1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _________________ to _________________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
1-9130 CENTERIOR ENERGY CORPORATION 34-1479083
(An Ohio Corporation)
6200 Oak Tree Boulevard
Independence, Ohio 44131
Telephone (216) 447-3100
1-2323 THE CLEVELAND ELECTRIC ILLUMINATING 34-0150020
COMPANY
(An Ohio Corporation)
55 Public Square
Cleveland, Ohio 44113
Telephone (216) 622-9800
1-3583 THE TOLEDO EDISON COMPANY 34-4375005
(An Ohio Corporation)
300 Madison Avenue
Toledo, Ohio 43652
Telephone (419) 249-5000
Indicate by check mark whether each of the registrants (1) has filed all re-
ports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that
the registrants were required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes X . No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
2
The aggregate market value of Centerior Energy Corporation Common Stock, with-
out par value, held by non-affiliates was $1,754,200,163 on February 28, 1994
based on the closing sale price of $11.875 as quoted for that date on a
composite transactions basis in The Wall Street Journal and on the 147,722,119
shares of Common Stock outstanding on that date. Centerior Energy Corporation
is the sole holder of the 79,590,689 shares and 39,133,887 shares of the
outstanding common stock of The Cleveland Electric Illuminating Company and
The Toledo Edison Company, respectively.
3
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
Centerior Energy Common Stock,
Corporation without par value New York Stock Exchange
Chicago Stock Exchange
Pacific Stock Exchange
The Cleveland Electric Cumulative Serial Preferred
Illuminating Company Stock, without par value:
$7.40 Series A New York Stock Exchange
$7.56 Series B New York Stock Exchange
Adjustable Rate, Series L New York Stock Exchange
Depository Shares:
1993 Series A, each share
representing 1/20 of a
share of Serial Preferred
Stock, $42.40 Series T
(without par value) New York Stock Exchange
First Mortgage Bonds:
4-3/8% Series due 1994 New York Stock Exchange
8-3/4% Series due 2005 New York Stock Exchange
9-1/4% Series due 2009 New York Stock Exchange
8-3/8% Series due 2011 New York Stock Exchange
8-3/8% Series due 2012 New York Stock Exchange
The Toledo Edison Cumulative Preferred Stock,
Company par value $100 per share:
4-1/4% Series American Stock Exchange
8.32% Series American Stock Exchange
7.76% Series American Stock Exchange
10% Series American Stock Exchange
Cumulative Preferred Stock,
par value $25 per share:
8.84% Series New York Stock Exchange
$2.365 Series New York Stock Exchange
Adjustable Rate, Series A New York Stock Exchange
Adjustable Rate, Series B New York Stock Exchange
$2.81 Series New York Stock Exchange
First Mortgage Bonds:
7-1/2% Series due 2002 New York Stock Exchange
8% Series due 2003 New York Stock Exchange
4
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
Centerior Energy None
Corporation
The Cleveland Electric None
Illuminating Company
The Toledo Edison Cumulative Preferred Stock,
Company par value $100 per share:
4.56% Series and 4.25% Series
---------------------
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K
Into Which Document
Description Is Incorporated
Portions of Proxy Statement of Centerior Energy
Corporation, dated March 23, 1994 Part III
5
TABLE OF CONTENTS
Page
Number
Glossary of Terms iv
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . 1
The Centerior System . . . . . . . . . . . . . . . . . . . . . . 1
CAPCO Group . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Construction and Financing Programs . . . . . . . . . . . . . . 3
Construction Program . . . . . . . . . . . . . . . . . . . . . 3
Financing Program . . . . . . . . . . . . . . . . . . . . . . 5
General Regulation . . . . . . . . . . . . . . . . . . . . . . . 5
Holding Company Regulation . . . . . . . . . . . . . . . . . . 5
State Utility Commissions . . . . . . . . . . . . . . . . . . 6
Ohio Power Siting Board . . . . . . . . . . . . . . . . . . . 7
Federal Energy Regulatory Commission . . . . . . . . . . . . . 7
Nuclear Regulatory Commission . . . . . . . . . . . . . . . . 7
Other Regulation . . . . . . . . . . . . . . . . . . . . . . . 7
Environmental Regulation . . . . . . . . . . . . . . . . . . . . 8
General . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Air Quality Control . . . . . . . . . . . . . . . . . . . . . 8
Water Quality Control . . . . . . . . . . . . . . . . . . . . 9
Waste Disposal . . . . . . . . . . . . . . . . . . . . . . . . 10
Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . . 10
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Sales of Electricity . . . . . . . . . . . . . . . . . . . . . 11
Operating Statistics . . . . . . . . . . . . . . . . . . . . . 12
Nuclear Units . . . . . . . . . . . . . . . . . . . . . . . . 12
Competitive Conditions . . . . . . . . . . . . . . . . . . . . 14
General . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . 15
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . 16
- i -
6
Page
Number
Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . 17
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Executive Officers of the Registrants and the Service Company . 20
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . 26
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
The Centerior System . . . . . . . . . . . . . . . . . . . . . 26
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . 27
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . 27
Title to Property . . . . . . . . . . . . . . . . . . . . . . . 28
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 30
Item 4. Submission of Matters to a Vote of Security Holders . . . 30
PART II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . 30
Market Information . . . . . . . . . . . . . . . . . . . . . . 31
Share Owners . . . . . . . . . . . . . . . . . . . . . . . . . 31
Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . 31
Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 31
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . 32
Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 32
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32
- ii -
7
Page
Number
Item 8. Financial Statements and Supplementary Data . . . . . . . 32
Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 32
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 32
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 32
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . 32
PART III
Item 10. Directors and Executive Officers of the Registrants . . 33
Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 33
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 33
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 33
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . 34
Centerior Energy, Cleveland Electric and Toledo Edison . . . . . 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . 34
Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . . 34
Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . . 36
Toledo Edison . . . . . . . . . . . . . . . . . . . . . . . . . 36
Item 13. Certain Relationships and Related Transactions . . . . . 37
Centerior Energy, Cleveland Electric and Toledo Edison . . . . . 37
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . . 37
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Index to Selected Financial Data; Management's Discussion and
Analysis of Financial Condition and Results of Operations;
and Financial Statements . . . . . . . . . . . . . . . . . . . . . F-1
Index to Schedules . . . . . . . . . . . . . . . . . . . . . . . . . S-1
The Cleveland Electric Illuminating Company and Subsidiaries and The
Toledo Edison Company Combined Pro Forma Condensed Financial
Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . P-1
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1
- iii -
8
This combined Form 10-K is separately filed by Centerior Energy Corporation,
The Cleveland Electric Illuminating Company and The Toledo Edison Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. No registrant makes any representation as
to information relating to any other registrant, except that information
relating to either or both of the Operating Companies is also attributed to
Centerior Energy.
GLOSSARY OF TERMS
The following terms and abbreviations used in the text of this report are
defined as indicated:
Term Definition
AFUDC Allowance for Funds Used During Construction.
AMP-Ohio American Municipal Power-Ohio, Inc., an Ohio
not-for-profit corporation, the members of
which are certain Ohio municipal electric
systems.
Beaver Valley Unit 2 Unit 2 of the Beaver Valley Power Station, in
which the Operating Companies have ownership
and leasehold interests.
CAPCO Group Central Area Power Coordination Group.
Centerior Energy or Centerior Centerior Energy Corporation.
Centerior System Centerior Energy, the Operating Companies and
the Service Company.
Clean Air Act Federal Clean Air Act of 1970 as amended.
Clean Air Act Amendments November 1990 Amendments to the Clean Air
Act.
Clean Water Act Federal Water Pollution Control Act as
amended.
Cleveland Electric The Cleveland Electric Illuminating Company,
an electric utility subsidiary of Centerior
Energy and a member of the CAPCO Group.
Consol Consolidation Coal Company.
CPP Cleveland Public Power, a municipal electric
system operated by the City of Cleveland.
CWIP Construction Work in Progress.
Davis-Besse Davis-Besse Nuclear Power Station.
- iv -
9
Term Definition
Detroit Edison Detroit Edison Company, an electric utility.
District of Columbia United States Court of Appeals for the Dis-
Circuit Appeals Court trict of Columbia Circuit.
DOE United States Department of Energy.
Duquesne Duquesne Light Company, an electric utility
subsidiary of DQE, Inc. and a member of the
CAPCO Group.
ECAR East Central Area Reliability Coordination
Group.
Energy Act Energy Policy Act of 1992.
Federal Power Act Federal Power Act, as amended, codified in
Chapter 12 of Title 16 of the United States
Code.
FERC Federal Energy Regulatory Commission.
General Electric General Electric Company.
Holding Company Act Public Utility Holding Company Act of 1935.
Mansfield Plant Bruce Mansfield Generating Plant, a coal-
fired power plant, in which the Operating
Companies have leasehold interests as joint
and several lessees.
Note or Notes Note or Notes to the Financial Statements in
the Centerior Energy, Cleveland Electric and
Toledo Edison Annual Reports for 1993 (Note
or Notes, where used, refers to all three
companies unless otherwise specified).
NPDES National Pollutant Discharge Elimination
System.
NRC United States Nuclear Regulatory Commission.
Ohio Edison Ohio Edison Company, an electric utility and
a member of the CAPCO Group.
Ohio EPA Ohio Environmental Protection Agency.
Ohio Power Ohio Power Company, an electric utility sub-
sidiary of American Electric Power Company,
Inc.
- v -
10
Term Definition
Ohio Valley The Ohio Valley Coal Company, the successor
corporation to The Nacco Mining Company and a
subsidiary of Ohio Valley Resources, Inc.
Operating Companies Cleveland Electric and Toledo Edison.
(individually, Operating
Company)
OPSB Ohio Power Siting Board.
PaPUC Pennsylvania Public Utility Commission.
Penelec Pennsylvania Electric Company, an electric
utility subsidiary of GPU.
Pennsylvania Power Pennsylvania Power Company, an electric
utility subsidiary of Ohio Edison and a
member of the CAPCO Group.
Perry Plant Perry Nuclear Power Plant.
Perry Unit 1 and Perry Unit 2 Unit 1 and Unit 2 of the Perry Plant, in
which the Operating Companies have ownership
interests.
PUCO The Public Utilities Commission of Ohio.
Quarto Quarto Mining Company, a subsidiary of
Consol.
SALP Systematic Assessment of Licensee
Performance - the NRC's performance
evaluation of a nuclear unit.
SEC United States Securities and Exchange
Commission.
Seneca Plant Seneca Power Plant, a pumped-storage, hydro-
electric generating station jointly owned by
Cleveland Electric and Penelec.
Service Company Centerior Service Company, a service sub-
sidiary of Centerior Energy.
Superfund Comprehensive Environmental Response, Com-
pensation and Liability Act of 1980 and the
Superfund Amendments and Reauthorization Act
of 1986.
- vi -
11
Term Definition
Toledo Edison The Toledo Edison Company, an electric
utility subsidiary of Centerior Energy and a
member of the CAPCO Group.
U.S. EPA United States Environmental Protection
Agency.
Westinghouse Westinghouse Electric Corporation.
- vii -
12
PART I
Item 1. Business
THE CENTERIOR SYSTEM
Centerior Energy is a public utility holding company and the parent company of
the Operating Companies and the Service Company. Centerior was incorporated
under the laws of the State of Ohio in 1985 for the purpose of enabling
Cleveland Electric and Toledo Edison to affiliate by becoming wholly owned
subsidiaries of Centerior. The affiliation of the Operating Companies became
effective in April 1986. Nearly all of the consolidated operating revenues of
the Centerior System are derived from the sale of electric energy by Cleveland
Electric and Toledo Edison.
The Operating Companies' combined service areas encompass approximately 4,200
square miles in northeastern and northwestern Ohio with an estimated popula-
tion of about 2,600,000. At December 31, 1993, the Centerior System had 6,748
employees. Centerior Energy has no employees.
Cleveland Electric, which was incorporated under the laws of the State of Ohio
in 1892, is a public utility engaged in the generation, purchase, transmis-
sion, distribution and sale of electric energy in an area of approximately
1,700 square miles in northeastern Ohio, including the City of Cleveland.
Cleveland Electric also provides electric energy at wholesale to other elec-
tric utility companies and to two municipal electric systems (directly and
through AMP-Ohio) in its service area. Cleveland Electric serves approxi-
mately 748,000 customers and derives approximately 75% of its total electric
revenue from customers outside the City of Cleveland. Principal industries
served by Cleveland Electric include those producing steel and other primary
metals; automotive and other transportation equipment; chemicals; electrical
and nonelectrical machinery; fabricated metal products; and rubber and plastic
products. Nearly all of Cleveland Electric's operating revenues are derived
from the sale of electric energy. At December 31, 1993, Cleveland Electric
had 3,606 employees of which about 51% were represented by one union having a
collective bargaining agreement with Cleveland Electric.
Toledo Edison, which was incorporated under the laws of the State of Ohio in
1901, is a public utility engaged in the generation, purchase, transmission,
distribution and sale of electric energy in an area of approximately 2,500
square miles in northwestern Ohio, including the City of Toledo. Toledo
Edison also provides electric energy at wholesale to other electric utility
companies and to 13 municipally owned distribution systems (through AMP-Ohio)
and one rural electric cooperative distribution system in its service area.
Toledo Edison serves approximately 285,000 customers and derives approximately
55% of its total electric revenue from customers outside the City of Toledo.
Among the principal industries served by Toledo Edison are metal casting,
forming and fabricating; petroleum refining; automotive equipment and
assembly; food processing; and glass. Nearly all of Toledo Edison's operating
revenues are derived from the sale of electric energy. At December 31, 1993,
Toledo Edison had 1,909 employees of which about 55% were represented by three
unions having collective bargaining agreements with Toledo Edison.
13
The Service Company, which was incorporated in 1986 under the laws of the
State of Ohio, is also a wholly owned subsidiary of Centerior Energy. It pro-
vides management, financial, administrative, engineering, legal, governmental
and public relations and other services to Centerior Energy and the Operating
Companies. At December 31, 1993, the Service Company had 1,233 employees.
On March 25, 1994, Centerior Energy announced plans to merge Toledo Edison
into Cleveland Electric. Since Cleveland Electric and Toledo Edison
affiliated in 1986, efforts have been made to consolidate operations and
administration as much as possible to achieve maximum cost savings. The
merger of the two companies into a single entity is the completion of this
consolidation process. Various aspects of the merger are subject to the
approval of the FERC, the PUCO, the PaPUC and other regulatory authorities.
The merger must be approved by Toledo Edison preferred stock share owners.
Preferred stock share owners of Cleveland Electric must approve the authori-
zation of additional shares of preferred stock. Upon the merger becoming
effective, the outstanding shares of Toledo Edison preferred stock will be
exchanged for shares of Cleveland Electric preferred stock having sub-
stantially the same terms. Cleveland Electric and Toledo Edison plan to seek
preferred share owner approval in the summer of 1994. The merger is expected
to be effective late in 1994.
See Note 15 to the Operating Companies' Financial Statements for further
discussion of this matter and "3. Combined Pro Forma Condensed Financial
Statements (Unaudited)" contained under Item 14. of this Report for selected
historical and combined pro forma financial information of Cleveland Electric
and Toledo Edison.
CAPCO GROUP
Cleveland Electric and Toledo Edison are members of the CAPCO Group, a power
pool created in 1967 with Duquesne, Ohio Edison and Pennsylvania Power. This
pool affords greater reliability and lower cost of providing electric service
through coordinated generating unit operations and maintenance and generating
reserve back-up among the five companies. In addition, the CAPCO Group has
completed programs to construct larger, more efficient electric generating
units and to strengthen interconnections within the pool.
The CAPCO Group companies have placed in service nine major generating units,
of which the Operating Companies have ownership or leasehold interests in
seven (three nuclear and four coal-fired). Each CAPCO Group company owns, as
a tenant-in-common, or leases a portion of certain of these generating units.
Each company has the right to the net capability and associated energy of its
respective ownership and leasehold portions of the units and is, severally and
not jointly, obligated for the capital and operating costs equivalent to its
respective ownership and leasehold portions of the units and the required
fuel, except that the obligations of Pennsylvania Power are the joint and
several obligations of that company and Ohio Edison and except that the
leasehold obligations of Cleveland Electric and Toledo Edison are joint and
several. (See "Operations--Fuel Supply".) For all plants but one, the
company in whose service area a generating unit is located is responsible for
the operation of that unit for all the owners, except for the procurement of
nuclear fuel for a nuclear generating unit. The Mansfield Plant, which is
located in Duquesne's service area, is operated by Pennsylvania Power. Each
company owns the necessary interconnecting transmission facilities within its
service area, and the other CAPCO Group companies contribute toward fixed
charges and operating costs of those transmission facilities.
14
All of the CAPCO Group companies are members of ECAR, which is comprised of 28
electric companies located in nine contiguous states. ECAR's purpose is to
improve reliability of bulk power supply through coordination of planning and
operation of member companies' generation and transmission facilities.
CONSTRUCTION AND FINANCING PROGRAMS
Construction Program
The Centerior System carries on a continuous program of constructing trans-
mission, distribution and general facilities and modifying existing generating
facilities to meet anticipated demand for electric service, to comply with
governmental regulations and to protect the environment. The Operating
Companies' 1993 long-term (20-year) forecast, as filed with the PUCO (see
"General Regulation--State Utility Commissions"), projects long-term annual
growth rates in peak demand and kilowatt-hour sales for the Operating
Companies of 1.1% and 1.4%, respectively, after demand-side management con-
siderations. The Centerior System's integrated resource plan for the 1990s
(which is included in the long-term forecast) combines demand-side management
programs with maximum utilization of existing generating capacity to postpone
the need for new generating units until the next decade. Demand-side manage-
ment programs, such as energy-efficient lighting and motors, curtailable load
and energy management, are expected to assist customers in achieving greater
energy efficiency. Centerior plans to invest up to $35,000,000 in demand-side
programs in 1994 and 1995.
Operable capacity margins over the next ten years are expected to be adequate
without adding generating capacity. According to the current long-term
integrated resource plan, the next increment of generating capacity that the
Centerior System plans to put into service will be two 136,000-kilowatt units
in 2003, with additional small, short-lead-time capacity in subsequent years.
The following tables show, categorized by major components, the construction
expenditures by Cleveland Electric and Toledo Edison and, by aggregating them,
for the Centerior System during 1991, 1992 and 1993 and the estimated cost of
their construction programs for 1994 through 1998, in each case including
AFUDC and excluding nuclear fuel:
Actual Estimated
1991 1992 1993 1994 1995 1996 1997 1998
Cleveland Electric (Millions of Dollars)
Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ -
Transmission, Distribution
and General Facilities 77 73 85 76 82 86 96 97
Renovation and Modification
of Generating Units
Nuclear 25 23 16 18 14 15 14 11
Nonnuclear 48 56 65 55 70 36 29 41
Clean Air Act Amendments
Compliance 0 1 9 27 22 3 4 33
Total $150 $156 $175 $176 $188 $140 $143 $182
Note: The footnote to the tables is on the following page.
15
Actual Estimated
1991 1992 1993 1994 1995 1996 1997 1998
Toledo Edison (Millions of Dollars)
Perry Unit 2* $ 0 $ 0 $ 0 $ - $ - $ - $ - $ -
Transmission, Distribution
and General Facilities 30 25 22 23 27 26 25 20
Renovation and Modification
of Generating Units
Nuclear 17 12 15 15 10 12 10 8
Nonnuclear 7 7 6 11 9 6 6 8
Clean Air Act Amendments
Compliance 0 0 0 6 4 11 11 11
Total $ 54 $ 44 $ 43 $ 55 $ 50 $ 55 $ 52 $ 47
Actual Estimated
1991 1992 1993 1994 1995 1996 1997 1998
Centerior System (Millions of Dollars)
Perry Unit 2* $ 0 $ 3 $ 0 $ - $ - $ - $ - $ -
Transmission, Distribution
and General Facilities 107 98 107 99 109 112 121 117
Renovation and Modification
of Generating Units
Nuclear 42 35 31 33 24 27 24 19
Nonnuclear 55 63 71 66 79 42 35 49
Clean Air Act Amendments
Compliance 0 1 9 33 26 14 15 44
Total $204 $200 $218 $231 $238 $195 $195 $229
*Construction of Perry Unit 2 was suspended in 1985. In 1992, Cleveland
Electric purchased Duquesne's ownership share of Perry Unit 2 for
$3,324,000. At December 31, 1993, Centerior Energy, Cleveland Electric
and Toledo Edison wrote off their investment in Perry Unit 2 (see Note
4(b)).
Each company in the CAPCO Group is responsible for financing the portion of
the capital costs of nuclear fuel equivalent to its ownership and leased
interest in the unit in which the fuel will be utilized. See "Operations--
Fuel Supply--Nuclear" for information regarding nuclear fuel supplies and Note
6 regarding leasing arrangements to finance nuclear fuel capital costs.
Nuclear fuel capital costs incurred by Cleveland Electric, Toledo Edison and
the Centerior System during 1991, 1992 and 1993 and their estimated nuclear
fuel capital costs for 1994 through 1998 are as follows:
16
Actual Estimated
1991 1992 1993 1994 1995 1996 1997 1998
(Millions of Dollars)
Cleveland Electric $ 32 $ 30 $ 26 $ 28 $ 18 $ 29 $ 33 $ 37
Toledo Edison $ 27 $ 22 $ 20 $ 23 $ 12 $ 30 $ 27 $ 28
Centerior System $ 59 $ 52 $ 46 $ 51 $ 30 $ 59 $ 60 $ 65
Financing Program
Reference is made to Centerior Energy's, Cleveland Electric's and Toledo
Edison's Management's Financial Analysis contained under Item 7 of this Report
and to Notes 11 and 12 for discussions of the Centerior System's financing
activity in 1993; debt and preferred stock redemption requirements during the
1994-1998 period; expected external financing needs during such period; re-
strictions on the issuance of additional debt securities and preferred stock;
short-term and long-term financing capability; and securities ratings for the
Operating Companies.
In the second quarter of 1994, Cleveland Electric and Toledo Edison expect to
issue $46,100,000 and $30,500,000, respectively, of first mortgage bonds as
collateral security for the sale by a public authority of equal principal
amounts of tax-exempt bonds. The proceeds from the sales of the public
authority's bonds will be used to refund $46,100,000 and $30,500,000, respec-
tively, of tax-exempt bonds that were issued in 1988 and have been continu-
ously remarketed on a floating rate basis. The new series of bonds will each
be issued at a fixed rate of interest for the remaining term to July 1, 2023.
Centerior expects to raise about $35,000,000 in 1994 from the sale of
authorized but unissued common stock under certain of its employee and share
owner stock purchase plans.
GENERAL REGULATION
Holding Company Regulation
Centerior Energy is currently exempt from regulation under the Holding Company
Act.
The Energy Act contains, among other provisions, amendments to the Holding
Company Act and the Federal Power Act. The Energy Act also adopted nuclear
power licensing and related regulations, energy efficiency standards and
incentives for the use of alternative transportation fuels. Amendments to the
Holding Company Act create a new class of independent power producers known as
"Exempt Wholesale Generators", which are exempt from the Holding Company Act
corporate structure regulations and operate without SEC approval or
regulation. Exempt Wholesale Generators may be owned by holding companies,
electric utility companies or any other person.
17
State Utility Commissions
- -------------------------
The Operating Companies are subject to the jurisdiction of the PUCO with re-
spect to rates, service, accounting, issuance of securities and other matters.
Under Ohio law, municipalities may regulate rates, subject to appeal to the
PUCO if not acceptable to the utility. See "Electric Rates" for a description
of certain aspects of Ohio rate-making law. The Operating Companies are also
subject to the jurisdiction of the PaPUC in certain respects relating to their
ownership interests in generating facilities located in Pennsylvania.
The PUCO is composed of five commissioners appointed by the Governor of Ohio
from nominees recommended by a Public Utility Commission Nominating Council.
Nominees must have at least three years' experience in one of several disci-
plines. Not more than three commissioners may belong to the same political
party.
Under Ohio law, a public utility must file annually with the PUCO a long-term
forecast of customer loads, facilities needed to serve those loads and
prospective sites for those facilities. This forecast must include the
following:
(1) Demand Forecast--the utility's 20-year forecast of sales and peak demand,
before and after the effects of demand-side management programs.
(2) Integrated Resource Plan (required biennially)--the utility's projected
mix of resource options to meet the projected demand.
(3) Short-Term Implementation Plan and Status Report (required biennially)--
the utility's discussion of how it plans to implement its integrated
resource plan over the next four years. Estimates of annual expenditures
and security issuances associated with the integrated resource plan over
the four-year period must also be provided.
The PUCO must hold a public hearing on the long-term forecast at least once
every five years to determine the reasonableness of such forecast. The PUCO
and the OPSB are required to consider the record of such hearings in proceed-
ings for approving facility sites, changing rates, approving security issues
and initiating energy conservation programs. Ohio law also permits electric
utilities under PUCO jurisdiction to submit environmental compliance plans for
PUCO review and approval. Ohio law requires that the PUCO make certain
statutory findings prior to approving the environmental compliance plan, which
includes that the plan is a reasonable least cost strategy for compliance with
air quality requirements. In 1992, the PUCO held hearings on the Operating
Companies' 1992 long-term forecast and environmental compliance plan.
Centerior and the parties intervening in the proceeding reached agreement on
the forecast and environmental compliance plan, and the agreement was sub-
sequently approved by the PUCO in February 1993.
The PUCO has jurisdiction over certain transactions by companies in an elec-
tric utility holding company system if it includes at least one Ohio electric
utility and is exempt from regulation under Section 3(a)(1) or (2) of the
Holding Company Act. An Ohio electric utility in such a holding company
18
system, such as Centerior, must obtain PUCO approval to invest in, lend funds
to, guarantee the obligations of or otherwise finance or transfer assets to
any nonutility company in that holding company system, unless the transaction
is in the ordinary course of business operations in which one company acts for
or with respect to another company. Also, the holding company in such a hold-
ing company system must obtain PUCO approval to make any investment in any
nonutility subsidiaries, affiliates or associates of the holding company if
such investment would cause all such capital investments to exceed 15% of the
consolidated capitalization of the holding company unless such funds were
provided by nonutility subsidiaries, affiliates or associates.
The PUCO has a reserve capacity policy for electric utilities in Ohio stating
that (i) 20% of service area peak load excluding interruptible load is an
appropriate generic benchmark for an electric utility's reserve margin; (ii) a
reserve margin exceeding 20% gives rise to a presumption of excess capacity,
but may be appropriate if it confers a positive net present benefit to cus-
tomers or is justified by unique system characteristics; and (iii) appropriate
remedies for excess capacity (possibly including disallowance of costs in
rates) will be determined by the PUCO on a case-by-case basis.
Ohio Power Siting Board
The OPSB has state-wide jurisdiction, except to the extent pre-empted by
Federal law, over the location, need for and certain environmental aspects of
electric generating units with a capacity of 50,000 kilowatts or more and
transmission lines with a rating of at least 125 kV.
Federal Energy Regulatory Commission
The Operating Companies are each subject to the jurisdiction of the FERC with
respect to the transmission and sale of power at wholesale in interstate com-
merce, interconnections with other utilities, accounting and certain other
matters. Cleveland Electric is also subject to FERC jurisdiction with respect
to its ownership and operation of the Seneca Plant.
Nuclear Regulatory Commission
The nuclear generating units in which the Operating Companies have an interest
are subject to regulation by the NRC. The NRC's jurisdiction encompasses
broad supervisory and regulatory powers over the construction and operation of
nuclear reactors, including matters of health and safety, antitrust considera-
tions and environmental impacts.
Owners of nuclear units are required to purchase the full amount of nuclear
liability insurance available. See Note 5(b) for a description of nuclear in-
surance coverages.
Other Regulation
The Operating Companies are subject to regulation by Federal, state and local
authorities with regard to the location, construction and operation of certain
facilities. The Operating Companies are also subject to regulation by local
authorities with respect to certain zoning and planning matters.
19
ENVIRONMENTAL REGULATION
General
The Operating Companies are subject to regulation with respect to air quality,
water quality and waste disposal matters. Federal environmental legislation
affecting the operations and properties of the Operating Companies includes
the Clean Air Act, the Clean Air Act Amendments, the Clean Water Act,
Superfund, and the Resource Conservation and Recovery Act. The requirements
of these statutes and related state and local laws are continually changing
due to the promulgation of new or revised laws and regulations and the results
of judicial and agency proceedings. Compliance with such laws and regulations
may require the Operating Companies to modify, supplement, abandon or replace
facilities and may delay or impede construction and operation of facilities,
all at costs which could be substantial. The Operating Companies expect that
the impact of such costs would eventually be reflected in their respective
rate schedules. Cleveland Electric and Toledo Edison plan to spend, during
the period 1994-1996, $70,000,000 and $20,000,000, respectively, for pollution
control facilities, including Clean Air Act Amendments compliance costs.
The Operating Companies believe that they are currently in compliance in all
material respects with all applicable environmental laws and regulations, or
to the extent that one or both of the Operating Companies may dispute the
applicability or interpretation of a particular environmental law or regula-
tion, the affected company has filed an appeal or has applied for permits,
revisions in requirements, variances or extensions of deadlines.
Concerns have been raised regarding the possible health effects associated
with electric and magnetic fields. Although scientific research as to such
effects has yielded inconclusive results, additional studies are being con-
ducted. If electric and magnetic fields are ultimately found to pose a health
risk, the Operating Companies may be required to modify transmission and
distribution lines or other facilities.
