yearly changes.  However,




fuel costs have risen consistently over the last six years.  In current dol-




lars, fuel costs in 1976 were generally three times what they were in 1971.




In 1971 dollars though, the percentage increases are less dramatic, growing




only between 25 percent and 128 percent over the six year period (Table 15).




     In addition, the average cost of fuel per million Btu rose for most util-




ities, although not uniformly as evidenced by the wide variation in percentage




increases, ranging from 42 percent to 246 percent.  Increases calculated in




terms of 1971 dollars were not as great, falling between 50 percent to 150 per-




cent for most utilities.  Two interesting exceptions should be noted.  In 1971




dollars, average costs per million Btu increases only 2 percent at Kentucky Util-




ities Company and 11 percent at Iowa-Illinois Gas and Electric Company; these




slight increases may be due to the existence of long-term fuel contracts.  Fur-




thermore, the 29 percent increase at Commonwealth Edison Co. was significantly




lower than the remaining utilities, probably as a result of the company's large




scale use of nuclear power.






                             Utility Ratings




     Underlying a utility's ability to maintain and expand its service is its




ability to attract new capital.  The money can be raised in essentially two



ways:  through the issuance of new stock or borrowing through the sale of bonds



or notes.  The ease with which the utility attracts the capital is highly de-



pendent on its previous performance.  The greater the risk is for the investor,




the more the money will cost the utility in dividends or interest payments.




     The Standard and Poor's Corporation has raced many of the utilities



in the ORBES states; this rating is a current assessment of the utility's
                                     70

-------
                                  TABLE 15
       PERCENTAGE INCREASES IN REAL FUEL COSTS:   AVERAGE COST PER TON
                      AMU AVERAGE COST PER MILLION BTU
State/
Company
Code
IL CEIL
COEC
ILPC
IOIG
UNEC
IN INPL
NO IP
PSIN
SOIG
KY KEUC
LOGE
OH CIGE
CLEI
COSO
DAPO
OHEC
TOEC
PA DULC
PHEC
APSI
Fuel:
1971
6.31
8.02
5.27
8.46
6.42
5.94
7.41
5.59
4.68
8.32
5.87
7.58
9.03
6.38
9.86
7.36
10.12
7.63
10.06
	
Average
1976
19.99
13.90
15.04
17.33
15.29
14.68
16.29
14.17
11.78
16.65
13.80
20.14
23.98
19.85
21.96
20.65
25.40
22.78
25.81
	
Cost per Ton
% Increase in
Real Costs
(1971-1976)
128
24
105
47
71
78
58
82
81
43
69
90
90
123
60
101
30
115
84
—
Fuel:
1971
0.30
0.40
0.27
0.38
0.30
0.27
0.34
0.26
0.26
0.52
0.27
0.37
0.41
0.32
0.43
—
0.44
0.34
0.59
0.28
Average
1976
1.04
0.72
0.78
0.59
0.71
0.68
0.81
0.66
0.57
0.74
0.63
1.00
1.06
0.95
1.03
—
1.12
1.03
1.24
0.97
Cost per 10 Btu
% Increase in
Real Costs
(1971-1976)
149
29
107
11
70
81
71
82
57
2
67
94
85
113
72
—
83
117
51
148
Percentage increase in real
  fuel costs (1971-1976)
Average Fuel Cost/Ton-1976
(Average Fuel Cost/Ton-1971
                                                                      X  100
                                (Implicit GOT Price Deflator-1976
                                (Implicit GNP Price Deflator-1971
                                            - 100
  where: implicit GNP price deflator-1976
         deflator-1971 = 96.0
        133.9 and implicit GNP price
This gives an indication of how much fuel costs rose in relation to prices of all
goods and services.  The real increase in average fuel cost/million Btu can be
calculated in a similar fashion.

     SOURCES:  Statistical Abstract of the United States-1978,  Table 783 "Gross
National Product, Implicit Price Deflators: 1960-1977" p. 483
               Additiona-1 data from Appendix E of this report
                                      71

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credit-worthiness.  The ratings range from AA to 3BB where:

     AA Bonds rated AA also qualify as high-quality  debt obligations.
     Capacity to  pay principal and interest is very  strong,  and  in
     the majority of instances they differ from AM  issues only  in
     small degree.

     .A Bonds rated A have a strong capacity to pay principal and
     interest although they are somewhat more susceptible to the
     adverse effects of changes in circumstances and economic
     conditions.

     BBS Bonds rated BBB are regarded as having adequate capacity
     to pay principal and interest.  Whereas they normally exhibit
     protection parameters, adverse economic conditions or changing
     circumstances are more likely to lead to a weakened capacity
     to pay principal and interest for bonds in this category than
     for bonds in the A category.

     BB, B, CCC,  CC Bonds rated BB, B, CCC, and CC are regarded, on
     balance as predominantly speculative with respect to the issuer's
     capacity to  pay interest and repay principal in accordance  with
     the terms of the obligation.  BB indicates the  lowest degree of
     speculation  and CC the highest degree of speculation.   While such
     bonds will likely have some quality and protective characteristics,
     these are outweighed by large uncertainties or  major risk exposures
     to adverse conditions.

     In the bond rating process,  subjective as well  as objective factors

are considered,2  Typically, a rating agency such as Standard and Poor's

would examine & number of criteria before assigning  a bond rating.   It would

conduct a general analysis of the company, including the revenues,  earnings,

and investment mix, the utility's service area, and  the quality of service.

It would also evaluate the size of the company's construction  program, relative

to its capitalization; the financial flexibility of  the company, and the cover-

age ratios.

     The regulatory climate in which the utility operates is  also an im-

portant, albeit difficult, part of the bond evaluation process.  The rating
     2This discussion is based on:  Marvin E. Ray, "A New Twist for the
Management Audit and Bond Ratings" in Public Utilities Fortnightly, 105 No.  2
Section 1,  (January 11, 1980) p.  34.
                                    72

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agency determines the likelihood of future rate increases by examining the




utility's future rate increase needs and past success in obtaining rate




relief in conjunction with the prevailing sentiments of the public utility




commission.  Based on these factors, estimates of the utility's probable




earnings and cash flow situation can be made.  These estimates are used




to evaluate the adequacy of the company's construction plans, debt ser-




vice requirements, financing plans, and capital structure objectives.




     Finally, the company management is evaluated.  Attention is given to




management's ability to meet the company's objectives, planning sophistication,




and credibility with the financial community, the public, the media,  and




the regulatory agencies.




     Thus the rating a utility receives is based on many factors.  As a




result, it is difficult to identify those which are most responsible for




the overall rating.  This is particularly true of the subjective criteria



such as the evaluation of the management and of the regulatory environment.




However, the record indicates that the utilities in the ORBES states were




highly rated in 1976 with two-thirds of them achieving an "A" category or




better, while the other one-third received a "BBB" rating.   Since 1976 many




of these ratings have been placed in jeopardy as a result of a number of




problems including the Three Mile Island accident, the lower than anticipated




demand for electricity and the increasing cost of capital.   Under these new




circumstances, the electric utility industry in the ORBES states will have




great difficulty in maintaining their traditionally high ratings.
                                    73

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                              CHAPTER VIII








               REGULATION IN THE ELECTRIC UTILITY INDUSTRY








                       Legal Basis for Regulation




     The electric utility industry is generally considered a natural monopoly,




because the expense of duplicating the generation, transmission and distribu-




tion systems would exceed the benefits of competition.  Therefore, since the




free market does not set the price of electricity, it has been agreed that the




government should regulate the private corporations which produce and transmit




electricity.




     Today, governmental regulation of the electrical generating industry




occurs at the federal, state, and local  level, and applies to virtually every




aspect of the business endeavor  from fuel purchasing to consumer billing.




Each exercise of regulatory control over electric utilities by a governmental




unit must be supported by some  recognized governmental power.  The sources




of these powers are determined by the federal structure of our government.




     The federal government may exercise only those powers which are enumerated




in the Constitution of the United States.  All other governmental powers




are retained by the individual state governments which may legislatively dele-



gate these powers to local levels of government or various administrative




agencies.



     The enumerated powers upon which federal regulation of electric utilities




is based include the power to regulate interstate commerce,1 to exercise
       .S. CONST.  Art. I i 8, C1.3
                                    74

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authority over federal enclaves,2 to dispose of and regulate all other proper-

ty belonging to the United States,3 to impose taxes and spend for the general

welfare,1* and to provide for national security.5  Of these powers, the power

to regulate interstate commerce is the source of most federal regulatory

authority over electric utilities.

    The fundamental source of state authority to regulate electric utilities

is the police power, which enables a state to regulate for protection of the

public health, safety, morals, and welfare.  This power is extremely broad and

limited  only by state or federal constitutional provisions.  The primary con-

straints upon the police power are ones of due process rather than substance.

In other words, state regulation of private activity to protect the public

health, safety, welfare or morals will not be restricted unless it can be

demonstrated that the activity is unrelated to the public interests, the means

of regulation are not reasonably related to protecting the public interest or

the regulation is arbitrary or unreasonable.  The public interest in electric

utility service is  clearly compelling, and thus  is the basis for  reasonable

state  regulation of this private activity.

     The  federal powers discussed above have resulted in many federal programs

which  regulate electric utilities directly, including the Federal Power Act,5
     2Id.  Art.  I  §  8,  cl.l

     3Id.  Art.  IV §  3,  cl.  2  the  distinction  between Article I  federal property
 (see note 2  above)  and  Article  IV federal  property  has  particular  significance
 with respect to the power of  states  to  regulate  private activity on  such land.
 Within  the ORBES  states, this issue  may not be as significant as in  western
 states  where there  are  large  federal holdings.   See,  M.  D.  White,  H.  J.  Barry
 III, Energy  Development in  the  West; Conflict and  Coordination of Governmental
 Decision Making;.  52 N.D.L.  REV. 451, 499 (1976).

      **U.S. CONST. Art.  I §  8  cl.  17
      S49  Stat.  838,  16  USC  §  791A  et  seq.  (1970)


                                     75

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and the Atomic Energy Act.7  Utilities and other businesses are also affected

by various environmental protection programs,8 the several antitrust  and

securities acts,9 and the various regulatory activities under the Department

of Energy.10  The most common format in which the state exercises authority

over electric utilities is through a legislative delegation of power to an

independent public utility commission (PUC).

     This discussion will focus upon  the federal regulatory authority over

utilities embodied in the Federal Power Act and the regulatory format of state

public utility commissions.


                           Federal Regulation
                    of the Electric Utility Industry

     The Department of Energy (DOE) consolidated all energy-related federal

regulatory efforts into two DOE agencies, the Federal Energy Regulatory Com-

mission  (FERC) and  the Economic Regulatory Administration (ERA).  These two

agencies carry out the bulk of federal regulation of electric utilities, reg-

ulation previously carried out by the Federal Power Commission.ll

     The source  of FERC and ERA  authority  to  regulate  electric utilities  is
      7Atomic Energy Act of 1954, Pub. L. 83-703  (as amended); 42  USC  2010  et.
seq.  (1970), especially I§ 2164, 2131

      aSee eg.:  Clean Air Act Pub. L. 91-604, as amended by  Publ.  L.  92-157,
Pub.  L. 93-15, Pub. L. 93-319, Pub. L. 95-95  (codified at 42 USC  5  7401  et seq.
1977  supc.)

      9See eg.:  Public Utility Holding Company Act of 1935,  15 USC §3  79-79Z
(1970); Securities Exchange Act 15 USC 78 et  seq. (1970)

    1QSee:  Department of Energy Organization Act, Pub. L. 95-91,  August 4,
1977; Department of Energy Fact Book, Organizations and Functions;  (September,
1977)

    ^This reallocation of regulatory authority is spelled out in  the  Depart-
ment  of Energy Organization Act, Pub. L. 95-91, August 2, 1977 (codified'at
various sections of titles 3, 57, 12, 15, 42  of USC)
                                     76

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                       12
 Che  Federal Power Act.   This  legislation  was  enacted  to  fill a gap in the

 regulation of  electric utilities.   This  gap  arose  from the so-called Attleboro

 decision, a Supreme Court  determination  that the "commerce clause" of the U.S.

 Constitution prevented state FUC's  from  regulating interstate sales or trans-
                                                                           13
 mission of electric energy, even  in the  absence of any federal regulation.

     The Federal Power Act is  composed of  two  major sections,  which are act-

 ually  two separate pieces  of legislation.  Part I  of the  Act  deals with the

 permitting and licensing of hydroelectric  facilities on the navigable waters

 of the U.S. and was originally the  Federal Water Power Act.   Fart  II dealing

 with the regulation of electric utility  companies  engaged in  interstate com-

 merce was enacted in 1935  as the  Public  Utility Holding Company  Act of 1935,

 an amendment of the Federal Water Power  Act.

     This discussion will  focus upon Part  II of the Federal Power  Act (herein-

 after the Act).  Under the current  interpretations  of  the Act,  federal author-

 ity to regulate the interstate aspects of  electric  utility companies  extends

 further than that necessary to fill the  regulatory  gap  created by  the Attleboro

 decision.  The reach of regulatory  authority of the Act is based upon court
                                                                     1<+
 construction of the language and  the legislative history  of the  act.
     12
       49 Stat. 868, 16 USC § 791 A et seq.   (1970)

     13
       Public Utilities Comm'n v. Attleboro Steam and Elec. Co., 273 U.S.
83 (1927)

     It
       See 2 Priest, Principles of Public Utility Regulation at 550: Federal
Power Comm'n v. Southern California Edison Co., 376 U.S. 205 (1964).  The issue
of federal or state jurisdiction over sales in interstate commerce has been
extensively litigated.  Although these issues are important to understanding
the respective state and federal authority, the legal distinctions between
jurisdiction based upon the commerce clause limitation on state authority and
the plenary authority granted by the language of the Act are too involved to
warrant discussion here.  (continued)
                                  77

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Essentially the Act grants the ETC  (now FERC or ERA) the authority to regulate

the transmission of electric energy in interstate commerce and the sale of
                                                    15
electric energy at wholesale in interstate commerce.   Generating facilities,

local distribution facilities, wholly intrastate transmission facilities, and
                                                                                16
transmitter consumed electricity are exempted from the reach of this authority.

