ORDES
THE CURRENT STATUS OF
THE ELECTRIC UTILITY INDUSTRY
IN THE
OHIO RfVER BASIN ENERGY STUDY STATES
PHASE
OHIO RIVER DASIN ENERGY STUDY
-------
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.
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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.
-------
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)
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
APPENDIX A
GLOSSARY
38
-------
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
-------
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
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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
------- |