Air Quality Control
Under the Clean Air Act, the Ohio EPA has adopted Ohio emission limitations
for particulate matter and sulfur dioxide for each of the Operating Companies'
plants. The Clean Air Act provides for civil penalties of up to $25,000 per
day for each violation of an emission limitation. The U.S. EPA has approved
the Ohio EPA's emission limitations and the related implementation plans ex-
cept for some particulate matter emissions and certain sulfur dioxide emis-
sions. The U.S. EPA has adopted separate sulfur dioxide emission limitations
for each of the Operating Companies' plants.
In November 1990, the Clean Air Act Amendments were signed into law imposing
restrictions on nitrogen oxides emissions and making sulfur dioxide emission
limitations significantly more severe beginning in 1995. See Note 4(a) for a
description of the Operating Companies' compliance strategy, which was in-
cluded in the agreement approved by the PUCO in February 1993 in connection
with the Operating Companies' 1992 long-term forecast. The Clean Air Act
20
Amendments also require studies to be conducted on the emission of certain
potentially hazardous air pollutants which could lead to additional
restrictions.
In 1985, the U.S. EPA issued revised regulations specifying the extent to
which power plant stack height may be incorporated into the establishment of
an emission limitation. Pursuant to the revised regulations, the Operating
Companies submitted to the Ohio EPA information intended to support continua-
tion of the stack height credit received under the previous regulations for
stacks at Cleveland Electric's Avon Lake and Eastlake Plants and Toledo
Edison's Bay Shore Station. The Ohio EPA has accepted the submissions and
forwarded them to the U.S. EPA for approval. In January 1988, the District of
Columbia Circuit Appeals Court remanded portions of the 1985 regulations to
the U.S. EPA for further consideration; however, the U.S. EPA has not taken
action specifically on this issue.
Congress is considering legislation to reduce emissions of gases such as those
resulting from the burning of coal that are thought to cause global warming.
If such legislation is adopted, the cost of operating coal-fired plants could
increase significantly and coal-fired generating capacity could decrease
significantly.
Water Quality Control
The Clean Water Act requires that power plants obtain permits that contain
certain effluent limitations (that is, limits on discharges of pollutants into
bodies of water). It also requires the states to establish water quality
standards (which could result in more stringent effluent limitations than
those required under the Clean Water Act) and a permit system to be approved
by the U.S. EPA. Violators of effluent limitations and water quality
standards are subject to a civil penalty of up to $25,000 per day for each
such violation.
The Clean Water Act permits thermal effluent limitations to be established for
a facility which are less stringent than those which otherwise would apply if
the owner can demonstrate that such less stringent limitations are sufficient
to assure the protection and propagation of aquatic and other wildlife in the
affected body of water. By 1978, the Operating Companies had submitted to the
Ohio EPA such demonstrations for review with respect to their Ashtabula, Avon
Lake, Lake Shore, Eastlake, Acme and Bay Shore plants. The Ohio EPA has taken
no action on the submittals.
The Operating Companies have received NPDES permit renewals from the Ohio EPA
or have applied for such renewals for all of their power plants. In those
situations where a permit application is pending, the affected plant may con-
tinue to operate under the expired permit while such application is pending.
Any violation of an NPDES permit is considered to be a violation of the Clean
Water Act subject to the penalty discussed above.
21
In 1990, the Ohio EPA issued revised water quality standards applicable to
Lake Erie and waters of the State of Ohio. Based upon these revised water
quality standards, the Ohio EPA placed additional effluent limitations in
their most recent NPDES permits. The revised standards also may serve as the
basis for more stringent effluent limitations in future NPDES permits. Such
limitations could result in the installation of additional pollution control
equipment and increased operating expenses. The Operating Companies are
monitoring discharges at their plants to support their position that addi-
tional effluent limitations are not justified.
On April 16, 1993, the U.S. EPA issued proposed rules for water quality
standards applicable to all states abutting the Great Lakes, including Ohio.
These states would be required to adopt state water quality standards and
procedures consistent with the rules within two years of final publication.
Preliminary reviews indicate that the cost of complying with these rules could
be significant. However, Centerior cannot determine what impact these rules
will have on its operations until such rules are issued in final form and are
incorporated into Ohio regulations.
Waste Disposal
See "Hazardous Waste Disposal Sites" in Management's Financial Analysis
contained under Item 7 of this Report and Note 4(c) for a discussion of the
Operating Companies' potential involvement in certain hazardous waste disposal
sites, including those subject to Superfund. See "Nuclear Units" and "Fuel
Supply--Nuclear" under "Operations", below, for discussions concerning the
disposal of nuclear waste.
The Resource Conservation and Recovery Act exempts certain fossil fuel com-
bustion waste products, such as fly ash, from hazardous waste disposal re-
quirements. The Operating Companies are unable to predict whether Congress
will choose to amend this exemption in the future or, if so, the costs relat-
ing to any required changes in the operations of the Operating Companies.
ELECTRIC RATES
Under Ohio law, rate base is the original cost less depreciation of a
utility's total plant adjusted for certain items. The law permits the PUCO,
in its discretion, to include CWIP in rate base when a construction project is
at least 75% complete, but limits the amount included to 10% of rate base ex-
cluding CWIP or, in the case of a project to construct pollution control fa-
cilities which would remove sulfur and nitrous oxides from flue gas emissions,
20% of rate base excluding CWIP. When a project is completed, the portion of
its cost which had been included in rate base as CWIP is excluded from rate
base until the revenue received due to the CWIP inclusion is offset by the
revenue lost due to its exclusion. During this period of time, an AFUDC-type
credit is allowed on the portion of the project cost excluded from rate base.
Also, the law permits inclusion of CWIP for a particular project for a period
not longer than 48 consecutive months, plus any time needed to comply with
22
changed governmental regulations, standards or approvals. The PUCO is em-
powered to permit inclusion for up to another 12 months for good cause shown.
If a project is canceled or not completed within the allowable period of time
after inclusion of its CWIP has started, then CWIP is excluded from rate base
and any revenues which resulted from such prior inclusion are offset against
future revenues over the same period of time as the CWIP was included.
Current Ohio law further provides that requested rates can be collected by a
public utility, subject to refund, if the PUCO does not make a decision within
275 days after the rate request application is filed. If the PUCO does not
make its final decision within 545 days, revenues collected thereafter are not
subject to refund. A notice of intent to file an application for a rate in-
crease cannot be filed before the issuance of a final order in any prior pend-
ing application for a rate increase or until 275 days after the filing of the
prior application, whichever is earlier. The minimum period by which the
notice of intent to file must precede the actual filing is 30 days. The test
year for determining rates may not end more than nine months after the date
the application for a rate increase is filed.
Under Ohio law, electric rates are adjusted every six months to reflect
changes in fuel costs. The PUCO reviews such adjustments annually. Any
difference between actual fuel costs during a six-month period and the fuel
revenues recovered in that period is deferred and is taken into account in
setting the fuel recovery factor for a subsequent six-month period.
The PUCO has authorized the Operating Companies to adjust their rates on a
seasonal basis such that electric rates are higher in the summer.
Also, under Ohio law, municipalities may regulate rates charged by a utility,
subject to appeal to the PUCO if not acceptable to the utility. If
municipally fixed rates are accepted by the utility, such rates are binding on
both parties for the specified term and cannot be changed by the PUCO.
See Note 7 and Management's Financial Analysis contained under Item 7 of this
Report for information relating to the PUCO's January 1989 rate orders and the
Rate Stabilization Program that was approved by the PUCO for the Operating
Companies in October 1992.
OPERATIONS
Sales of Electricity
Kilowatt-hour sales by the Operating Companies follow a seasonal pattern
marked by increased customer usage in the summer for air conditioning and in
the winter for heating. Historically, Cleveland Electric has experienced its
heaviest demand for electric service during the summer months because of a
significant air conditioning load on its system and a relatively low amount of
electric heating load in the winter. Toledo Edison, although having a
significant electric heating load, has experienced in recent years its
heaviest demand for electric service during the summer months because of heavy
air conditioning usage.
23
The Centerior System's largest customer is a steel manufacturer which has two
major steel producing facilities served by Cleveland Electric. Sales to these
facilities accounted for 2.5% and 3.5% of the 1993 total electric operating
revenues of Centerior Energy and Cleveland Electric, respectively. The loss
of these facilities (and the resultant loss of another large customer whose
primary product is purchased by the two steel producing facilities) would
reduce Centerior Energy's and Cleveland Electric's net income by about
$34,000,000 based on 1993 sales levels.
The largest customer served by Toledo Edison is a major automobile manufac-
turer. Sales to this customer accounted for 1.4% and 3.9% of the 1993 total
electric operating revenues of Centerior Energy and Toledo Edison, re-
spectively. The loss of this customer would reduce Centerior Energy's and
Toledo Edison's net income by about $10,000,000 based on 1993 sales levels.
Operating Statistics
For data on operating revenues by service category, electric sales by service
category, customers by service category and electric energy generation for
1983 and 1989 through 1993, see the attached Pages F-23 and F-24 for Centerior
Energy, F-46 and F-47 for Cleveland Electric and F-68 and F-69 for Toledo
Edison.
Nuclear Units
The Operating Companies' generating facilities include, among others, three
nuclear units owned or leased by the CAPCO Group--Perry Unit 1, Beaver Valley
Unit 2 and Davis-Besse. These three units are in commercial operation.
Cleveland Electric has responsibility for operating Perry Unit 1, Duquesne has
responsibility for operating Beaver Valley Unit 2 and Toledo Edison has re-
sponsibility for operating Davis-Besse. Cleveland Electric and Toledo Edison
own, respectively, 31.11% and 19.91% of Perry Unit 1, 24.47% and 1.65% of
Beaver Valley Unit 2 and 51.38% and 48.62% of Davis-Besse. Cleveland Electric
and Toledo Edison also lease, as joint lessees, another 18.26% of Beaver
Valley Unit 2 as a result of a September 1987 sale and leaseback transaction
(see Note 2).
Davis-Besse was placed in commercial operation in 1977, and its operating
license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2 were placed in
commercial operation in 1987, and their operating licenses expire in 2026 and
2027, respectively.
As part of its January 1989 rate orders, the PUCO approved nuclear plant
performance standards for the Operating Companies based on rolling three-year
industry averages of operating availability for pressurized water reactors and
for boiling water reactors over the 1988-1998 period. Operating availability
is the ratio of the number of hours a unit is available to generate elec-
tricity (whether or not the unit is operated) to the number of hours in the
period, expressed as a percentage. The three-year operating availability
averages of the Operating Companies' nuclear units are compared against the
industry averages for the same three-year period with a resultant penalty or
banked benefit. If the industry performance standards are not met, a penalty
24
would be incurred which would require the Operating Companies to refund in-
cremental replacement power costs to customers through the semiannual fuel
cost rate adjustment. However, if the performance of the Operating Companies'
nuclear units exceeds the industry standards, a banked benefit results which
can be used to offset disallowances of incremental replacement power costs
should future performance be below industry standards.
The relevant industry standards for the 1991-1993 period are 78.0% for
pressurized water reactors such as Davis-Besse and Beaver Valley Unit 2 and
72.8% for boiling water reactors such as Perry Unit 1. The 1991-1993
availability average for Davis-Besse and Beaver Valley Unit 2 was 87.1% and
for Perry Unit 1 was 69.2%. At December 31, 1993, the total banked benefit
for the Operating Companies is estimated to be between $18,000,000 and
$20,000,000.
All three nuclear units have received generally favorable evaluations from the
NRC in their most recent SALP reviews. Each of the functional areas evaluated
is rated according to three performance categories, with category 1 indicating
performance substantially exceeding regulatory requirements and that reduced
NRC attention may be appropriate; category 2 indicating performance above that
needed to meet regulatory requirements and that NRC attention may be main-
tained at normal levels; and category 3 indicating performance does not
significantly exceed that needed to meet minimal regulatory requirements and
that NRC attention should be increased above normal levels. The most recent
review periods and SALP review scores for Perry Unit 1 and Davis-Besse are:
Perry Unit 1 Davis-Besse
SALP Review Period 11/1/91-1/31/93 12/1/91-6/30/93
Plant Operations 2 2
Radiological Controls 2 2
Maintenance/Surveillance 2 1
Emergency Preparedness 1 1
Security and Safeguards 1 1
Engineering/Technical Support 2 1
Safety Assessment/Quality Verif. 3 1
The NRC increased its attention to Perry Unit 1 in 1993 and placed the unit on
a newly created list for units identified as showing "safety performance
trending downward." Centerior made specific organizational changes and
developed a comprehensive course of action to improve the operating
performance of Perry Unit 1. In response to this course of action, on
January 27, 1994, the NRC removed Perry Unit 1 from the performance trending
downward list.
In 1993, the NRC revised the functional areas which comprise the SALP grading
process. Plant Support is a new category which covers the areas previously
covered by Security, Emergency Preparedness and Radiological Controls. The
Safety Assessment/Quality Verification category is now an integral part of
each category and is no longer being singled out. Beaver Valley Unit 2 is the
only Centerior System unit to have been graded under the new system. Perry
Unit 1 and Davis-Besse will be graded under the new system when their next
25
SALP scores are issued. The most recent review period and SALP review scores
for Beaver Valley Unit 2 are:
SALP Review Period 6/14/92-11/27/93
Operations 1
Engineering 2
Maintenance 2
Plant Support 1
The Operating Companies ship low-level radioactive waste produced at their
nuclear plants to an offsite disposal facility which may not accept such
shipments after mid-1994. The Operating Companies' ability to continue
offsite disposal depends on whether the State of Ohio develops a low-level
radioactive waste disposal facility within the next several years. If offsite
disposal becomes unavailable, the Operating Companies have facilities to
temporarily store such waste on site at each of the nuclear plants. However,
the Operating Companies do not intend to store such waste on site until all
available off-site options have been exhausted.
See Note 4(b) for a discussion of the write-off of Perry Unit 2, and see Note
5(a) and "Outlook--Nuclear Operations" in Management's Financial Analysis
contained under Item 7 of this Report for a discussion of potential risks
facing Centerior and the Operating Companies as owners of nuclear generating
units.
Competitive Conditions
General. The Operating Companies compete in their respective service areas
with suppliers of natural gas to satisfy customers' energy needs with regard
to heating and appliance usage. The Operating Companies also are engaged in
competition to a lesser extent with suppliers of oil and liquefied natural gas
for heating purposes and with suppliers of cogeneration equipment. One
competitor provides steam for heating purposes and provides chilled water for
cooling purposes in certain areas of downtown Cleveland.
The Operating Companies also compete with municipally owned electric systems
within their respective service areas. As discussed below, two of the munici-
palities served by the Operating Companies, the City of Toledo and the City of
Garfield Heights, are investigating the economic feasibility of establishing
and operating municipally owned electric systems. A few other communities
have evaluated municipalization of electric service and decided to continue
service from Cleveland Electric and Toledo Edison. Officials in still other
communities have indicated an interest in evaluating the municipalization
issue.
The Operating Companies face continuing competition from locations outside
their service areas which are promoted by governmental and private agencies in
attempts to influence potential and existing commercial and industrial cus-
tomers to locate in their respective areas.
26
Cleveland Electric and Toledo Edison also periodically compete with other
producers of electricity for sales to electric utilities which are in the
market for bulk power purchases. The Operating Companies have inter-
connections with other electric utilities (see "Item 2. Properties--General")
and have a transmission system capable of transmitting ("wheeling") power
between the Midwest and the East.
Cleveland Electric. Located within Cleveland Electric's service area are two
municipally owned electric systems. Cleveland Electric supplies a small
portion of those systems' power needs at wholesale rates.
One of those systems, CPP, is operated by the City of Cleveland in competition
with Cleveland Electric. CPP is primarily an electric distribution system
which currently supplies electric power in approximately 70% of the City's
geographical area (expected to increase to 100% by the end of 1997) and to
approximately 28% (about 59,000) of the electric consumers in the City--equal
to about 8% of all customers served by Cleveland Electric. CPP's kilowatt-
hour sales and revenues are equal to about 5% of Cleveland Electric's
kilowatt-hour sales and revenues. Much of the area served by CPP overlaps
that of Cleveland Electric. For all classes of customers, Cleveland
Electric's rates are higher than CPP's rates due largely to CPP's exemption
from taxation, its reliance on short- and medium-term power supply contracts
and the spot market which are lower in cost and the lower-cost financing
available to CPP.
Cleveland Electric makes power available to CPP on a wholesale basis, subject
to FERC regulation. In 1993, Cleveland Electric directly and through AMP-Ohio
provided about 15% of CPP's energy requirements. The balance of CPP's power is
purchased from other sources and wheeled over Cleveland Electric's transmission
system. In cases currently pending, the FERC has been asked to determine
whether Cleveland Electric is obligated to provide an additional inter-
connection with CPP and to rule on Cleveland Electric's request for an increase
in rates for power and services provided to CPP. Cleveland Electric believes
that it is entitled to a higher level of compensation for the power and the
services it provides because the rates currently paid by CPP do not adequately
cover the cost of providing such power and services.
CPP is constructing new transmission and distribution facilities extending
into eastern portions of Cleveland and plans to expand to western portions of
Cleveland, both of which now are served exclusively by Cleveland Electric.
During the 1991-1993 period, Cleveland Electric had a net loss of about 7,000
customers, including several hundred commercial and industrial customers, to
the CPP system which resulted in a reduction in Cleveland Electric's 1993
annual income of about $14,000,000. CPP's Phase I expansion, as now planned,
could take away about 18,000 more of Cleveland Electric's customers, while its
Phase II expansion could take away about 29,000 customers over the next
several years. This could eventually reduce Cleveland Electric's net income
by about $27,000,000. Cleveland Electric has retained many medium and large
commercial and industrial customers in Cleveland despite CPP's expansion
efforts. Long-term contracts with many of these customers provide them with
economic incentives to remain with Cleveland Electric. Most of those
contracts have remaining terms of one to five years.
27
In 1991, the City of Brook Park, located within the Cleveland Electric service
territory, commissioned a feasibility study regarding the establishment of a
municipal electric system. Ford Motor Company operates a large engine manu-
facturing plant in Brook Park. In April 1993, Cleveland Electric entered into
an agreement with Brook Park running through the year 2000 whereby Cleveland
Electric would make available a total of $1,250,000 for demand-side manage-
ment programs to help reduce the energy bills of Brook Park customers over the
next five years and $400,000 to study the feasibility of a resource recovery
plant in the City to process municipal waste. At the same time, Cleveland
Electric entered into a five-year agreement with Ford Motor Company in Brook
Park which provides pricing incentives to help Ford improve its competitive-
ness and encourage economic growth in Cleveland Electric's service area. The
agreement can be renewed, at Ford's option, through the year 2000.
In March 1994, the City Council of Garfield Heights, a suburb of Cleveland,
passed an ordinance calling for a 30% reduction in rates for Cleveland
Electric's customers in that city. Cleveland Electric will appeal that
ordinance to the PUCO which will allow the existing rates to stay in effect.
The potential impact of the rate reduction on Cleveland Electric's annual
revenues is $5,500,000.
Currently, one commercial customer and one industrial customer of Cleveland
Electric have cogeneration installations. A number of customers have inquired
about cogeneration applications, but there were no new installations in 1991,
1992 or 1993.
Toledo Edison. Located wholly or partly within Toledo Edison's service area
are six rural electric cooperatives, five of which are supplied with power,
transmitted in some cases over Toledo Edison's facilities, by Buckeye Power,
Inc. (an affiliate of a number of Ohio rural electric cooperatives) and the
sixth is supplied by Toledo Edison.
Also located within Toledo Edison's service area are 16 municipally owned
electric distribution systems, three of which are supplied by other electric
systems. Toledo Edison provides a portion of the power purchased by the other
13 municipalities at wholesale rates through a contract with AMP-Ohio that
expires in 2009. Rates under this agreement are permitted to increase
annually to compensate for increased costs of operation. Less than 2% of
Toledo Edison's total electric operating revenues in 1993 were derived from
sales under the AMP-Ohio contract.
In October 1989, the City of Toledo adopted an ordinance establishing an
Electric Franchise Review Committee for the purpose of studying Toledo
Edison's franchise agreement with the City to determine whether alternate
energy sources may be utilized. The Committee investigated the feasibility of
establishing a municipal electric system within the City of Toledo and the
feasibility of utilizing other alternative electric power sources. In May
1992, the Committee recommended that the City negotiate with Toledo Edison
with regard to rates and other customer initiatives rather than create its own
municipal electric system. The Committee recommended that if negotiations
with Toledo Edison were unsuccessful, the City should create a small municipal
utility to serve approximately 20% of the City's electricity load, primarily
28
City facilities, such as the waste water treatment plant, and businesses with
large electricity consumption. In March 1993, the City and Toledo Edison
reached agreement on a non-exclusive franchise which runs through 2000. The
franchise, which was approved by voters in November 1993, will terminate two
years earlier if Toledo Edison files for a rate increase with the PUCO prior
to 1999. The City also retains its right to establish a municipal electric
system. In addition, Toledo Edison will provide $6,000,000 for demand-side
management programs; energy efficiency programs for senior citizens, low
income customers and small businesses; and economic development programs over
a five-year period beginning in 1994. These expenditures will be in addition
to the demand-side management expenditures currently planned by the Centerior
System. The agreement does not call for a reduction in base electric rates.
Meanwhile, the Electric Franchise Review Committee continues to explore the
formation of a municipal system to serve 20% of the load in the City.
The last commercial customer of Toledo Edison having a cogeneration unit
ceased operation of its unit during the first quarter of 1992.
Fuel Supply
Generation by type of fuel for 1993 was 73% coal-fired and 27% nuclear for
Cleveland Electric; 54% coal-fired and 46% nuclear for Toledo Edison; and 67%
coal-fired and 33% nuclear for the Centerior System.
Coal. In 1993, Cleveland Electric and Toledo Edison burned 6,238,000 tons and
2,138,000 tons of coal, respectively, for electric generation. Each utility
normally maintains a reserve supply of coal sufficient for about 40 days of
normal operations. On March 1, 1994, this reserve was about 24 days for
plants operated by Cleveland Electric, 34 days for plants operated by Toledo
Edison and 40 days for the Mansfield Plant, which is operated by Pennsylvania
Power.
In 1993, about 59% of Cleveland Electric's coal requirements were purchased
under long-term contracts, with the longest remaining term being almost 10
years. In most cases, these contracts provide for adjusting the price of the
coal on the basis of changes in coal quality and mining costs. The sulfur
content of the coal purchased under these contracts ranges from less than 1%
to about 4%. The balance of Cleveland Electric's coal was purchased on the
spot market with sulfur content ranging from less than 1% to 3.5%.
In 1993, about 66% of Toledo Edison's coal requirements were purchased under
long-term contracts, with the longest remaining term being almost seven years.
In most cases, these contracts provide for adjusting the price of the coal on
the basis of changes in coal quality and mining costs. The sulfur content of
the coal purchased under these contracts ranges from less than 1% to 4%.
One of Cleveland Electric's long-term coal supply contracts is with Ohio
Valley. Cleveland Electric has agreed to pay Ohio Valley certain amounts to
cover Ohio Valley's costs regardless of the amount of coal actually delivered.
Included in those costs are amounts sufficient to service certain long-term
debt and lease obligations incurred by Ohio Valley. If the coal sales agree-
ment is terminated for any reason, including the inability to use the coal,
29
Cleveland Electric must assume certain of Ohio Valley's debt and lease obli-
gations and may incur other expenses including mine closing costs, if
necessary. The principal amount of debt and termination values of leased
property covered by Cleveland Electric's agreement was $27,116,000 at
December 31, 1993. Cleveland Electric is considering terminating the Ohio
Valley agreement as part of its least cost plan to comply with the
requirements of the Clean Air Act Amendments. If the agreement is so
terminated, Cleveland Electric would ask the PUCO to allow recovery of the
termination charges from its customers through the fuel component. If the
agreement is not terminated early, Cleveland Electric expects that Ohio Valley
revenues from sales of coal will continue to be sufficient for Ohio Valley to
meet its debt and lease obligations. The contract with Ohio Valley expires in
September 1997.
The CAPCO Group companies, including the Operating Companies, have a long-term
contract with Quarto and Consol for the supply of about 75%-85% of the annual
coal needs of the Mansfield Plant. The contract runs through at least the end
of 1999, and the price of coal is adjustable to reflect changes in labor,
materials, transportation and other costs. The CAPCO Group companies have
guaranteed, severally and not jointly, the debt and lease obligations incurred
by Quarto to develop, equip and operate two of the mines which supply the
Mansfield Plant. At December 31, 1993, the total dollar amount of Quarto's
debt and lease obligations guaranteed by Cleveland Electric was $33,380,000
and by Toledo Edison was $19,522,000. Centerior, Cleveland Electric and
Toledo Edison expect that Quarto revenues from sales of coal to the CAPCO
Group companies will continue to be sufficient for Quarto to meet its debt and
lease obligations.
The Operating Companies' least cost plan for complying with the Clean Air Act
Amendments, which was included in the agreement approved by the PUCO in
February 1993 in connection with the Operating Companies' 1992 long-term
forecast, calls for greater use of low-sulfur coal and less use of high-sulfur
coal. Some of the low-sulfur coal required to comply with Phase 1 of the
Clean Air Act Amendments was contracted for in 1992. Additional supplies of
low-sulfur coal will be contracted for in 1994. The only long-term coal
contract affected by the Clean Air Act Amendments is Cleveland Electric's
contract with Ohio Valley.
Nuclear. The acquisition and utilization of nuclear fuel involves six dis-
tinct steps: (i) supply of uranium oxide raw material, (ii) conversion to
uranium hexafluoride, (iii) enrichment, (iv) fabrication into fuel assemblies,
(v) utilization as fuel in a nuclear reactor and (vi) storing or disposing of
spent fuel. The Operating Companies have inventories of raw material
sufficient to provide nuclear fuel through 1996 for the operation of their
nuclear generating units and have contracts for fabrication services for all
of that fuel. The CAPCO Group companies have a 30-year contract with the DOE
which will supply all of the needed enrichment services for their nuclear
units' fuel supply through 1995. Beyond 1995, the amount of enrichment
services under the DOE contract varies by CAPCO Group company, with Cleveland
Electric's and Toledo Edison's enrichment services reduced to 70% in 1996-1999
and reduced to 0% in 2000-2002. The additional required enrichment services
are available. Substantial additional fuel will have to be obtained in the
30
future over the remaining useful lives of the units. There is a plentiful
supply of uranium oxide raw material to meet the industry's nuclear fuel
needs.
Off-site disposal of spent nuclear fuel is unavailable, but the CAPCO Group
companies have contracts with the DOE which provide for the future acceptance
of spent fuel for disposal by the Federal government. Pursuant to the Nuclear
Waste Policy Act of 1982, the Federal government has indicated it will begin
accepting spent fuel from utilities by the year 2010. On-site storage
capacity at Davis-Besse, Perry Unit 1 and Beaver Valley Unit 2 should be
sufficient through 1996, 2009 and 2008, respectively. Any additional storage
capacity needed for the period until the government accepts the fuel can be
provided for either on-site or off-site by the time it is needed.
Oil. The Operating Companies each have adequate supplies of oil and fuel for
their oil-fired electric generating units which are used primarily as reserve
and peaking capacity.
31
EXECUTIVE OFFICERS OF THE REGISTRANTS AND THE SERVICE COMPANY
Set forth below are the names, ages as of March 15, 1994, and business
experience during the past five years (effective dates of positions in
parentheses) of the executive officers of Centerior Energy, the Service
Company, Cleveland Electric and Toledo Edison. Positions currently held are
designated with an asterisk (*).
Business Experience
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
Robert J. Farling *Chairman of the *Chairman of the *Chairman of the *Chairman of the
(57) Board and Chief Board and Chief Board and Chief Board and Chief
Executive Officer Executive Executive Officer Executive Officer
(March 1992) Officer (March (February 1989 to (October 1988 to
*President 1992) April 1990; July April 1990; July
(October 1988) *President (July 1993) 1993)
1988)
Murray R. Edelman *Executive Vice *Executive Vice *President *Vice Chairman
(54) President President- (November 1993) (November 1993)
(July 1988) Operations & President (July 1988)
Engineering
(July 1993)
Executive Vice
President-Power
Generation
(April 1990)
32
Business Experience
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
Fred J. Lange, Jr. *Senior Vice *Senior Vice *Vice President *President (November
(44) President President- (April 1990) 1993)
(July 1993) Fossil & Vice President (April
Senior Vice Transmission 1990)
President-Legal, and Distribution
Human & Corporate Operations
Affairs (March (July 1993)
1992) Senior Vice
Vice President- President-Legal,
Legal & Corporate Human &
Affairs (April Corporate Affairs
1990) (March 1992)
Vice President-
Legal & Corporate
Affairs (April
1990)
General Attorney and
Senior Director of
Governmental Affairs
(July 1989)
Assistant General Counsel
and Principal Corporate
Counsel (November 1986)
Donald C. Shelton *Senior Vice Vice President-
(60) President-Nuclear Nuclear (August
(July 1993) 1986)
Vice President-
Nuclear-Davis-
Besse (April
1990)
33
Business Experience
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
Jacquita K. Hauserman *Vice President- *Vice President
(51) Customer Support (November 1993)
(July 1993) Vice President-
Vice President- Administration
Customer Service (October 1988)
& Community
Affairs (April
1990)
Gary R. Leidich *Vice President *Vice President- *Vice President & *Vice President &
(43) (July 1993) Finance & Chief Financial Chief Financial
Administration Officer (July Officer (July
(July 1993) 1993) 1993)
Director-Human
Resources Dept.