     For those utilities which sell or purchase electric energy for resale in

interstate commerce, or transmit power in interstate commerce, which includes

the bulk of the large investor-owned utilities, the FERC exercises authority

very similar to the state PUC with respect to such interstate activity.  Thus,
                                   17                                  18
FERC reviews all rates and charges,   approves disposition of property,
                                              19
ensures the adequacy of interstate facilities,   specifies the forms of
                          20                                           21
accounts and depreciation,   and supervises the issuance of securities.
The question of what constitutes transmission or sale in interstate commerce
and hence triggers FERC jurisdiction has been extensively litigated for the
purposes of the Act.  Interstate electricity is defined as being transmitted
from a state and consumed at any point outside of that state.  Thus, a public
utility located entirely within a state with no connections with any out-of-
state system is not subject to FERC jurisdiction as operating facilities for
the transmission of electrical energy in interstate commerce, even though it is
connected with in-state utilities which, in turn, connect to out-of-state util-
ities and even though it is a member of a multi-state power pool.  Florida
Power and Light Co. v. FFC. 430 F2d 1337 (CAS 1969).

     15
       Federal Power Act § 201 (b), 16 USC i 824 (b)

     16
       II-
     17
       Id.  i  205, 16 USC 5 824 (d)

     13
       Id.  §  203  16 USC % 824 (c)

     19
       Id.  §  207  16 USC § 824 (b)

     20
       Id.  §  303  16 USC § 824 (g)

     21
       Id.  §  204  16 USC § 824 (f).  FERC authority to regulate the issuance of
securities by public utilities is limited only to those utilities which are not
subject to any state security review.  Presumably this would apply to W. Va.

                                     78

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     In addition FERC has authority to order utilities  subject  to  its  juris-

diction to establish physical connections of transmission facilities,  but  only

when the public interest is served by such connection and when  no  undue  hard-
                                                 22
ship or impairment of service capability results.   Additional  interconnection

powers under the Act have been delegated by the Secretary of  the DOE to  the
                                                          23
ERA; these include coordinating voluntary interconnections    and emergency
                 2i+
interconnections.   In addition, the ERA regulates the  international export  of
            25
electricity,   and reviews interlocking directorates between  public utilities
                                  26
and security-issuing institutions.

     The powers exercised by both FERC and ERA may be coordinated  with the

efforts of state PUC, but this coordination and consultation  is strictly
          27
voluntary.

                      State Regulatory Commissions

Background

     In most states in the United States and in all of  the ORBES states, the

power to regulate electric utilities has been legislatively delegated to

state-wide public utility commissions (PUC).  These administrative agencies

have fairly broad powers to regulate the operations of  electric utilities, but

only those powers which can be traced to the enabling legislation.  Therefore,

although the state may have the legal authority to regulate certain aspects of

a utilities operation, unless the state legislature has specifically delegated
     22
       IA. § 202 (b), 16 USC § 824A (b)

     23
       Id. i 202 (a), 16 USC § 824A (c)

     2*
       Id. 3 202 (c), (d), 16 USC § 824A (c), (d)

     25
       Id. i 202 (e), 16 USC i 324A (e)

     26
       Id_. 3 209, 16 USC § 825 (d)

     Z7ld. I 209, 16 USC f 824 (h)
                                    79

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this authority, the FUG is without that power.  This derivative characteristic

of PUC authority is especially important when implementing changes in the reg-

ulatory format.  PUC's authorities are very similar from state to state and

most often include the authority and duty to fix the rates for service, ensure

the adequacy of service, supervise the fiscal structure of the utility, certify

additions to capacity or service area, approve mergers, transfers, or consolida-

tions of utilities, supervise the issuance of equity securities and the acquisi-
                     28
tion of indebtedness,   give permission of abandonment of franchises, and in

general, supervise every aspect of a utility's operation.  The goal of this

supervision is to ensure that every utility:

          ...shall establish and maintain adequate and suitable facilities,
          safety appliances, and other suitable devices, and shall perform
          such service in respect thereto as shall be reasonable, safe, and
          sufficient for the security and convenience of the public...29

Although the language varies from state to state the essence is the same:

"adequate service at reasonable rates."

     The policy justification for such pervasive regulation arises from a

combination of the semi-monopolistic status of most utilities, the public in-

terest in the essential services supplied, and the preference for private

ownership and operation of utilities.  Thus, when essential public services

are to be provided by private interests in a relatively competition free mar-

ket, public regulation is necessary to protect the public's interest.30  A re-

sult of this perception is that "... regulatory commissions view  their
     28The West Virginia Public Service Commission  (PSC) is one of a handful of
state commissions that do not regulate the  issuance of utility securities, un-
der  the provisions of the Federal Power Act  i 204F, FERC will exercise such
authority where a state does not.

     2gW. VA.  CODE 24-3-1  (Michie 1976)

     30See:   I. Priest, Principles of Public Utility  Regulation,  a 4  (Michie
Co., 1969)
                                     80

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assignment as a mandate to do che job that competition would do if competition

were desirable or feasible in the markets for public utility service."31


Rate Regulation

     PUC regulation of the rates of utilities probably generates more public

attention and awareness than any other PUC activity.  This attention has in-

creased in recent years primarily due to the increased frequency of rate re-

lief requests by utilities of all sorts, and proposed modifications of tradi-

tional electric structures to serve various non-traditional goals.

     In most jurisdictions the legislative grant of authority to the PUC to

regulate rates is very broad.  The statutory restrictions on PUC discretion

in rate regulation are typically limited to requiring rates to be "just and

reasonable"32 and non-discriminatory.33  In Ohio, however, the legislature

has specified the procedures and determinations which the commission must fol-

low in fixing rates.3U  This legislative specification limits the discretion

of the Ohio PUC to use differing techniques for rate determination.  This

limitation may be insignificant as a practical matter because the Ohio legis-

lative mandates follow widely accepted practices for race determination.
     31H. P. Wald, "Recent Proposals for Redesigning Utility Rates," 92
Public Utilities Fortnightly.  (September 13, 1973) p. 27.

     32This standard is found in the PUC enabling legislation for each of che
ORBES states:  ILL. ANN. STAT. ch. Ill 2/3 I 32  (Smith Kurd); DiD. CODE ANN
§ 8-L-2-4 (Burns); KY REV. STAT. § 278.030; OHIO REV. CODE 5 4909.15; W. VA.
CODE a 24-2-3  (Michie 1976); PA. STAT. ANN. tit. 66 i 1141 (Purdon)

     33This standard is also uniformly expressed legislatively,  ILL. ANN. STAT.
ch. Ill  2/3 §  38  (Smith Hurd): INC. CODE ANN. §  8-1-2-106  (Burns); KY REV. STAT.
§ 278.170; OHIO REV. CODE  § 4905.33; W. VA. CODE § 24-3-2  (Michie, 1976); PA.
STAT. ANN. tit. 66 i 1143  (Purdon's)

     31lOHIO REV.  CODE 1§ 4909.15 et seq.  (Page  1977)
                                    81

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     The traditional approach to PUC rate setting  involves four basic deter-

minations:   (1) what utility property is used to provide  the  service, this

constituting the rate base  (2) what are the utility's operating expenses,  (3)

what rate of return should be applied to the rate  base to establish an adequate

return on investment, (4) what are the gross revenues from a  given rate struc-

ture.35

     Typically these data are derived by examining a test year of service and

then projecting this figure ahead to the period covered by the proposed rate

structure.  Operating expenses, plus the required  return on capital investments,

make up the gross revenue requirements that must be generated by a given rate.

     This rate structuring process is directed at  providing an opportunity for

a utility to generate enough revenue to make an adequate return on its invest-

ments and thereby attract new capital that may be  necessary to continue or ex-

pand its operations.  The treatment of operating expenses, the manner of valu-

ing property used in the rate base, the determination of an appropriate ratio

between debt and equity capitalization,  and the company's accounting practices

all become crucial issues in making a rate determination, and all have been

excessively litigated.   A detailed discussion of these issues is beyond the

scope of this report.36
     35See:  I. Priest, Principles, ac 45


     36Several of these fairly esoteric issues may be of particular significance
to ORBES efforts and warrant more detailed examination.  PUC treatment of con-
struction work in progress (CWIP) is particularly significant with respect to
the issue of capital acquisition for major capacity expansions.  Traditionally,
only that utility property used to supply service could be part of the rate
base to compute revenue requirements.  Projects under construction were ex-
cluded from the rate base resulting in greater capital requirements for ex-
pansion.  Some PUCs now allow CWIP in the rate base, thus, in effect having
present consumers finance future capacity.
                                    82

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                          Rate Structure Reform




     A common feature of the most prevalent rate reform proposals is that they




seek to expand the type and nature of the considerations the utility and the




PUC make with respect to rate structures.  This expanded scope focuses upon




issues of conservation and social welfare.  The conservation type proposals




include peak load pricing rate structures, elimination of promotional or de-




clining block rates, seasonal rates, and interruptible service rates.  The




social welfare approach to rate reform is typified by life-line rates which




would provide a minimal amount of service to low income persons at a reduced




rate.




     It should be noted that these proposals for rate reform focus upon rate




structure not rate level.  Traditionally the structure of the rates between




classes and types of customers has been left to the individual utility's dis-




cretion to a larger extent than overall rate levels.37  Thus as these types




of proposals are implemented through governmental policy, a new field of reg-




ulatory standards will be opened up.  In addition to the standards of adequate




service at reasonable rates, FUC review of rate-making may expand to consider




conservation standards of promoting efficient use of energy, and standards for




implementing social welfare goals.




     There is a level of tension between the conservation and social welfare




approach to rate reform and the traditional legal standards applied to rate




structuring.  This tension is most evident between life-line rates and the




standard prohibiting undue discrimination among customers.  In granting lower




rates to certain classes of customers based upon their economic status and




not upon any differentials relating to the service supplied, the issue of
     37I. Priest at 342-343.
                                     83

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discrimination is raised.  Although it may be argued that such discrimination

is reasonable, some courts have held that, because of the prohibition on dis-

crimination, a strict interpretation of PUC authority requires legislation  if

life-line rates are to be implemented.38

     Similar tensions occur between eliminating promotional rates and the

cost-of-service standard, although these are more readily resolved due to the

shift occuring in economies of scale in the electric utility industry.39

     This expanded scope of regulatory review will require a more sophisticated

method of balancing these diverse objectives in rate structuring, and a substan-

tial increase in PUC staff if the agency is to keep on top of its workload.

     Legislation currently pending in the U.S. Congress, if passed, would re-

quire state PUC's to consider implementing the types of rate reforms mentioned

above.^  Given the tentative nature of the national energy policy it is pre-

mature to report upon the precise configuration of such legislation.  However,

it is fairly safe to say that the scope of regulatory concern with the structure

and allocation of rates will expand greatly in the near future, both in issues

covered and in level of conflict among the objectives of the rates.1*1

     Two other questions have arisen as a result of the increasing dependency

of municipal utilities on power purchased from investor-owned utilities.  Both
     38See eg.:  RE:  Rate Concessions to Poor Persons and Senior Citizens, 14
PUR 4th 87 (Ore. PSC), Moore v. Gilbert 131 Vt. 545, 310 A 2d 27 (1973); Penn-
sylvania Public Utility Commission v. Philadelphia Electric Co. 91 PUR 3d 321
(PA. 1971).  RE:  Louisville Transit Co. 82 3d 1, (KY 1969)

     39See:  West Virginia Public Service Commission, "Systems and Polices for
the Pricing of Electrical Power in West Virginia."   (December 31, 1975), p. 5

     40See:  D. Reed, "Utility Rates Under the National Energy Act; Quo Vadis?"
Public Utilities Fortnightly.  102 (July 20, 1978) p. 11

     ltLId. at 15.
                                    84

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are related to the pricing structure which governs the cost of the wholesale

power purchased by the municipals.  The first involves the problems of "pancak-

ing" which arises when the investor-owned utilities are granted successive

temporary rate increases before final action on earlier requests is completed.

     The second area of conflict involves what is known as a "price squeeze."

Municipal utilities contend that their customers must pay more than the custo-

mers or areas served by the investor-owned utility for comparable service, even

when the municipal utility purchases the power at wholesale rates.


                     Adequacy of Service Regulations

     In addition to the regulations of rates, FUC's have a duty to insure that

the utility provides adequate service.  This duty is carried out in several

ways.  The most prevalent technique for electric utilities to extend or enlarge

services is to obtain a certificate of convenience and necessity from the PUC.

This certificate typically authorizes the utility to provide service in a des-

ignated geographic area, and ensures that the utility will not be subject to

direct competition by another utility offering the same service.42  In exchange

for this authorization, the utility is under a duty to provide service in that

area until the PUC orders otherwise.  This duty to provide service has been

construed by many courts and in statutory language to include a duty to antici-

pate and provide for reasonable extension of facilities to meet probable future

demand.  A number of courts have held that this expansion of service obligation

is not limited by considerations of immediate profit to the utility.1*3
     u2See:  ILL. ANN. STAT. ch. Ill 2/3 i 56 (Smith-Hurd);  IND CODE ANN § 8-1
2-5 (Burns); KY REV. STAT. § 278.025; OHIO REV.  CODE § 4906.10 et seg. (Page);
W. VA. CODE 3 24-2-11 (Michie 1976); PA. STAT. ANN. tit. 66 § 1122 (Purdon).


     lt3See:  I. Priest,  Principles, p.  232.
                                    85

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     In the electric utility industry, the issue of the service obligation has




not been of great significance in the past, as most utilitites were eager to ex-




pand their capacity both to realize the economies of scale possible with a larger




capacity, and to increase their rate base and ensure continued growth.  However,




as the economics of increased capacity shift with the higher costs of additional




capacity, and the difficulty in obtaining suitable sites for generating facili-




ties, the legal issues of the service obligation may become increasingly signi-




cant.
                                     36

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                                  CHAPTER IX




                                  CONCLUSION






     Electricity is considered a necessity in the United States today.  The




electric utility industry is mandated to provide sufficient electric power




to meet both present and future needs.  Meeting future needs requires that




the utilities anticipate the extent of these demands and insure that facili-




ties are available to meet these needs.  Thus the electric utility industry




is a major force controlling the growth of electric conversion facilities in




the six-states of the ORBES region.  For this reason, understanding the basic




functions of the industry is essential to ORBES as a whole.  This report cov-




ered many of the important components:  institutions, technology, governmental




regulations and financial affairs.  All of these provide insight into the op-




eration of the electric utility industry.
                                     87

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APPENDIX A




 GLOSSARY
   38

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A    -  A statewide association of rural electric  cooperatives




AEPS ~  American Electric Power  Systems




AIEC ~  Association of  Illinois Cooperatives




ALEC ~  Allegheny  Electric  Cooperative, Inc.




APPC ~  Appalachian Power Co.




APS I ~  Allegheny  Power Systems




BTRI ~  Big  Rivers Electric Corp.




BOP I ~  Buckeye Power Inc.




CAPCO~  Central Area Power  Coordinating Group




CECO ~  Citizen's  Electric  Corporation, Ste. Genevieve,  Mo.




CEIL ~  Central Illinois Light Co.




CEIP ~  Central Illinois Public Service Co.




CFC  ~  National Rural  Utilities  Cooperative Finance  Corporation




CIGE -  Cincinnati Gas  & Electric Co.




CLEI ~  Cleveland  Electric  Illuminating Co.




COEC ~  Commonwealth Edison Co.




COSO ~  Columbus & Southern Ohio  Electric  Co.




•Q    -  Distribution Utility or Cooperative




DAPO ~  Dayton Power &  Light Co.




DULC ~  Duquesne Light  Co.




DLPC ~  Dairyland  Power Cooperative, LaCrosse,  Wi.




EAKR ~  East Kentucky Power Coop.




ECAR ~  East Central Area Reliability  Coordination Agreement




F    -  Federally-owned power agency




FERC "  Federal Energy  Regulatory Commission




G    -  Generation and  transmission Utility or  Cooperative




GPU  -  General Public  Utilities  Co.
                                     89

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HEDI  ~   Hoosier  Energy Division,  Indiana Statewide Rural Electric Corp.




ICC   ~   Illinois Commerce  Commission




ILPC  -   Illinois Power Co.



IMP   -   Illinois-Missouri  Pool




INME  -   Indiana  & Michigan Electric Co.




INPL  ~   Indianapolis Power & Light Co,




IPSC  -   Indiana  Public Service  Commission




ISCC  -   Iowa State Commerce Commission




JECP  -   Jersey Central Power & Light Co.



      -   Kentucky Association of Electric Cooperatives




      -   Kentucky Power Co.




KEUC  -   Kentucky Utilities Co.




KPSC  -   Kentucky Public Service Commission




LOGE  ~   Louisville Gas & Electric Co.




M    -   Municipal Utility




      -   Mid-Atlantic Area  Council



      -   Mid America Interpool Network




MARCA -   Mid-Continent Area Reliability Coordination. Agreement




MEEC  ~   Metropolitan Edison Co.




MOPC  ~   Monongahela Power  Co.



jjpSC  ~   Michigan Public Service Commission




MoPSC ~   Missouri Public Service Commission



 NRECA ~   National Rural Electric Cooperative Association




 NOIP  ~   Northern Indiana Public Service Co.




 OHEC  ~   Ohio Edison Co.



 OHPC  ~   Ohio Power Co.



 OHVE  -   Ohio Valley Electric Corp.



 OREC  ~   Ohio Rural Electric Cooperative, Inc.






                                     90

-------
PEEC -  Pennsylvania Electric Co.




PEPL -  Pennsylvania Power & Light Co.




PHEC -  Philadelphia Electric Co.




PJM  -  PJM Interconnection




POAS -  Power Authority of the State of New York




POEC -  Potomac Edison Co.




PPUC -  Pennsylvania Public Utilities Commission




PSIN -  Public Service Company of Indiana, Inc.




PSCM -  Public Service Commission of Maryland




PUC  -  Public Utility Commission




PUCO -  Public Utilities  Commission of Ohio




R    -  Regional Utility




S    -  State owned power agency




SEC  -  Securities and Exchange Commission




SEPA -  Southeastern Power Administration




SOIG -  Southern Indiana  Gas & Electric Company




SOIP -  Southern Illinois Power Co-operative




SOYP -  Soyland Power Cooperative




SPFL -  Springfield, City Water, Light & Power




TELE -  T. C. Lewis  (Industrial/Manufacturing firm)




TEVA -  Tennessee Valley  Authority




TOEC -  Toledo Edison Co.




TPSC -  Tennessee Public  Service Commission




UNEC -  Union Electric Co.




VSCC -  Virginia State Corporation Commission Division of  Public  Utilities




WEIL -  Western Illinois  Power Cooperatives, Inc.
                                    91

-------
WEPP   -  West Penn Power Co.



WVPA   -  Wabash Valley Power Association



WVPSC  -  West Virginia Public Service Commission
                                   92

-------
                    APPENDIX B




INVESTOR-OWED UTILITIES IN THE SIX ORBES STATES
                       93

-------
VTILITT
CODE

csa
ass
CQEC
CUE
ILK
fflPO
1016
SHPS
SOBW
DHEC

CEO
am
IKME
nw.
MI?
PS IS
sou

KEPC
KEDC
LOGE
OHLH
|I
rumors
Central Illinois Light Co.
CeatTBl ULinois Public
Service Co.
Coaaonwealth Eaiaoa Co.
Electric Energy Inc.
Ullaol* Power Co.
Interstate Power Co.
lova-Illlaola Gas i Electric
Co.
Sherrard Power System
South Belolt Uatar, Gae &
Electric Co.
Union Electric Co.
BPIAHfc
Coenonwealth Ed loon of
lad Una
Indiana-Kentucky Electric
Corp.
Indiana-Michigan Electric
Co.
Indianapolis Pou«r 4 Light
Co.
northern Indiana Public
Service Co.
Public Service drapany of
ladlau. Inc.
Seutlwm ladlxaa
Gaa i Electric Co.
KM mm
Kancucky Power Co.
Eancuclcy Utllltlea Co.
Louisville Gaa « Electric
Co.
Union Light, Heat, 4 Power
Co.
|

Feoria, 111.
Sptiojileld. UL
Chicago . Ul.
Joppa. Ul.
Oacaeut. Ul.
Oubuque , Iowa
Davenport, Iowa
Orion. 111.
Rockton, 111.
St. Louis, Mo.

UHtini. Ind.
HadlBon. bid.
rt. Wayne, Ind.
Indlanaoolla.
Ind.
Baaaood, lad.
PlainCleld, Ind.
Evtnsvllla, Ind

Aahland, lj.
Lexington, Cy.
Loulavllle. Cy.
Cincinnati, Oh.
||
••8




ILPC
KEVC
CEIP
J QREC







COEC
OHVE
ASS





AZFS


CIGI
M


OS


IMF




IMP













RELIABILITY!
COUNCIL I

HUH
WLCt
was

MAIN
tURCA
XARCA


MAIN


ECAR
ECA&
ECAR
SCAR
ECAR
VM

ECAR
ECAR
ECAR

a




Owned Jointly by Illinois Power Co
(201) , Kentucky Utilities (2015 ,
Central Illinois Public Service Co
(201) and Union Electric Co. («OX)
to operate Joppa atatlon to supply
power to the O.S. Department of
Snergy'a Paducaa. Ky. fuel enrich-
ment plant



Hoc-generating utility; distri-
butes power purchased fron lowa-
Illlaola Gas & Electric 

Owna three subsidiaries which do
not operace la the OKfiES States:
Missouri Fever & Light. Missouri
Edison Co., and Missouri Utilltie:
Co.

•holly owned subsidiary of Cofaoo'
wealth Edison Co. (COEC) to oper-
ate the State Line plant. Power
from Steee Line aold co COEC  Electric Co. for
sale in Kentucky

-------
3003
urn in

am
OSi
oei
coso
DAW
MPC
OOEC
OHEL
OHFC
oavc
TOEC

con
DOLE
SERC
ffiEC
?mc
PZJC
PEPL
P8EC
PHES
SATO
sosq
DCIC
WEFF
Eg
•j a
• M as
OBIO
Cardinal Operating Co.
Cincinnati Gas I Elaccrlc
Co.
Cleveland Electric illumliut-
lag Co.
Coliabua t Southern
Ohio Electric Co.
Dayton Power * Light Co.
Sloni Power Corp.
Ohio Edison Co.
Ohio Electric CD.
Ohio Power Co.
Ohio Valley Electric
Corp.
Toledo Edison Co.
PENNSYLVANIA
Cooowlago Pover Co.
' Duquesne Light Ca.
Berihey Eltecrlc Co.
Metropolitan Ulaon Co.
Pennsylvania Electric Co.
Jenm^lvaaia ?OW«T Co.
?«nnffylv«nia ?OH«T & light
Philadelphia Ueuilc Co.
Philadelphia Electric Power
Co.
Safe Barber Uacet Pouer
Corp.
Susquchamu Electric Ca.
United CM laprevaenc Corp
West P«nn Power Co.
i
H

trill tint. Ohio
Cincinnati, Ohio
Cleveland, Ohio
Coluofaua. Ohio
Dayton, Ohio
Hlaai. Ohio
Akron, Ohio

Canton, Ohio
Piketon, Ohio
Toledo, Ohio

Philadelphia, Pa
Pittsburgh, Pa-
AUeneoira, Pa.
Reading, Pa.
Johnston, Pa.
Hew Cutla, Pa.
Alleatovn, Pa.
Philadelphia, Zj
Phllodelpaia.PB
Uncaacer
County, Pa.
Philadelphia fa
Philadelphia ft
aiMoaburg, Pa.
||

BtJPI
OHPC




C1CS
-
OHPC
AEPS



PHEC

PZFL
CPU
CPU
CB£C


PHEC

PHEC

APSI
H



UFCO



CAPCO



CA7CO


CAPCO

PJX
PJM
CAPCO
PJM
PJM



PJM

RELlADILin
COUNCIL


ECAB
ECAR
ecu
ECAR

ECAR

ECAR
ECAR
ECAR


ECAR

NAAC
MAAC
ECA&
MAAC
HAAC



MAAC
ECAR
a

Jointly otmed by Che cooperative ,
Buckeye Power Inc. (JOZ) and Ohio
POUBT Co. (SOt); operates Cardi-
nal generating plant.




Hon-generacing Coapanf

Operttet the Gavin Stem Plane
for Ohio Power Co.

Ovned Jointly by Li investor
ovned utilities and oaoaged by
AEPS; organized to aupply power
to U.S. department of Energy's
Portsmouth Ohio gaseous diffusior
cooplex.


lacerperated la the State at
Maryland co develop and operate
Che Cotwwtngo Hydro-electric pro-
ject. Bar ford County, Md.

Non-generating utility
Operates fork Haven Pover Co., >
voelly-ovned aubaldlary
Operates Uaverly Electric Light
» Power Co., e vhaUy-omed Job-.
sidlary.



Organlxed to develop and operate
the Conovlngo hydroelectric pro-
ject with its subsidiary the
Susquehanns Power Co.
SOI of voting stock held by
Pennsylvania Power S Light Co.



95

-------
UTILITY
CODE
AFFC
SE3P
CMC
CV70
MOK
POEC
?IEP
UEEC
£9
• 3 1
WEST 7taGCTIA
Appalachian Proer Co,
Bench Bottom Power Co.
Central Operating Station
Kanavha Valley Povir Co.
Monoogahela Power Co.
Potomac Edlian Co.
Tlrjlflla Electric Power
Co.
Wheeling Electric Co.
|
Boanoke, To.
Wlndacu, W.7».
Etc* Haven, tf.Ta
Cuuutu Uvcr
TiUar. W. 74.
TalEoooc. V. ^
Oigaricom. Mi.
Xlchrad. Vi.
Uhaeling. V.Va.
P
21
ABPS
OHEC
WEFP
APPC
OBK
AFK
ATSI
APS1

ACTS
u







£u
d5
^i
a8
ECU.


ECAR
ECAB


I
Jointly o«Q«d by Ohio ?an*i Co.
(SOX) ud Vest Peon Power Co.
(SOX); organized ED op«MH Wind-
sor Pover Scaclaai will apttiie
Beech Boteoa Seatioo
Jointly owned by Appalachian
Fovcr Co. ud Ohio Paver Co. to
operate PblUp Spam plane.
Owaa and operacaa chree hydro*
•lactrlc power plaota located no
fovcrtnecc owned land.