(August 1991)
Director-System
Planning
Engineering
Dept. (December
1987)
34
Business Experience
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
Terrence G. Linnert *Vice President *Vice President- *Vice President *Vice President
(47) (July 1993) Legal & (July 1993) (July 1993)
Governmental
Affairs and
General Counsel
(July 1993)
Vice President-
Legal and
General Counsel
(March 1992)
General Counsel
and Director-
Legal Services
Dept. (May 1990)
General Counsel
(July 1989)
Principal Counsel
(June 1987)
David L. Monseau *Vice President- Vice President-
(53) Transmission & Customer
Distribution Operations
Operations (September 1987)
(April 1990)
35
Business Experience
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
Robert A. Stratman *Vice President- General Manager-
(45) Nuclear-Perry Perry Plant
(December 1992) Operations Dept.
(April 1990)
Director-Perry
Plant Nuclear
Engineering
Dept. (January
1989)
Al R. Temple *Vice President-
(48) Marketing
(February 1994)
WMX Technologies, Inc.:
Alliance Executive
(July 1992)
Vice President/
General Manager,
Midwest Region
(April 1991)
Director of
Marketing,
Chemical Waste
Management
(June 1989)
Borg Warner Chemicals:
General Mgr., Multi-
National Accts.
(November 1988)
36
Business Experience
---------------------------------------------------------------------------------
Name (Age) Centerior Energy Service Company Cleveland Electric Toledo Edison
- ---------- ---------------- --------------- ------------------ -------------
Paul G. Busby *Controller (April *Controller (June *Controller (April *Controller (April
(45) 1988) 1986) 1990) 1990)
Gary M. Hawkinson *Treasurer *Treasurer (April *Treasurer (April *Treasurer (April 1990)
(45) (February 1986) 1986) 1990)
Assistant Treasurer Assistant Treasurer
(August 1987) (September 1986)
E. Lyle Pepin *Secretary *Secretary (April *Secretary (October *Secretary (October
(52) (February 1986) 1986) 1988) 1988)
37
All of the executive officers of Centerior Energy, the Service Company,
Cleveland Electric and Toledo Edison are elected annually for a one-year term
by the Board of Directors of Centerior, the Service Company, Cleveland
Electric or Toledo Edison, as the case may be.
No family relationship exists among any of the executive officers and direc-
tors of any of the Centerior System companies.
Item 2. Properties
GENERAL
The Centerior System
The wholly owned, jointly owned and leased electric generating facilities of
the Operating Companies in commercial operation as of February 28, 1994 pro-
vide the Centerior System with a net demonstrated capability of 5,980,000
kilowatts during the winter. These facilities include 20 generating units
(3,634,000 kilowatts) at seven fossil-fired steam electric generation sta-
tions; three nuclear generating units (1,856,000 kilowatts); a 351,000 kilo-
watt share of the Seneca Plant; seven combustion turbine generating units
(135,000 kilowatts) and one diesel generator (4,000 kilowatts). Operations at
two fossil-fired generating units (320,000 kilowatts) ceased in 1993 and the
units are being preserved for future use. All of the Centerior System's
generating facilities are located in Ohio and Pennsylvania.
The Centerior System's net 60-minute peak load of its service area for 1993
was 5,397,000 kilowatts and occurred on August 27. At the time of the 1993
peak load, the operable capacity available to serve the load was 5,998,000
kilowatts. The Centerior System's 1994 service area peak load is forecasted
to be 5,250,000 kilowatts, after demand-side management considerations. The
operable capacity expected to be available to serve the Centerior System's
1994 peak is 5,670,000 kilowatts. Over the 1994-1996 period, Centerior Energy
forecasts its operable capacity margins at the time of the projected Centerior
System peak loads to range from 7% to 9.5%.
Each Operating Company owns the electric transmission and distribution facili-
ties located in its respective service area. Cleveland Electric and Toledo
Edison are interconnected by 345 kV transmission facilities, some portions of
which are owned and used by Ohio Edison. The Operating Companies have a long-
term contract with the CAPCO Group companies, including Ohio Edison, relating
to the use of these facilities. These interconnection facilities provide for
the interchange of power between the two Operating Companies. The Centerior
System is interconnected with Ohio Edison, Ohio Power, Penelec and Detroit
Edison.
38
Cleveland Electric
The wholly owned, jointly owned and leased electric generating facilities of
Cleveland Electric in commercial operation as of February 28, 1994 provide a
net demonstrated capability of 4,148,000 kilowatts during the winter. These
facilities include 16 generating units (2,709,000 kilowatts) at five fossil-
fired steam electric generation stations; its share of three nuclear generat-
ing units (1,026,000 kilowatts); a 351,000 kilowatt share of the Seneca Plant;
two combustion turbine generating units (58,000 kilowatts) and one diesel gen-
erator (4,000 kilowatts). Operations at one fossil-fired generating unit
(245,000 kilowatts) ceased in October 1993 and the unit is being preserved for
future use. All of Cleveland Electric's generating facilities are located in
Ohio and Pennsylvania.
The net 60-minute peak load of Cleveland Electric's service area for 1993 was
3,862,000 kilowatts and occurred on July 28. The operable capacity at the
time of the 1993 peak was 4,122,000 kilowatts. Cleveland Electric's 1994
service area peak load is forecasted to be 3,790,000 kilowatts, after demand-
side management considerations. The operable capacity, which includes firm
purchases, expected to be available to serve Cleveland Electric's 1994 peak is
4,018,000 kilowatts. Over the 1994-1996 period, Cleveland Electric forecasts
its operable capacity margins at the time of its projected peak loads to range
from 6% to 9%.
Cleveland Electric owns the facilities located in the area it serves for
transmitting and distributing power to all its customers. Cleveland Electric
has interconnections with Ohio Edison, Ohio Power and Penelec. The intercon-
nections with Ohio Edison provide for the interchange of electric power with
the other CAPCO Group companies and for transmission of power from the tenant-
in-common owned or leased CAPCO Group generating units as well as for the
interchange of power with Toledo Edison. The interconnection with Penelec
provides for transmission of power from Cleveland Electric's share of the
Seneca Plant. In addition, these interconnections provide the means for the
interchange of electric power with other utilities.
Cleveland Electric has interconnections with each of the municipal systems
operating within its service area.
Toledo Edison
The wholly owned, jointly owned and leased electric generating facilities of
Toledo Edison in commercial operation as of February 28, 1994 provide a net
demonstrated capability of 1,832,000 kilowatts during the winter. These
facilities include six generating units (925,000 kilowatts) at three fossil-
fired steam electric generation stations; its share of three nuclear
generating units (830,000 kilowatts) and five combustion turbine generating
units (77,000 kilowatts). Operations at one fossil-fired generating unit
(75,000 kilowatts) ceased in July 1993 and the unit is being preserved for
future use. All of Toledo Edison's generating facilities are located in Ohio
and Pennsylvania.
39
The net 60-minute peak load of Toledo Edison's service area for 1993 was
1,568,000 kilowatts and occurred on August 27. The operable capacity at the
time of the 1993 peak was 1,874,000 kilowatts. Toledo Edison's 1994 service
area peak load is forecasted to be 1,490,000 kilowatts, after demand-side
management considerations. The operable capacity, which includes the effect
of firm sales, expected to be available to serve Toledo Edison's 1994 peak is
1,652,000 kilowatts. Over the 1994-1996 period, Toledo Edison forecasts its
operable capacity margins at the time of its projected peak loads to range
from 0% to 10%.
Toledo Edison owns the facilities located in the area it serves for trans-
mitting and distributing power to all its customers. Toledo Edison has
interconnections with Ohio Edison, Ohio Power and Detroit Edison. The in-
terconnection with Ohio Edison provides for the interchange of electric power
with the other CAPCO Group companies and for transmission of power from the
tenant-in-common owned or leased CAPCO Group generating units as well as for
the interchange of power with Cleveland Electric. In addition, these inter-
connections provide the means for the interchange of electric power with other
utilities.
Toledo Edison has interconnections with each of the municipal systems
operating within its service area.
TITLE TO PROPERTY
The generating plants and other principal facilities of the Operating
Companies are located on land owned in fee by them, except as follows:
(1) Cleveland Electric and Toledo Edison lease from others for a term of
about 29-1/2 years starting on October 1, 1987 undivided 6.5%, 45.9% and
44.38% tenant-in-common interests in Units 1, 2 and 3, respectively, of
the Mansfield Plant located in Shippingport, Pennsylvania. Cleveland
Electric and Toledo Edison lease from others for a term of about 29-1/2
years starting on October 1, 1987 an 18.26% undivided tenant-in-common
interest in Beaver Valley Unit 2 located in Shippingport, Pennsylvania.
Cleveland Electric and Toledo Edison own another 24.47% interest and
1.65% interest, respectively, in Beaver Valley Unit 2 as a tenant-in-
common. Cleveland Electric and Toledo Edison continue to own as a
tenant-in-common the land upon which the Mansfield Plant and Beaver
Valley Unit 2 are located, but have leased to others certain portions of
that land relating to the above-mentioned generating unit leases.
(2) Most of the facilities of Cleveland Electric's Lake Shore Plant are
situated on artificially filled land, extending beyond the natural shore-
line of Lake Erie as it existed in 1910. As of December 31, 1993, the
cost of Cleveland Electric's facilities, other than water intake and
discharge facilities, located on such artificially filled land aggregated
approximately $112,026,000. Title to land under the water of Lake Erie
within the territorial limits of Ohio (including artificially filled
land) is in the State of Ohio in trust for the people of the State for
the public uses to which it may be adapted, subject to the powers of the
40
United States, the public rights of navigation, water commerce and
fishery and the rights of upland owners to wharf out or fill to make use
of the water. The State is required by statute, after appropriate pro-
ceedings, to grant a lease to an upland owner, such as Cleveland Elec-
tric, which erected and maintained facilities on such filled land prior
to October 13, 1955. Cleveland Electric does not have such a lease from
the State with respect to the artificially filled land on which its Lake
Shore Plant facilities are located, but Cleveland Electric's position, on
advice of counsel for Cleveland Electric, is that its facilities and
occupancy may not be disturbed because they do not interfere with the
free flow of commerce in navigable channels and constitute (at least in
part) and are on land filled pursuant to the exercise by it of its
property rights as owner of the land above the shoreline adjacent to the
filled land. Cleveland Electric holds permits, under Federal statutes
relating to navigation, to occupy such artificially filled land.
(3) The facilities of Cleveland Electric's Seneca Plant in Warren County,
Pennsylvania, are located on land owned by the United States and occupied
by Cleveland Electric and Penelec pursuant to a license issued by the
FERC for a 50-year period starting December 1, 1965 for the construction,
operation and maintenance of a pumped-storage hydroelectric plant.
(4) The water intake and discharge facilities at the electric generating
plants of Cleveland Electric and Toledo Edison located along Lake Erie,
the Maumee River and the Ohio River are extended into the lake and rivers
under their property rights as owners of the land above the water line
and pursuant to permits under Federal statutes relating to navigation.
(5) The transmission systems of the Operating Companies are located on land,
easements or rights-of-way owned by them. Their distribution systems
also are located, in part, on interests in land owned by them, but, for
the most part, their distribution systems are located on lands owned by
others and on streets and highways. In most cases, permission has been
obtained from the apparent owner of the property or, if the distribution
system is located on streets and highways, from the apparent owner of the
abutting property. Their electric underground transmission and distri-
bution systems are located, for the most part, in public streets. The
Pennsylvania portions of the main transmission lines from the Seneca
Plant, the Mansfield Plant and Beaver Valley Unit 2 are not owned by
Cleveland Electric or Toledo Edison.
All Cleveland Electric and Toledo Edison properties, with certain exceptions,
are subject to the lien of their respective mortgages.
The fee titles which Cleveland Electric and Toledo Edison acquire as tenant-
in-common owners, and the leasehold interests they have as joint lessees, of
certain generating units do not include the right to require a partition or
sale for division of proceeds of the units without the concurrence of all the
other owners and their respective mortgage trustees and the trustees under
Cleveland Electric's and Toledo Edison's mortgages.
41
Item 3. Legal Proceedings
Regulatory Proceedings and Suits Contesting Sulfur Dioxide Emission
Limitations and Related Regulations Applicable to the Operating Companies.
See "Item 1. Business--Environmental Regulation--Air Quality Control".
Westinghouse Lawsuit. In April 1991, the CAPCO Group companies filed a
lawsuit against Westinghouse in the United States District Court for the
Western District of Pennsylvania. The suit alleges that six steam generators
supplied by Westinghouse for Beaver Valley Power Station Units 1 and 2 contain
serious defects, particularly defects causing tube corrosion and cracking.
Steam generator maintenance costs have increased due to these defects and will
likely continue to increase. The condition of the steam generators is being
monitored closely. If the corrosion and cracking continue, replacement of the
steam generators could be required earlier than their 40-year design life.
The suit seeks monetary and corrective relief.
General Electric Lawsuit. On February 2, 1994, the CAPCO Group companies
announced that a settlement had been reached with General Electric regarding
the lawsuit filed by the CAPCO Group companies against General Electric in
August 1991. In that suit which was filed in the United States District Court
in Cleveland, the CAPCO Group companies as joint owners of the Perry Plant
alleged that General Electric had provided defective design information
relating to the containment vessels for Perry Units 1 and 2. The CAPCO Group
companies also alleged that the required corrective actions caused extensive
delays and cost increases in the construction of the Perry Plant.
Under the settlement agreement, General Electric will provide the CAPCO Group
companies with discounts on future purchases and cash payments. The value of
the settlement depends on the volume of future purchases. Because the
payments will be made over a period of years and the discounts will be offered
over the life of the plant, they will not have a material impact on the
financial results of Centerior, Cleveland Electric and Toledo Edison in any
particular year or on their financial conditions. The terms of the settlement
agreement are the subject of a confidentiality agreement.
Item 4. Submission of Matters to a Vote of Security Holders
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
None.
PART II
Item 5. Market for Registrants' Common Equity and Related Stockholder Matters
The information regarding common stock prices and number of share owners
required by this Item is not applicable to Cleveland Electric or Toledo Edison
because all of their common stock is held solely by Centerior Energy.
42
Market Information
Centerior Energy's common stock is traded on the New York, Chicago and Pacific
Stock Exchanges. The quarterly high and low prices of Centerior common stock
(as reported on the composite tape) in 1992 and 1993 were as follows:
1992 1993
High Low High Low
1st Quarter $20 $17-7/8 $20 $18-5/8
2nd Quarter 18-5/8 16-3/8 19-7/8 17-3/8
3rd Quarter 17-3/4 15-3/4 18-7/8 17-3/8
4th Quarter 20 17-1/8 17-7/8 12
Share Owners
As of March 15, 1994, Centerior Energy had 159,506 common stock share owners
of record.
Dividends
See Note 14 to Centerior's Financial Statements for quarterly dividend pay-
ments in the last two years.
See "Outlook--Common Stock Dividends" in Management's Financial Analysis
contained under Item 7 of this Report for a discussion of the payment of
future dividends by Centerior and the Operating Companies.
At December 31, 1993, Centerior Energy had a retained earnings deficit of $523
million and capital surplus of $2 billion, resulting in an overall surplus of
$1.477 billion that was available to pay dividends under Ohio law. Any
current period earnings in 1994 will increase surplus under Ohio law. See
Note 11(c) to Centerior's Financial Statements and Note 11(b) to the Operating
Companies' Financial Statements for discussions of dividend restrictions
affecting Cleveland Electric and Toledo Edison.
Dividends paid in 1993 on each of the Operating Companies' outstanding series
of preferred stock were fully taxable. The Operating Companies believe that
all or a portion of their preferred stock dividends paid in 1994 will be a
return of capital because they intend to take a deduction for the abandonment
of Perry Unit 2.
Item 6. Selected Financial Data
CENTERIOR ENERGY
The information required by this Item is contained on Pages F-23 and F-24
attached hereto.
43
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages F-46 and F-47
attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages F-68 and F-69
attached hereto.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
CENTERIOR ENERGY
The information required by this Item is contained on Pages F-3 through F-6
attached hereto.
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages F-26 through F-29
attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages F-49 through F-52
attached hereto.
Item 8. Financial Statements and Supplementary Data
CENTERIOR ENERGY
The information required by this Item is contained on Pages F-2 and F-7
through F-22 attached hereto.
CLEVELAND ELECTRIC
The information required by this Item is contained on Pages F-25 and F-30
through F-45 attached hereto.
TOLEDO EDISON
The information required by this Item is contained on Pages F-48 and F-53
through F-67 attached hereto.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
None.
44
PART III
Item 10. Directors and Executive Officers of the Registrants
CENTERIOR ENERGY
The information required by this Item for Centerior regarding directors is
incorporated herein by reference to Pages 4 through 8 of Centerior's
definitive proxy statement dated March 23, 1994. Reference is also made to
"Executive Officers of the Registrants and the Service Company" in Part I of
this Report for information regarding the executive officers of Centerior
Energy.
CLEVELAND ELECTRIC
Set forth below are the name and other directorships held, if any, of each
director of Cleveland Electric. The year in which the director was first
elected to Cleveland Electric's Board of Directors is set forth in paren-
thesis. Reference is made to "Executive Officers of the Registrants and the
Service Company" in Part I of this Report for information regarding the
directors and executive officers of Cleveland Electric. The directors
received no remuneration in their capacity as directors.
Robert J. Farling*
Mr. Farling is a director of National City Bank. (1986)
Murray R. Edelman
Mr. Edelman is a director of Society Bank & Trust. (1993)
Fred J. Lange, Jr.
(1993)
*Also a director of Centerior Energy and the Service Company.
TOLEDO EDISON
Set forth below are the name and other directorships held, if any, of each
director of Toledo Edison. The year in which the director was first elected
to Toledo Edison's Board of Directors is set forth in parenthesis. Reference
is made to "Executive Officers of the Registrants and the Service Company" in
Part I of this Report for information regarding the directors and the
executive officers of Toledo Edison. The directors received no remuneration
in their capacity as directors.
45
Robert J. Farling*
Mr. Farling is a director of National City Bank. (1988)
Murray R. Edelman
Mr. Edelman is a director of Society Bank & Trust. (1993)
Fred J. Lange, Jr.
(1993)
*Also a director of Centerior Energy and the Service Company.
Item 11. Executive Compensation
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
The information required by this Item for Centerior is incorporated herein by
reference to the information concerning compensation of directors on Page 9
and the information concerning compensation of executive officers, stock
option transactions, long-term incentive awards and pension benefits on
Pages 17 through 25 of Centerior's definitive proxy statement dated March 23,
1994. The named executive officers for Centerior are included for Cleveland
Electric and Toledo Edison regardless of whether they were officers of
Cleveland Electric or Toledo Edison because they were key policymakers for the
Centerior System in 1993.
Item 12. Security Ownership of Certain Beneficial Owners and Management
CENTERIOR ENERGY
The following table sets forth the beneficial ownership of Centerior common
stock by individual directors of Centerior, the named executive officers and
all directors and executive officers of Centerior Energy and the Service
Company as a group as of February 28, 1994:
46
Name of Beneficial Number of Common
Owner Shares Owned (1)
Richard P. Anderson 1,444
Albert C. Bersticker 1,000
Leigh Carter 2,257
Thomas A. Commes 5,000
Wayne R. Embry 1,000
Robert J. Farling 23,970 (2)
George H. Kaull 4,842
Richard A. Miller 12,027
Frank E. Mosier 1,591
Sister Mary Marthe Reinhard, SND 500 (3)
Robert C. Savage 1,000
William J. Williams 1,649
Murray R. Edelman 7,488 (2)
Donald C. Shelton 1,665
Fred J. Lange, Jr. 1,270
David L. Monseau 4,164 (2)
Lyman C. Phillips (4) 706
All directors and executive
officers as a group 89,726 (2)
(1) Beneficially owned shares include any shares with respect to which voting
or investment power is attributed to a director or executive officer
because of joint or fiduciary ownership of the shares or relationship to
the record owner, such as a spouse, even though the director or executive
officer does not consider himself or herself the beneficial owner. On
February 28, 1994, all directors and executive officers of Centerior
Energy and the Service Company as a group were considered to own bene-
ficially 0.1% of Centerior's common stock and none of the preferred stock
of Cleveland Electric and Toledo Edison. Certain individuals disclaim
beneficial ownership of some of those shares.
(2) Includes the following numbers of shares which are not owned but could
have been purchased within 60 days after February 28, 1994 upon exercise
of options to purchase shares of Centerior common stock: Mr. Farling -
6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and
executive officers as a group - 15,612. None of those options have been
exercised as of March 28, 1994.
(3) Owned by the Sisters of Notre Dame.
(4) Mr. Phillips is included in the table because he would have been one of
the five most highly compensated executive officers had he not retired on
November 1, 1993.
47
CLEVELAND ELECTRIC
Individual directors of Cleveland Electric, the named executive officers and
all directors and executive officers of Cleveland Electric as a group as of
March 15, 1994 beneficially owned the following number of shares of Centerior
common stock on February 28, 1994:
Name of Beneficial Number of Common
Owner Shares Owned (1)
Robert J. Farling 23,970 (2)
Murray R. Edelman 7,488 (2)
Donald C. Shelton 1,665
Fred J. Lange, Jr. 1,270
David L. Monseau 4,164 (2)
Lyman C. Phillips (3) 706
All directors and executive
officers as a group 51,602 (2)
(1) Beneficially owned shares include any shares with respect to which voting
or investment power is attributed to a director or executive officer
because of joint or fiduciary ownership of the shares or relationship to
the record owner, such as a spouse, even though the director or executive
officer does not consider himself or herself the beneficial owner. On
February 28, 1994, all directors and executive officers of Cleveland
Electric as a group were considered to own beneficially 0.03% of
Centerior's common stock and none of Cleveland Electric's serial preferred
stock. Certain individuals disclaim beneficial ownership of some of those
shares.
(2) Includes the following numbers of shares which are not owned but could
have been purchased within 60 days after February 28, 1994 upon exercise
of options to purchase shares of Centerior common stock: Mr. Farling -
6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all directors and
executive officers as a group - 15,612. None of those options have been
exercised as of March 28, 1994.
(3) Mr. Phillips is included in the table because he would have been one of
the five most highly compensated executive officers had he not retired on
November 1, 1993.
TOLEDO EDISON
Individual directors of Toledo Edison, the named executive officers and all
directors and executive officers of Toledo Edison as a group as of March 15,
1994 beneficially owned the following number of shares of Centerior common
stock on February 28, 1994:
48
Name of Beneficial Number of Common
Owner Shares Owned (1)
Robert J. Farling 23,970 (2)
Murray R. Edelman 7,488 (2)
Donald C. Shelton 1,665
Fred J. Lange, Jr. 1,270
David L. Monseau 4,164 (2)
Lyman C. Phillips (3) 706
All directors and executive
officers as a group 44,249 (2)
(1) Beneficially owned shares include any shares with respect to which voting
or investment power is attributed to a director or executive officer
because of joint or fiduciary ownership of the shares or relationship to
the record owner, such as a spouse, even though the director or executive
officer does not consider himself or herself the beneficial owner. On
February 28, 1994, all directors and executive officers of Toledo Edison
as a group were considered to own beneficially 0.03% of Centerior's common
stock. Certain individuals disclaim beneficial ownership of some of those
shares.
(2) Includes the following numbers of shares which are not owned but could
have been purchased within 60 days after February 28, 1994 upon exercise
of options to purchase shares of Centerior common stock: Mr. Farling -
6,832; Mr. Edelman - 5,550; Mr. Monseau - 1,665; and all other executive
officers as a group - 15,612. None of those options have been exercised
as of March 28, 1994.
(3) Mr. Phillips is included in the table because he would have been one of
the five most highly compensated executive officers had he not retired on
November 1, 1993.
Item 13. Certain Relationships and Related Transactions
CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
None.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Documents Filed as a Part of the Report
1. Financial Statements:
Financial Statements for Centerior Energy, Cleveland Electric and
Toledo Edison are listed in the Index to Selected Financial Data;
Management's Discussion and Analysis of Financial Condition and Re-
sults of Operations; and Financial Statements. See Page F-1.
49
2. Financial Statement Schedules:
Financial Statement Schedules for Centerior Energy, Cleveland
Electric and Toledo Edison are listed in the Index to Schedules. See
Page S-1.
3. Combined Pro Forma Condensed Financial Statements (Unaudited):
Combined Pro Forma Condensed Financial Statements (unaudited) for
Cleveland Electric and Toledo Edison related to their pending
merger. See Pages P-1 to P-4.
4. Exhibits:
Exhibits for Centerior Energy, Cleveland Electric and Toledo Edison
are listed in the Exhibit Index. See Page E-1.
(b) Reports on Form 8-K
During the quarter ended December 31, 1993, Centerior Energy, Cleveland
Electric and Toledo Edison did not file any Current Reports on Form 8-K.
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CENTERIOR ENERGY CORPORATION
Registrant
March 30, 1994 By *ROBERT J FARLING, Chairman of the
Board, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this re-
port has been signed below by the following persons on behalf of the regi-
strant and in the capacities and on the date indicated:
Signature Title Date
Principal Executive Officer: )
*ROBERT J. FARLING Chairman of the Board, )
President and Chief )
Executive Officer )
Principal Financial Officer: )
*GARY R. LEIDICH Vice President and )
Chief Financial )
Officer )
Principal Accounting Officer:
*PAUL G. BUSBY Controller )
Directors: )
*RICHARD P. ANDERSON Director )
*ALBERT C. BERSTICKER Director )
*LEIGH CARTER Director )
*THOMAS A. COMMES Director ) March 30, 1994
*WAYNE R. EMBRY Director )
*ROBERT J. FARLING Director )
*GEORGE H. KAULL Director )
*RICHARD A. MILLER Director )
*FRANK E. MOSIER Director )
*SR. MARY MARTHE REINHARD, SND Director )
*ROBERT C. SAVAGE Director )
*WILLIAM J. WILLIAMS Director )
*By J. T. PERCIO
J. T. Percio, Attorney-in-Fact
51
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
Registrant
March 30, 1994 By *ROBERT J. FARLING, Chairman of the
Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this re-
port has been signed below by the following persons on behalf of the regi-
strant and in the capacities and on the date indicated:
Signature Title Date
Principal Executive Officer: )
*ROBERT J. FARLING Chairman of the Board )
and Chief Executive )
Officer )
Principal Financial Officer: )
*GARY R. LEIDICH Vice President and )
Chief Financial ) March 30, 1994
Officer )
Principal Accounting Officer: )
*PAUL G. BUSBY Controller )
Directors: )
*ROBERT J. FARLING Director )
*MURRAY R. EDELMAN Director )
*FRED J. LANGE, JR. Director )
*By J. T. PERCIO
J. T. Percio, Attorney-in-Fact
52
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE TOLEDO EDISON COMPANY
Registrant
March 30, 1994 By *ROBERT J. FARLING, Chairman of the
Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this re-
port has been signed below by the following persons on behalf of the regi-
strant and in the capacities and on the date indicated:
Signature Title Date
Principal Executive Officer: )
*ROBERT J. FARLING Chairman of the Board )
and Chief Executive )
Officer )
Principal Financial Officer: )
*GARY R. LEIDICH Vice President and )
Chief Financial )
Officer )
Principal Accounting Officer: ) March 30, 1994
*PAUL G. BUSBY Controller )
Directors: )
*ROBERT J. FARLING Director )
*MURRAY R. EDELMAN Director )
*FRED J. LANGE, JR. Director )
*By J. T. PERCIO
J. T. Percio, Attorney-in-Fact
53
INDEX TO
SELECTED FINANCIAL DATA; MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS; AND FINANCIAL STATEMENTS
Page
Centerior Energy Corporation and Subsidiaries:
Report of Independent Public Accountants . . . . . . . . . . . . . F-2
Management's Financial Analysis . . . . . . . . . . . . . . . . . F-3
Income Statement for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7
Retained Earnings for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7
Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-8
Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-10
Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-11
Notes to the Financial Statements . . . . . . . . . . . . . . . . F-12
Financial and Statistical Review . . . . . . . . . . . . . . . . . F-23
The Cleveland Electric Illuminating Company and Subsidiaries:
Report of Independent Public Accountants . . . . . . . . . . . . . F-25
Management's Financial Analysis . . . . . . . . . . . . . . . . . F-26
Income Statement for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-30
Retained Earnings for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-30
Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-31
Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-32
Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-34
Notes to the Financial Statements . . . . . . . . . . . . . . . . F-35
Financial and Statistical Review . . . . . . . . . . . . . . . . . F-46
The Toledo Edison Company:
Report of Independent Public Accountants . . . . . . . . . . . . . F-48
Management's Financial Analysis . . . . . . . . . . . . . . . . . F-49
Income Statement for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-53
Retained Earnings for the Years Ended December 31, 1993, 1992
and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-53
Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 . F-54
Balance Sheet as of December 31, 1993 and 1992 . . . . . . . . . . F-55
Statement of Preferred Stock at December 31, 1993 and 1992 . . . . F-57
Notes to the Financial Statements . . . . . . . . . . . . . . . . F-58
Financial and Statistical Review . . . . . . . . . . . . . . . . . F-68
F-1
54
REPORT OF
INDEPENDENT
PUBLIC ACCOUNTANTS
- --------------------------------------------------------------------------------
To the Share Owners and
Board of Directors of [Logo]
Centerior Energy Corporation:
We have audited the accompanying consolidated balance sheet and consolidated
statement of preferred stock of Centerior Energy Corporation (an Ohio
corporation) and subsidiaries as of December 31, 1993 and 1992, and the related
consolidated statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1993. These financial
statements and the schedules referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Centerior Energy Corporation
and subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of
accounting for nuclear plant depreciation in 1991 and for postretirement
benefits other than pensions in 1993.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules of Centerior Energy
Corporation and subsidiaries listed in the Index to Schedules are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in the audits of the basic
financial statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio
February 14, 1994
(Centerior Energy) F-2 (Centerior Energy)
55
MANAGEMENT'S
FINANCIAL ANALYSIS
- --------------------------------------------------------------------------------
Results of Operations
1993 VS. 1992
Factors contributing to the 1.5% increase in 1993 operating revenues are as
follows:
Millions
Increase (Decrease) in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $ 65
Base Rates and Miscellaneous (18)
Fuel Cost Recovery Revenues (11)
-----
Total $ 36
-----
-----
The net revenue increase resulted primarily from the different weather
conditions and the changes in the composition of the sales mix among customer
categories. Weather accounted for approximately $53 million of the higher 1993
revenues. Hot summer weather in 1993 boosted residential, commercial and
wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in
56 years in Northern Ohio. Residential and commercial sales also increased as a
result of colder late-winter temperatures in 1993 which increased electric
heating-related demand. As a result, total sales increased 3.1% in 1993.
Residential and commercial sales increased 4.6% and 3.1%, respectively.
Industrial sales increased 1.2%. Increased sales to large automotive
manufacturers, petroleum refiners and the broad-based, smaller industrial group
were partially offset by lower sales to large steel industry customers. Other
sales increased 5.9% because of increased sales to wholesale customers. Base
rates and miscellaneous revenues decreased in 1993 primarily from lower revenues
under contracts having reduced rates with certain large customers and a
declining rate structure tied to usage. The contracts have been negotiated to
meet competition and encourage economic growth. The net decrease in 1993 fuel
cost recovery revenues resulted from changes in the fuel cost factors. The
weighted average of these factors increased slightly for The Toledo Edison
Company (Toledo Edison) but decreased 5% for The Cleveland Electric Illuminating
Company (Cleveland Electric).
Operating expenses increased 13.7% in 1993. The increase in total operation and
maintenance expenses resulted from the $218 million of net benefit expenses
related to an early retirement program, called the Voluntary Transition Program
(VTP), other charges totaling $54 million and an increase in other operation and
maintenance expenses. Other charges recorded at year-end 1993 related to a
performance improvement plan for Perry
Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and other
expense accruals. The increase in other operation and maintenance expenses
resulted from higher environmental expenses, power restoration and repair
expenses following a July 1993 storm in the Cleveland area, and an increase in
other postretirement benefit expenses. See Note 9 for information on retirement
and postemployment benefits. Deferred operating expenses decreased because of
the write-off of the phase-in deferred operating expenses in 1993 as discussed
in Note 7. Federal income taxes decreased as a result of lower pretax operating
income.
As discussed in Note 4(b), $583 million of our Perry Nuclear Power Plant Unit 2
(Perry Unit 2) investment was written off in 1993. Credits for carrying charges
recorded in nonoperating income decreased because of the write-off of the
phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal
income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.8% decrease in 1992 operating revenues are as
follows:
Millions
Decrease in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $ 79
Base Rates and Miscellaneous 32
Fuel Cost Recovery Revenues 11
-----
Total $ 122
-----
-----
The revenue decreases resulted primarily from the different weather conditions
and the changes in the composition of the sales mix among customer categories.
Weather accounted for approximately $77 million of the lower 1992 revenues.
Winter and spring in 1992 were milder than in 1991. In addition, the cooler
summer in 1992 contrasted with the summer of 1991 which was much hotter than
normal. As a result, total kilowatt-hour sales decreased 1.1% in 1992.
Residential and commercial sales decreased 4.5% and 1.3%, respectively, as
moderate temperatures in 1992 reduced electric heating and cooling demands.
Industrial sales were virtually the same as in 1991 as sales increases to steel
producers and auto manufacturers of 10.9% and 2.7%, respectively, offset a
decline in sales to other industrial customers. Other sales increased 2.3%
because of increased sales to wholesale customers. Operating revenues in 1991
included the recognition by Toledo Edison of $24 million of deferred revenues
over the period of a refund to customers under a provision of its January 1989
rate order. No such revenues were reflected in 1992 as the refund period ended
in December 1991. The decrease in 1992 fuel cost recovery revenues resulted from
the good performance of our generating units, which in turn decreased our fuel
cost factors. The weighted averages of these factors decreased approximately 3%
for Cleveland Electric and Toledo Edison (Operating Companies).
Operating expenses decreased 4% in 1992. Lower fuel and purchased power expense
resulted from less amortization of previously deferred fuel costs than the
amount amortized in 1991 and lower generation requirements stemming from less
electric sales. A reduction of $17 million in other operation and maintenance
expenses resulted primarily from cost-cutting measures. Federal income
(Centerior Energy) F-3 (Centerior Energy)
56
taxes decreased because of the amortization of certain tax benefits under the
Rate Stabilization Program discussed in Note 7 and the effects of adopting the
new accounting standard for income taxes (SFAS 109) in 1992. These decreases
were partially offset by higher depreciation and amortization, caused primarily
by the adoption of SFAS 109, and by higher taxes, other than federal income
taxes, caused by increased Ohio property and gross receipts taxes. Deferred
operating expenses increased as a result of the deferrals under the Rate
Stabilization Program.
The federal income tax provision for nonoperating income decreased because of
lower carrying charge credits and a greater tax allocation of interest charges
to nonoperating activities. Credits for carrying charges recorded in
nonoperating income decreased primarily because of lower phase-in carrying
charge credits. Interest charges decreased as a result of debt refinancings at
lower interest rates and lower short-term borrowing requirements.
Outlook
RECENT ACTIONS
In January 1994, we announced a comprehensive strategic action plan to
strengthen our financial and competitive position. The plan established specific
objectives and was designed to guide us through the year 2001. While the plan
has a long-term focus, it also required us to take some very difficult, but
necessary, financial actions at that time. We reduced the quarterly common stock
dividend from $.40 per share to $.20 per share effective with the dividend
payable February 15, 1994. This action was taken because projected financial
results did not support continuation of the dividend at its former rate. We also
wrote off our investment in Perry Unit 2 and certain deferred charges related to
a January 1989 rate agreement (phase-in deferrals). The aggregate after-tax
effect of these write-offs was $1.023 billion which resulted in a net loss in
1993 and a retained earnings deficit. The write-offs are discussed in Notes 4(b)
and 7. We also recognized other one-time charges totaling $39 million after
taxes related to a performance improvement plan for Perry Unit 1, postemployment
benefits and other expense accruals.
Also contributing to the net loss in 1993 was a charge of $87 million after
taxes representing a portion of the VTP costs. We will realize approximately $50
million of savings in annual payroll and benefit costs beginning in 1994 as a
result of the VTP.
STRATEGIC PLAN
The objectives of our strategic plan are to maximize share owner return from
corporate assets and resources, achieve profitable revenue growth, become an
industry leader in customer satisfaction, build a winning team and attain
increasingly competitive power supply costs. To achieve these objectives, we
will continue controlling our operation and maintenance expenses and capital
expenditures, reduce our outstanding debt, increase revenues by finding new uses
for existing assets and resources, implement a broad range of new marketing
programs, increase revenues by restructuring rates for various customers where
appropriate, improve the operating performance of our plants and take other
appropriate actions.
COMMON STOCK DIVIDENDS
The indicated quarterly common stock dividend is $.20 per share. We believe that
the new level is sustainable barring unforeseen circumstances and that the new
strategic plan will provide the opportunity to grow the dividend as the
objectives are achieved. Nevertheless, future dividend action by our Board of
Directors will continue to be decided on a quarter-to-quarter basis after the
evaluation of financial results, potential earning capacity and cash flow.
The lower dividend reduces our cash outflow by about $120 million annually,
which we intend to use to repay debt more quickly than would otherwise be the
case. This will help improve our capitalization structure and interest coverage
ratios, both of which are key measures considered by securities rating agencies
in determining credit ratings. Improved credit ratings and less outstanding
debt, in turn, will lower our interest costs.
COMPETITION
Our electric rates are among the highest in our region because we are recovering
the substantial investment in our nuclear construction program. Accordingly,
some of our customers continue to seek less costly alternatives, including
switching to or working to create a municipal electric system. There are a
number of rural and municipal systems in our service area. In addition, we face
threats of other municipalities in our service area establishing new systems and
the expansion of an existing system. We have entered into agreements with some
of the communities which considered establishing systems. Accordingly, they will
not proceed with such development at this time in return for rate concessions
and/or economic development funds. Others have determined that developing a
system was not feasible. Cleveland Public Power continues to expand its
operations into areas we have served exclusively. We have been successful in
retaining most of the large industrial and commercial customers in those areas
by providing economic incentive packages in exchange for sole-supplier
contracts. We also have similar contracts with customers in other areas. Most of
these contracts have remaining terms of one to five years. We will continue to
address municipal system threats through aggressive marketing programs and
emphasizing to our customers the value of our service and the risks of a
municipal system.
(Centerior Energy) F-4 (Centerior Energy)
57
The Energy Policy Act of 1992 (Energy Act) will provide additional competition
in the electric utility industry by requiring utilities to wheel to municipal
systems in their service areas electricity from other utilities. This provision
of the Energy Act should not significantly increase the competitive threat to us
since the operating licenses for our nuclear units have required us to wheel to
municipal systems in our service area since 1977. The Energy Act also created a
class of exempt wholesale generators which may increase competition in the
wholesale power market. A further risk is the possibility that the government
could mandate that utilities deliver power from another utility or generation
source to their retail customers.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed
to freeze base rates until 1996 and limit rate increases through 1998. In
exchange, we are permitted to defer through 1995 and subsequently recover
certain costs not currently recovered in rates and to accelerate the
amortization of certain benefits. The amortization and recovery of the deferrals
will begin with future rate recognition and will continue over the average life
of the related assets, or approximately 30 years. The continued use of these
regulatory accounting measures will be dependent upon our continuing assessment
and conclusion that there will be probable recovery of such deferrals in future
rates.
Our analysis leading to the year-end 1993 financial actions and strategic plan
also included an evaluation of our regulatory accounting measures. We decided
that, once the deferral of expenses and acceleration of benefits under our Rate
Stabilization Program are completed in 1995, we should no longer plan to use
regulatory accounting measures to the extent we have in the past.
NUCLEAR OPERATIONS
Our three nuclear units may be impacted by activities or events beyond our
control. Operating nuclear generating units have experienced unplanned outages
or extensions of scheduled outages because of equipment problems or new
regulatory requirements. A major accident at a nuclear facility anywhere in the
world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit
the operation or licensing of any nuclear unit. If one of our nuclear units is
taken out of service for an extended period of time for any reason, including an
accident at such unit or any other nuclear facility, we cannot predict whether
regulatory authorities would impose unfavorable rate treatment. Such treatment
could include taking our affected unit out of rate base or disallowing certain
construction or maintenance costs. An extended outage of one of our nuclear
units coupled with unfavorable rate treatment could have a material adverse
effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993, we increased our decommissioning expense accruals for
revisions in our cost estimates. We expect the increases associated with the new
estimates will be recoverable in future rates. See Note 1(e).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
as amended (Superfund) established programs addressing the cleanup of hazardous
waste disposal sites, emergency preparedness and other issues. The Operating
Companies have been named as "potentially responsible parties" (PRPs) for three
sites listed on the Superfund National Priorities List (Superfund List) and are
aware of their potential involvement in the cleanup of several other sites not
on such list. The allegations that the Operating Companies disposed of hazardous
waste at these sites and the amounts involved are often unsubstantiated and
subject to dispute. Superfund provides that all PRPs to a particular site can be
held liable on a joint and several basis. Consequently, if the Operating
Companies were held liable for 100% of the cleanup costs of all of the sites
referred to above, the cost could be as high as $400 million. However, we
believe that the actual cleanup costs will be substantially lower than $400
million, that the Operating Companies' share of any cleanup costs will be
substantially less than 100% and that most of the other PRPs are financially
able to contribute their share. The Operating Companies have accrued a liability
totaling $19 million at December 31, 1993 based on estimates of the costs of
cleanup and their proportionate responsibility for such costs. We believe that
the ultimate outcome of these matters will not have a material adverse effect on
our financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in
August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did
not materially impact the results of operations for 1993, but did affect certain
Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected
to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected
by even modest inflation which causes increases in the unit cost of labor,
materials and services.
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of
securities and an ongoing pro-
(Centerior Energy) F-5 (Centerior Energy)
58
gram of constructing new facilities and modifying existing facilities. The
construction program is needed to meet anticipated demand for electric service,
comply with governmental regulations and protect the environment. Over the
three-year period of 1991-1993, these construction and mandatory retirement
needs totaled approximately $1.4 billion. In addition, we exercised various
options to redeem and purchase approximately $900 million of our securities.
We raised $2.2 billion through security issues and term bank loans during the
1991-1993 period as shown in the Cash Flows statement. During the three-year
period, the Operating Companies also utilized their short-term borrowing
arrangements to help meet their cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993
negatively affected our earnings, they did not adversely affect our current cash
flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for Cleveland Electric and Toledo
Edison, respectively, are $791 million and $249 million for their construction
programs and $715 million and $324 million for the mandatory redemption of debt
and preferred stock. Cleveland Electric and Toledo Edison expect to finance
internally all of their 1994 cash requirements of approximately $239 million and
$109 million, respectively. About 15-20% of the Operating Companies' 1995-1998
requirements are expected to be financed externally. If economical, additional
securities may be redeemed under optional redemption provisions.
Our capital requirements are dependent upon our implementation strategy to
achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act).
Cash expenditures for our plan are estimated to be approximately $128 million
over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Operating Companies under
their respective mortgages on the basis of property additions, cash or
refundable first mortgage bonds. Under their respective mortgages, each
Operating Company may issue first mortgage bonds on the basis of property
additions and, under certain circumstances, refundable bonds only if the
applicable interest coverage test is met. At December 31, 1993, Cleveland
Electric and Toledo Edison would have been permitted to issue approximately $78
million and $323 million of additional first mortgage bonds, respectively. After
the fourth quarter of 1994, Cleveland Electric's ability to issue first mortgage
bonds is expected to increase substantially when its interest coverage ratio
will no longer be affected by the write-offs recorded at December 31, 1993.
As discussed in Note 11(e), certain unsecured debt agreements contain covenants
relating to capitalization, fixed charge coverage ratios and secured financings.
The write-offs recorded at December 31, 1993 caused Centerior Energy Corporation
(Centerior Energy) and the Operating Companies to violate certain of those
covenants. The affected creditors have waived those violations in exchange for
our commitment to provide them with a second mortgage security interest on our
property and other considerations. We expect to complete this process in the
second quarter of 1994. We will provide the same security interest to certain
other creditors because their agreements require equal treatment. We expect to
provide second mortgage collateral for $219 million of unsecured debt, $228
million of bank letters of credit and a $205 million revolving credit facility.
For the next five years, the Operating Companies do not expect to raise funds
through the sale of debt junior to first mortgage bonds. However, if necessary
or desirable, the Operating Companies believe that they could raise funds
through the sale of unsecured debt or debt secured by the second mortgage
referred to above. The Operating Companies also are able to raise funds through
the sale of preference stock and, in the case of Cleveland Electric, preferred
stock. Toledo Edison will be unable to issue preferred stock until it can meet
the interest and preferred dividend coverage test in its articles of
incorporation. Centerior Energy will continue to raise funds through the sale of
common stock.
The Operating Companies currently cannot sell commercial paper because of their
low commercial paper ratings by Standard & Poor's Corporation (S&P) and Moody's
Investors Service, Inc. (Moody's) of "B" and "Not Prime", respectively. We have
a $205 million revolving credit facility which will run through mid-1996.
However, we currently cannot draw on this facility because the write-offs taken
at year-end 1993 caused us to fail to meet certain capitalization and fixed
charge coverage covenants. We expect to have this facility available to us again
after it is amended in the second quarter of 1994 to provide the participating
creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Operating
Companies' needs over the next several years. The availability and cost of
capital to meet our external financing needs, however, also depend upon such
factors as financial market conditions and our credit ratings. Current credit
ratings for both Operating Companies are as follows:
S&P Moody's
----------- -------------
First mortgage bonds BB Ba2
Unsecured notes B+ Ba3
Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued
a negative outlook for the Operating Companies.
(Centerior Energy) F-6 (Centerior Energy)
59
INCOME STATEMENT
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
- -------------------------------------------------------------------------------
For the years ended December 31,
--------------------------------
1993 1992 1991
------ ------ ------
(millions of dollars,
except per share amounts)
OPERATING REVENUES $2,474 $2,438 $2,560
------ ------ ------
OPERATING EXPENSES
Fuel and purchased power 474 473 500
Other operation and maintenance 811 784 801
Early retirement program expenses and other 272 -- --
------ ------ ------
Total operation and maintenance 1,557 1,257 1,301
Depreciation and amortization 258 256 243
Taxes, other than federal income taxes 312 318 305
Deferred operating expenses, net 23 (52) (6)
Federal income taxes 11 122 138
------ ------ ------
2,161 1,901 1,981
------ ------ ------
OPERATING INCOME 313 537 579
------ ------ ------
NONOPERATING INCOME (LOSS)
Allowance for equity funds used during construction 5 2 9
Other income and deductions, net (6) 9 6
Write-off of Perry Unit 2 (583) -- --
Deferred carrying charges, net (649) 100 110
Federal income taxes -- credit (expense) 398 (7) (30)
------ ------ ------
(835) 104 95
------ ------ ------
INCOME (LOSS) BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS (522) 641 674
------ ------ ------
INTEREST CHARGES AND PREFERRED DIVIDENDS
Debt interest 359 365 381
Allowance for borrowed funds used during construction (5) (1) (5)
Preferred dividend requirements of subsidiaries 67 65 61
------ ------ ------
421 429 437
------ ------ ------
NET INCOME (LOSS) $ (943) $ 212 $ 237
------ ------ ------
------ ------ ------
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (MILLIONS) 144.9 141.7 139.1
------ ------ ------
------ ------ ------
EARNINGS (LOSS) PER COMMON SHARE $(6.51) $ 1.50 $ 1.71
------ ------ ------
------ ------ ------
DIVIDENDS DECLARED PER COMMON SHARE $ 1.60 $ 1.60 $ 1.60
------ ------ ------
------ ------ ------
RETAINED EARNINGS
- ----------------------------------------------------------------------
For the years ended December 31,
--------------------------------
1993 1992 1991
------- ------ ------
(millions of dollars)
RETAINED EARNINGS AT BEGINNING OF YEAR $ 652 $ 669 $ 655
------- ------ ------
ADDITIONS
Net income (loss) (943) 212 237
DEDUCTIONS
Common stock dividends (231) (226) (222)
Other, primarily preferred stock redemption expenses of
subsidiaries (1) (3) (1)
------- ------ ------
Net Increase (Decrease) (1,175) (17) 14
------- ------ ------
RETAINED EARNINGS (DEFICIT) AT END OF YEAR $ (523) $ 652 $ 669
------- ------ ------
------- ------ ------
The accompanying notes are an integral part of these statements.
(Centerior Energy) F-7 (Centerior Energy)
60
CASH FLOWS
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
- ----------------------------------------------------------------------
For the years ended December
31,
----------------------------
1993 1992 1991
------ ------ ------
(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES (1)
Net Income (Loss) $ (943) $ 212 $ 237
------ ------ ------
Adjustments to Reconcile Net Income (Loss) to Cash from Operating
Activities:
Depreciation and amortization 258 256 243
Deferred federal income taxes (452) 95 85
Investment tax credits, net -- (14) 43
Deferred and unbilled revenues (10) (6) (51)
Deferred fuel 5 1 18
Deferred carrying charges, net 649 (100) (110)
Leased nuclear fuel amortization 86 126 123
Deferred operating expenses, net 23 (52) (6)
Allowance for equity funds used during construction (5) (2) (9)
Noncash early retirement program expenses, net 208 -- --
Write-off of Perry Unit 2 583 -- --
Changes in amounts due from customers and others, net 1 7 14
Changes in inventories 26 (10) (22)
Changes in accounts payable 45 (5) (49)
Changes in working capital affecting operations 25 8 19
Other noncash items 18 3 1
------ ------ ------
Total Adjustments 1,460 307 299
------ ------ ------
Net Cash from Operating Activities 517 519 536
------ ------ ------
CASH FLOWS FROM FINANCING ACTIVITIES (2)
Bank loans, commercial paper and other short-term debt (50) 50 (110)
Debt issues:
First mortgage bonds 300 600 --
Secured medium-term notes 128 138 285
Term bank loans and other long-term debt 40 135 108
Preferred stock issues 100 74 125
Common stock issues 71 53 32
Reacquired common stock 1 (3) --
Maturities, redemptions and sinking funds (434) (1,013) (312)
Nuclear fuel lease obligations (106) (117) (116)
Common stock dividends paid (231) (226) (222)
Premiums, discounts and expenses (13) (14) (7)
------ ------ ------
Net Cash from Financing Activities (194) (323) (217)
------ ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES (2)
Cash applied to construction (209) (200) (189)
Interest capitalized as allowance for borrowed funds used during
construction (5) (1) (5)
Sale and leaseback restructuring fees -- (43) --
Other cash received (applied) 23 (36) (1)
------ ------ ------
Net Cash from Investing Activities (191) (280) (195)
------ ------ ------
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 132 (84) 124
------ ------ ------
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 93 177 53
------ ------ ------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 225 $ 93 $ 177
------ ------ ------
------ ------ ------
(1) Interest paid (net of amounts capitalized) was $295 million, $299 million
and $339 million in 1993, 1992 and 1991, respectively. Income taxes paid
were $50 million, $32 million and $57 million in 1993, 1992 and 1991,
respectively.
(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance
Sheet resulting from the noncash capitalizations under nuclear fuel
agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
(Centerior Energy) F-8 (Centerior Energy)
61
BALANCE SHEET
- ----------------------------------------------------------------------
December 31,
------------------
1993 1992
------- -------
(millions of
dollars)
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant in service $ 9,571 $ 9,449
Less: accumulated depreciation and amortization 2,677 2,488
------- -------
6,894 6,961
Construction work in progress 181 167
Perry Unit 2 -- 614
------- -------
7,075 7,742
Nuclear fuel, net of amortization 344 385
Other property, less accumulated depreciation 41 39
------- -------
7,460 8,166
------- -------
CURRENT ASSETS
Cash and temporary cash investments 225 93
Amounts due from customers and others, net 221 222
Unbilled revenues 124 114
Materials and supplies, at average cost 136 129
Fossil fuel inventory, at average cost 32 65
Taxes applicable to succeeding years 250 247
Other 5 7
------- -------
993 877
------- -------
DEFERRED CHARGES AND OTHER ASSETS
Amounts due from customers for future federal income taxes 968 975
Unamortized loss from Beaver Valley Unit 2 sale 105 110
Unamortized loss on reacquired debt 92 101
Carrying charges and operating expenses 862 1,533
Nuclear plant decommissioning trusts 56 42
Other 174 267
------- -------
2,257 3,028
------- -------
Total Assets $10,710 $12,071
------- -------
------- -------
The accompanying notes are an integral part of this statement.
(Centerior Energy) F-9 (Centerior Energy)
62
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
December 31,
-------------------
1993 1992
------- -------
(millions of
dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shares, without par value (stated value of $345 million and $274 million
for 1993 and 1992, respectively): 180 million authorized; 147 million
(excluding 2.7 million shares in Treasury) and 142.9 million (excluding 2.7
million shares in Treasury) outstanding in 1993 and 1992, respectively $ 2,308 $ 2,237
Retained earnings (deficit) (523) 652
------- -------
Common stock equity 1,785 2,889
Preferred stock
With mandatory redemption provisions 313 364
Without mandatory redemption provisions 451 354
Long-term debt 4,019 3,694
------- -------
6,568 7,301
------- -------
OTHER NONCURRENT LIABILITIES
Nuclear fuel lease obligations 254 303
Other 195 119
------- -------
449 422
------- -------
CURRENT LIABILITIES
Current portion of long-term debt and preferred stock 127 368
Current portion of nuclear fuel lease obligations 111 118
Notes payable to banks and others -- 50
Accounts payable 188 143
Accrued taxes 378 368
Accrued interest 87 84
Other 75 59
------- -------
966 1,190
------- -------
DEFERRED CREDITS
Unamortized investment tax credits 329 353
Accumulated deferred federal income taxes 1,579 2,035
Unamortized gain from Bruce Mansfield Plant sale 551 578
Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 128 116
Other 140 76
------- -------
2,727 3,158
------- -------
Total Capitalization and Liabilities $10,710 $12,071
------- -------
------- -------
(Centerior Energy) F-10 (Centerior Energy)
63
STATEMENT OF
PREFERRED STOCK
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
- ----------------------------------------------------------------------
Current December 31,
1993 Shares Call Price -------------
Outstanding Per Share 1993 1992
----------- ---------- ---- ----
(millions of
dollars)
CLEVELAND ELECTRIC
Without par value, 4,000,000 preferred shares authorized
Subject to mandatory redemption:
$7.35 Series C 150,000 $ 101.00 $ 15 $ 16
88.00 Series E 21,000 1,022.96 21 24
Adjustable Series M 200,000 100.00 20 30
9.125 Series N 600,000 103.04 59 74
91.50 Series Q 75,000 -- 75 75
88.00 Series R 50,000 -- 50 50
90.00 Series S 75,000 -- 74 74
---- ----
314 343
Less: Current maturities 29 29
---- ----
285 314
---- ----
Not subject to mandatory redemption:
$7.40 Series A 500,000 101.00 50 50
7.56 Series B 450,000 102.26 45 45
Adjustable Series L 500,000 103.00 49 49
Remarketed Series P -- -- -- 9
42.40 Series T 200,000 -- 97 --
---- ----
241 153
Less: Current maturities -- 9
---- ----
241 144
---- ----
TOLEDO EDISON
$100 par value, 3,000,000 preferred shares authorized and $25 par value,
12,000,000 preferred shares authorized
Subject to mandatory redemption:
$100 par $9.375 100,150 102.47 10 12
25 par 2.81 1,200,000 25.94 30 50
---- ----
40 62
Less: Current maturities 12 12
---- ----
28 50
---- ----
Not subject to mandatory redemption:
$100 par $ 4.25 160,000 104.625 16 16
4.56 50,000 101.00 5 5
4.25 100,000 102.00 10 10
8.32 100,000 102.46 10 10
7.76 150,000 102.437 15 15
7.80 150,000 101.65 15 15
10.00 190,000 101.00 19 19
25 par 2.21 1,000,000 25.25 25 25
2.365 1,400,000 27.75 35 35
Series A Adjustable 1,200,000 25.75 30 30
Series B Adjustable 1,200,000 25.75 30 30
---- ----
210 210
---- ----
CENTERIOR ENERGY
Without par value, 5,000,000 preferred shares authorized, none outstanding -- --
---- ----
TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $313 $364
---- ----
---- ----
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $451 $354
---- ----
---- ----
The accompanying notes are an integral part of this statement.
(Centerior Energy) F-11 (Centerior Energy)
64
NOTES TO THE
FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
(1) Summary of Significant
Accounting Policies
(A) GENERAL
Centerior Energy is a holding company with two electric utility subsidiaries,
Cleveland Electric and Toledo Edison. The consolidated financial statements also
include the accounts of Centerior Energy's other wholly owned subsidiary,
Centerior Service Company (Service Company), and Cleveland Electric's wholly
owned subsidiaries. The Service Company provides management, financial,
administrative, engineering, legal and other services at cost to Centerior
Energy and the Operating Companies. The Operating Companies operate as separate
companies, each serving the customers in its service area. The preferred stock,
first mortgage bonds and other debt obligations of the Operating Companies are
outstanding securities of the issuing utility. All significant intercompany
items have been eliminated in consolidation.
Centerior Energy and the Operating Companies follow the Uniform System of
Accounts prescribed by the Federal Energy Regulatory Commission and adopted by
The Public Utilities Commission of Ohio (PUCO). As rate-regulated utilities, the
Operating Companies are subject to Statement of Financial Accounting Standards
(SFAS) 71 which governs accounting for the effects of certain types of rate
regulation. The Service Company follows the Uniform System of Accounts for
Mutual Service Companies prescribed by the Securities and Exchange Commission
under the Public Utility Holding Company Act of 1935.
The Operating Companies are members of the Central Area Power Coordination Group
(CAPCO). Other members are Duquesne Light Company, Ohio Edison Company and its
wholly owned subsidiary, Pennsylvania Power Company. The members have
constructed and operate generation and transmission facilities for their use.
(B) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based
on rate schedules or contracts authorized by the PUCO or on ordinances of
individual municipalities. An accrual is made at the end of each month to record
the estimated amount of unbilled revenues for kilowatt-hours sold in the current
month but not billed by the end of that month.
A fuel factor is added to the base rates for electric service. This factor is
designed to recover from customers the costs of fuel and most purchased power.
It is reviewed and adjusted semiannually in a PUCO proceeding.
(C) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The
cost of nuclear fuel, including an interest component, is charged to fuel
expense based on the rate of consumption. Estimated future nuclear fuel disposal
costs are being recovered through the base rates.
The Operating Companies defer the differences between actual fuel costs and
estimated fuel costs currently being recovered from customers through the fuel
factor. This matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for
the cost of decontamination and decommissioning of nuclear enrichment facilities
operated by the United States Department of Energy. The assessments are based
upon the amount of enrichment services used in prior years and cannot be imposed
for more than 15 years. The Operating Companies have accrued the liability for
their share of the total assessments. These costs have been recorded in a
deferred charge account since the PUCO is allowing the Operating Companies to
recover the assessments through their fuel cost factors.