Son-seneratlng ticilley
            : Steven D. Jaaaen, gleetrleal Generating gnit Inventory. Prepared for the Ohio liver 3«»l.n
Energy Study (Eteveober, 1978)

     Annual Report. 1977 fraa the Individual conpaalea

     Hoody'i Investor Service*. iteodT'i Public gtlitty tanual. 1976 (Hen York. 1977)
     SOTES: To prevent aultlple entries, a utility la llatad only under the itatt where It nalntalna Us eorparata
headquarters.  Santa utllltlaa. however, operate In several itatee.  Utilities operating in the sl*-«cate region,
but having corporate office* outside the area, ire listed la tne first itace (alphabetically) "here It Is Licensed
eo operate.  The location of the utility la determine by the location of the corporate headquarters as well.
Subsidiaries and other coopanla* set up :o operate a tingle station are located « the (Its of that station.
                                                     96

-------
                   APPENDIX C
PUBLICLY-OWED UTILITIES IN THE SIX ORBES STATES
                     97

-------
UTILITT
CODE^



CAB1
caso

FKLP

GEMU

HIGH
MCPD


PERU
PMIL
RVLP
Roa


SPFL

snu
own.
WISK



BL07



CHAW


FRAF



£ l
i1
ILLINOIS
Batavia, City of
Cairo Public Utility Commission
Carlyle Municipal Utility
Chicago Metropolitan Sanitary
District
Fairfield Municipal Electric
Light Department
Geneseo Municipal Utility
Geneva Municipal Electric Dept.
ighland Light & Power Dept.
Maacoutah Municpal Light & Water
Dept.
Naperville Light Dept.
Peru Light Departaent
Princeton Water & Light Dept.
Rantoul, Village of
Rochelle Electric Department
Rock Falls Electric Departaent
St. Charles, City of
Springfield City Water, Lighc &
Power*
Sullivan Electric Departaent
University of Illinois
Winnetka Electric Department
INDIANA
Anderson Municipal Light & Power
huburn Electric & Water Dept.
Bluffton Municipal Light & Water
Works
:olumbia City Municipal Electric
Department
:ravfordsville Electric Light &
Power
Edinburgh Water & Light Dept.
'rankfort City Light & Power
Jreendale Utilities
luntingburg Municipal Light 4
Water Plant
I3
a
s

Batavia, IL
Cairo, n,
Carlyle, IL
Chicago, IL

Fairfield, IL

Geneseo, IL
Geneva, IL
Highland, IL
Mascoutah, IL

Naperville, IL
Peru, IL
Princeton, IL
Etantoul, IL
Rochelle, IL
Rock Falls, IL
St. Charles, IL
Springfield, IL

Sullivan, IL
Urbana, IL
Wianetka, IL

Anderson, IN
Auburn, IS
Bluffton. IN

Colunbla City, IN

Crawfordsville. IN

Edinburgh, IN
Frankfort, IN
Greendale, IN
Huntingburg, It)

OWNERSHIP
•F

M
M
M
R

M

M
M
M
M

M
M
M
M
M
M
M
M

M

M

M
M
M

M

M

M
M
M
M

FUNCTION I
Ln 1

D
D
G
G

G

G
D
G
G

D
D
G
G
G
D
D
G

G
G
G

0
D
G

D

G

D
G
D
D

98

-------
UTILITY
CODE

JMS

LOSP

PERI
RICI











HEND







OWEN



TEVA

CZTV




H
3
INDIANA (eont.)
Jasper Municipal Utilities
Lebanon Utilities
Logaasport Municipal Utilities
Misbavaka Municipal Utilities
Peru Utilities
Richmond Power & Light7
Tell City Electric Department
Tlpton Municipal Electric Dept.
Washington City tight & Power
KENTUCKY
Benton Electric Plant 3d.
Bowling Green Municipal Utilities
Frankfort Electric & Hater Plant
Bd.
Franklin Electric Plant Bd.
Fulton Electric System
Glasgow Electric Plant 3d.
Henderson Man. Power & Light7
Kopkinsville Electric Plant 3d.
Madisonvllle Mun. Light & Water
Kayfleld Electric & Vater Systems
fonticello Electric Plane Bd.
Murray Electric System
Nlcholasvllle Municipal Light &
Hater Division
Cvensboro Municipal Utilities7
Paducah Electric Plant 3d.
Princeton Electric Plant Bd.
Etussellville Electric Plant Bd.
Tennessee Valley Authority

U.S. Department of the Army,
Corps of Engineers



§
§

Jasper, IN
Lebanon, IN
Logansport, IN
Mishavaka, IN
Peru, IN
Richmond, IN
tell City, IN
Tlpton, IN
Washington, IN

Benton, KY
Bowling Green, KY
Frankfort, KY

Franklin, KY
Fulton, KY
Glasgow, KY
Henderson, KY
Hopkinsvllle, KY
Madisonvllle , KY
Mayfield, KY
Monticello, KY
Hurray, KY
Hicholasville, KY

Cvensboro , KY
Paducah, KY
Princeton, KY
Russellvllle, KY
Paducah, 7Y
Central City, KY
Barkley Dam & Lake Project

Dale Hollow Lake Project
Wolf Creek Dam & Lake
Cumberland Project
OWNERSHIP

H
M
M
M
M
K
M
M
M

M
H
M

M
H
M
M
H
M
M
H
M
M

M
H
M
M
F

F

F
F

FUNCTION

G
D
G
D
C
G
D
D
D
.
D8
D*
D

D
D8
D8
C'
Oa
D
0
oa
DS
D

G'
»3
08
Da
Bu>

Gil

c"
G"

99

-------
UTILITY
CODE




CLOT
COLD

DOVE

HAMI

LZOH




ORRV
PAD?
PIQU
SMML
SHBY






UdfciU



KM
M Z
s*
OHIO
Bowling Green 84. of Public
Affairs
Bryan Light & Water Works
Celina Municipal Utilities
Cleveland, Division of Light &
Power?
lolumbua , Division of Electricity
Cuyahoga Falls Electric System
Dover Municipal Light & Power
Department
Gallotf, Department of Utilities
lamllton Department of Public
Utilities7
Hudson Light &. Power
Lebanon Division of Electricity
Montpelier Municipal Utilities
Napoleon Utility Board
tiles Water & Light
Oberlin Municipal Light & Power
frrville Municipal Utilities
Gainesville Electric Power Dept.
'iqua Municipal Power System
>C. Marys Municipal Light & Water
Shelby Department of Utilities
fodsvorth Light & Power Dept.
fcpakonetta. Municipal Light Dept.
Wellington Bd..of Public Affairs
festervllle Light Department
fellow Springs Light & Power
PamSTLVAHIA
!hanbersburg Municipal Electric
Light Dept.
Illwood City Municipal Electric
Department
iphrata Light & Power Department
Irove City Municipal Electric Co.
I
E«

Bowling Green, OH
Bryan, OH
Celina, OH
Cleveland, OH
Columbus, OB
Cuyahoga Falls, OH
Dover , OH
Gallon, OH
Hamilton, OH
Hudson, OH
Lebanon, OH
Montpeller, OH
Napoleon, OH
Niles. OH
Oberlin, OH
Orrville, OH
Painesville, OH
Plqua, OH
St. Marys, OH
Shelby, OH
Wadsworth, OH
Uapakonetta, OB
Wellington, OH
Westerville, OH
Yellow Springs, OH

Chamber s burg, PA
Ellwood City, PA
Ephrata, PA
Grove City, PA
OWNERSHIP

M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M
M

M
»
M
M
FUNCTION

D
G
G
G
G
D
G

G
D
C
D
D
D
G
C
G
G
G
G
D
D
D
D
D

G
D
D
D
100

-------
UTILITY
CODE









£a
I1
PENHSYL7AHIA(cont.)
Kutztown Municipal Light & Power
Laosdale Municipal Power Plane
Lebighun Light & Power Dept.
Perkasie Borough Electric Light
Department
Quakertown Municipal Electric
Department
Schuylkill Haven Borough Util.
WEST VIRGINIA
None
§
»4

Kutztown, PA
Lansdale, PA
Lehighton, PA
Perkasie, PA
Quaker town, PA
Schuylkill Haven, PA


a,
M
X

M
M
M
M
M
M


FUNCTION

D
D
D
D
D
0


     SOURCES: American Public Power Association, Public Power 37 (January-
February 1979) 41-91

     Steven 0. Janaen, Electrical Generating Unit Inventory. Prepared for the Ohio
River Basin Energy Study (November, 1978)
      Because of the large number of municipal utilities in the six states, only those
municipals with gross annual revenues in excess of $1 million axe included.

      Company code identify those public utilities and power agencies listed In Che
Electrical Generating Unit Inventory.

      The site of the municipal utilities is assumed to be within the corporate limits
of the community.  Federal power agencies are located at the site or sites of the
associated generating units.
     4
      Each publicly-owned utility or power agency is described by one of chree
catagories: municipal (M), regional  (R), and federal (F).

      Identifies whether utility functions as a generation and transmission operation (G)
or as a distribution operation (D).

     Sfember of Mid-America Interpool Network (MAIN).
      Liaison member of East Central Area Reliability Council (ECAR).

      Systems which.purchase power from the Tennessee Valley Authority.

     ^Municipal wholesaler, which is defined as a publicly-owned utility vhose revenues
3
from sales for resale are 51 percent or more of the total electric operating revenue.

      Member of Southeastern Electric Reliability Council (SERC).

      All power generated at these sites Is marketed by the U.S. Department of the Interior,
Southeastern Power Administration.
                                          101

-------
          APPENDIX D

RURAL ELECTRIC COOPERATIVES
   IN THE SIX ORBES STATES
             102

-------
!.•
u r
I
niHOIS
Adams Electrical Co-
operative
da? Clietile Co-
operative, Inc.
Clinton Come? Slectrlc
Cooperative, be.
Colei-MoultTla Electric
Cooperative
Can laic Electric
Cooperative, Inc.
Eaacern Illinola Power
Cooperative
Edgar Electric Co-
operative Aae.
Egyptian Electric
Cooperative AM.
Farmers Mutual Electric
Coapany
Illlnl Electric Co-
operative
Illinois Rural Electric
Co.
Illinois 7alley Electric
Cooperative
Jo-Carrall Electric
Cooperative
Meflonough Power Co-
operative
K.J.Jf. Electric Co-
operative
Jtooard Electric Co-
operative
Monroe County Electric
Co-Operatlve
Horria Electric Co-
operative
bital Electric Conven-
ience Cooperative Co.
Shelby Electric Co-
operative
Southeastern' Illinois
Electric Cooperative
Southern Elllaola Elec-
tric Cooperative
SOIP — Southern Illinois
?ower Co-operative
Southwestern Electric
Cooperative
SOTP — Soylaod fewer
Cooperative
Spoon liver Electric
Co-Operative
V
E

Cap Point. 111.
Flora. 111.
Bracae, 111.
Hat toco. 111.
Bloomlagton, 111.
Faxtea. 111.
Parla. 111.
Steelavllla. 111.
Ceneaeo, 111.
Chanpaign, 111.
Winchester, 111.
Princeton, 111.
Elisabeth, 111.
MaCaab, 111.
Cirllavllle. 111.
Fetertburg, 111.
Waterloo, 111.
Newton, 111.
Auburn. 111.
Soelbyvllla, 111.
Eldorado, 111.
Doogola, I1L
Marlon. 111.
Greenville, IlL
Champaign, 111.
Caotoa, 111.
a3

D
0
D
D
D
0
0
D
D
D
D
D
D
D
D
D
D
D
D
D
D
0
G
D
C
D
S
s
5

BRECA, AIEC
CFC
HRECA, AIEC
crc
mECA, AIEC
CFC
SBECX. AIEC
crc
HRECA, AIEC
CFC
JfRECA, AIEC
CFC
HRECA, AIEC
CFC
HRSCA, AIEC
CFC
' NKECA. AIEC
C7C
HKECA, AIEC
CFC
HRECA. AIEC
CFC
HBECA. AIEC
crc
HRECA, AIEC
CFC
NRECA, AIEC
ere
NRECA, AIEC
CFC
NRECA, AIEC
CTC
NRECA, AIEC
CTC
NRECA, AIEC
CFC
XRECA. AIEC
CFC
NRECA, AIEC
CFC
NRECA, AIEC
CTC
HRECA. AIEC
CFC
HRECA, CFC.
AIEC, MAIS3
REECA, AIEC
CFC
NRECA. CFC
AIEC. wa.tr
HRECA. AIEC
CFC
WHOLESALE POWEH
SUPPLIERS^ 1

VEIL
SOTP
SOTP
SOY?
SOTP
SOTP
SOT?
SOIP
CECO
SOTP
SOTP
WEIL
SOTT
DLPC
SOTT
VEIL
WEIL
SOTP
CEIP
VEIL
SOTP
SOIP
SOIP

SOTP
VEIL
!























Supplies power to three
rural cooperatives.