(D) DEFERRED CARRYING CHARGES
AND OPERATING EXPENSES
The PUCO authorized the Operating Companies to defer operating expenses and
carrying charges for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver
Valley Unit 2) from their respective in-service dates in 1987 through December
1988. The annual amortization and recovery of these deferrals, called
pre-phase-in deferrals, are $17 million which began in January 1989 and will
continue over the lives of the related property.
Beginning in January 1989, the Operating Companies deferred certain operating
expenses and both interest and equity carrying charges pursuant to PUCO-approved
rate phase-in plans for their investments in Perry Unit 1 and Beaver Valley Unit
2. These deferrals, called phase-in deferrals, were written off at December 31,
1993. See Note 7.
The Operating Companies also defer certain costs not currently recovered in
rates under a Rate Stabilization Program approved by the PUCO in October 1992.
See Notes 7 and 14.
(Centerior Energy) F-12 (Centerior Energy)
65
(E) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated
useful lives on a straight-line basis. The annual straight-line depreciation
provision for nonnuclear property expressed as a percent of average depreciable
utility plant in service was 3.5% in 1993 and 3.4% in both 1992 and 1991.
Effective January 1, 1991, the Operating Companies, after obtaining PUCO
approval, changed their method of accounting for nuclear plant depreciation from
the units-of-production method to the straight-line method at about a 3% rate.
This change decreased 1991 depreciation expense $36 million and increased 1991
net income $28 million (net of $8 million of income taxes) and earnings per
share $.20 from what they otherwise would have been. The PUCO subsequently
approved in 1991 a change to lower the 3% rate to 2.5% retroactive to January 1,
1991.
Pursuant to a PUCO order, the Operating Companies currently use external funding
for the future decommissioning of their nuclear units at the end of their
licensed operating lives. The estimated costs are based on the NRC's DECON
method of decommissioning (prompt decontamination). Cash contributions are made
to the trust funds on a straight-line basis over the remaining licensing period
for each unit. The current level of annual expense being recovered from
customers based on prior estimates is approximately $8 million. However, actual
decommissioning costs are expected to significantly exceed those estimates.
Current site-specific estimates for the Operating Companies' share of the future
decommissioning costs are $92 million in 1992 dollars for Beaver Valley Unit 2
and $223 million and $300 million in 1993 dollars for Perry Unit 1 and the
Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for
Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by
the end of the second quarter of 1994. The Operating Companies used these
estimates to increase their decommissioning expense accruals in 1993. It is
expected that the increases associated with the revised cost estimates will be
recoverable in future rates. In the Balance Sheet at December 31, 1993,
Accumulated Depreciation and Amortization included $74 million of
decommissioning costs previously expensed and the earnings on the external
funding. This amount exceeds the Balance Sheet amount of the external Nuclear
Plant Decommissioning Trusts because the reserve began prior to the external
trust funding.
(F) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts ordered
by the PUCO to be written off. Construction costs include related payroll taxes,
pensions, fringe benefits, management and general overheads and allowance for
funds used during construction (AFUDC). AFUDC represents the estimated composite
debt and equity cost of funds used to finance construction. This noncash
allowance is credited to income. The AFUDC rates averaged 9.9% in 1993, 10.8% in
1992 and 10.7% in 1991.
Maintenance and repairs are charged to expense as incurred. The cost of
replacing plant and equipment is charged to the utility plant accounts. The cost
of property retired plus removal costs, after deducting any salvage value, is
charged to the accumulated provision for depreciation.
(G) DEFERRED GAIN AND LOSS FROM
SALES OF UTILITY PLANT
The sale and leaseback transactions discussed in Note 2 resulted in a net gain
for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net
loss for the sale of Beaver Valley Unit 2. The net gain and net loss were
deferred and are being amortized over the terms of leases. These amortizations
and the lease expense amounts are recorded as other operation and maintenance
expenses.
(H) INTEREST CHARGES
Debt Interest reported in the Income Statement does not include interest on
obligations for nuclear fuel under construction. That interest is capitalized.
See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt
are deferred, consistent with the regulatory rate treatment. Such losses and
gains are either amortized over the remainder of the original life of the debt
issue retired or amortized over the life of the new debt issue when the proceeds
of a new issue are used for the debt redemption. The amortizations are included
in debt interest expense.
(Centerior Energy) F-13 (Centerior Energy)
66
(I) FEDERAL INCOME TAXES
The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard
for accounting for income taxes, in February 1992. We adopted the new standard
in 1992. The standard amended certain provisions of SFAS 96 which we had
previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our
results of operations, but did affect certain Balance Sheet accounts. See Note
8.
The financial statements reflect the liability method of accounting for income
taxes. This method requires that deferred taxes be recorded for all temporary
differences between the book and tax bases of assets and liabilities. The
majority of these temporary differences are attributable to property-related
basis differences. Included in these basis differences is the equity component
of AFUDC, which will increase future tax expense when it is recovered through
rates. Since this component is not recognized for tax purposes, we must record a
liability for our tax obligation. The PUCO permits recovery of such taxes from
customers when they become payable. Therefore, the net amount due from customers
through rates has been recorded as a deferred charge and will be recovered over
the lives of the related assets.
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7 for a
discussion of the amortization of certain unrestricted excess deferred taxes and
unrestricted investment tax credits under the Rate Stabilization Program.
(2) Utility Plant Sale and
Leaseback Transactions
The Operating Companies are co-lessees of 18.26% (150 megawatts) of Beaver
Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355
megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for
terms of about 29 1/2 years. These leases are the result of sale and leaseback
transactions completed in 1987.
Under these leases, the Operating Companies are responsible for paying all
taxes, insurance premiums, operation and maintenance expenses and all other
similar costs for their interests in the units sold and leased back. They may
incur additional costs in connection with capital improvements to the units. The
Operating Companies have options to buy the interests back at the end of the
leases for the fair market value at that time or to renew the leases. Additional
lease provisions provide other purchase options along with conditions for
mandatory termination of the leases (and possible repurchase of the leasehold
interests) for events of default. These events include noncompliance with
several financial covenants discussed in Note 11(e).
In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds
(SLOBs) issued by a special purpose corporation in connection with financing the
sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender
offer and the sale of new bonds having a lower interest rate. As part of the
refinancing transaction, Toledo Edison paid $43 million as supplemental rent to
fund transaction expenses and part of the tender premium. This amount has been
deferred and is being amortized over the remaining lease term. The refinancing
transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease
by $9 million.
Future minimum lease payments under the operating leases at December 31, 1993
are summarized as follows:
Year Amount
- ------------------------------------------------- ------------
(millions of
dollars)
1994 $ 166
1995 165
1996 188
1997 165
1998 165
Later Years 3,412
------
Total Future Minimum Lease Payments $4,261
======
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1993, 1992 and 1991 as annual rental expense for the
Mansfield Plant leases was $115 million. The amounts recorded in 1993, 1992 and
1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63
million, $66 million and $72 million, respectively. Amounts charged to expense
in excess of the lease payments are classified as Accumulated Deferred Rents in
the Balance Sheet.
Toledo Edison is selling 150 megawatts of its Beaver Valley Unit 2 leased
capacity entitlement to Cleveland Electric. We anticipate that this sale will
continue indefinitely.
(Centerior Energy) F-14 (Centerior Energy)
67
(3) Property Owned with Other Utilities and Investors
The Operating Companies own, as tenants in common with other utilities and those
investors who are owner-participants in various sale and leaseback transactions
(Lessors), certain generating units as listed below. Each owner owns an
undivided share in the entire unit. Each owner has the right to a percentage of
the generating capability of each unit equal to its ownership share. Each
utility owner is obligated to pay for only its respective share of the
construction costs and operating expenses. Each Lessor has leased its capacity
rights to a utility which is obligated to pay for such Lessor's share of the
construction costs and operating expenses. The Operating Companies' share of the
operating expenses of these generating units is included in the Income
Statement. The Balance Sheet classification of Property, Plant and Equipment at
December 31, 1993 includes the following facilities owned by the Operating
Companies as tenants in common with other utilities and Lessors:
In- Plant Construction
Service Ownership Ownership Power in Work in Accumulated
Generating Unit Date Share Megawatts Source Service Progress Depreciation
- ------------------------------- ------- --------- --------- -------- ------- ------------ ------------
(millions of dollars)
Seneca Pumped Storage 1970 80.00% 351 Hydro $ 67 $ -- $ 22
Eastlake Unit 5 1972 68.80 411 Coal 156 2 --
Perry Unit 1 1987 51.02 609 Nuclear 2,832 11 473
Beaver Valley Unit 2 and
Common Facilities (Note 2) 1987 26.12 214 Nuclear 1,480 5 255
------- --- -----
Total $4,535 $ 18 $750
------- --- -----
------- --- -----
Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear
depreciable property rather than by specific units of depreciable property.
(4) Construction and
Contingencies
(A) CONSTRUCTION PROGRAM
The estimated cost of our construction program for the 1994-1998 period is
$1.088 billion, including AFUDC of $48 million and excluding nuclear fuel.
The Clean Air Act will require, among other things, significant reductions in
the emission of sulfur dioxide in two phases over a ten-year period and nitrogen
oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at
least 2005 primarily through greater use of low-sulfur coal at some of our units
and the banking of emission allowances. The plan will require capital
expenditures over the 1994-2003 period of approximately $222 million for
nitrogen oxide control equipment, emission monitoring equipment and plant
modifications. In addition, higher fuel and other operation and maintenance
expenses will be incurred. The anticipated rate increase associated with the
capital expenditures and higher expenses would be about 1-2% in the late 1990s.
Cleveland Electric may need to install sulfur emission control technology at one
of its generating plants after 2005 which could require additional expenditures
at that time. The PUCO has approved this plan. We also are seeking United States
Environmental Protection Agency (U.S. EPA) approval of the first phase of our
plan.
We are continuing to monitor developments in new technologies that may be
incorporated into our compliance strategy. If a different plan is required by
the U.S. EPA, significantly higher capital expenditures could be required during
the 1994-2003 period. We believe Ohio law permits the recovery of compliance
costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1,
was approximately 50% complete when construction was suspended in 1985 pending
consideration of various options. These options included resumption of full
construction with a revised estimated cost, conversion to a nonnuclear design,
sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we
determined that it would not be completed or sold. The write-off totaled $583
million ($425 million after taxes) for our 64.76% ownership share of the unit.
See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Operating Companies are aware of their potential involvement in the cleanup
of three sites listed on the Superfund List and several other waste sites not on
such list. The Operating Companies have accrued a liability totaling $19 million
at December 31, 1993 based on estimates of the costs of cleanup and their
proportionate responsibility for such costs. We believe that the ultimate
outcome of these matters will not have a material adverse effect on our
financial condition or results of operations. See Management's Financial
Analysis -- Outlook-Hazardous Waste Disposal Sites.
(Centerior Energy) F-15 (Centerior Energy)
68
(5) Nuclear Operations and
Contingencies
(A) OPERATING NUCLEAR UNITS
Our three nuclear units may be impacted by activities or events beyond our
control. An extended outage of one of our nuclear units for any reason, coupled
with any unfavorable rate treatment, could have a material adverse effect on our
financial condition and results of operations. See discussion of these risks in
Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power
plant to the amount provided by private insurance and an industry assessment
plan. In the event of a nuclear incident at any unit in the United States
resulting in losses in excess of the level of private insurance (currently $200
million), our maximum potential assessment under that plan would be $155 million
(plus any inflation adjustment) per incident. The assessment is limited to $20
million per year for each nuclear incident. These assessment limits assume the
other CAPCO companies contribute their proportionate share of any assessment.
The CAPCO companies have insurance coverage for damage to property at the
Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up
costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994.
Damage to property could exceed the insurance coverage by a substantial amount.
If it does, our share of such excess amount could have a material adverse effect
on our financial condition and results of operations. Under these policies, we
can be assessed a maximum of $25 million during a policy year if the reserves
available to the insurer are inadequate to pay claims arising out of an accident
at any nuclear facility covered by the insurer.
We also have extra expense insurance coverage. It includes the incremental cost
of any replacement power purchased (over the costs which would have been
incurred had the units been operating) and other incidental expenses after the
occurrence of certain types of accidents at our nuclear units. The amounts of
the coverage are 100% of the estimated extra expense per week during the 52-week
period starting 21 weeks after an accident and 67% of such estimate per week for
the next 104 weeks. The amount and duration of extra expense could substantially
exceed the insurance coverage.
(6) Nuclear Fuel
Nuclear fuel is financed for the Operating Companies through leases with a
special-purpose corporation. The total amount of financing currently available
under these lease arrangements is $382 million ($232 million from
intermediate-term notes and $150 million from bank credit arrangements).
Financing in an amount up to $750 million is permitted. The intermediate-term
notes mature in the period 1994-1997, with $75 million maturing in September
1994. At December 31, 1993, $370 million of nuclear fuel was financed. The
Operating Companies severally lease their respective portions of the nuclear
fuel and are obligated to pay for the fuel as it is consumed in a reactor. The
lease rates are based on various intermediate-term note rates, bank rates and
commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and
Beaver Valley Unit 2 reactors with remaining lease payments of $110 million, $78
million and $46 million, respectively, at December 31, 1993. The nuclear fuel
amounts financed and capitalized also included interest charges incurred by the
lessors amounting to $14 million in 1993, $15 million in 1992 and $21 million in
1991. The estimated future lease amortization payments based on projected
consumption are $111 million in 1994, $97 million in 1995, $87 million in 1996,
$77 million in 1997 and $69 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in
plans approved by the PUCO in January 1989 rate orders for the Operating
Companies. The phase-in plans were designed so that the projected revenues
resulting from the authorized rate increases and anticipated sales growth
provided for the phase-in of certain nuclear costs over a ten-year period. The
plans required the deferral of a portion of the operating expenses and both
interest and equity carrying charges on the Operating Companies' deferred
rate-based investments in Perry Unit 1 and Beaver Valley Unit 2 during the early
years of the plans. The amortization and recovery of such deferrals were
scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our
deferred charges and continued application of the regulatory accounting measures
we follow pursuant to PUCO orders. We concluded that projected revenues would
not provide for the recovery of the phase-in deferrals as scheduled because of
economic and competitive pressures. Accordingly, we wrote off the cumulative
balance of the phase-in deferrals. The total phase-in deferred operating
expenses and carrying charges written off at December 31, 1993 were $172 million
and $705 million, respectively (totaling $598 million after taxes). See Note 14.
While recovery of our other regulatory deferrals remains probable, our current
(Centerior Energy) F-16 (Centerior Energy)
69
assessment of business conditions has prompted us to change our future plans. We
decided that, once the deferral of expenses and acceleration of benefits under
our Rate Stabilization Program are completed in 1995, we should no longer plan
to use regulatory accounting measures to the extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was
designed to encourage economic growth in our service area by freezing base rates
until 1996 and limiting subsequent rate increases to specified annual amounts
not to exceed $216 million for Cleveland Electric and $89 million for Toledo
Edison over the 1996-1998 period.
As part of the Rate Stabilization Program, the Operating Companies are allowed
to defer and subsequently recover certain costs not currently recovered in rates
and to accelerate amortization of certain benefits. Such regulatory accounting
measures provide for rate stabilization by rescheduling the timing of rate
recovery of certain costs and the amortization of certain benefits during the
1992-1995 period. The continued use of these regulatory accounting measures will
be dependent upon our continuing assessment and conclusion that there will be
probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December
31, 1995 include the deferral of post-in-service interest carrying charges,
depreciation expense and property taxes on assets placed in service after
February 29, 1988 and the deferral of Toledo Edison operating expenses
equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which
resulted from the April 1992 refinancing of SLOBs as discussed in Note 2). The
cost deferrals recorded in 1993 and 1992 pursuant to these provisions were $95
million and $84 million, respectively. Amortization and recovery of these
deferrals will occur over the average life of the related assets and the
remaining lease period, or approximately 30 years, and will commence with future
rate recognition. The regulatory accounting measures also provide for the
accelerated amortization of certain unrestricted excess deferred tax and
unrestricted investment tax credit balances and interim spent fuel storage
accrual balances for Davis-Besse. The total amount of such regulatory benefits
recognized in 1993 and 1992 pursuant to these provisions was $46 million and $12
million, respectively.
The Rate Stabilization Program also authorized the Operating Companies to defer
and subsequently recover the incremental expenses associated with the adoption
of the accounting standard for postretirement benefits other than pensions (SFAS
106). In 1993, we deferred $96 million pursuant to this provision. Amortization
and recovery of this deferral will commence prior to 1998 and is expected to be
completed by no later than 2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying the income before taxes and
preferred dividend requirements of subsidiaries by the statutory rate (35% in
1993 and 34% in both 1992 and 1991), is reconciled to the amount of federal
income tax recorded on the books as follows:
1993 1992 1991
------- ---- ----
(millions of dollars)
Book Income (Loss) Before Federal Income
Tax $(1,263) $406 $466
------- ---- ----
------- ---- ----
Tax (Credit) on Book Income (Loss) at
Statutory Rate $ (442) $138 $158
Increase (Decrease) in Tax:
Write-off of Perry Unit 2 46 -- --
Write-off of phase-in deferrals 28 -- --
Depreciation (6) (9) 1
Rate Stabilization Program (30) (7) --
Other items 17 7 9
------- ---- ----
Total Federal Income Tax Expense
(Credit) $ (387) $129 $168
------- ---- ----
------- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991
----- ----- -----
(millions of dollars)
Operating Expenses:
Current Tax Provision $ 99 $ 71 $ 88
Changes in Accumulated Deferred
Federal Income Tax:
Write-off of deferred operating
expenses (39) -- --
Accelerated depreciation and
amortization 95 39 17
Alternative minimum tax credit (57) (31) (46)
Retirement and postemployment
benefits (43) -- --
Sale and leaseback transactions and
amortization 9 8 4
Taxes, other than federal income
taxes (25) 19 --
Rate Stabilization Program (9) 4 --
Reacquired debt costs (3) 10 22
Deferred fuel costs (2) (1) (9)
Other items (14) 3 23
Investment Tax Credits -- -- 39
----- ----- -----
Total Charged to Operating
Expenses 11 122 138
----- ----- -----
Nonoperating Income:
Current Tax Provision (34) (38) (46)
Changes in Accumulated Deferred
Federal Income Tax:
Write-off of deferred carrying
charges (240) -- --
Write-off of Perry Unit 2 (158) -- --
Disallowed nuclear costs 20 14 --
Rate Stabilization Program 11 11 --
AFUDC and carrying charges 12 24 41
Net operating loss carryforward (7) -- 35
Other items (2) (4) --
----- ----- -----
Total Expense (Credit) to
Nonoperating Income (398) 7 30
----- ----- -----
Total Federal Income Tax Expense
(Credit) $(387) $ 129 $ 168
----- ----- -----
----- ----- -----
(Centerior Energy) F-17 (Centerior Energy)
70
In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993,
the top marginal corporate income tax rate increased to 35%. The change in tax
rate increased Accumulated Deferred Federal Income Taxes for the future tax
obligation by approximately $90 million. Since the PUCO has historically
permitted recovery of such taxes from customers when they become payable, the
deferred charge, Amounts Due from Customers for Future Federal Income Taxes,
also was increased by $90 million. The 1993 Tax Act is not expected to
materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $619 million and deferred tax liabilities of $2.198 billion at
December 31, 1993 and deferred tax assets of $563 million and deferred tax
liabilities of $2.598 billion at December 31, 1992. These are summarized as
follows:
December 31,
---------------
1993 1992
------ ------
(millions of
dollars)
Property, plant and equipment $1,845 $2,125
Deferred carrying charges and operating 206 368
expenses
Net operating loss carryforwards (108) (137)
Investment tax credits (183) (190)
Other (181) (131)
------ ------
Net deferred tax liability $1,579 $2,035
------ ------
------ ------
For tax purposes, net operating loss (NOL) carryforwards of approximately $309
million are available to reduce future taxable income and will expire in 2003
through 2005. The 35% tax effect of the NOLs is $108 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit
to be used to reduce the regular tax to the AMT level should the regular tax
exceed the AMT. AMT credits of $171 million are available to offset future
regular tax. The credits may be carried forward indefinitely.
(9) Retirement and
Postemployment Benefits
(A) RETIREMENT INCOME PLAN
We sponsor a noncontributing pension plan which covers all employee groups. Two
existing plans were merged into a single plan on December 31, 1993. The amount
of retirement benefits generally depends upon the length of service. Under
certain circumstances, benefits can begin as early as age 55. Our funding policy
is to comply with the Employee Retirement Income Security Act of 1974
guidelines.
In 1993, we offered the VTP, an early retirement program. Operating expenses for
1993 included $205 million of pension plan accruals to cover enhanced VTP
benefits and an additional $10 million of pension costs for VTP benefits paid to
retirees from corporate funds. The $10 million is not included in the pension
data reported below. A credit of $81 million resulting from a settlement of
pension obligations through lump sum payments to almost all the VTP retirees
partially offset the VTP expenses.
Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the
following components:
1993 1992 1991
---- ---- -----
(millions of dollars)
Pension Costs (Credits):
Service cost for benefits earned
during the
period $ 15 $ 15 $ 14
Interest cost on projected benefit
obligation 37 38 36
Actual return on plan assets (65) (24) (129)
Net amortization and deferral 4 (45) 65
---- ---- -----
Net pension costs (credits) (9) (16) (14)
VTP cost 205 -- --
Settlement gain (81) -- --
---- ---- -----
Net costs (credits) $115 $(16) $ (14)
---- ---- -----
---- ---- -----
The following table presents a reconciliation of the funded status of the
plan(s) at December 31, 1993 and 1992.
1993 1992
---- ----
(millions of
dollars)
Actuarial present value of benefit obligations:
Vested benefits $333 $310
Nonvested benefits 37 40
---- ----
Accumulated benefit obligation 370 350
Effect of future compensation levels 53 121
---- ----
Total projected benefit obligation 423 471
Plan assets at fair market value 386 754
---- ----
Funded status (37) 283
Unrecognized net loss (gain) from variance
between assumptions and experience 11 (140)
Unrecognized prior service cost 10 12
Transition asset at January 1, 1987 being
amortized over 19 years (43) (99)
---- ----
Net prepaid pension cost (accrued pension
liability) included in other deferred
charges (credits) in the Balance Sheet $(59) $ 56
---- ----
---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of
return on plan assets assumptions were 7.25% and 8.75%, respectively. The
long-term rate of annual compensation increase assumption was 4.25%. At December
31, 1992, the settlement rate and long-term rate of return on plan assets
assumptions were 8.5% and the long-term rate of annual compensation increase
assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed
investment contracts, cash equivalent securities and real estate.
(Centerior Energy) F-18 (Centerior Energy)
71
(B) OTHER POSTRETIREMENT BENEFITS
We sponsor a postretirement benefit plan which provides all employee groups
certain health care, death and other postretirement benefits other than
pensions. The plan is contributory, with retiree contributions adjusted
annually. The plan is not funded. A policy limiting the employer's contribution
for retiree medical coverage for employees retiring after March 31, 1993 was
implemented in February 1993.
We adopted SFAS 106, the accounting standard for postretirement benefits other
than pensions, effective January 1, 1993. The standard requires the accrual of
the expected costs of such benefits during the employees' years of service.
Previously, the costs of these benefits were expensed as paid, which is
consistent with ratemaking practices. Such costs totaled $9 million in 1992 and
$10 million in 1991, which included medical benefits of $8 million in 1992 and
$9 million in 1991. The total amount accrued for SFAS 106 costs for 1993 was
$111 million, of which $5 million was capitalized and $106 million was expensed
as other operation and maintenance expenses. In 1993, we deferred incremental
SFAS 106 expenses totaling $96 million pursuant to a provision of the Rate
Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as
follows:
Millions
of Dollars
----------
Service cost for benefits earned $ 3
Interest cost on accumulated postretirement
benefit obligation 16
Amortization of transition obligation at January
1, 1993 of $167 million over 20 years 8
VTP curtailment cost (includes $16 million
transition obligation adjustment) 84
-----
Total costs $111
-----
-----
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost at December 31, 1993 are summarized as follows:
Millions
of Dollars
----------
Accumulated postretirement benefit obligation
attributable to:
Retired participants $ (229)
Fully eligible active plan participants (1)
Other active plan participants (28)
----------
Accumulated postretirement benefit obligation (258)
Unrecognized net loss from variance between
assumptions and experience 14
Unamortized transition obligation 143
----------
Accrued postretirement benefit cost included
in other noncurrent liabilities in the
Balance Sheet $ (101)
----------
----------
At December 31, 1993, the settlement rate and the long-term rate of annual
compensation increase assumptions were 7.25% and 4.25%, respectively. The
assumed annual health care cost trend rates (applicable to gross eligible
charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce
gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the
obligation affected by contribution caps are significantly less sensitive to the
health care cost trend rate than other elements. If the assumed health care cost
trend rates were increased by 1% in each future year, the accumulated
postretirement benefit obligation as of December 31, 1993 would increase by $11
million and the aggregate of the service and interest cost components of the
annual postretirement benefit cost would increase by $1 million.
(C) POSTEMPLOYMENT BENEFITS
In 1993, we adopted SFAS 112, the new accounting standard which requires the
accrual of postemployment benefit costs. Postemployment benefits are the
benefits provided to former or inactive employees after employment but before
retirement, such as worker's compensation, disability benefits and severance
pay. The adoption of this accounting method did not materially affect our 1993
results of operations or financial position.
(10) Guarantees
Cleveland Electric has guaranteed certain loan and lease obligations of two
mining companies under two long-term coal purchase arrangements. Toledo Edison
is also a party to one of these guarantee arrangements. This arrangement
requires payments to the mining company for any actual expenses (as advance
payments for coal) when the mines are idle for reasons beyond the control of the
mining company. At December 31, 1993, the principal amount of the mining
companies' loan and lease obligations guaranteed by the Operating Companies was
$80 million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Shares sold, retired and purchased for treasury during the three years ended
December 31, 1993 are listed in the following tables.
1993 1992 1991
----- ----- -----
(thousands of shares)
Centerior Energy Common Stock:
Dividend Reinvestment and Stock
Purchase Plan 3,542 2,570 1,422
Employee Savings Plan 544 322 348
Employee Purchase Plan 52 -- --
----- ----- -----
Total Common Stock Sales 4,138 2,892 1,770
Treasury Shares 26 (172) (11)
----- ----- -----
Net Increase 4,164 2,720 1,759
----- ----- -----
----- ----- -----
(Centerior Energy) F-19 (Centerior Energy)
72
1993 1992 1991
----- ----- -----
(thousands of shares)
Preferred Stock of Subsidiaries
Subject to Mandatory Redemption:
Cleveland Electric Sales
$ 91.50 Series Q -- -- 75
88.00 Series R -- -- 50
90.00 Series S -- 75 --
Cleveland Electric Retirements
$ 7.35 Series C (10) (10) (10)
88.00 Series E (3) (3) (3)
75.00 Series F -- -- (2)
145.00 Series I -- -- (14)
113.50 Series K -- -- (10)
Adjustable Series M (100) (100) (100)
9.125 Series N (150) -- --
Toledo Edison Retirements
$100 par $11.00 -- (25) (10)
9.375 (17) (17) (17)
25 par 2.81 (800) -- --
Preferred Stock of Subsidiaries Not
Subject to Mandatory Redemption:
Cleveland Electric Sales
$ 42.40 Series T 200 -- --
Cleveland Electric Retirements
Remarketed Series P -- (1) --
----- ----- -----
Net (Decrease) (880) (81) (41)
----- ----- -----
----- ----- -----
Shares of common stock required for our stock plans in 1993 were either acquired
in the open market, issued as new shares or issued from treasury stock.
The Board of Directors has authorized the purchase in the open market of up to
1,500,000 shares of our common stock until June 30, 1994. As of December 31,
1993, 225,500 shares had been purchased at a total cost of $4 million. Such
shares are being held as treasury stock.
(B) COMMON SHARES RESERVED FOR ISSUE
Common shares reserved for issue under the Employee Savings Plan and the
Employee Purchase Plan were 1,962,174 and 469,457 shares, respectively, at
December 31, 1993.
Stock options to purchase unissued shares of common stock under the 1978 Key
Employee Stock Option Plan were granted at an exercise price of 100% of the fair
market value at the date of the grant. No additional options may be granted. The
exercise prices of option shares purchased during the three years ended December
31, 1993 ranged from $14.09 to $17.41 per share. Shares and price ranges of
outstanding options held by employees were as follows:
1993 1992 1991
--------- --------- ---------
Options Outstanding at
December 31:
Shares 37,627 93,312 129,798
Option Prices $14.09 to $14.09 to $14.09 to
$20.73 $20.73 $20.73
(C) EQUITY DISTRIBUTION RESTRICTIONS
The Operating Companies make cash available for the funding of Centerior
Energy's common stock dividends by paying dividends on their respective common
stock, which are held solely by Centerior Energy. Federal law prohibits the
Operating Companies from paying dividends out of capital accounts. However, the
Operating Companies may pay preferred and common stock dividends out of
appropriated retained earnings and current earnings. At December 31, 1993,
Cleveland Electric and Toledo Edison had $125 million and $42 million,
respectively, of appropriated retained earnings for the payment of dividends.
However, Toledo Edison is prohibited from paying a common stock dividend by a
provision in its mortgage.
(D) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next
five years are $40 million in 1994, $51 million in 1995, $41 million in 1996,
$31 million in 1997 and $16 million in 1998.
The annual mandatory redemption provisions are as follows:
Shares Price
To Be Beginning Per
Redeemed in Share
-------- --------- ------
Cleveland Electric Preferred:
$ 7.35 Series C 10,000 1984 $ 100
88.00 Series E 3,000 1981 1,000
Adjustable Series M 100,000 1991 100
9.125 Series N 150,000 1993 100
91.50 Series Q 10,714 1995 1,000
88.00 Series R 50,000 2001* 1,000
90.00 Series S 18,750 1999 1,000
Toledo Edison Preferred:
$100 par $9.375 16,650 1985 100
25 par 2.81 400,000 1993 25
* All outstanding shares to be redeemed on December 1, 2001.
In June 1993, Cleveland Electric issued $100 million principal amount of Serial
Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent
which issued Depositary Receipts, each representing 1/20 of a share of the
Series T stock.
The annualized preferred dividend requirement for the Operating Companies at
December 31, 1993 was
$68 million.
The preferred dividend rates on Cleveland Electric's Series L and M and Toledo
Edison's Series A and B fluctuate based on prevailing interest rates and market
conditions. The dividend rates for these issues averaged 7%, 7%, 7.41% and
8.22%, respectively, in 1993. Cleveland Electric's Series P had a 6.5% dividend
rate in 1993 until it was redeemed in August 1993.
(Centerior Energy) F-20 (Centerior Energy)
73
Preference stock authorized for the Operating Companies are 3,000,000 shares
without par value for Cleveland Electric and 5,000,000 shares with a $25 par
value for Toledo Edison. No preference shares are currently outstanding for
either company.
With respect to dividend and liquidation rights, each Operating Company's
preferred stock is prior to its preference stock and common stock, and each
Operating Company's preference stock is prior to its common stock.
(E) LONG-TERM DEBT AND OTHER
BORROWING ARRANGEMENTS
Long-term debt, less current maturities, for the Operating Companies was as
follows:
Actual
or Average
Interest
Rate at December 31,
December 31, ---------------
Year of Maturity 1993 1993 1992
- -------------------------------- ------------ ------ ------
(millions of
dollars)
First mortgage bonds:
1994 4.375% $ -- $ 25
1994 13.75 -- 4
1995 13.75 4 4
1995 7.00 1 1
1996 13.75 4 4
1996 7.00 1 1
1997 10.88 6 6
1997 13.75 4 4
1997 7.00 1 1
1997 6.125 31 31
1998 10.88 6 6
1998 13.75 4 4
1998 7.00 1 1
1998 10.00 1 1
1999-2003 7.89 568 468
2004-2008 8.14 260 264
2009-2013 7.68 436 436
2014-2018 8.07 513 513
2019-2023 7.89 733 583
------ ------
2,574 2,357
Secured medium term notes due
1995-2021 8.77 963 860
Term bank loans due 1995-1996 7.41 154 121
Notes due 1995-1997 9.63 43 60
Debentures due 2002 8.70 135 135
Pollution control notes due
1995-2015 10.11 158 158
Other -- net -- (8) 3
------ ------
Total Long-Term Debt $4,019 $3,694
------ ------
------ ------
Long-term debt matures during the next five years as follows: $87 million in
1994, $317 million in 1995, $242 million in 1996, $94 million in 1997 and $117
million in 1998.
The Operating Companies issued $550 million aggregate principal amount of
secured medium-term notes during the 1991-1993 period. The notes are secured by
first mortgage bonds.
The mortgages of the Operating Companies constitute direct first liens on
substantially all property owned and franchises held by them. Excluded from the
liens, among other things, are cash, securities, accounts receivable, fuel,
supplies and, in the case of Toledo Edison, automotive equipment.
Certain unsecured loan agreements of the Operating Companies contain covenants
relating to capitalization ratios, fixed charge coverage ratios and limitations
on secured financing other than through first mortgage bonds or certain other
transactions. Two reimbursement agreements relating to separate letters of
credit issued in connection with the sale and leaseback of Beaver Valley Unit 2
contain several financial covenants affecting Centerior Energy and the Operating
Companies. Among these are covenants relating to fixed charge coverage ratios
and capitalization ratios. The write-offs recorded at December 31, 1993 caused
Centerior Energy and the Operating Companies to violate certain covenants
contained in a Cleveland Electric loan agreement and the two reimbursement
agreements. The affected creditors have waived those violations in exchange for
our commitment to provide them with a second mortgage security interest on our
property and other considerations. We expect to complete this process in the
second quarter of 1994. We will provide the same security interest to certain
other creditors because their agreements require equal treatment. We expect to
provide second mortgage collateral for $219 million of unsecured debt, $228
million of bank letters of credit and a $205 million revolving credit facility.
(12) Short-Term Borrowing
Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving
credit facility. The facility may be renewed twice for one-year periods at the
option of the participating banks. Centerior Energy and the Service Company may
borrow under the facility, with all borrowings jointly and severally guaranteed
by the Operating Companies. Centerior Energy plans to transfer any of its
borrowed funds to the Operating Companies, while the Service Company may borrow
up to $25 million for its own use. The banks' fee is 0.5% per annum payable
quarterly in addition to interest on any borrowings. That fee is expected to
increase to 0.625% when the facility agreement is amended as discussed below.
There were no borrowings under the facility at December 31, 1993. The facility
agreement contains covenants relating to capitalization and fixed charge
coverage ratios. The write-offs recorded at December 31, 1993 caused the ratios
to fall below those covenant requirements. The
(Centerior Energy) F-21 (Centerior Energy)
74
revolving credit facility is expected to be available for borrowings after the
facility agreement is amended in the second quarter of 1994 to provide the
participating creditors with a second mortgage security interest.
Short-term borrowing capacity authorized by the PUCO annually is $300 million
for Cleveland Electric and $150 million for Toledo Edison. The Operating
Companies are authorized by the PUCO to borrow from each other on a short-term
basis.
At December 31, 1993, the Operating Companies had no commercial paper
outstanding. The Operating Companies are unable to rely on the sale of
commercial paper to provide short-term funds because of their below investment
grade commercial paper credit ratings.
(13) Financial Instruments'
Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments
that do not approximate their carrying amounts are as follows:
December 31,
----------------------------------
1993 1992
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- ------
(millions of dollars)
Nuclear Plant Decommissioning
Trusts $ 56 $ 59 $ 42 $ 45
Preferred Stock, with Mandatory
Redemption Provisions
(including current portion) 354 349 405 408
Long-Term Debt (including
current portion) 4,113 4,260 4,017 4,107
The fair value of the nuclear plant decommissioning trusts is estimated based on
the quoted market prices for the investment securities. The fair value of the
Operating Companies' preferred stock with mandatory redemption provisions and
long-term debt is estimated based on the quoted market prices for the respective
or similar issues or on the basis of the discounted value of future cash flows.
The discounted value used current dividend or interest rates (or other
appropriate rates) for similar issues and loans with the same remaining
maturities.
The estimated fair values of all other financial instruments approximate their
carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of
their short-term nature.
(14) Quarterly Results of Operations
(Unaudited)
The following is a tabulation of the unaudited quarterly results of operations
for the two years ended December 31, 1993.
Quarters Ended
----------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
(millions of dollars,
except per share amounts)
1993
Operating Revenues $ 598 $589 $ 709 $ 578
Operating Income (Loss) $ 122 $126 $ 106 $ (42)
Net Income (Loss) $ 35 $ 34 $ 17 $(1,029)
Average Common Shares
(millions) 143.4 144.4 145.3 146.4
Earnings (Loss) Per
Common Share $ .25 $.23 $ .12 $ (7.02)
Dividends Paid Per
Common Share $ .40 $.40 $ .40 $ .40
1992
Operating Revenues $ 592 $581 $ 665 $ 600
Operating Income $ 122 $115 $ 191 $ 109
Net Income $ 23 $ 20 $ 122 $ 47
Average Common Shares
(millions) 140.6 141.6 142.0 142.5
Earnings Per Common
Share $ .16 $.14 $ .86 $ .33
Dividends Paid Per
Common Share $ .40 $.40 $ .40 $ .40
Earnings for the quarter ended September 30, 1993 were decreased by $81 million,
or $.56 per share, as a result of the recording of $125 million of VTP
pension-related benefits.
Earnings for the quarter ended December 31, 1993 were decreased as a result of
year-end adjustments for the $583 million write-off of Perry Unit 2 (see Note
4(b)), the $877 million write-off of the phase-in deferrals (see Note 7) and $58
million of other charges. These adjustments decreased quarterly earnings by
$1.06 billion, or $7.24 per share.
Earnings for the quarter ended September 30, 1992 were increased by $41 million,
or $.29 per share, as a result of the recording of deferred operating expenses
and carrying charges for the first nine months of 1992 totaling $61 million
under the Rate Stabilization Program approved by the PUCO in October 1992. See
Note 7.
(Centerior Energy) F-22 (Centerior Energy)
75
FINANCIAL AND
STATISTICAL REVIEW
- ----------------------------------------------------------------------
Operating Revenues (millions of dollars)
Steam Total
Total Total Heating Operating
Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas Revenues
- -----------------------------------------------------------------------------------------------------------------------------------
1993 $ 768 716 754 143 2 381 93 2 474 -- $ 2 474
1992 732 706 766 143 2 347 91 2 438 -- 2 438
1991 777 723 783 188 2 471 89 2 560 -- 2 560
1990 719 669 779 190 2 357 70 2 427 -- 2 427
1989 686 617 747 204 2 254 107 2 361 -- 2 361
1983 546 440 600 83 1 669 29 1 698 25 1 723
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Expenses (millions of dollars)
Other Deferred
Fuel & Operation Depreciation Taxes, Operating Federal Total
Purchased & & Other Than Expenses, Income Operating
Year Power Maintenance Amortization FIT Net Taxes Expenses
- ------------------------------------------------------------------------------------------------------------------
1993 $ 474 1 083(a) 258 312 23(b) 11 $ 2 161
1992 473 784 256 318 (52) 122 1 901
1991 500 801 243(c) 305 (6) 138 1 981
1990 472 863 242 283 (34) 96 1 922
1989 473 860 273 260 (59) 122 1 929
1983 464 384 145 172 -- 184 1 349
- ------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Federal Income
Other Deferred Income (Loss)
Income & Carrying Tax-- Before
Operating AFUDC-- Deductions, Charges, Credit Interest Debt
Year Income Equity Net Net (Expense) Charges Interest
- -----------------------------------------------------------------------------------------------------------
1993 $ 313 5 (589)(d) (649)(b) 398 (522) 359
1992 537 2 9 100 (7) 641 365
1991 579 9 6 110 (30) 674 381
1990 505 8 (1) 205 (13) 704 384
1989 432 17 14 299 (73) 689 369
1983 374 153 5 -- 47 579 258
- -----------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars) Common Stock (dollars per share & %)
Return on
Preferred & Average Average
Preference Net Shares Common
AFUDC-- Stock Income Outstanding Earnings Stock Dividends
Year Debt Dividends (Loss) (millions) (Loss) Equity Declared
- ------------------------------------------------------------------------------------------------------------------------
1993 $ (5) 67 $ (943) 144.9 $ (6.51) (40.3)% $ 1.60
1992 (1) 65 212 141.7 1.50 7.4 1.60
1991 (5) 61 237 139.1 1.71 8.4 1.60
1990 (6) 62 264 138.9 1.90 9.4 1.60
1989 (13) 66 267 140.5 1.90 9.6 1.60
1983 (54) 69 306 98.2(e) 3.11(e) 15.7 2.19(e)
- ------------------------------------------------------------------------------------------------------------------------
Book
Year Value
- ---------- -----------
1993 $12.14
1992 20.22
1991 20.37
1990 20.30
1989 19.99
1983 20.24(e)
- ----------------------------
NOTE: 1983 data is the result of combining and restating data for the Operating
Companies.
(a) Includes early retirement program expenses and other charges of $272 million
in 1993.
(b) Includes write-off of phase-in deferrals of $877 million in 1993, consisting
of $172 million of deferred operating expenses and $705 million of deferred
carrying charges.
(c) In 1991, the Operating Companies adopted a change in accounting for nuclear
plant depreciation, changing from the units-of-production method to the
straight-line method at a 2.5% rate.
(Centerior Energy) F-23 (Centerior Energy)
76
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
Electric Sales (millions of KWH) Electric Customers (year end)
Industrial
Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other
- ----------------------------------------------------------------------------------------- --------------------------------------
1993 6 974 7 306 11 687 3 027 1 022 30 016 924 227 96 491 12 219
1992 6 666 7 086 11 551 2 814 1 011 29 128 925 099 96 813 12 741
1991 6 981 7 176 11 559 2 690 1 048 29 454 921 995 96 449 12 843
1990 6 666 6 848 12 168 2 487 959 29 128 918 965 94 522 12 906
1989 6 806 6 830 12 520 3 235 996 30 387 914 020 93 833 12 763
1983 6 327 5 606 10 641 703 854 24 131 886 024 85 769 11 557
Residential Usage
Average Average
Average Price Revenue
KWH Per Per Per
Year Total Customer KWH Customer
- ------- ----------- ---------------------------------
1993 1 032 937 7 546 11.01cent $830.99
1992 1 034 653 7 227 10.98 793.68
1991 1 031 287 7 410 11.16 827.10
1990 1 026 393 7 079 10.82 765.93
1989 1 020 616 7 295 10.08 737.58
1983 983 350 6 967 8.64 603.22
- --------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel
Operable
Capacity Company Generated
at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost
Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH
- -------------------------------------------------------- --------------------------------------------------------- ----------
1993 5 998 5 397 10.0% 61.6% 21 105 10 435 31 540 273 31 813 1.39cent
1992 6 430 5 091 20.8 63.4 17 371 13 814 31 185 (122) 31 063 1.45
1991 6 453 5 361 16.9 62.9 18 041 13 454 31 495 40 31 535 1.48
1990 6 437 5 261 18.3 63.6 21 114 9 481 30 595 413 31 008 1.52
1989 6 430 5 389 16.2 63.3 20 174 12 122 32 296 21 32 317 1.47
1983 6 218 4 717 24.1 63.1 19 487 4 895 24 382 1 650 26 032 1.72
Efficiency--
BTU Per
Year KWH
- -------- ----------
1993 10 276
1992 10 395
1991 10 442
1990 10 354
1989 10 435
1983 10 419
- --------------------------------------------------------------------------------
Investment (millions of dollars)
Construction
Utility Work In Total
Plant Accumulated Progress Nuclear Property, Utility
In Depreciation & Net & Perry Fuel and Plant and Plant Total
Year Service Amortization Plant Unit 2 Other Equipment Additions Assets
- ------------------------------------------------------------------------------------------------ ------- --------
1993 $9 571 2 677 6 894 181 385 $ 7 460 $ 218 $10 710
1992 9 449 2 488 6 961 781 424 8 166 200 12 071
1991 8 888 2 274 6 614 853 503 7 970 204 11 829
1990 8 636 2 039 6 597 921 568 8 086 251 11 681
1989 8 398 1 824 6 574 945 592 8 111 217 11 454
1983 4 180 1 047 3 133 2 710 392(f) 6 235 785 6 922
- --------------------------------------------------------------------------------
Capitalization (millions of dollars & %)
Preferred &
Preference Preferred
Stock, with Stock, without
Mandatory Mandatory
Common Stock Redemption Redemption
Year Equity Provisions Provisions Long-Term Debt Total
- -------------------------------------------------------------------------------------------------------
1993 $1 785 27% 313 5% 451 7% 4 019 61% $6 568
1992 2 889 39 364 5 354 5 3 694 51 7 301
1991 2 855 38 332 4 427 6 3 841 52 7 455
1990 2 810 39 237 3 427 6 3 729 52 7 203
1989 2 795 40 281 4 427 6 3 534 50 7 037
1983 2 065 39 412 8 344 6 2 504 47 5 325
- --------------------------------------------------------------------------------
(d) Includes write-off of Perry Unit 2 of $583 million in 1993.
(e) Average shares outstanding and related per share computations reflect the
Cleveland Electric 1.11-for-one exchange ratio and the Toledo Edison
one-for-one exchange ratio for Centerior Energy shares at the date of
affiliation, April 29, 1986.
(f) Restated for effects of capitalization of nuclear fuel lease and financing
arrangements pursuant to Statement of Financial Accounting Standards 71.
(Centerior Energy) F-24 (Centerior Energy)
77
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
- ----------------------------------------------------------------------
To the Share Owners of
The Cleveland Electric [Logo]
Illuminating Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of preferred stock of The Cleveland Electric Illuminating Company (a
wholly owned subsidiary of Centerior Energy Corporation) and subsidiaries as of
December 31, 1993 and 1992, and the related consolidated statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1993. These financial statements and the schedules referred to
below are the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements and schedules based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of The Cleveland Electric
Illuminating Company and subsidiaries as of December 31, 1993 and 1992, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1993, in conformity with generally accepted
accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of
accounting for nuclear plant depreciation in 1991 and for postretirement
benefits other than pensions in 1993.
Our audits were made for the purposef of forming an opinion on the
basic financial statements taken as a whole. The schedules of The Cleveland
Electric Illuminating Company and subsidiaries listed in the Index to Schedules
are presented for purposes of complying with the Securities and Exchange
Commission rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio
February 14, 1994
(except with respect to the matter discussed in Note 15, as to which the date is
March 25, 1994)
(Cleveland Electric) F-25 (Cleveland Electric)
78
MANAGEMENT'S
FINANCIAL ANALYSIS
- ----------------------------------------------------------------------
Results of Operations
1993 VS. 1992
Factors contributing to the 0.5% increase in 1993 operating revenues for The
Cleveland Electric Illuminating Company (Company) are as follows:
Millions
Increase (Decrease) in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $ 27
Fuel Cost Recovery Revenues (13)
Base Rates and Miscellaneous (10)
Wholesale Sales 4
-----
Total $ 8
-----
-----
The net revenue increase resulted primarily from the different weather
conditions and the changes in the composition of the sales mix among customer
categories. Weather accounted for approximately $36 million of the higher 1993
revenues. Hot summer weather in 1993 boosted residential, commercial and
wholesale kilowatt-hour sales. In contrast, the 1992 summer was the coolest in
56 years in Northeastern Ohio. Residential and commercial sales also increased
as a result of colder late-winter temperatures in 1993 which increased electric
heating-related demand. As a result, total sales increased 2.9% in 1993.
Residential and commercial sales increased 4.4% and 3.1%, respectively.
Industrial sales decreased 1%. Lower sales to large steel industry customers
were partially offset by increased sales to large automotive manufacturers and
the broad-based, smaller industrial customer group. Other sales increased 11.9%
because of increased sales to wholesale customers. The net decrease in 1993 fuel
cost recovery revenues resulted from changes in the fuel cost factors. The
weighted average of these factors decreased approximately 5%. Base rates and
miscellaneous revenues decreased in 1993 primarily from lower revenues under
contracts having reduced rates with certain large customers and a declining rate
structure tied to usage. The contracts have been negotiated to meet competition
and encourage economic growth.
Operating expenses increased 12.4% in 1993. The increase in total operation and
maintenance expenses resulted from the $130 million of net benefit expenses
related to an early retirement program, called the Voluntary Transition Program
(VTP), other charges totaling $35 million and an increase in other operation and
maintenance expenses. The VTP benefit expenses consisted of $102 million of
costs for the Company plus $28 million for the Company's pro rata share of the
costs for its affiliate, Centerior Service Company (Service Company). Other
charges recorded at year-end 1993 related to a performance improvement plan for
Perry Nuclear Power Plant Unit 1 (Perry Unit 1), postemployment benefits and
other expense accruals. The increase in other operation and maintenance expenses
resulted from higher environmental expenses, power restoration and repair
expenses following a July 1993 storm, and an increase in other postretirement
benefit expenses. See Note 9 for information on retirement and postemployment
benefits. Deferred operating expenses decreased because of the write-off of the
phase-in deferred operating expenses in 1993 as discussed in Note 7. Federal
income taxes decreased as a result of lower pretax operating income.
As discussed in Note 4(b), $351 million of our Perry Nuclear Power Plant Unit 2
(Perry Unit 2) investment was written off in 1993. Credits for carrying charges
recorded in nonoperating income decreased because of the write-off of the
phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal
income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.5% decrease in 1992 operating revenues are as
follows:
Millions
Decrease in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $50
Base Rates and Miscellaneous 23
Fuel Cost Recovery Revenues 10
---
$83
---
---
The revenue decreases resulted primarily from the different weather conditions
and the changes in the composition of the sales mix among customer categories.
Weather accounted for approximately $55 million of the lower 1992 revenues.
Winter and spring in 1992 were milder than in 1991. In addition, the cooler
summer in 1992 contrasted with the summer of 1991 which was much hotter than
normal. As a result, total kilowatt-hour sales decreased 3.5% in 1992.
Residential and commercial sales decreased 4.4% and 0.5%, respectively, as
moderate temperatures in 1992 reduced electric heating and cooling demands.
Industrial sales declined 0.4% as an 8.1% decrease in sales to the broad-based,
smaller industrial customer group completely offset an 8.8% increase in sales to
the larger industrial customer group. Sales to steel producers and auto
manufacturers within the large industrial customer group rose 10.9% and 7%,
respectively. Other sales decreased 16.1% because of decreased sales to
wholesale customers and public authorities. The decrease in 1992 fuel cost
recovery revenues resulted primarily because of the good performance of our
generating units, which in turn decreased our fuel cost factors. The weighted
averages of these factors decreased approximately 3%.
Operating expenses decreased 3.6% in 1992. Lower fuel and purchased power
expense resulted from lower generation requirements stemming from less electric
sales and less amortization of previously deferred fuel costs than the amount
amortized in 1991. Federal income taxes decreased because of the amortization of
certain tax benefits under the Rate Stabilization Program discussed
(Cleveland Electric) F-26 (Cleveland Electric)
79
in Note 7 and the effects of adopting the new accounting standard for income
taxes (SFAS 109) in 1992. These decreases were partially offset by higher
depreciation and amortization, caused primarily by the adoption of SFAS 109, and
by higher taxes, other than federal income taxes, caused by increased Ohio
property and gross receipts taxes. Deferred operating expenses increased as a
result of the deferrals under the Rate Stabilization Program.
The federal income tax provision for nonoperating income decreased because of
lower carrying charge credits and a greater tax allocation of interest charges
to nonoperating activities. Credits for carrying charges recorded in
nonoperating income decreased primarily because of lower phase-in-carrying
charge credits. Interest charges decreased as a result of debt refinancings at
lower interest rates and lower short-term borrowing requirements.
Outlook
RECENT ACTIONS
In January 1994, Centerior Energy Corporation (Centerior Energy), along with the
Company and The Toledo Edison Company (Toledo Edison), announced a comprehensive
strategic action plan to strengthen their financial and competitive positions.
The Company and Toledo Edison are the two wholly owned electric utility
subsidiaries of Centerior Energy. The plan established specific objectives and
was designed to guide Centerior Energy and its subsidiaries through the year
2001. Several actions were taken at that time. Centerior Energy reduced its
quarterly common stock dividend from $.40 per share to $.20 per share effective
with the dividend payable February 15, 1994. This action was taken because
projected financial results did not support continuation of the dividend at its
former rate. The Company and Toledo Edison also wrote off their investments in
Perry Unit 2 and certain deferred charges related to a January 1989 rate
agreement (phase-in deferrals). The aggregate after-tax effect of these
write-offs for the Company was $691 million which resulted in a net loss in 1993
and a retained earnings deficit. The write-offs are discussed in Notes 4(b) and
7. The Company also recognized other one-time charges totaling $25 million after
taxes related to a performance improvement plan for Perry Unit 1, postemployment
benefits and other expense accruals.
Also contributing to the net loss in 1993 was a charge of $51 million after
taxes representing a portion of the VTP costs. The Company will realize
approximately $30 million of savings in annual payroll and benefit costs
beginning in 1994 as a result of the VTP.
STRATEGIC PLAN
The objectives of the strategic plan are to maximize share owner return on
Centerior Energy common stock from corporate assets and resources, achieve
profitable revenue growth, become an industry leader in customer satisfaction,
build a winning team and attain increasingly competitive power supply costs. To
achieve these objectives, the Company will continue controlling its operation
and maintenance expenses and capital expenditures, reduce its outstanding debt,
increase revenues by finding new uses for existing assets and resources,
implement a broad range of new marketing programs, increase revenues by
restructuring rates for various customers where appropriate, improve the
operating performance of its plants and take other appropriate actions.
COMMON STOCK DIVIDENDS
Centerior Energy's common stock dividend has been funded in recent years
primarily by common stock dividends paid by the Company. We expect this practice
to continue for the foreseeable future. Centerior Energy's lower common stock
dividend reduces its cash outflow by about $120 million annually which, in turn,
reduces the common stock dividend demands placed on the Company. The Company
intends to use the increased retained cash to repay debt more quickly than would
otherwise be the case. This will help improve the Company's capitalization
structure and interest coverage ratios.
COMPETITION
Our electric rates are among the highest in our region because we are recovering
the substantial investment in our nuclear construction program. Accordingly,
some of our customers continue to seek less costly alternatives, including
switching to or working to create a municipal electric system. There are two
municipal systems in our service area. In addition, we face threats of other
municipalities in our service area establishing new systems and the expansion of
an existing system. We have entered into agreements with some of the communities
which considered establishing systems. Accordingly, they will not proceed with
such development at this time in return for rate concessions and/or economic
development funds. Others have determined that developing a system was not
feasible. Cleveland Public Power continues to expand its operations into areas
we have served exclusively. We have been successful in retaining most of the
large industrial and commercial customers in those areas by providing economic
incentive packages in exchange for sole-supplier contracts. We also have similar
contracts with customers in other areas. Most of these contracts have remaining
terms of one to five years. We will continue to address municipal system threats
through aggressive marketing programs and emphasizing to our customers the value
of our service and the risks of a municipal system.
The Energy Policy Act of 1992 (Energy Act) will provide additional competition
in the electric utility industry by requiring utilities to wheel to municipal
systems in their service areas electricity from other utilities. This provision
of the Energy Act should not significantly increase the competitive threat to us
since the operating licenses
(Cleveland Electric) F-27 (Cleveland Electric)
80
for our nuclear units have required us to wheel to municipal systems in our
service area since 1977. The Energy Act also created a class of exempt wholesale
generators which may increase competition in the wholesale power market. A
further risk is the possibility that the government could mandate that utilities
deliver power from another utility or generation source to their retail
customers. As mentioned above, we have contracts with many of our large
industrial and commercial customers. We will attempt to renew those contracts as
they expire which will help us compete if retail wheeling is permitted in the
future.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed
to freeze base rates until 1996 and limit rate increases through 1998. In
exchange, we are permitted to defer through 1995 and subsequently recover
certain costs not currently recovered in rates and to accelerate the
amortization of certain benefits. The amortization and recovery of the deferrals
will begin with future rate recognition and will continue over the average life
of the related assets, or approximately 30 years. The continued use of these
regulatory accounting measures will be dependent upon our continuing assessment
and conclusion that there will be probable recovery of such deferrals in future
rates.
The analysis leading to the year-end 1993 financial actions and strategic plan
also included an evaluation of our regulatory accounting measures. We decided
that, once the deferral of expenses and acceleration of benefits under our Rate
Stabilization Program are completed in 1995, we should no longer plan to use
regulatory accounting measures to the extent we have in the past.
NUCLEAR OPERATIONS
The Company's three nuclear units may be impacted by activities or events beyond
our control. Operating nuclear generating units have experienced unplanned
outages or extensions of scheduled outages because of equipment problems or new
regulatory requirements. A major accident at a nuclear facility anywhere in the
world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit
the operation or licensing of any nuclear unit. If one of our nuclear units is
taken out of service for an extended period of time for any reason, including an
accident at such unit or any other nuclear facility, we cannot predict whether
regulatory authorities would impose unfavorable rate treatment. Such treatment
could include taking our affected unit out of rate base or disallowing certain
construction or maintenance costs. An extended outage of one of our nuclear
units coupled with unfavorable rate treatment could have a material adverse
effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993, we increased our decommissioning expense accruals for
revisions in our cost estimates. We expect the increases associated with the new
estimates will be recoverable in future rates. See Note 1(f).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
as amended (Superfund) established programs addressing the cleanup of hazardous
waste disposal sites, emergency preparedness and other issues. The Company has
been named as a "potentially responsible party" (PRP) for three sites listed on
the Superfund National Priorities List (Superfund List) and is aware of its
potential involvement in the cleanup of several other sites not on such list.
The allegations that the Company disposed of hazardous waste at these sites and
the amounts involved are often unsubstantiated and subject to dispute. Superfund
provides that all PRPs to a particular site can be held liable on a joint and
several basis. Consequently, if the Company were held liable for 100% of the
cleanup costs of all of the sites referred to above, the cost could be as high
as $250 million. However, we believe that the actual cleanup costs will be
substantially lower than $250 million, that the Company's share of any cleanup
costs will be substantially less than 100% and that most of the other PRPs are
financially able to contribute their share. The Company has accrued a liability
totaling $13 million at December 31, 1993 based on estimates of the costs of
cleanup and its proportionate responsibility for such costs. We believe that the
ultimate outcome of these matters will not have a material adverse effect on our
financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in
August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did
not materially impact the results of operations for 1993, but did affect certain
Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected
to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected
by even modest inflation which causes increases in the unit cost of labor,
materials and services.