Owns 10.51 of planned
Clinton 1 4 2, with ILPC
and VEIL.
103

-------
B
p
P-'jTfJlS (cone.)
Tri-County Electric
Cooperative
"•yne-White Coracle*
Electric Cooperative
Western Illinois Blee-
trical Cooperative
VEIL — Western Ulinoie
Power Cooperative
Association of Illinol*
Electric Co-ops
IHDIAHA
Bartholomew County
Run! Electric
Membership Corp.
Boon* County Rural
Electric Membership
Carp.
Carroll Councr Rural
Bleeerte Hemberahlp
Carp.
Clark County Electric
Membership Corp.
Daviaas-Mjrtin County
Rural Electric Hea-
barablp
Dcucur County ftunl
Electric Membership
Corp.
Dubela Rural Electric
Cooperative, lac
Fayetra Union County
Rural Electric Meober-
ihlp Corp.
Pulton County Sural
Electric Membership
Cotp.
asncock. County Rural
Electric Meaberahlp
Carp.
Barrison County Rural
Zleccrlc Menbership
Corp.
Bendrlcka County Sturel
Electric Xemberahlp
Corp.
Henry County Rural
Electric Hcnberehip
Corp.
BEDI — Booiler Enersy
Dlvlalon. Indlaoa State-
vide Rural Electric Corp.
Jackson County Bural
Electric Menbership
Corp.
§
H
Kt. Verooa, 111,
FtlrfUU, 111.
Carthage, til.
Jacksonville, 111.
Springlleld, 111.

Coluobuif lad.
l*baaoo, Ind.
Delphi, tad.
ScUenburg, Ind.
tfaahlagton, Ind.
Crvanaburg. lad .
Jaeper, lad.
Liberty, Ind.
Socbefter. Ind.
Greenfield, lad.
Corydofl, Ind.
Denvllle, Ind.
Hew Caetle, Ind.
aiooalngton, Ind.
Browne town, Ind.
£
D
D
D
C
k

D
0
D
D
D
D
D
D
D
D
D
D
D
G
D
!
SUCA. AIEC
C?C
lua. AIK
cw
KBEa. AIM
C7C
HMCA, C7C.
«EC, H*THJ
SRECA, WAIN5

HUCA, IStK
KKECA, ISKK
crc
•JRZCA, ISSZC
CFC
HRECA. ISUC
CFC
HRECA, ISUC
CFC
HRECA, I5B£C
CFC
SRECA, KUC
CFC
HRECA, ISREC
CFC
XRECA, ISREC
CFC
SRECA, ISSEC
ere
HRECA, ISUC
crc
VRECA, ISREC
crc

SRECA. IS££C
ECAR3
HRECA
MIOLESALB FOUEU
SUPPLIERS 1
son
son
VEIL
aw
ILPC
SPFL


BEDI
fflPL
PS1N
HOIP
?SIS
WFA
KIN
HEDI
azui
REQI
SED1
HOIP
7SIH
WVPA
PSitr
UV?A
HEDI
PSIM
W7A

PSIH,
SEFA
SOIC
PSIH
S
I



Cvns 9.JI of planned
Clinton 112, with OPC
and SOY!.















Supplies pover to 17 rural
electric cooperatives.

104

-------
H
>
H
I8PIA11A (coat.)
Jasper COUDCT Rural
Electric Membership
Carp.
Jay County Rural
Electric Membership
Carp.
Jahasaa County Rural
Electric Membership
Corp.
Kankakee Valley Rural
Electric Membership
Corp.
loos County Kuril
Uaccric Membership
Corp.
Koaciuako County Rural
Electric Membership
Carp.
LaCuoge County Rural
Electric Maoberablp
Corp.
Marshall County Rural
Electric Membership
Corp.
Miami-Case County Rural
electric Membership
Corp.
Marian County Rural
Electric Membership
Corp.
Hevcoa County Rural
Electric Membership
Corp.
Sob la County Sural
Electric Membership
Corp.
Orange County Ruxal
Electric .tenbetship
Corp.
Parka County Rural
Electric Meabetahlp
Corp.
Ruah County Rural
Electric Menbership Corp.
Shelby County Rural
Electric Membership Corp.
Southeastern Indiana
Rural Electric Membership
Corp.
Southern Indiana Rural
Electric Cooperative, Inc
Steub«n County Rural
Electric Membership Corp.
Sullivan County Sbiral Elec-
tric Membership Corp.
§
5

Ranaaalaer, lad.

Portland, Ind,

Franklin. Ind.


Waoatah, Ind.

Tlneenoes. Ind.


Uaraw, lad.

LaGrange, Ind

Plymouth. Ind

Peru. Ind


MarcimvlUa, Ind,

Kent-Und. Ind.


Albion. Ind.


Orleans i Ind.


tockvllla, lad.


Ruihvllla, lad.

Shalbyvilla, Ind.

Oitood, Ind.


Tell City. Ind.

Angola, Ind.

Sullivan, Ind.

£

D

D

D


0

D


D .

D

D

D


0

D


D


0


D


D

D

D


D

D

D

AFFILIATION

HRECa. ISKEC
CTC

HHSCA. ISUC
CTC

8RZCA. IS8EC
CFC

N82CA. ISRZC
CTC

HRECA. ISREC
CTC

HRECA. ISREC
CTC

• HRECA, ISREC
CTC

HRECA, ISREC
CTC

HRECA, ISRZC
CFC

TftECA, ISREC
CFC

HRECA, ISREC
CTC

HRECA, ISREC
CFC

DRECA, ISREC
CFC

HRECA. ISREC
CFC

KftECA. ISREC
CFC
HRECA, ISREC
CTC
SUCA. ISREC
CFC

NRECA. ISREC
CFC
NRECA, ISREC
CFC
HRECA, ISREC
CTC
WHOLESALE POUER
SUPPLIERS

501?
W7TA

TJME
WrA

ESDI


ROIF
WVPA

BEDI


WIT
PSIH
WVPA
HOI?
WVPA

SOIP
tfVTA

PSIN
WVPA

ISFL
HEOI

HUI?
UVPA

1NME
HOIP
WVFA
OEDI


PSIH
WVPA

SE01

BZDI

HEDI


ami

HOI?
WVPA
HEDI

1

















































105

-------
s
fi
nmiAHA (cent.)
Tipmont Rural Electric
Maaberahip Corp.
United Rural Electric Member-
ship Corp.
Utilities M«tr±ct:ot Vest-
en Indiana. Rural Electric
HeBbeiablp Corp.
ttabasb County Rural
Electric Heab«shlp Corp.
WPA- — Kabash Va-lleyr. Power
Association, Inc.





Warren County Rural Electric
Membership Corp.

Wayne County Rural
Electric Membership Corp.
White County Rural Electric
Membership Corp.
Vbitly County Rural Electric
Membership Corp.
Indiana Statewide Rural
Electric Cooperative, Inc.
BtRI — Big Rivera Electric
Corp.
Big Sandy Rural Electric Co-
operative Association
Hue Crase Rural Electric
Cooperative Corp.
Clark Rural Electric
Cooperative Corp.
Cumberland Valley Rural
Electric Cooperative
Corp.
EAKR — East Kentucky Power
Cooperative, Inc.
Faraars Rural Electric
Cooperative Corp.
Fleming-Mason Rural
Electric Cooperative Corp.
»c» Creak Rural Electric
Coooeratlve Corp.
Gray sen Rural Electric
Cooperative Carp.
Green River Electric Corp.

B

Linden, Ind,

Huntingtoa, lad.

tloamfleld. lad.


Habasb, lad.

Indianapolis, Ind,





Wllllaaaport, Ind,


Richmond, led.

Monticello. Ind.

Columbia City. Ind.

Indlaaapolla. Ind.

Sanderson, Ky,
Palntevllle, Ky.

Nlcholasvllle, Ky.

Winchester, Ky.

Cray, ty.


Winchester, Ky.
Glasgow, Ky,

Tlealngsburg, Xy,

Lawrencabuxg, Ky,

Crayaon, Ky.

Owenaboro, Ky.

£

D

a

D


D

G





D


D

D

D

A

S
D

D

D

D


C
D

9

D

D

D

I
E

HXECA, I3HEC
CTC

HRZCA, ISREC
CFC

SIRICA, ISREC


HRECA, ISREC
CTC
HMCA, ISREC
2CAR. CTC'





NR1CA, ISREC
CTC

NRZCA, ISREC
CTC
HRECA. ISREC
CTC
HRECA. ISRZC
CTC
KRECA

KUCA, UEC
ECAR3
NRECA, UEC
CTC
HRECA, UEC
CTC
SntECA, UEC
CTC
KRECA. UEC
CTC

NRECA, CTC.
UEC, ECAR
NRECA, UEC
CTC
NRECA, UEC
CTC
KRECA, UEC
CTC
.NRECA. UEC
CTC
HRECA, UEC
CTC
UIIOLESALE POWER
SUPPLIERS

PSIH

OWE
PSIH
HVPA
BED1


PSIH
WVPA






NOIP
PS IB
WPA
DIKE
HEDI
SOIP
WVPA
IKHE
WPA



EAKR

EAKS

EAKR

EAK&



EAKR

EAKR

EAKR

EAKR

SIRI

a
1










Owna with East Kentucky
Power Cooperative {EAKR) 251
of proposed Marble Hill
Hucleai Plant. Public Ser-
vice Co. of Indiana owns
che reoalaing 7SZ; euppliee
power to 21 rural coopera-
tives In Indiana.











Supplies power to J Ken-
tucky Co-ops.









Supplies power to IS Ken-
tucky cooperatives.










106

-------
B
ii
uurrucm (cont.)
Harrison County Rural Elec-
tric Cooperative Corp.
Henderson-Union Rural
Electric Cooperative Corp.
Uckaan-Fultoa Counties
Rural Electric Cooperative
Corp.
later-County aural Electric
Cooperative Corp.
Jackson County Rural
Electric Cooperative Corp.
Jackson Purchase Electric
Cooperative Corp.
licking valley Rural
Electric Cooperative Corp.
Meads County Rural Electric
Cooperative Corp.
Malln Rural Electric
Cooperative Corp.
Oven County Rural Electric
Cooperative Corp.
Pennyrlle aural Electric
Cooperative Corp.
Salt River *ural Electric
Cooperative Corp.
Shelby Rural Electric
Cooperative Corporation
South Kentucky *ural
Electric Cooperative Corp
Taylor County Rural
Electric Cooperative Corp
United Dtllity Supply Co-op
siarren Rural Electric
Cooperative Corp.
Jeat Kentucky Rural
Cooperative Corporation
Kentucky Association at
Electric Cooperatives
OHIO
Adau Rural Electric
Cooperative, Inc.
3elmoac Electric
Cooperative, Inc.
Wn — Buckeye Power.
T|«>
me.
luckeye Rural Electric
Cooperative, Inc.
Sutler Rural Electric
Cooperative, Inc.
\
H

Cyathlans, Xy.

Henderson, Ky,

Hicknan, Ky.


Danville, Ky.

iteKee, Ky.
?aducah, Ky.

Heat Uberty, Ky.

Jraodenburg. ly.

EllxabetbtovB, Ky.

Ouenton, Ky.

Hopklnavllle, Ky,

Sardstovo, Ky.

Shelbyvilla, Ky.

Somerset, Ky.

Caapballavllle, Ky.

Louisville, Ky.
Bowling Creen, Sy.

Kayfleld, Ky.

Louisville, Ky.


West Onion. Oh.

St. ClalrsvUle,
Oh.
Caluabue, Oh.

Galiipolis, Oh.

Baallton, Oh.

u
A.

0

0

D


0

D
D

D

D

D

D

D

D

0

D

D


D

D

A


0

D

0

0

D

AFFILIATION

HUCA, KAEC
etc
ww
MttECA, CAEC
CFC

trazcA. CAEC
CK
V« v

RUGA, uzc
ere

NRECA, UEC
CPC
SMCA, KAEC
C7C

NRECA, KAEC

HBECA, KAEC
CTC

HRECA, KAEC
C7C

HRECA, KAEC
c?c

•mzcA



HRECA, KAEC
C7C

XRECA, KAEC
rvr
Lritf


NRECA, KAEC
C7C
HRECA, KAEC
fVt*
urc
3RECA, CTC

XRECA


HB2CA, OREC
CFC
HRECA, OREC
CTC
MRECA, OREC
ZCAiS

MRECA. OREC
CFC

HRECA. ORIC
CTC

1 WHOLESALE POWERJ
SUPPLIERS I

EMOL

BIRI

TZVA


EAKJL

EACR
CEUC

EAER

BIRI

EAKR

EAKR

TEVA

EAKR

EAKR

EAKR1

EAKR


TFTA

TB7A




3DTI

BOTI

OHFC

BUPI

3UPI

3











































Distributes power to all
Ohio eooperscives and one
Nlchi(an cooperative.




107

-------
•I
i*
a 5
OHIO (coot.)
Carroll Electric Cooperative,
lac.
Derke Rural Electric
Cooperative, lac.
Delaware Rural Electric
Cooperative. Inc.
Plrelanda Electric
Cooperative, Inc.
The Frontier Power Co.
Cuernsey-MueklnguD
Electric Cooperative Inc.
Hancock-Hood Electric
Cooperative, Inc.
Holaea-Uayae Electric
Cooperative, Inc.
Licking Rural Electri-
fication, Inc.
Logan County Cooperative
Power
Loraln-Hedina Rural
Electric, Cooperatives,
Inc.
Marlon Rural Electric
Cooperative, Inc.
Midwest Electric. Inc.
Morrow Electric Coop-
erative, Inc.
North General Electric
Cooperative, Inc.
(forth Western Electric
Cooperative, IDC.
Pauld ing-Putnam Electric
Cooperative, Inc.
Pioneer Rural Electric
Cooperative, Inc.
South Central Power Co.
Trlcounty Rural Electric
Cooperative, lac.
Onion Rural Electric
Cooperative, Inc.
United Rural Electric
Cooperative, Inc.
Veahlngton Electric
Cooperative, Inc.
Ohio Rural Electric
Cooperative. Inc.
1

Carroll tan, Oh.

Greenville, Ob.

Delaware, Oh.

Rev London, Oh.

Coahocton, Oh.
New Concord, Oh.

North Baltimore, Oh.

MlllerabuTg, Oh.

Uelca, Oh.

Bellefontaine, Oh.

Wellington. Oh.


Marlon. Oh.

St. Karya, Oh.
Mt. (Ulead, Oh.

Attica, Oh.

Bryan, Oh,

Pauldlng, Oh.

Pliua. Oh,

Lancaster, Oh.
Napoleon, Oh.

Meryevllle, Oh.

Centra, Oh.

Marietta, Oh.

Coluobua, Oh.

'

D

D

D

8

D
II

n

D

D

D

D


D

D
D

D

D

D

D

D
D

D

D

D

A

AFFILIATION

HRECA, OREC
CTC

HUCA, OREC
CTC

HRECA, OREC
CTC

HRECA, OREC
CTC

HRECA, OREC
HRECA, OREC
CTC

HRECA. OREC
CFC

RRECA. OREC
CTC

NRECA, OREC
CTC

MRECA, OREC
CFC

SMCA. OREC
CTC


NRECA, OREC
CTC

HRECA, OREC
CTC
HRECA, OREC

HRECA, OREC
CTC

SRZCA, OREC
CTC

HRECA, OREC
CTC

HRECA, OREC
CTC

HRECA, OREC
HRECA, OREC

HRECA, OREC
CTC

OREC

HRECA, OREC
CFC

SBECA

(WHOLESALE. TOKEN
SUPPLIERS 1

BOPI

KJPI

BOPI

BUPI

BUPI
BOPI

BOPI

BOPI

BUPI

aopi

BCPI


BOPI

BUPI
BOPI

BUPI

BUPI

BOPI
IKKE

BUPI

BUPI
BUPI

iUPI

BUPI

aupt

BUPI

a















































108

-------
g
H w
ai
i
PENNSYLVANIA
Adams Electric Coop-
erative, Inc.
AECI — Allegheny Electric
Cooperative, Inc.
Bedford Rural Electric
Cooperative, lac.
Central Electric Coo-
eratlve. Inc.
Claverack Rural Electric
Cooperative, lac.
Sew Enterprise Rural
Electric Co-op, Inc.
The Northwestern Rural
Electric Cooperative
Association, Inc.
Somerset Itural Electric
Cooperative, Inc.
Southwest Central Rural
Electric Cooperative
Corp.
Sullivan County Rural
Electric Cooperative,
Inc.
Tri-County Rural Electric
Cooperative, Inc.
United Electric Coop-
erative, Inc.
7alley Rural Electric
Cooperative, lac.
warren Electric Coop-
erative, lac.
Pennsylvania Rural
Electric Association
VEST 7TRCIHTA
Harrison Rural Electrifica-
tion Association, Cnc,
g
tj
Gettysburg, Pa.
Hanlsburg, Pa.
Bedford. Pa.
Parker, Pa.
Towanda, Pa.
New Enterprise, Pa.
Cambridge Springs, Pi
Somerset, Pa.
Indiana, Pa.
?orkavllle. Pa.
Mansfield, Pa.
DuBois, Pa.
Buntlngdon, Pa.
Toungsvllle, Pa.
Barriaburg, Pa.
Clarksburg, tf. 7s.
S
D
G
D
D
D
D
D
D
D
D
0
D
D
D
A
0
1
NRECA, PREA
CTC
HRECA, CTC.
PREA, KAAC
HRECA. PREA
CTC
SRZCA, PREA
CTC
NRECA, PREA
CTC

RRECA, PREA
CTC
NRECA, PREA
CTC
HRECA, PREA
CTC
HRECA, PREA
CTC
JTRECA. PREA
CTC
MRECA. PHEA
CTC
HRECA. PREA
CTC
HRECA. PREA
CFC
1RECA
HRECA, OREC
CTC
WHOLESALE POWER]
SUPPLIERS
AECI
JEC?
HEEC
PEEC
POAS
WEPP
AECI
AECI
AECI
AECI
AECI
AECI
AECI
AECI
AECI
AECI
AECI
AECI
HOK

-------
                      APPENDIX E

SELECTED OPERATING STATISTICS FOR MAJOR INVESTOR-OWNED
           UTILITIES IN THE SIX ORBES STATES
                          110

-------
     Unless otherwise noted, the following sources provided the data reported

In this Appendix:

     "Operation Statistics" from the individual Company's Annual Report, 1976

     "Additional Ratios" from Moody's Investor Sources, Moody's Public Utility
        Manual (New York, 1977)

     In addition, Data on utility ratings were obtained from Standard and Poor's

Corporation. Standard and Poor's Bond Guide (New York, 1977)
                                     111

-------
TABLE E-L: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
murruM
EJTKLjiT CD01
fnTfUlH Tlffltrnn
"TH.tu
teul Ca^HnlAl * tMMCTiai
CtMTCUl
ladMtrui
Otter
WML eranuu
14L0 (Ml
UlUuCUl
Taul CMmiil 4 IoA-trt.1
CmrcKl
laduicrtil
ocr»r
IDUL UUS
mono («>uui)
tmUmetml
Tot»l uamul 4 la^KtTUI
CcMIKlll
lodMcitil
ntiL tfVDBS
anunai (IMI
GnncM
T««l pank*Md 4 tai«eMt|id
FnicUHd
CaufOatM
Tout, cntnunoit
ran COST — i or tinns
1971
1911
lt'4
LMOI eon — l of mono
1*71
1971
1*73
197*
197]
Bit ma (itu/M)
1972
1973
1974
1971
197:
L97J
L97t
117!
1974
JOB, (!«•»•• coBC/lO^tca)
1971
1971
117]
1971
1974
8t7lirilB/ll **TT1 *"** UHUU
1971
1971
1171
197*
JBIDS
4T9C
911.191
109.111
94.Mt
15,04]
74*
I.UI. 751

7.JU.OM
1I.3M.090
4,OM,aM
14.JM.OOO
1.1)1.000
lt.441.000

II5t.Mt.000
Nl.147.000
U4.3U.OOO
171,011.000
41.341.000
ITU, 27*. MO

J(.39«,OM
(4.M4.I>M)

I»,ttl,000C

-
10.111*
10. 13*
10.091
10.1*4
10.017

M.ITIO'
M.1U1
10.414*
W 9711
H.W94
-

CO. OOf BO,
IOX NIC KIT
IM.4J4 IM.3U *4t,M9
19.470 19.770 4»,J71
U.HI 11.111
4.JI1 7.JM
20* 407 »Jt
1M.UI 240.302 *9*.MJ

1.4*9, (70 1.391.131 1.471.441
t. tW.lt* 1.247.5U 1. 134.J11
994.191 1.1*9.117
l.H7,9»1 4.184.11*
919.474 1,174, n* 1.41J.9«9
7.414.744 Mll.Ofl ll.031.lll

1 44.711, 000 1 11,3*9.209 tlll.41t.000
IU.4I4.0U LOl.Ut.Ml V47.4U.OOO
• . 031,000 13.161.000
87.134.090 114.479.000
21.110.000 20.*0!.11« 31,401.000
U16.M9..000* H07.312.lrl9 1114.101, 0»

10.1*0,407 1.141.1** 17,111.129
(1.141. Ml) 1.141.117 (1.797.313)

7.42*. JU* 9.JOI.OII I3.933.JII*

. •



.

                          112

-------
                              Notes:  Table E-l
 All information for this company taken from Moody's Public Utility Manual,  1976


 Includes $33,554,000 of revenues subject to refund

Q
 Includes (2,291,000 mwh) as losses and system uses


 Includes (592,170 mwh) as losses and system uses

g
 Includes (1,002,126 mwh) as losses and system uses


 This data taken from Utility's annual report for year 1976
                                    113

-------
TABLE E-2: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
                                uaaiea menu wwi sntn
M*n «v* Mun HVXLCMi UXCTKIC
OnUTT WHB 	 .. -m .mut
HJHU iK»ui
QTXUTT COM AVS
amaae ntmstia
biUmlU 1.419.100
Tout, Maircul 6 la*«m*l 109,41*
c^rciu
UtacrUl
Olhn 1,9(4
tout, cmoms i, 117,910
ULJB OM)
1UU.MU1 16, 619. 000
T«U4 CmrcUl 6 UdMcrUl 40,02*. 000
bMKlll
lohucrKl
Octar U.14a,000
Tom tjnu »4.iii,ooo
UVUUIU (dolltril
UiUinlU 1 490.4M,000
Taul CoMteul 6 Iidwitul 647,136,000
COBiKlJl
OCIMC 479.721.000
TOt4L Bnma si. in, m, ooo
e«mt<4 90.111.000
Tout pacch
-------
                             Notes:  Table E-2



SA11 information for this company from Moody's Public Utility Manual. 1976.
This description of American Electric Power Company consolidates data for the
following companies:  Appalachian Power Co., Indiana & Michigan Electric Co.,
Kentucky Power Co., Kingsport Power Co. (not in ORBES states), Michigan Power
Co.  (Not in ORBES states), Ohio Power Co., Wheeling Electric Co. (a non-generat-
ing company), Ohio Valley Electric Company (37.8%  Ownership).  The major com-
panies in this system are shown separately.

^Includes information"on Indiana and Michigan Electric Company's subsidiary,
Indiana and Michigan Power Company

clncludes $165,386,000 from other kwh sales, ($3,553,000) of unallocated revenue,
 and $8,141,000 from other operating teventae

dlncludes $154,086,000 from other kwh sales, ($2,444,000) of unallocated revenue,
 and $3,811,000 from other operating revenues

Includes $17,463,000 from other kwh sales and $745,000 from other operating
 revenues.

fIncludes 7,700,000 mwh of steam-fossil and 6,809,000 mwh steam-nuclear and
 73,000 mwh of hydro

      taken from Company's annual report, year ending December 31, 1976
                                     115

-------
   TABLE  E-3:   CHARACTERISTICS  OF  INVESTOR-OWNED  UTILITIES
                                one rwn co.
                                                                EBPM. nm.ietmi.rf
                                                  	> IfnLtC   KCTIOMLlTAILCDIi
                                                   •nutus*             at-
                                                                                 ^
                                  accrue to."
         mum coat
               l 1 S«MUI*I
     latucrUL
  TOUL council
UU* OHM
                * tldMftUl
  Teul pueouM * mirctad*
  TotH. anunaM
                                   S1«.M1
                                    M.IM
                                     J.UJ
                                   M7.M1
                                  1.711,300
                                 lt.199.J79
                                 U.111.390
                                 14,IM,lt9

                               Ut7.071.i4J
                                14MM,lt«
                                117.031,tM
                               1712.747,074
                                 U.719.347
                                 (9.M7.IM)
                                 17.097. 711
fCTL COS1 — I OF UVVUIS
   1971
   1971
   \tn
   III*
   vm
1.310,400
  UB.734
  1W.OH
      »,071
  I.UI.ICM
  19. (31. Id
  li.M9.t4>
  1.743.ill
  U.tM.9M

I444.lt4.t30

 213.413.17)
 111 .096.174
  J3.U1.6H
  K.212.M3
   1.419.111
   1,133,111
   1.334,19*
  11,701.179
                                                                    »7.167d
                 IX, III*

               1.1M.OOO
               1.111.400
               1.331.000
               1.194,000
                 llt.OOO
               7.019.000

             uoi.34i.ooe
             131.401.000
              il.t9i.ooa
              71.709.000
              11.794,000*
             U63.303.000
                                  tll.114
                                   i*.14t
    441,201

  1.113,000
  MI9.000
  1,079,000
  1.340.000
    709,000
  10.019.000

1130.191.000
 IH,131.000
  19.120,000
 107,412,000
  31.01t.0001
»U7.911,000
                                                                                 io,it4.;»i
urn con — i or
   1971
   1971
   1911
   1979
   1176
au un
   1971
   1972
   197*
   197)
   1974
   U71
   H7J
   1)7)
   1171
 m. (»mt< CMt/U mi
   1171
   1979
   1971
   U7t
 Murm/i  i auzoi unm
   1171
   1171
   LI71
   1171
   1973
   1174
                                              116

-------
                            Notes:   Table E-3
     ,  taken from Moody 's Public Utility Manual.  I976T includes information on
 all three GPU subsidiaries


blncludes data of Metropolitan Edison Company's subsidiary,  York Haven Power
 Company


clncludes data on Pennsylvania Electric Company's subsidiary Waverly Electric
 Light and Power Company


'Sata taken from Moody 's Public Utility Manual. 1976


Includes $21,980,000 of revenue from other Kwh sales and $5,774,000 of revenue
 from other sources

flncludes $20,415,000 of revenue from other Kwh sales and $10,659,000 of revenue
 from other sources
     , taken from Moody 's Public Utility Manual.  1976 refers only to Mwh gener-
 ated, including 4,859,844 MWh from steam, 2,167,813 Mwh from Nuclear,  and
 266,346 Mwh of hydro and other sources; no purchased or interchanged power is
 included .
     , taken from Moody 's Public Utility Manual. 1976, refers only to Mwh
 generated, including 8,968,061 MWh from steam, 1,083 Mwh from nuclear and
 1,195,621 Mwh from other sources; no purchased or interchanged power is included.
                                    117

-------
TABLE E-4:  CHARACTERISTICS  OP INVESTOR-OWNED  UTILITIES
                 tLLomi
                 cnmui, IU.IMU lien OKTUU. IIUMII ontaivuin aim iuaoii mm
          tuu         cat        mucuntci       eo.          CD.*

mun eoBc
onungajUQrna
""iHlLui
TOC4U COMKU1 1 UdWrUi
iZ^
Otb»
•ntu. aarama
tun OMO
iMUBCUl
Total CoMiKUl 4 IMutrlal
CMBMcUi
TjriuicrLiI
aunt
TOTM. 14119
imnn 
iMUacUl
tota CMBIKUI 1 latauul
Bi_rcul
Iitenlal
Oltoi
TOTAL UIUUU
aminoi OMO
taunud
TKIl fBKau* 1 1«IK>M(M
Hill».liil
Uuntun(«d
TOUL conunoi
fQIL COST — ' Z OF 1ROOU
l«7l
It7t
1»1
W74
It71
MH
uut cost — i or snvDis
un
1J71
UT)
1$74
1J71
U7i
aa un (M«/bb)
IHl
1171
117)
1174
1171
1974
RJIL (mtB|* eoac/loa)
1171
wn
117)
1174
It71
1176
mL (i«m«ii ettct/U in)
It71
1171
It7]
19 H
1»7J
1171
DVUTUS/I 1 JOUIOI U7DDI
1171
1*71
1171
1174
1171
»7t

em.