(Cleveland Electric) F-28 (Cleveland Electric)
81
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of
securities and an ongoing program of constructing new facilities and modifying
existing facilities. The construction program is needed to meet anticipated
demand for electric service, comply with governmental regulations and protect
the environment. Over the three-year period of 1991-1993, these construction and
mandatory retirement needs totaled approximately $970 million. In addition, we
exercised various options to redeem and purchase approximately $430 million of
our securities.
We raised $1.2 billion through security issues and term bank loans during the
1991-1993 period as shown in the Cash Flows statement. During the three-year
period, the Company also utilized its short-term borrowing arrangements to help
meet its cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993
negatively affected our earnings, they did not adversely affect our current cash
flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for the Company are $791 million for
its construction program and $715 million for the mandatory redemption of debt
and preferred stock. The Company expects to finance internally all of its 1994
cash requirements of approximately $239 million. About 20% of the Company's
1995-1998 requirements are expected to be financed externally. If economical,
additional securities may be redeemed under optional redemption provisions.
Our capital requirements are dependent upon our implementation strategy to
achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act).
Cash expenditures for our plan are estimated to be approximately $87 million
over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Company under its mortgage
on the basis of property additions, cash or refundable first mortgage bonds.
Under its mortgage, the Company may issue first mortgage bonds on the basis of
property additions and, under certain circumstances, refundable bonds only if
the applicable interest coverage test is met. At December 31, 1993, the Company
would have been permitted to issue approximately $78 million of additional first
mortgage bonds. After the fourth quarter of 1994, the Company's ability to issue
first mortgage bonds is expected to increase substantially when its interest
coverage ratio will no longer be affected by the write-offs recorded at December
31, 1993.
As discussed in Note 11(d), certain unsecured debt agreements contain covenants
relating to capitalization, fixed charge coverage ratios and secured financings.
The write-offs recorded at December 31, 1993 caused the Company, Toledo Edison
and Centerior Energy to violate certain of those covenants. The affected
creditors have waived those violations in exchange for commitments to provide
them with a second mortgage security interest on property of the Company and
Toledo Edison and other considerations. We expect to complete this process in
the second quarter of 1994. We will provide the same security interest to
certain other creditors because their agreements require equal treatment. We
expect to provide second mortgage collateral for $47 million of unsecured debt,
$228 million of bank letters of credit and a $205 million revolving credit
facility. The bank letters of credit and revolving credit facility are joint and
several obligations of the Company and Toledo Edison. For the next five years,
the Company does not expect to raise funds through the sale of debt junior to
first mortgage bonds. However, if necessary or desirable, we believe that the
Company could raise funds through the sale of unsecured debt or debt secured by
the second mortgage referred to above. The Company also is able to raise funds
through the sale of preference and preferred stock.
The Company currently cannot sell commercial paper because of its low commercial
paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors
Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a
party to a $205 million revolving credit facility which will run through
mid-1996. However, we currently cannot draw on this facility because the
write-offs taken at year-end 1993 caused the Company, Toledo Edison and
Centerior Energy to fail to meet certain capitalization and fixed charge
coverage covenants. We expect to have this facility available to us again after
it is amended in the second quarter of 1994 to provide the participating
creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Company's needs
over the next several years. The availability and cost of capital to meet the
Company's external financing needs, however, also depend upon such factors as
financial market conditions and its credit ratings. Current credit ratings for
the Company are as follows:
S&P Moody's
----------- -------------
First mortgage bonds BB Ba2
Unsecured notes B+ Ba3
Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued
a negative outlook for the Company.
(Cleveland Electric) F-29 (Cleveland Electric)
82
INCOME STATEMENT
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
- --------------------------------------------------------------------------------
For the years ended December
31,
----------------------------
1993 1992 1991
------ ------ ------
(millions of dollars)
OPERATING REVENUES $1,751 $1,743 $1,826
------ ------ ------
OPERATING EXPENSES
Fuel and purchased power (1) 423 434 455
Other operation and maintenance 489 465 470
Early retirement program expenses and other 165 -- --
------ ------ ------
Total operation and maintenance 1,077 899 925
Depreciation and amortization 182 179 171
Taxes, other than federal income taxes 221 226 216
Deferred operating expenses, net 27 (35) (7)
Federal income taxes 22 89 106
------ ------ ------
1,529 1,358 1,411
------ ------ ------
OPERATING INCOME 222 385 415
------ ------ ------
NONOPERATING INCOME (LOSS)
Allowance for equity funds used during construction 4 1 8
Other income and deductions, net (5) 8 6
Write-off of Perry Unit 2 (351) -- --
Deferred carrying charges, net (487) 59 88
Federal income taxes -- credit (expense) 270 (5) (24)
------ ------ ------
(569) 63 78
------ ------ ------
INCOME (LOSS) BEFORE INTEREST CHARGES (347) 448 493
------ ------ ------
INTEREST CHARGES
Debt interest 244 243 251
Allowance for borrowed funds used during construction (4) -- (4)
------ ------ ------
240 243 247
------ ------ ------
NET INCOME (LOSS) (587) 205 246
PREFERRED DIVIDEND REQUIREMENTS 45 41 36
------ ------ ------
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ (632) $ 164 $ 210
------ ------ ------
------ ------ ------
<FN>
- ---------------
(1) Includes purchased power expense of $120 million, $130 million and $128
million in 1993, 1992 and 1991, respectively, for all purchases from Toledo
Edison.
RETAINED EARNINGS
- ----------------------------------------------------------------------
For the years ended December
31,
----------------------------
1993 1992 1991
------ ------ ------
(millions of dollars)
RETAINED EARNINGS AT BEGINNING OF YEAR $ 545 $ 578 $ 564
------ ------ ------
ADDITIONS
Net income (loss) (587) 205 246
DEDUCTIONS
Dividends declared:
Common stock (189) (195) (194)
Preferred stock (48) (41) (36)
Other, primarily preferred stock redemption expenses (1) (2) (2)
------ ------ ------
Net Increase (Decrease) (825) (33) 14
------ ------ ------
RETAINED EARNINGS (DEFICIT) AT END OF YEAR $ (280) $ 545 $ 578
------ ------ ------
------ ------ ------
The accompanying notes are an integral part of these statements.
(Cleveland Electric) F-30 (Cleveland Electric)
83
CASH FLOWS
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
- --------------------------------------------------------------------------------
For the years ended
December 31,
-------------------------
1993 1992 1991
----- ----- -----
(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES (1)
Net Income (Loss) $(587) $ 205 $ 246
----- ----- -----
Adjustments to Reconcile Net Income (Loss) to Cash from Operating
Activities:
Depreciation and amortization 182 179 171
Deferred federal income taxes (292) 66 51
Investment tax credits, net -- (8) 13
Deferred and unbilled revenues (6) (7) (25)
Deferred fuel 4 6 13
Deferred carrying charges, net 487 (59) (88)
Leased nuclear fuel amortization 47 70 69
Deferred operating expenses, net 27 (35) (7)
Allowance for equity funds used during construction (4) (1) (8)
Noncash early retirement program expenses, net 125 -- --
Write-off of Perry Unit 2 351 -- --
Changes in amounts due from customers and others, net 5 6 12
Changes in inventories 17 (2) (15)
Changes in accounts payable 18 7 (24)
Changes in working capital affecting operations 29 (4) 37
Other noncash items 5 (11) (13)
----- ----- -----
Total Adjustments 995 207 186
----- ----- -----
Net Cash from Operating Activities 408 412 432
----- ----- -----
CASH FLOWS FROM FINANCING ACTIVITIES (2)
Bank loans, commercial paper and other short-term debt (10) 10 (87)
Notes payable to affiliates (11) (13) 7
Debt issues:
First mortgage bonds 280 324 --
Secured medium-term notes 35 90 150
Term bank loan 40 -- --
Preferred stock issues 100 74 125
Maturities, redemptions and sinking funds (345) (481) (133)
Nuclear fuel lease obligations (59) (65) (64)
Dividends paid (232) (235) (230)
Premiums, discounts and expenses (11) (7) (5)
----- ----- -----
Net Cash from Financing Activities (213) (303) (237)
----- ----- -----
CASH FLOWS FROM INVESTING ACTIVITIES (2)
Cash applied to construction (167) (152) (138)
Interest capitalized as allowance for borrowed funds used during
construction (4) -- (4)
Loans to affiliates -- -- 11
Other cash received (applied) 19 (20) 2
----- ----- -----
Net Cash from Investing Activities (152) (172) (129)
----- ----- -----
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 43 (63) 66
----- ----- -----
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 34 97 31
----- ----- -----
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 77 $ 34 $ 97
----- ----- -----
----- ----- -----
<FN>
- ---------------
(1) Interest paid (net of amounts capitalized) was $204 million, $205 million
and $221 million in 1993, 1992 and 1991, respectively. Income taxes paid
were $28 million in both 1993 and 1992 and $50 million in 1991.
(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance
Sheet resulting from the noncash capitalizations under nuclear fuel
agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
(Cleveland Electric) F-31 (Cleveland Electric)
84
BALANCE SHEET
- ----------------------------------------------------------------------
December 31,
----------------
1993 1992
------ ------
(millions of
dollars)
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant in service $6,734 $6,602
Less: accumulated depreciation and amortization 1,889 1,728
------ ------
4,845 4,874
Construction work in progress 141 130
Perry Unit 2 -- 371
------ ------
4,986 5,375
Nuclear fuel, net of amortization 202 224
Other property, less accumulated depreciation 41 37
------ ------
5,229 5,636
------ ------
CURRENT ASSETS
Cash and temporary cash investments 77 34
Amounts due from customers and others, net 156 161
Amounts due from affiliates 5 10
Unbilled revenues 99 93
Materials and supplies, at average cost 93 90
Fossil fuel inventory, at average cost 20 40
Taxes applicable to succeeding years 179 176
Other 3 3
------ ------
632 607
------ ------
DEFERRED CHARGES AND OTHER ASSETS
Amounts due from customers for future federal income taxes 586 583
Unamortized loss on reacquired debt 60 64
Carrying charges and operating expenses 519 1,033
Nuclear plant decommissioning trusts 30 23
Other 103 177
------ ------
1,298 1,880
------ ------
Total Assets $7,159 $8,123
------ ------
------ ------
The accompanying notes are an integral part of this statement.
(Cleveland Electric) F-32 (Cleveland Electric)
85
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
December 31,
-----------------
1993 1992
------ ------
(millions of
dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shares, without par value: 105 million authorized;
79.6 million outstanding in 1993 and 1992 $1,241 $1,241
Other paid-in-capital 79 79
Retained earnings (deficit) (280) 545
------ ------
Common stock equity 1,040 1,865
Preferred stock
With mandatory redemption provisions 285 314
Without mandatory redemption provisions 241 144
Long-term debt 2,793 2,515
------ ------
4,359 4,838
------ ------
OTHER NONCURRENT LIABILITIES
Nuclear fuel lease obligations 151 177
Other 96 57
------ ------
247 234
------ ------
CURRENT LIABILITIES
Current portion of long-term debt and preferred stock 70 310
Current portion of nuclear fuel lease obligations 63 67
Notes payable to banks and others -- 10
Accounts payable 122 104
Accounts and notes payable to affiliates 61 50
Accrued taxes 305 291
Accrued interest 60 55
Other 52 37
------ ------
733 924
------ ------
DEFERRED CREDITS
Unamortized investment tax credits 235 250
Accumulated deferred federal income taxes 1,105 1,392
Unamortized gain from Bruce Mansfield Plant sale 343 359
Accumulated deferred rents for Bruce Mansfield Plant 77 70
Other 60 56
------ ------
1,820 2,127
------ ------
Total Capitalization and Liabilities $7,159 $8,123
------ ------
------ ------
(Cleveland Electric) F-33 (Cleveland Electric)
86
STATEMENT OF
PREFERRED STOCK
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
- ----------------------------------------------------------------------
Current December 31,
1993 Shares Call Price -------------
Outstanding Per Share 1993 1992
----------- ---------- ---- ----
(millions of
dollars)
Without par value, 4,000,000 preferred shares authorized
Subject to mandatory redemption:
$ 7.35 Series C 150,000 $ 101.00 $ 15 $ 16
88.00 Series E 21,000 1,022.96 21 24
Adjustable Series M 200,000 100.00 20 30
9.125 Series N 600,000 103.04 59 74
91.50 Series Q 75,000 -- 75 75
88.00 Series R 50,000 -- 50 50
90.00 Series S 75,000 -- 74 74
---- ----
314 343
Less: Current maturities 29 29
---- ----
TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $285 $314
---- ----
---- ----
Not subject to mandatory redemption:
$ 7.40 Series A 500,000 101.00 $ 50 $ 50
7.56 Series B 450,000 102.26 45 45
Adjustable Series L 500,000 103.00 49 49
Remarketed Series P -- -- -- 9
42.40 Series T 200,000 -- 97 --
---- ----
241 153
Less: Current maturities -- 9
---- ----
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $241 $144
---- ----
---- ----
The accompanying notes are an integral part of this statement.
(Cleveland Electric) F-34 (Cleveland Electric)
87
NOTES TO THE
FINANCIAL STATEMENTS
- ----------------------------------------------------------------------
(1) Summary of Significant
Accounting Policies
(A) GENERAL
The Company is an electric utility and a wholly owned subsidiary of Centerior
Energy. Centerior Energy has two other wholly owned subsidiaries, Toledo Edison
and the Service Company. The Company follows the Uniform System of Accounts
prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by The
Public Utilities Commission of Ohio (PUCO). As a rate-regulated utility, the
Company is subject to Statement of Financial Accounting Standards (SFAS) 71
which governs accounting for the effects of certain types of rate regulation.
The financial statements include the accounts of the Company's wholly owned
subsidiaries, which in the aggregate are not material.
The Company is a member of the Central Area Power Coordination Group (CAPCO).
Other members are Toledo Edison, Duquesne Light Company, Ohio Edison Company and
its wholly owned subsidiary, Pennsylvania Power Company. The members have
constructed and operate generation and transmission facilities for their use.
(B) RELATED PARTY TRANSACTIONS
Operating revenues, operating expenses and interest charges include those
amounts for transactions with affiliated companies in the ordinary course of
business operations.
The Company's transactions with Toledo Edison are primarily for firm power,
interchange power, transmission line rentals and jointly owned power plant
operations and construction. See Notes 2 and 3.
The Service Company provides management, financial, administrative, engineering,
legal and other services at cost to the Company and other affiliated companies.
The Service Company billed the Company $180 million, $150 million and $138
million in 1993, 1992 and 1991, respectively, for such services.
(C) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based
on rate schedules or contracts authorized by the PUCO. An accrual is made at the
end of each month to record the estimated amount of unbilled revenues for
kilowatt-hours sold in the current month but not billed by the end of that
month.
A fuel factor is added to the base rates for electric service. This factor is
designed to recover from customers the costs of fuel and most purchased power.
It is reviewed and adjusted semiannually in a PUCO proceeding.
(D) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The
cost of nuclear fuel, including an interest component, is charged to fuel
expense based on the rate of consumption. Estimated future nuclear fuel disposal
costs are being recovered through the base rates.
The Company defers the differences between actual fuel costs and estimated fuel
costs currently being recovered from customers through the fuel factor. This
matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for
the cost of decontamination and decommissioning of nuclear enrichment facilities
operated by the United States Department of Energy. The assessments are based
upon the amount of enrichment services used in prior years and cannot be imposed
for more than 15 years. The Company has accrued a liability for its share of the
total assessments. These costs have been recorded in a deferred charge account
since the PUCO is allowing the Company to recover the assessments through its
fuel cost factors.
(E) DEFERRED CARRYING CHARGES
AND OPERATING EXPENSES
The PUCO authorized the Company to defer operating expenses and carrying charges
for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2)
from their respective in-service dates in 1987 through December 1988. The annual
amortization and recovery of these deferrals, called pre-phase-in deferrals, are
$10 million which began in January 1989 and will continue over the lives of the
related property.
Beginning in January 1989, the Company deferred certain operating expenses and
both interest and equity carrying charges pursuant to a PUCO-approved rate
phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2.
These deferrals, called phase-in deferrals, were written off at December 31,
1993. See Note 7.
The Company also defers certain costs not currently recovered in rates under a
Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and
14.
(F) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated
useful lives on a straight-line basis. The annual straight-line depreciation
provision for nonnuclear property expressed as a percent of average depre-
(Cleveland Electric) F-35 (Cleveland Electric)
88
ciable utility plant in service was 3.4% in 1993, 1992 and 1991. Effective
January 1, 1991, the Company, after obtaining PUCO approval, changed its method
of accounting for nuclear plant depreciation from the units-of-production method
to the straight-line method at about a 3% rate. This change decreased 1991
depreciation expense $22 million and increased 1991 net income $17 million (net
of $5 million of income taxes) from what they otherwise would have been. The
PUCO subsequently approved in 1991 a change to lower the 3% rate to 2.5%
retroactive to January 1, 1991.
Pursuant to a PUCO order, the Company currently uses external funding for the
future decommissioning of its nuclear units at the end of their licensed
operating lives. The estimated costs are based on the NRC's DECON method of
decommissioning (prompt decontamination). Cash contributions are made to the
trust funds on a straight-line basis over the remaining licensing period for
each unit. The current level of annual expense being recovered from customers
based on prior estimates is approximately $4 million. However, actual
decommissioning costs are expected to significantly exceed those estimates.
Current site-specific estimates for the Company's share of the future
decommissioning costs are $51 million in 1992 dollars for Beaver Valley Unit 2
and $136 million and $154 million in 1993 dollars for Perry Unit 1 and the
Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for
Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by
the end of the second quarter of 1994. The Company used these estimates to
increase its decommissioning expense accruals in 1993. It is expected that the
increases associated with the revised cost estimates will be recoverable in
future rates. In the Balance Sheet at December 31, 1993, Accumulated
Depreciation and Amortization included $41 million of decommissioning costs
previously expensed and the earnings on the external funding. This amount
exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning
Trusts because the reserve began prior to the external trust funding.
(G) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts ordered
by the PUCO to be written off. Construction costs include related payroll taxes,
pensions, fringe benefits, management and general overheads and allowance for
funds used during construction (AFUDC). AFUDC represents the estimated composite
debt and equity cost of funds used to finance construction. This noncash
allowance is credited to income. The AFUDC rate was 9.63% in 1993, 10.56% in
1992 and 10.47% in 1991.
Maintenance and repairs are charged to expense as incurred. The cost of
replacing plant and equipment is charged to the utility plant accounts. The cost
of property retired plus removal costs, after deducting any salvage value, is
charged to the accumulated provision for depreciation.
(H) DEFERRED GAIN FROM
SALE OF UTILITY PLANT
The sale and leaseback transaction discussed in Note 2 resulted in a net gain
for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant). The net
gain was deferred and is being amortized over the term of leases. The
amortization and the lease expense amounts are recorded as other operation and
maintenance expenses.
(I) INTEREST CHARGES
Debt Interest reported in the Income Statement does not include interest on
obligations for nuclear fuel under construction. That interest is capitalized.
See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt
are deferred, consistent with the regulatory rate treatment. Such losses and
gains are either amortized over the remainder of the original life of the debt
issue retired or amortized over the life of the new debt issue when the proceeds
of a new issue are used for the debt redemption. The amortizations are included
in debt interest expense.
(J) FEDERAL INCOME TAXES
The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard
for accounting for income taxes, in February 1992. We adopted the new standard
in 1992. The standard amended certain provisions of SFAS 96 which we had
previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our
results of operations, but did affect certain Balance Sheet accounts. See Note
8.
The financial statements reflect the liability method of accounting for income
taxes. This method requires that deferred taxes be recorded for all temporary
differences between the book and tax bases of assets and liabilities. The
majority of these temporary differences are attributable to property-related
basis differences. Included in these basis differences is the equity component
of AFUDC, which will increase future tax expense when it is recovered through
rates. Since this component is not recognized for tax purposes, we must record a
liability for our tax obligation. The PUCO permits recovery of such taxes from
customers when they become payable. Therefore, the net amount due from customers
through rates has been recorded as a deferred charge and will be recovered over
the lives of the related assets.
(Cleveland Electric) F-36 (Cleveland Electric)
89
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7 for a
discussion of the amortization of certain unrestricted excess deferred taxes and
unrestricted investment tax credits under the Rate Stabilization Program.
(2) Utility Plant Sale and
Leaseback Transactions
The Company and Toledo Edison are co-lessees of 18.26% (150 megawatts) of Beaver
Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38% (355
megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all for
terms of about 29 1/2 years. These leases are the result of sale and leaseback
transactions completed in 1987.
Under these leases, the Company and Toledo Edison are responsible for paying all
taxes, insurance premiums, operation and maintenance expenses and all other
similar costs for their interests in the units sold and leased back. They may
incur additional costs in connection with capital improvements to the units. The
Company and Toledo Edison have options to buy the interests back at the end of
the leases for the fair market value at that time or to renew the leases.
Additional lease provisions provide other purchase options along with conditions
for mandatory termination of the leases (and possible repurchase of the
leasehold interests) for events of default. These events include noncompliance
with several financial covenants discussed in Note 11(d).
As co-lessee with Toledo Edison, the Company is also obligated for Toledo
Edison's lease payments. If Toledo Edison is unable to make its payments under
the Beaver Valley Unit 2 and Mansfield Plant leases, the Company would be
obligated to make such payments. No payments have been made on behalf of Toledo
Edison to date.
Future minimum lease payments under the operating leases at December 31, 1993
are summarized as follows:
For For
the Toledo
Year Company Edison
- ------------------------------------ ------- -------------
(millions of dollars)
1994 $ 63 $ 103
1995 63 102
1996 63 125
1997 63 102
1998 63 102
Later Years 1,391 2,021
------- ------
Total Future Minimum Lease
Payments $1,706 $ 2,555
------- ------
------- ------
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1993, 1992 and 1991 as annual rental expense for the
Mansfield Plant leases was $70 million. Amounts charged to expense in excess of
the lease payments are classified as Accumulated Deferred Rents in the Balance
Sheet.
The Company is buying 150 megawatts of Toledo Edison's Beaver Valley Unit 2
leased capacity entitlement. We anticipate that this purchase will continue
indefinitely. Purchased power expense for this transaction was $103 million,
$108 million and $107 million in 1993, 1992 and 1991, respectively. The future
minimum lease payments through the year 2017 associated with Beaver Valley Unit
2 aggregate $1.47 billion.
(3) Property Owned with Other Utilities and Investors
The Company owns, as a tenant in common with other utilities and those investors
who are owner-participants in various sale and leaseback transactions (Lessors),
certain generating units as listed below. Each owner owns an undivided share in
the entire unit. Each owner has the right to a percentage of the generating
capability of each unit equal to its ownership share. Each utility owner is
obligated to pay for only its respective share of the construction costs and
operating expenses. Each Lessor has leased its capacity rights to a utility
which is obligated to pay for such Lessor's share of the construction costs and
operating expenses. The Company's share of the operating expenses of these
generating units is included in the Income Statement. The Balance Sheet
classification of Property, Plant and Equipment at December 31, 1993 includes
the following facilities owned by the Operating Company as a tenant in common
with other utilities and Lessors:
In- Plant Construction
Service Ownership Ownership Power in Work in Accumulated
Generating Unit Date Share Megawatts Source Service Progress Depreciation
- ------------------------------- ------- --------- --------- -------- ------- ------------ -----------
(millions of dollars)
Seneca Pumped Storage 1970 80.00% 351 Hydro $ 67 $ -- $ 22
Eastlake Unit 5 1972 68.80 411 Coal 156 2 --
Davis-Besse 1977 51.38 454 Nuclear 700 5 179
Perry Unit 1 1987 31.11 371 Nuclear 1,781 8 287
Beaver Valley Unit 2 and
Common Facilities (Note 2) 1987 24.47 201 Nuclear 1,277 2 219
------- --- -----
Total $3,981 $ 17 $ 707
------- --- -----
------- --- -----
Depreciation for Eastlake Unit 5 has been accumulated with all other nonnuclear
depreciable property rather than by specific units of depreciable property.
(Cleveland Electric) F-37 (Cleveland Electric)
90
(4) Construction and
Contingencies
(A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1994-1998
period is $829 million, including AFUDC of $38 million and excluding nuclear
fuel.
The Clean Air Act will require, among other things, significant reductions in
the emission of sulfur dioxide in two phases over a ten-year period and nitrogen
oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at
least 2005 primarily through greater use of low-sulfur coal at some of our units
and the banking of emission allowances. The plan will require capital
expenditures over the 1994-2003 period of approximately $165 million for
nitrogen oxide control equipment, emission monitoring equipment and plant
modifications. In addition, higher fuel and other operation and maintenance
expenses will be incurred. The anticipated rate increase associated with the
capital expenditures and higher expenses would be about 1-2% in the late 1990s.
The Company may need to install sulfur emission control technology at one of its
generating plants after 2005 which could require additional expenditures at that
time. The PUCO has approved this plan. We also are seeking United States
Environmental Protection Agency (U.S. EPA) approval of the first phase of our
plan.
We are continuing to monitor developments in new technologies that may be
incorporated into our compliance strategy. If a different plan is required by
the U.S. EPA, significantly higher capital expenditures could be required during
the 1994-2003 period. We believe Ohio law permits the recovery of compliance
costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1,
was approximately 50% complete when construction was suspended in 1985 pending
consideration of various options. These options included resumption of full
construction with a revised estimated cost, conversion to a nonnuclear design,
sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we
determined that it would not be completed or sold. The write-off totaled $351
million ($258 million after taxes) for the Company's 44.85% ownership share of
the unit. See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Company is aware of its potential involvement in the cleanup of three sites
listed on the Superfund List and several other waste sites not on such list. The
Company has accrued a liability totaling $13 million at December 31, 1993 based
on estimates of the costs of cleanup and its proportionate responsibility for
such costs. We believe that the ultimate outcome of these matters will not have
a material adverse effect on our financial condition or results of operations.
See Management's Financial Analysis -- Outlook-Hazardous Waste Disposal Sites.
(5) Nuclear Operations and
Contingencies
(A) OPERATING NUCLEAR UNITS
The Company's three nuclear units may be impacted by activities or events beyond
our control. An extended outage of one of our nuclear units for any reason,
coupled with any unfavorable rate treatment, could
have a material adverse effect on our financial condition and results of
operations. See discussion of these risks in Management's Financial
Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power
plant to the amount provided by private insurance and an industry assessment
plan. In the event of a nuclear incident at any unit in the United States
resulting in losses in excess of the level of private insurance (currently $200
million), the Company's maximum potential assessment under that plan would be
$85 million (plus any inflation adjustment) per incident. The assessment is
limited to $11 million per year for each nuclear incident. These assessment
limits assume the other CAPCO companies contribute their proportionate share of
any assessment.
The CAPCO companies have insurance coverage for damage to property at the
Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up
costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994.
Damage to property could exceed the insurance coverage by a substantial amount.
If it does, the Company's share of such excess amount could have a material
adverse effect on its financial condition and results of operations. Under these
policies, the Company can be assessed a maximum of $14 million during a policy
year if the reserves available to the insurer are inadequate to pay claims
arising out of an accident at any nuclear facility covered by the insurer.
The Company also has extra expense insurance coverage. It includes the
incremental cost of any replacement power purchased (over the costs which would
have been
(Cleveland Electric) F-38 (Cleveland Electric)
91
incurred had the units been operating) and other incidental expenses after the
occurrence of certain types of accidents at our nuclear units. The amounts of
the coverage are 100% of the estimated extra expense per week during the 52-week
period starting 21 weeks after an accident and 67% of such estimate per week for
the next 104 weeks. The amount and duration of extra expense could substantially
exceed the insurance coverage.
(6) Nuclear Fuel
Nuclear fuel is financed for the Company and Toledo Edison through leases with a
special-purpose corporation. The total amount of financing currently available
under these lease arrangements is $382 million ($232 million from
intermediate-term notes and $150 million from bank credit arrangements).
Financing in an amount up to $750 million is permitted. The intermediate-term
notes mature in the period 1994-1997, with $75 million maturing in September
1994. At December 31, 1993, $216 million of nuclear fuel was financed for the
Company. The Company and Toledo Edison severally lease their respective portions
of the nuclear fuel and are obligated to pay for the fuel as it is consumed in a
reactor. The lease rates are based on various intermediate-term note rates, bank
rates and commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and
Beaver Valley Unit 2 reactors with remaining lease payments for the Company of
$57 million, $48 million and $26 million, respectively, at December 31, 1993.
The nuclear fuel amounts financed and capitalized also included interest charges
incurred by the lessors amounting to $9 million in both 1993 and 1992 and $12
million in 1991. The estimated future lease amortization payments based on
projected consumption are $63 million in 1994, $56 million in 1995, $50 million
in 1996, $44 million in 1997 and $39 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan
approved by the PUCO in a January 1989 rate order for the Company. The phase-in
plan was designed so that the projected revenues resulting from the authorized
rate increases and anticipated sales growth provided for the phase-in of certain
nuclear costs over a ten-year period. The plan required the deferral of a
portion of the operating expenses and both interest and equity carrying charges
on the Company's deferred rate-based investments in Perry Unit 1 and Beaver
Valley Unit 2 during the early years of the plan. The amortization and recovery
of such deferrals were scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our
deferred charges and continued application of the regulatory accounting measures
we follow pursuant to PUCO orders. We concluded that projected revenues would
not provide for the recovery of the phase-in deferrals as scheduled because of
economic and competitive pressures. Accordingly, we wrote off the cumulative
balance of the phase-in deferrals. The total phase-in deferred operating
expenses and carrying charges written off at December 31, 1993 by the Company
were $117 million and $519 million, respectively (totaling $433 million after
taxes). See Note 14. While recovery of our other regulatory deferrals remains
probable, our current assessment of business conditions has prompted us to
change our future plans. We decided that, once the deferral of expenses and
acceleration of benefits under our Rate Stabilization Program are completed in
1995, we should no longer plan to use regulatory accounting measures to the
extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was
designed to encourage economic growth in the Company's service area by freezing
the Company's base rates until 1996 and limiting subsequent rate increases to
specified annual amounts not to exceed $216 million over the 1996-1998 period.