UI.*»'
u,7nb

Ml'
in.tTo'

l,19l,14*b
i.m.7t>b


»,14*b
1. 211,200*

111. 141.000
It.Ut.OOQ
lt.J4f.000
4». tn ,000
l.OM.MO1
11*4 .IB .000

4.141.000'
(t,074)k
««'
(6.441)'
4. Ml. 921
11.
14.
17.
11.
2].
U.


_

.
,
.

10.114
10.109
10. JM
10.171

uOu

H 111
7 031
1.137
11.100
It.lU
if.m

(O.M
0.14
o.u
0.40

1.0(1

U.
u.
u.
u.
1.
1.
of
cur coie

U2.1U l.JJ7,44»*
1I.4M 121. 1«V
J6.«0C
717 U,»lb
M1.1M 1,7*1, 32lk

l.fn.lM lt.U4.900
), 173. 137 ll.Ml.gOO
711,317' ir.4JJ.0001
l.Ul.HO* 17.IH.W01
1.I02.H4* 7.111.000*
7,7»,(19 M.J17.000

tM.lK.OOO llSl.ltl.OOO
l»,7!(,00q l.QM.iSl.OOO
M.tll.OOO' U4.M1.000
M.145.00011 tot.Ml.OOO
41.1M.OOO1 m.211.000k
I142.1U.OM ll.WO.UI.OOO

7.71t.OOO 40.H7.073*
].35I,03lb

711,000
l.42», 000 6], 2)4, 1H1
11.
21.
21
21.
21
3J,

It.
11
11.
17
11.
U.

10, Ml
lO.ttl
lO.f J4
11.111
11.049
11 .M4

U 01
1 It
I.JJ
11.00
11.10
U.N

10.40
0.11
0.41
O.M
0.41
0.11

14.
1]
11.
10.
1.
}.

UK

415,411
32 .139
si .OM'
4W
IH,«4*

1.171.711
7,111.0)7
1,409,101'
6.4U.UI4
tli.Mt"
12,071.714

1100.411. 000
in.tii.ooa
31.6IO,OOOd
iia.nj.ooo*
ii.70i.oao1
IJOJ.04t.OW

U.7U.128
(1.707, 1U)


12.071.714'
11.0
11.6
14 1
It 1
21.7
If 1

11.1
11 t
11. t
11.7
10.6
10 4

10.J1I
tO. 30*
10, jj;
10.111
10.040
10,341

11.17
S.ll
4.11
1 31
u.ts
19.04

10.17
O.U
fr.J*
fl.rit
9.11
0.71

11.70
11 4t
11.17
10.10
1.14
7.44
                            118

-------
                              Notes:  Table E-4


aAlthough company distributes both natural gas and electric energy the figures
 given refer only to electric utility operation


 Data, taken from Moody's Public Utility Manual


°Figures given for "commercial" use correspond to "small light and power" and
 "industrial" corresponds to "large light and power" in Central Illinois Public
 Service's annual report

d
 Figures shown as "commercial" use correspond to "commercial and small power" in
 Illinois Power Company's annual report while "Industrial" use corresponds to
 "large power and light"

elncludes 1,323,247 Mwh sales to cooperatives and 479,617 Mwh sales to munici-
 pal and other customers

 The commercial designation in this case includes small commercial and industrial
 establishment.  The industrial designation refers to large commercial and indus-
 trial establishments.  These categories are not defined further

8Includes 5,345,000 Mwh of sales to public authorities, 334,000 Mwh sales to
 electric railroads, and 1,456,000 Mwh sales for resale

 Includes 736,834,000 Mwh of sales to rural cooperatives and municipal utilities,
 1,836 Mwh sales to other electric utilities, and 247,298 Mwh sales to other
 sources

1Includes $1,095,000 from other utilities, $1,479,000 from street lighting and
 public authorities, and $486,000 of other revenues

JIncludes $28,924,000 in revenues from cooperatives and $12,302,000 in revenues
 from municipals and other customers

v
 Includes $141,066,000 of revenue from public authorities, S7,615,000 of revenue
 from electric railroads.  $27,743,000 of revenue from sales for resale, and
 $14,799,000 from other revenues

 Includes $10,920,000 of revenue from rural cooperatives and municipal utilities
 $5,170,000 from other ultimate consumers, $39,000 from other electric utilities,
 and $2,572,000 from miscellaneous sources

^Includes (960,516 Mwh) of lost and unaccounted for power
                                      119

-------
TABLE E-5: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
imm «M
QTXU^ 0001
orauTtitt turuna
*££*>*.
I*ul CMMeUl 6 latmrUl
CammUl
taAMTial
octal
TOUL UA1UNUS
ULB 
1971
1*71
1*7)
1174
1173
1176
1*71
117]
1173
1*7*
1*79
1*74
7OL (rmfl nee/10 9ty)
1171
1171
1*73
1*74
1*79
1974
immua/i i nuiot umm
1171
1972
1*7)
1174
117)
1176
out-ill noiJ~Si
UCTUC CO.*
toio

14..913'
11.10*


14*
154,441*

(3*, 172*
1,400.000*


17*.HJ*
1.4)9,01**





IM, 174 ,000

4,0*0,1491*
1
77,219*



10.1*
10.1*
11.10
23.91
13. 16
-

12.14
1.17
1.17
1.64
1.41
t.u

11, m
U.*4*
11.271
U.741
11.991
11.437
M.4*
1.17
10.49
11.11
11.41
17. U

30.11
0.13
0.11
0.44
0.61
0.11

13.7
U.I
10.1

i.i
4.3
i 4 mum OKTiie
CO.*
one

111.56*
100,707
H,1U
4,67*
l.*Me
Ml, 747

6,613,000
13.0*4. 000
] .417,000
ll.31T.000
I.IM.OOO'
21.J39.000
11 41, 714,000
190.107,000
110,400,000
13*. 707, 000
M.IM.OOO1
1411,000,000

J4.WJ.OOO
(1,6*1,000)

21.N3.0001


14.4
17 4
1*.4
21.3
27 i
19.4








10,117
10.11*
10.117
L0.2N
10.102
10, in
U.41
7 Jl
1.09
10.41
13.11
13.11

10.10
0.1*
0.17
0.10
4.11
0.11

17.1
13.4
19.1
13.3
10 4
1.1
uBL6ura.il ion
LICR CO.
an

174,411
12,141
11,124'
1,014*
Ul'
MI.496

2.170,101
1,601.613
1. tit, 17*'
1,744,41*'
Ul.lll'
7. 906. 401
141,014,000
L LI. 111. 000
44,7*1,000'
41 ,011.000'
6.116.0CC-1
1114,933,000

1.110,000

(17* ,000)
I.W4.0M


U.I
14.1
11.1
29.1
14.1
13.0

11.7
12 1
11.7
11 i
12.1
11.1

10.100
10.121
10.131
10. Ul
10. in
10.401
11.94
6.76
7 3*
1.11
13.47
14 41

M.24*
.103
.1*2
.611
.420
.679

11.
14.
11.
11.
11.
10.
i 6 mxnu IKDUJU
rmuc mvict co.
tan

307,3*1
14,111
21.44*
1.312
4*4
141,071

1,011.111
«,37«,1I7
321, nt
1.0M.111
*D4.132a
U.372.400
I71,M*.000
221.110.000
11. 550,000
IK. 4)0,000
21.111.000k
1123,111,000

I.4M.741*
6.6M.M3*

13.U2.324*


7 4
7.1
7.3
10 0
13.0
11.1

11.1
11.1
U.I
U.l
u.o
10.3

10.204
10.244
10.310
10.319
10,141
10,11*
»T tl
1 17
1.31
11 31
13.11
14.1*

10.341
0.367
0.147
0.11*
0.711
O.J06

16.0
14.1
14.4
L2.1
10.3
1.7
                          120

-------
                              Notes:   Table E-5


aAlthough company distributes both natural gas and electric energy, Che figures
 given refer only to the electric utility operations

 Data; taken from Moody's Public Utility Manual - 1976

CIncludes 24 electric utilities and 1,472 other

 Figures given for "commercial" corresponds to "small industrial and commercial;
 "industrial" use corresponds to "large industrial and commercial"

elncludes 134 customers for public lighting and 2 electric utilities

flncludes 1,171,000 Mwh in sales to other utilities and 519,000 Mwh. in miscel-
 laneous sales

8Includes 55,020 Mwh sales for public lighting and 77,908 Mwh sales to other
 electric utilities

Includes 77,591 Mwh sales for street lighting, 716,051 Mwh sales for resale,
 and 110,490 Mwh sales for other uses

Includes $21,432,000 from other electric utilities and $14,677 from miscellane-
 ous sources

^Includes $3,153,000 in public lighting revenues, $1,18'3,000 from other electric
 utilities, and $1,820,000 in miscellaneous revenues

^Includes $3,122,000 from street lighting, $14,539,000 from sales for resale,
 and $3,652,000 from other sources

 Includes (1,946,000 Mwh) of losses and other uses
                                      121

-------
TABLE E-6: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
               nPUJU mac.)
CO
QTXU7Y COOK
onuTtK nAnsnci
<1"i^L,m
T>ul ConcUl 1 lidwnlU
ri.airi.Ul
latacrlil
octet
SUUL UU1UHU9
uui OM)
ITTHT-T1,!
total CoKMRlal 4 '-*•-•-«•'
S0MKKU1
IndwtTUl
Otkn
TOW. uus
Iivmu (doluri)
iMlMIClll
TK41 CoawEUl t Ia»a«rUl
CMMKlll
UdiMtrUl
ocbii
TOUL UVUUU
onunm UMI
Conicx
Tool punbud 4 fatiretenid
FUTCtUlM
btnebaiM
tor*!, craiutioii
ummoKAL unos
TQXL COST •• 3> OF UVUUiS
1971
197J
an
1>74

197t
uut COST — I or imnxi

1972
1971
1974
1179

BIT lAIt «>
1911
Wll
L97*
1*79
197t
4
ran. (imit* con/10 ten)
1*71
1971
1974
1*79
1971
twLOTO/1 i nuioi mam
1971
1971
191J
1974
1971
1)71
muc sunci
OUT a UD14H4
Mm

4».3U
41.120
39,199
1.441
m'
491,120

4. 136. 000
1.104.000


1,091.000*
11.911,000

1141.197.100
l1J.10t.MO
90.011.000
103.077.000
w.nT.ooo3
1197.142.000

U.M1.000
(l.MO.OOO)

14. 191. 000°


IT
11.
11.
11.
JJ


It.
17.
It.
17
11.
14.

10,149
10,444
lo',29»
10.192
10.114
10,191
11.39
i.l)
i.41
l.ll
11.11
14.17

W.233
O.JM
0.900
O.Mt
0.321
O.llt
17. t
14.9
U.9
U.D
11.1
9.14
•J ••!!•••• pflffinf CAI
i aicrsic co.'
utc

I2,*M
10,4*9
U.ltl
104
24
u.jir

711.141
1.MJ.M1
Ul.ltl
•71,280
1.109.910
1.411 .041

114.177.171
34,1*0.197

17.301.»ltk
179.179,111

l.Ml.itl'
m. ma
714.190
i tu'ni"


9 7
11. i
14.4
17.1
10 0


14.1
11.4
11 9
12 0
10 9
9.4

11,110
11,414
1«.U1
10,704
10.331
10.59*
U.il
t.u

1.11
11.71

M.2t
O.Jl
0.17
0.50
0.17
14.
U.
11.
10.
1.
I.
luiucii vnuizn
CO.'
one

111,999'
4J,t*l*


1,921*
130, 7I14

2.441.U1
1.129.113


9.141.3*1*
10.110,041

tM.tlt.OOO
71.437,000

M, 121. 000 '
»29,15t,000

?, 119 ,011
1.792.M4
1.171,873
110,941
10.110,0*2*


17 1
17 3
17.9
17.9
It 1
17.1

11 4
10.1
14.1
12.0
9.7
10.1

11 .106
11.119
11.104
» .tot
10.174
10.74S
11.11
1 11
I 14
14 19
11.19
14.63

H.92
O.M
0 39
0.44J
O.t2
0.74
17.10
15.97
11.13
10.lt
7.17
7.15
UD1I7IUJ Ul
4 EURUC CO.
LOCI

29,1.749'
24,426


J.H9*
2I1.WO'

2.001.94*
4.1U.090
l.tll.Kl1
1.474. lit'
1J9J.1401
7. 311.114

111. 1*4 .000
10.111.000
40.001.000*
40,114.000*
ll.ltl.OOO*
1194,117.000

l.27>,90t4
(304,177)

7.171.111


11.
13
14
13.
19.
11.

14.
lk>
14
14.
1)
12.

10.239
10.190
10.197
1,lt9
10.004
10.031
19.17
1 04
7 94
9.19
11.41
1J.M

SO 17
0 11
0.14
0.42
0.57
O.M
21.
11.
19.
11.
19.
14.
                          122

-------
                              Notes:   Table E-5
aAlthough the company distributes both natural gas and electric energy,  the fig-
 ures refer only to the electric utility operation

 Includes information on Kentucky Utilities Company's wholly owned subsidary,
 Old Dominion Power Company


clncludes 108 rural electric cooperatives (RECs),  44 Municipal customers,  and
 836 other customers

dData obtained from Moody's Public Utility Manual. 1976

elncludes 1,805 Mwh in sales to RECs,  1,204,000 Mwh in sales to muncipal custo-
 mers and 83,000 Mwh in sales to other customers

Includes 792,720 Mwh sales to mines,  629,405 Mwh sale to public authorities,
 and 3,819,416 Mwh sales to other electric utilities

*»"Commercial" includes 669,994 Mwh of  sales for "small commercial and industrial"
 use and 943,168 Mwh of sales for "large commercial" use

 "Industrial" refers to large industrial firms

Includes 681,018 Mwh of sales to public authorities and 611,142 Mwh of  sales
 to other utilities

^Includes $33,656,000 from RECs, $19,416,000 from muncipal customers, and
 $7,665,000 from other customers

Includes $2,582,029 from sales for resale, $13,169,390 from sales to other
 utilities and Alcoa Generating Corporation, and $1,554,217 from sales to  other
 customers

 Includes $15,772,000 from sales to mines, $14,477,000 from sales to public
 authorities, $57,516,000 from sales to other electric utilities, and $1,456,000
 from miscellaneous revenues

m"Commercial" includes $20,344,000 from "small commercial and industrial"  firms
 and $19,664,000 from "large commercial" firms.  "Industrial" refers to  large
 firms.

"includes $13,930,000 from "public authorities",  $7,255,000 from "other  electric
 utilities" and $1,176,000 from "miscellaneous sources"
                                      123

-------
°Does not Include (1,326,000 Mwh)  from company use and losses

^Includes (801,850 Mwh)  as a result of losses and company use

qlncludes 447,468 Hwh generated by hydropower; 3,053 Mwh generated by combustion
 turbine, 188,170 Mwh generated by Ohio Valley Electric Corporation
                                      124

-------
TABLE E-7: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
               ORO
vnun Mn»
VTXUTT O3D&
uratrae matmo
UESIOJOI
TOUl OOMKlll 6 JatOfCO.fi
COMfCUl
IndM rial
Octer
win, esnaoBi
ULH OHM
Taul 'laMTrl il 6 lofcBcrUl
rn«»iiiii
Mwtltol
Otter
TOUL SALU
unms (4aii*r>J
Tout CoHorclal t la*o«rl*l
C»«el«l
LoftHtrUl
Otter
mu. uvnrczs
cmunn oo*>
bunud
toul [inrrhiiil 4 uutchax**
latOTCteOfM
miLonuno*
imniauu. IATTOS
run. COST — i or irons
1911
1972
1973
1974
1973
u» COST — < OF unna
L971
1971
1971
1974
1973
1976
fXHT UTt Clta/Vnh)
1*71
1*72
197}
1974
1973
1976
TIB <»mi« can/to*)
1971
1972
197]
1974
1973
197o
f
ran. (7.»J


5,015*
401,600
]. 211. 000
1.313,000


1.423.0001
9.121,000
iui.ii3.oao
121,161,000

u.iu.ooa1
1271,171,000

9,113.230
110.214

10.163.464

16.
13
17.
:a
26
Ik.
11.
17
17
1*
LI
11.
10,120
f 911
10,004
10.120
10.040
10.106
19 16
I.M
10 12
19 S3
11.99
11.10

10 0
.41
.41
.97
.04
0]
16 4
11.2
11 9
10 6
6 7
7.9
                         125

-------
                              Notes:   .Table E-7
aAlthough company distributes both natural gas and electric  energy,  the figures
 given refer only to electric utility operation


 Includes information of Cincinnati Gas and Electric Company's subsidiaries:
 Union Light, Heat, and Power Company, Miami Power Corporation.   The West Harri-
 son Gas and Electric Company, Lawrenceburg Gas Company and  Lawrenceberg Gas
 Transmission Corporation.

^ata taken from Moody's Public Utility Manual. 1976


dlnclude 5,042 public authority customers and 16 other customers


elnclude 1,329,000 Mwh sales to other utilities

^Includes 308,688 Mwh sales to governmental authorities and 473,209 Mwh sales
 for resale

Includes 924,000 Mwh sales to public authorities and 501,000 Mwh other sales


      not include $10,928,000 of revenue from steam heating  operations


Includes $8,541,000 revenue from governmental authorities,  $9,583,000 revenue
 from sales for resale and $2,123,000 from other sales

^Includes $24,753,000 from public authorities and $13,503,000 from other sources


Includes (735,195 Mwh) dne to losses and company use
                                       126

-------
TABLE E-8: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
snun MM
vfiuTT ooos
ORUTHIC RAnsncs
""Z^Ltui
Taut CcmcUl 4 Mutlfel
IJHMII HI
lotanul
Otter
RIUL CBRQOSS
UU3 Out)
iHfcUMl*!
tool fiiMin 111 6 ladunlti
C^KICIU
tnteHilal
attar
tOIAL SAL23
UNDOES (dAllMl)
Toul Coo*rcua 4 Induttlil
CmrcUl
Wwcrui
Octet
TOtAL U9UUJ11
anuna nm>>
Toul parchaM* 4 l>carc£wf«d
>«*»..<
TOTAL COTOAT10II
tmiTTOIIAL UTI03
raiL COST •" z of uvuuxs
1911
1912
1911
1914
1971
1976
UL60I COST -™ X OF UVUU1S
1471
1911
1911
1174
1971

BAT UR (Icu/Iiib)
1971
1972

1974
191)
1976
ran. UwMr* ea>l/toa)
U71
1911
1911
1914
1911
1916
4
raiL («•»!• CHI/10 Itu)
1971
1971
1971
1971
191}
1976
aaumsn i mtuw mans
1971
1971
1*7]
1911
197}
1976
OBIO (Coat.)
eno OIK* eo.* ramuuuru m
one roc

711.126 101.715*
74.411 11 ,«5
71.441 11,090
176 115
M« 111
196,112 114,06}

1,171,100 7M.MOC
11.447,900 1.171.100
1.690,400 467.600
1,117, KM 1,704.100
1.444,000 111,000
11,167,400 1,034.600
1101.790.000 IM.641.000e
191.191,000 14,911.000
116,370,000 17.201.000
117,521,000 17,716,000
M.M1.0M* 2.953,000
1356,264.000 IM',116,000
11.001.614* 1.779.100
1.199. 40111 474.400
1.M9.9U*
20.J01.234" 3.233, SOO


11. »
21.f
11.4
97.9
34.1
12.9

U.I
U <
U.9
11.3
12.5
12.1

10.246
10.161
10,212
10,411
10.691
10. Mi

17.16
1.13
9.16
14.66
22.71
20.69


_






19.00
17.M
U.7I
11.11
10.2»
1.21
touM cpisai
n eo. co.v
TOK

227.167
16,140
11.911
1,411*

211,101

1.162,000
4.197.000
1.201.000
1,394.000
141.000
7.221,000
111.162.000
122.J12.900
4} .314,000
16.991.000
21.163,000
1119.119.000
1.411.000
1.143.000s

7,114,000


20 7
20.0
21.1
27 3
26 1
27.1

11 2
16.0
14 7
14. S
11.6
10 1

10.017
10. OM
9.560
10,041
9.911
9,96]

110.11
LO (0
11.04
16 66
22.60
21.40


to u
0.4*
0.11
0.71
l.U
1.12

17.4
16.1
U.I
11.3
10.1
1.9
nmBtu-Aiiu
aoqaun HOT
CO.
NIC

414. 101
4I.JJ4
46.611
1.U2
1.774
SJ4.M9

1.691.000
9.694,000
1,144. an
1,113.000
129,000
12,116.000
1127.111,000
274,297.000


ll,4!4.00o'
1411.261.000*
12.467.000
742.000

12.116.OOOJ


21 M
11 77
tl.20
11 13
12.11
11 11

11 64
12 19
10 91
9 01
1 21
1.12

11.204
10.647
10.313
10, .11
10.224
10.621

11.61
6 29
9.14
11 31
12.0)
21 71


Mt.M
0.17
0.41
0.10
1.34
1.0)

21.0
16 0
14.0
13.0
11.0
10.0
                        L27

-------
                              Notes:   Table E-8
      is for Ohio Edison Company; it does not include the Company's wholly ouned
 subsidiary Pennsylvania Power Company.  These figures were obtained by subtract-
 ing Pennsylvania Power Company data (published in a separate annual report)  from
 the consolidated annual report filed by Ohio Edison Company.  Data on Pennsyl-
 vania Power Company is detailed separately

 Although company distributes both natural gas and electric energy, data refers
 to electric utility operation.

 Includes farm customers

Includes "other"

Includes $34,807,000 from "other -electric sales", $19,542,000 from "other elec-
 tric revenues" and $4,232,000 from "steam heating"

fIncludes $7,789,000 from street lighting and other sources and $3,667,000 from
 miscellaneous sources

      not include $11,310,000 of revenue from steam heating operations

     taken from Moody's Public Utility Manual, 1976

Includes 1,644,000 Mwh purchased from the CAPCO pool,  and 749,000 Mwh of  other
 purchased and interchanged power

^Includes (713,000 Mwh) due to losses and company uses
                                      128

-------
TABLE E-9: CHARACTERISTICS OF INVESTOR-OWNED UTILITIES
                          .TUTU (Coot )
tram IM
OTXLRT GODS
amATnG RATianes
•MldntlAj
total CooBsrclal 4 IndMCrtal
COSMKlal
tadwtrUl
Otter
TOTAL COSTOMUS
SAUS (IM)
loaUootlal
Total CosBorclaU 4 Industrial
Cas»irclal
Industrial
Otter
TOTAL SAUS
WDRJES (dollar!)
Total Coowclal 6 Industrial
ti— -Tin
Industrial
Otter
TOTAL UVUIUKS
smiATim (IM)
ratal p.rduaad 4 utaraha»t«d
POKfcoood
latoieointoo1
TOTAL cwnurtos
ABDIT101IAL KATIOS
FOB, COST — t OF UVUHJEa*
1971
1971
1971
1974
1979
1976
um COST — t OF unmiu
1971
1972
1973
1974
197]
1976
HAT IATI (Itu/M)
1971
1972
197]
1*74
197]
1976
run. (mrs|a cool/too)
1971
197]
1971
1974
1973
1976
1
IDSL( mri|i coot/10 Itu)
1971
1*7]
197]
1974
197]
1976
DO?URtS/S 1 IQLUOI UVIWII
1*71
1*7]
1*7]
1*74
197)
1*76
ra0n.>aiu pom
6 uen oo.
put

I11.6111
in.oji*


l.l*!1
916.079*

7.167,000
12.U9.000
4.174,000
7.411,000
712.000
10.194.000
1137,127,6*2*
131,946,691*


21.611,041*
1611,427,429*
21, 711.000*

2,126,000
(i.ua.ooo)
20,134,000'


_






.













.







.






.





CO.*
me

1.117.144
121.169
113.411°
S.J47e
1.14)
1.161.091

7,313,000
17,417.000
2.7]>.MOC
14.642. 000°
1.271.000
26.271.000
1171.200.000
)92|]00.000
14*. 100. 000°
442.900.000°
19.400.000
11.014.100.000
20.771,000*
7.666.000


21.437.000


11 2
10.9
J4 0
tj i
40 1
19.1

17 9
17 t
16.4
11 2
11 4
11.2

.114
.294
,37S
,1)9
.627
,619

110 06
11.61
13 04
19 96
!J 11
21.11


sa.a
0.62
0.71
1.42
1.22
1.24

17 1
13 6
11.4
10.0
1.6
7.7
                        129

-------
                            Notes:  Table E-9
aT)ata taken from Moody's Public Utility Manual. 1976

 Includes data on Philadelphia Electric Company's subsidiaries:  Philadelphia
 Electric Power Co., the Susquehanna Electric Co., and Conwingo Power Co.

ft
 Figures shown as "Commercial" use corresponds to "small commercial and indus-
 trial:   in Company's annual report;  "industrial" use corresponds to "large
 commercial and industrial"

 Includes 1,947,000 Mwh from Oil-fired stations,  40,000 Mwh from combustion
 turbines and dlesels, and 809,000 Mwh from hydroelectric stations

elncludes 13,385,000 Mwh of steam generation, 4,937,000 Mwh from nuclear power;
 2,065,000 Mwh from hydraulic turbines; 1,062,000 Mwh from pumped storage out-
 put; (1,506,000 Mwh) from pumped storage input;  792,000 Mwh from internal com-
 bustion; and 36,000 Mwh from other sources

 Includes (1,961,000) loss due to company uses and transmission losses
                                     130

-------