As part of the Rate Stabilization Program, the Company is allowed to defer and
subsequently recover certain costs not currently recovered in rates and to
accelerate amortization of certain benefits. Such regulatory accounting measures
provide for rate stabilization by rescheduling the timing of rate recovery of
certain costs and the amortization of certain benefits during the 1992-1995
period. The continued use of these regulatory accounting measures will be
dependent upon our continuing assessment and conclusion that there will be
probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December
31, 1995 include the deferral of post-in-service interest carrying charges,
depreciation expense and property taxes on assets placed in service after
February 29, 1988. The cost deferrals recorded in 1993 and 1992 pursuant to
these provisions were $56 million and $52 million, respectively. Amortization
and recovery of these deferrals will occur over the average life of the related
assets, approximately 30 years, and will commence with future rate recognition.
The regulatory accounting measures also provide for the accelerated amortization
of certain unrestricted excess deferred tax and unrestricted investment tax
credit balances and interim spent fuel storage accrual balances for Davis-Besse.
The total amount of such regulatory benefits recognized in 1993 and 1992
pursuant to these provisions was $28 million and $7 million, respectively.
The Rate Stabilization Program also authorized the Company to defer and
subsequently recover the incremental
(Cleveland Electric) F-39 (Cleveland Electric)
92
expenses associated with the adoption of the accounting standard for
postretirement benefits other than pensions (SFAS 106). In 1993, we deferred $60
million pursuant to this provision. Amortization and recovery of this deferral
will commence prior to 1998 and is expected to be completed by no later than
2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying income before taxes by the statutory
rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of
federal income tax recorded on the books as follows:
1993 1992 1991
----- ---- ----
(millions of dollars)
Book Income (Loss) Before Federal Income
Tax $(835) $299 $376
----- ---- ----
----- ---- ----
Tax (Credit) on Book Income (Loss) at
Statutory Rate $(292) $102 $128
Increase (Decrease) in Tax:
Write-off of Perry Unit 2 30 -- --
Write-off of phase-in deferrals 20 -- --
Depreciation 6 (3) (2)
Rate Stabilization Program (20) (5) --
Other items 8 -- 4
----- ---- ----
Total Federal Income Tax Expense (Credit) $(248) $ 94 $130
----- ---- ----
----- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991
----- ---- ----
(millions of dollars)
Operating Expenses:
Current Tax Provision $ 64 $ 47 $ 75
Changes in Accumulated Deferred
Federal Income Tax:
Write-off of deferred operating
expenses (26) -- --
Accelerated depreciation and
amortization 60 32 9
Alternative minimum tax credit (19) (18) (3)
Retirement and postemployment
benefits (24) -- --
Sale and leaseback transactions and
amortization 4 4 (9)
Taxes, other than federal income
taxes (18) 14 --
Rate Stabilization Program (8) 2 --
Reacquired debt costs (2) 6 16
Deferred fuel costs (2) (2) (5)
Other items (7) 4 12
Investment Tax Credits -- -- 11
----- ---- ----
Total Charged to Operating
Expenses 22 89 106
----- ---- ----
Nonoperating Income:
Current Tax Provision (20) (19) (8)
Changes in Accumulated Deferred
Federal Income Tax:
Write-off of deferred carrying
charges (177) -- --
Write-off of Perry Unit 2 (93) -- --
Disallowed nuclear costs 6 7 --
Rate Stabilization Program 7 6 --
AFUDC and carrying charges 7 14 32
Other items -- (3) --
----- ---- ----
Total Expense (Credit) to
Nonoperating Income (270) 5 24
----- ---- ----
Total Federal Income Tax Expense
(Credit) $(248) $ 94 $130
----- ---- ----
----- ---- ----
The Company joins in the filing of a consolidated federal income tax return with
its affiliated companies. The method of tax allocation reflects the benefits and
burdens realized by each company's participation in the consolidated tax return,
approximating a separate return result for each company.
In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993,
the top marginal corporate income tax rate increased to 35%. The change in tax
rate increased Accumulated Deferred Federal Income Taxes for the future tax
obligation by approximately $61 million. Since the PUCO has historically
permitted recovery of such taxes from customers when they become payable, the
deferred charge, Amounts Due from Customers for Future Federal Income Taxes,
also was increased by $61 million. The 1993 Tax Act is not expected to
materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $426 million and deferred tax liabilities of $1.531 billion at
December 31, 1993 and deferred tax assets of $415 million and deferred tax
liabilities of $1.807 billion at December 31, 1992. These are summarized as
follows:
December 31,
---------------
1993 1992
------ ------
(millions of
dollars)
Property, plant and equipment $1,311 $1,468
Deferred carrying charges and operating 127 249
expenses
Sale and leaseback transactions (126) (123)
Net operating loss carryforwards (69) (79)
Investment tax credits (128) (132)
Other (10) 9
------ ------
Net deferred tax liability $1,105 $1,392
------ ------
------ ------
For tax purposes, net operating loss (NOL) carryforwards of approximately $197
million are available to reduce future taxable income and will expire in 2003
through 2005. The 35% tax effect of the NOLs is $69 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit
to be used to reduce the regular tax to the AMT level should the regular tax
exceed the AMT. AMT credits of $94 million are available to offset future
regular tax. The credits may be carried forward indefinitely.
(9) Retirement and
Postemployment Benefits
(A) RETIREMENT INCOME PLAN
Prior to December 31, 1993, the Company and Service Company jointly sponsored a
noncontributing pension plan which covered all employee groups. The plan was
merged with another plan which covered the employees of Toledo Edison into a
single plan on December 31, 1993. The amount of retirement benefits generally
depends
(Cleveland Electric) F-40 (Cleveland Electric)
93
upon the length of service. Under certain circumstances, benefits can begin as
early as age 55. The funding policy is to comply with the Employee Retirement
Income Security Act of 1974 guidelines.
In 1993, the Company and Service Company offered the VTP, an early retirement
program. Operating expenses for both companies for 1993 included $146 million of
pension plan accruals to cover enhanced VTP benefits and an additional $7
million of pension costs for VTP benefits paid to retirees from corporate funds.
The $7 million is not included in the pension data reported below. A credit of
$66 million resulting from a settlement of pension obligations through lump sum
payments to almost all the VTP retirees partially offset the VTP expenses.
Net pension and VTP costs (credits) for 1991 through 1993 were comprised of the
following components:
1993 1992 1991
---- ---- ----
(millions of
dollars)
Pension Costs (Credits):
Service cost for benefits earned
during the
period $ 10 $ 10 $ 9
Interest cost on projected benefit
obligation 26 27 25
Actual return on plan assets (50) (19) (99)
Net amortization and deferral 2 (35) 50
---- ---- ----
Net pension costs (credits) (12) (17) (15)
VTP cost 146 -- --
Settlement gain (66) -- --
---- ---- ----
Net costs (credits) $ 68 $(17) $(15)
---- ---- ----
---- ---- ----
The following table presents a reconciliation of the funded status of the former
plan of the Company and Service Company at December 31, 1992 with comparable
information for a portion of the merged plan at December 31, 1993. The December
31, 1993 benefit obligation estimates were derived from information for the
former plans. Plan assets of the merged plan were allocated based on a pro rata
share of the projected benefit obligation.
1993 1992
---- ----
(millions of
dollars)
Actuarial present value of benefit obligations:
Vested benefits $231 $215
Nonvested benefits 26 28
---- ----
Accumulated benefit obligation 257 243
Effect of future compensation levels 37 86
---- ----
Total projected benefit obligation 294 329
Plan assets at fair market value 268 585
---- ----
Funded status (26) 256
Unrecognized net loss (gain) from variance
between assumptions and experience 61 (107)
Unrecognized prior service cost 6 7
Transition asset at January 1, 1987 being
amortized over 19 years (35) (82)
---- ----
Net prepaid pension cost $ 6 $ 74
---- ----
---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of
return on plan assets assumptions were 7.25% and 8.75%, respectively. The
long-term rate of annual compensation increase assumption was 4.25%. At
December 31, 1992, the settlement rate and long-term rate of return on plan
assets assumptions were 8.5% and the long-term rate of annual compensation
increase assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed
investment contracts, cash equivalent securities and real estate.
(B) OTHER POSTRETIREMENT BENEFITS
Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit
plan which provides all employee groups certain health care, death and other
postretirement benefits other than pensions. The plan is contributory, with
retiree contributions adjusted annually. The plan is not funded. A policy
limiting the employer's contribution for retiree medical coverage for employees
retiring after March 31, 1993 was implemented in February 1993.
The Company adopted SFAS 106, the accounting standard for postretirement
benefits other than pensions, effective January 1, 1993. The standard requires
the accrual of the expected costs of such benefits during the employees' years
of service. Previously, the costs of these benefits were expensed as paid, which
is consistent with ratemaking practices. Such costs for the Company totaled $5
million in 1992 and $6 million in 1991, which included medical benefits of $4
million in 1992 and $5 million in 1991. The total amount accrued by the Company
for SFAS 106 costs for 1993 was $69 million, of which $4 million was capitalized
and $65 million was expensed as other operation and maintenance expenses. In
1993, the Company deferred incremental SFAS 106 expenses totaling $60 million
pursuant to a provision of the Rate Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as
follows:
Millions
of Dollars
----------
Service cost for benefits earned $ 2
Interest cost on accumulated postretirement
benefit obligation 10
Amortization of transition obligation at January
1, 1993 of $104 million over 20 years 5
VTP curtailment cost (includes $10 million
transition obligation adjustment) 52
---
Total costs $ 69
---
---
These amounts included costs for the Company and a pro rata share of the Service
Company's costs.
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost at December 31, 1993
(Cleveland Electric) F-41 (Cleveland Electric)
94
for the Company and its share of the Service Company's obligation are summarized
as follows:
Millions
of Dollars
----------
Accumulated postretirement benefit obligation
attributable to:
Retired participants $ (141)
Fully eligible active plan participants (1)
Other active plan participants (19)
----------
Accumulated postretirement benefit obligation (161)
Unrecognized net loss from variance between
assumptions and experience 9
Unamortized transition obligation 89
----------
Accrued postretirement benefit cost $ (63)
----------
----------
The Balance Sheet classification of Other Noncurrent Liabilities at December 31,
1993 includes only the Company's accrued postretirement benefit cost of $52
million and excludes the Service Company's portion since the Service Company's
total accrued cost is carried on its books.
At December 31, 1993, the settlement rate and the long-term rate of annual
compensation increase assumptions were 7.25% and 4.25%, respectively. The
assumed annual health care cost trend rates (applicable to gross eligible
charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce
gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the
obligation affected by contribution caps are significantly less sensitive to the
health care cost trend rate than other elements. If the assumed health care cost
trend rates were increased by 1% in each future year, the accumulated
postretirement benefit obligation as of December 31, 1993 would increase by $7
million and the aggregate of the service and interest cost components of the
annual postretirement benefit cost would increase by $0.5 million.
(C) POSTEMPLOYMENT BENEFITS
In 1993, the Company adopted SFAS 112, the new accounting standard which
requires the accrual of postemployment benefit costs. Postemployment benefits
are the benefits provided to former or inactive employees after employment but
before retirement, such as worker's compensation, disability benefits and
severance pay. The adoption of this accounting method did not materially affect
the Company's 1993 results of operations or financial position.
(10) Guarantees
The Company has guaranteed certain loan and lease obligations of two mining
companies under two long-term coal purchase arrangements. One of these
arrangements requires payments to the mining company for any actual expenses (as
advance payments for coal) when the mines are idle for reasons beyond the
control of the mining company. At December 31, 1993, the principal amount of the
mining companies' loan and lease obligations guaranteed by the Company was $60
million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares sold and retired during the three years ended December
31, 1993 are listed in the following table.
1993 1992 1991
----- ----- -----
(thousands of shares)
Subject to Mandatory Redemption:
Sales
$ 91.50 Series Q -- -- 75
88.00 Series R -- -- 50
90.00 Series S -- 75 --
Retirements
$ 7.35 Series C (10) (10) (10)
88.00 Series E (3) (3) (3)
75.00 Series F -- -- (2)
145.00 Series I -- -- (14)
113.50 Series K -- -- (10)
Adjustable Series M (100) (100) (100)
9.125 Series N (150) -- --
Not Subject to Mandatory Redemption:
Sales
$ 42.40 Series T 200 -- --
Retirements
Remarketed Series P -- (1) --
----- ----- -----
Net (Decrease) (63) (39) (14)
----- ----- -----
----- ----- -----
(B) EQUITY DISTRIBUTION RESTRICTIONS
Federal law prohibits the Company from paying dividends out of capital accounts.
However, the Company may pay preferred and common stock dividends out of
appropriated retained earnings and current earnings. At December 31, 1993, the
Company had $125 million of appropriated retained earnings for the payment of
preferred and common stock dividends.
(C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next
five years are $29 million in 1994, $40 million in 1995, $30 million in both
1996 and 1997 and $15 million in 1998.
The annual preferred stock mandatory redemption provisions are as follows:
Shares Price
To Be Beginning Per
Redeemed in Share
-------- --------- ------
$ 7.35 Series C 10,000 1984 $ 100
88.00 Series E 3,000 1981 1,000
Adjustable Series M 100,000 1991 100
9.125 Series N 150,000 1993 100
91.50 Series Q 10,714 1995 1,000
88.00 Series R 50,000 2001* 1,000
90.00 Series S 18,750 1999 1,000
* All outstanding shares to be redeemed on December 1, 2001.
In June 1993, the Company issued $100 million principal amount of Serial
Preferred Stock, $42.40 Series T. The Series T stock was deposited with an agent
which issued
(Cleveland Electric) F-42 (Cleveland Electric)
95
Depositary Receipts, each representing 1/20 of a share of the Series T stock.
The annualized preferred dividend requirement at December 31, 1993 was $47
million.
The preferred dividend rates on the Company's Series L and M fluctuate based on
prevailing interest rates and market conditions. The dividend rates for both
issues averaged 7% in 1993. The Company's Series P had a 6.5% dividend rate in
1993 until it was redeemed in August 1993.
Preference stock authorized for the Company is 3,000,000 shares without par
value. No preference shares are currently outstanding.
With respect to dividend and liquidation rights, the Company's preferred stock
is prior to its preference stock and common stock, and its preference stock is
prior to its common stock.
(D) LONG-TERM DEBT AND OTHER
BORROWING ARRANGEMENTS
Long-term debt, less current maturities, was as follows:
Actual
or Average
Interest
Rate at December 31,
December 31, ---------------
Year of Maturity 1993 1993 1992
- -------------------------------- ------------ ------ ------
(millions of
dollars)
First mortgage bonds:
1994 4.375% $ -- $ 25
1994 13.75 -- 4
1995 13.75 4 4
1995 7.00 1 1
1996 13.75 4 4
1996 7.00 1 1
1997 10.88 6 6
1997 13.75 4 4
1997 7.00 1 1
1998 10.88 6 6
1998 13.75 4 4
1998 7.00 1 1
1999-2003 8.06 406 306
2004-2008 8.48 115 119
2009-2013 8.08 405 405
2014-2018 8.07 513 513
2019-2023 8.23 518 368
------ ------
1,989 1,772
Secured medium term notes due
1995-2021 8.88 713 678
Term bank loans due 1995-1996 4.07 45 8
Pollution control notes due
1995-2012 6.31 53 53
Other -- net -- (7) 4
------ ------
Total Long-Term Debt $2,793 $2,515
------ ------
------ ------
Long-term debt matures during the next five years as follows: $42 million in
1994, $246 million in 1995, $151 million in 1996, $55 million in 1997 and $78
million in 1998.
The Company issued $275 million aggregate principal amount of secured
medium-term notes during the 1991-1993 period. The notes are secured by first
mortgage bonds.
The Company's mortgage constitutes a direct first lien on substantially all
property owned and franchises held by the Company. Excluded from the lien, among
other things, are cash, securities, accounts receivable, fuel and supplies.
An unsecured loan agreement of the Company contains covenants relating to
capitalization ratios, fixed charge coverage ratios and limitations on secured
financing other than through first mortgage bonds or certain other transactions.
Two reimbursement agreements relating to separate letters of credit issued in
connection with the sale and leaseback of Beaver Valley Unit 2 contain several
financial covenants affecting the Company, Toledo Edison and Centerior Energy.
Among these are covenants relating to fixed charge coverage ratios and
capitalization ratios. The write-offs recorded at December 31, 1993 caused the
Company, Toledo Edison and Centerior Energy to violate certain covenants
contained in the loan agreement and the two reimbursement agreements. The
affected creditors have waived those violations in exchange for commitments to
provide them with a second mortgage security interest on property of the Company
and Toledo Edison and other considerations. We expect to complete this process
in the second quarter of 1994. We will provide the same security interest to
certain other creditors because their agreements require equal treatment. We
expect to provide second mortgage collateral for $47 million of unsecured debt,
$228 million of bank letters of credit and a $205 million revolving credit
facility. The bank letters of credit and revolving credit facility are joint and
several obligations of the Company and Toledo Edison.
(12) Short-Term Borrowing
Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving
credit facility. The facility may be renewed twice for one-year periods at the
option of the participating banks. Centerior Energy and the Service Company may
borrow under the facility, with all borrowings jointly and severally guaranteed
by the Company and Toledo Edison. Centerior Energy plans to transfer any of its
borrowed funds to the Company and Toledo Edison, while the Service Company may
borrow up to $25 million for its own use. The banks' fee is 0.5% per annum
payable quarterly in addition to interest on any borrowings. That fee is
expected to increase to 0.625% when the facility agreement is amended as
discussed
(Cleveland Electric) F-43 (Cleveland Electric)
96
below. There were no borrowings under the facility at December 31, 1993. The
facility agreement contains covenants relating to capitalization and fixed
charge coverage ratios for the Company, Toledo Edison and Centerior Energy. The
write-offs recorded at December 31, 1993 caused the ratios to fall below those
covenant requirements. The revolving credit facility is expected to be available
for borrowings after the facility agreement is amended in the second quarter of
1994 to provide the participating creditors with a second mortgage security
interest.
Short-term borrowing capacity authorized by the PUCO annually is $300 million
for the Company. The Company and Toledo Edison are authorized by the PUCO to
borrow from each other on a short-term basis.
At December 31, 1993, the Company had no commercial paper outstanding. The
Company is unable to rely on the sale of commercial paper to provide short-term
funds because of its below investment grade commercial paper credit ratings.
(13) Financial Instruments'
Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments
that do not approximate their carrying amounts are as follows:
December 31,
----------------------------------
1993 1992
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- ------
(millions of dollars)
Nuclear Plant Decommissioning
Trusts $ 30 $ 32 $ 23 $ 24
Preferred Stock, with Mandatory
Redemption Provisions
(including current portion) 314 307 343 342
Long-Term Debt (including
current portion) 2,841 2,946 2,793 2,886
The fair value of the nuclear plant decommissioning trusts is estimated based on
the quoted market prices for the investment securities. The fair value of the
Company's preferred stock with mandatory redemption provisions and long-term
debt is estimated based on the quoted market prices for the respective or
similar issues or on the basis of the discounted value of future cash flows. The
discounted value used current dividend or interest rates (or other appropriate
rates) for similar issues and loans with the same remaining maturities.
The estimated fair values of all other financial instruments approximate their
carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of
their short-term nature.
(14) Quarterly Results of Operations
(Unaudited)
The following is a tabulation of the unaudited quarterly results of operations
for the two years ended December 31, 1993.
Quarters Ended
----------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
(millions of dollars)
1993
Operating Revenues $ 421 $417 $ 507 $ 406
Operating Income (Loss) 82 85 89 (32)
Net Income (Loss) 33 30 39 (689)
Earnings (Loss)
Available for Common
Stock 23 19 27 (701)
1992
Operating Revenues $ 422 $415 $ 479 $ 427
Operating Income 83 85 139 77
Net Income 27 33 102 43
Earnings Available for
Common Stock 17 23 92 32
Earnings for the quarter ended September 30, 1993 were decreased by $46 million
as a result of the recording of $71 million of VTP pension-related benefits.
Earnings for the quarter ended December 31, 1993 were decreased as a result of
year-end adjustments for the $351 million write-off of Perry Unit 2 (see Note
4(b)), the $636 million write-off of the phase-in deferrals (see Note 7) and $38
million of other charges. These adjustments decreased quarterly earnings by $716
million.
Earnings for the quarter ended September 30, 1992 were increased by $26 million
as a result of the recording of deferred operating expenses and carrying charges
for the first nine months of 1992 totaling $39 million under the Rate
Stabilization Program approved by the PUCO in October 1992. See Note 7.
(15) Pending Merger of the Company
with Toledo Edison
On March 25, 1994, Centerior Energy announced that its operating utility
subsidiaries, the Company and Toledo Edison, plan to merge into a single
operating entity. Since the Company and Toledo Edison affiliated in 1986,
efforts have been made to consolidate operations and administration as much as
possible to achieve maximum cost savings. The merger of the two companies into a
single entity is the completion of this consolidation process. Various aspects
of the merger are subject to the approval of the FERC, the PUCO and other
regulatory authorities. The merger must be approved by share owners of Toledo
Edison's preferred stock. Share owners of the Company's preferred stock must
approve the authorization of additional shares of preferred stock. Share owners
of Toledo Edison's preferred stock will exchange their shares for preferred
stock shares of the successor corporation having substantially the same terms,
while the
(Cleveland Electric) F-44 (Cleveland Electric)
97
Company's preferred stock will automatically become shares of the successor
corporation. Debt holders of the merging companies will become debt holders of
the successor corporation. The merging companies plan to seek preferred stock
share owner approval in the summer of 1994. The merger is expected to be
effective in late 1994.
For the merging companies, the combined pro forma operating revenues were $2.475
billion, $2.439 billion and $2.561 billion and the combined pro forma net
income (loss) was $(876) million, $276 million and $296 million for the years
ended December 31, 1993, 1992 and 1991, respectively. The pro forma data is
based on accounting for the merger on a method similar to a pooling of
interests. The pro forma data is not necessarily indicative of the results of
operations which would have been reported had the merger been in effect during
those years or which may be reported in the future. The pro forma data should be
read in conjunction with the audited financial statements of both the Company
and Toledo Edison.
(Cleveland Electric) F-45 (Cleveland Electric)
98
FINANCIAL AND
STATISTICAL REVIEW
- ----------------------------------------------------------------------
Operating Revenues (millions of dollars)
Total
Total Total Steam Operating
Year Residential Commercial Industrial Other Retail Wholesale Electric Heating Revenues
- ------------------------------------------------------------------------------------------------------------------------------------
1993 $ 539 536 510 98 1 683 68 1 751 -- $ 1 751
1992 517 531 530 101 1 679 64 1 743 -- 1 743
1991 547 540 547 117 1 751 75 1 826 -- 1 826
1990 495 494 544 123 1 656 35 1 691 -- 1 691
1989 470 453 520 117 1 560 74 1 634 -- 1 634
1983 385 335 430 43 1 193 9 1 202 16 1 218
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses (millions of dollars)
Other Deferred
Fuel & Operation Depreciation Taxes, Operating Federal Total
Purchased & & Other Than Expenses, Income Operating
Year Power Maintenance Amortization FIT Net Taxes Expenses
- ------------------------------------------------------------------------------------------------------------------------------------
1993 $ 423 654(a) 182 221 27(b) 22 $ 1 529
1992 434 465 179 226 (35) 89 1 358
1991 455 470 171(c) 216 (7) 106 1 411
1990 412 514 170 197 (24) 75 1 344
1989 427 508 188 183 (42) 85 1 349
1983 341 270 94 127 -- 127 959
- ------------------------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Federal Income
Other Deferred Income (Loss)
Income & Carrying Taxes-- Before
Operating AFUDC-- Deductions, Charges, Credit Interest
Year Income Equity Net Net (Expense) Charges
- ------------------------------------------------------------------------------------------------------------------------------------
1993 $ 222 4 (356)(d) (487)(b) 270 $ (347)
1992 385 1 8 59 (5) 448
1991 415 8 6 88 (24) 493
1990 347 5 1 162 (20) 495
1989 285 8 9 235 (56) 481
1983 259 87 4 -- 23 373
- ------------------------------------------------------------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Earnings
Preferred & (Loss)
Net Preference Available for
Debt AFUDC-- Income Stock Common
Year Interest Debt (Loss) Dividends Stock
- ------------------------------------------------------------------------------------------------------------------------------------
1993 $ 244 (4) (587) 45 $(632)
1992 243 -- 205 41 164
1991 251 (4) 246 36 210
1990 255 (3) 243 37 206
1989 238 (7) 250 40 210
1983 154 (27) 246 38 208
- ------------------------------------------------------------------------------------------------------------------------------------
(a) Includes early retirement program expenses and other charges of $165 million
in 1993.
(b) Includes write-off of phase-in deferrals of $636 million in 1993, consisting
of $117 million of deferred operating expenses and $519 million of deferred
carrying charges.
(c) In 1991, a change in accounting for nuclear plant depreciation was adopted,
changing from the units-of-production method to the straight-line method at
a 2.5% rate.
(Cleveland Electric) F-46 (Cleveland Electric)
99
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
Electric Sales (millions of KWH) Electric Customers (year end)
Industrial
Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other
- ----------------------------------------------------------------------------------------- ---------------------------------------
1993 4 934 5 634 7 911 2 290 532 21 301 669 118 70 442 8 149
1992 4 725 5 467 7 988 1 989 533 20 702 669 800 70 943 8 375
1991 4 940 5 493 8 017 2 442 565 21 457 667 495 70 405 8 398
1990 4 716 5 234 8 551 1 607 463 20 571 665 000 68 700 8 351
1989 4 789 5 208 8 780 2 132 501 21 410 660 786 68 030 8 329
1983 4 412 4 265 7 514 263 426 16 880 643 065 62 075 7 693
Residential Usage
Average Average
Average Price Revenue
KWH Per Per Per
Year Total Customer KWH Customer
- ------ ------- ---------------------------------
1993 747 709 7 373 10.93c $805.68
1992 749 118 7 071 10.94 773.77
1991 746 298 7 170 11.08 797.25
1990 742 051 6 867 10.53 723.15
1989 737 145 7 025 9.81 691.83
1983 712 833 6 608 8.77 579.49
- -----------------------------------------------------------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel
Operable
Capacity Company Generated
at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost
Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH
- -------------------------------------------------------- --------------------------------------------------------- ---------
1993 4 122 3 862 6.3% 59.9% 15 557 5 644 21 201 1 454 22 655 1.37c
1992 4 703 3 605 23.3 63.0 12 715 7 521 20 236 1 649 21 885 1.47
1991 4 695 3 886 17.2 61.8 13 193 7 451 20 644 2 144 22 788 1.49
1990 4 685 3 778 19.4 63.3 15 579 5 262 20 841 964 21 805 1.52
1989 4 536 3 866 14.8 65.2 14 968 6 570 21 538 1 268 22 806 1.49
1983 4 441 3 404 23.4 61.9 14 804 2 512 17 316 937 18 253 1.77
Efficiency--
BTU Per
Year KWH
- ----------- ---------
1993 10 339
1992 10 456
1991 10 503
1990 10 417
1989 10 506
1983 10 452
- -----------------------------------------------------------------------------------------------------------------------------------
Investment (millions of dollars)
Construction
Utility Work In Total
Plant Accumulated Progress Nuclear Property, Utility
In Depreciation & Net & Perry Fuel and Plant and Plant Total
Year Service Amortization Plant Unit 2 Other Equipment Additions Assets
- ----------------------------------------------------------------------------------------------- ------- --------
1993 $6 734 1 889 4 845 141 243 $ 5 229 $ 175 $7 159
1992 6 602 1 728 4 874 501 261 5 636 156 8 123
1991 6 196 1 565 4 631 545 305 5 481 150 7 942
1990 6 032 1 398 4 634 572 344 5 550 165 7 821
1989 5 869 1 259 4 610 603 354 5 567 144 7 546
1983 2 838 722 2 116 1 617 228(e) 3 961 491 4 425
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization (millions of dollars & %)
Preferred &
Preference Preferred
Stock, with Stock, without
Mandatory Mandatory
Common Stock Redemption Redemption
Year Equity Provisions Provisions Long-Term Debt Total
- ------------------------------------------------------------------------------------------------------
1993 $1 040 24% 285 7% 241 5% 2 793 64% $4 359
1992 1 865 39 314 6 144 3 2 515 52 4 838
1991 1 898 38 268 5 217 4 2 683 53 5 066
1990 1 884 38 171 3 217 4 2 632 55 4 904
1989 1 828 40 212 4 217 5 2 336 51 4 593
1983 1 355 41 318 9 144 4 1 519 46 3 336
- -----------------------------------------------------------------------------------------------------------------------------------
(d) Includes write-off of Perry Unit 2 of $351 million in 1993.
(e) Restated for effects of capitalization of nuclear fuel lease and financing
arrangements pursuant to Statement of Financial Accounting Standards 71.
(Cleveland Electric) F-47 (Cleveland Electric)
100
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
- ----------------------------------------------------------------------
To the Share Owners of
The Toledo [Logo]
Edison Company:
We have audited the accompanying balance sheet and statement of preferred stock
of The Toledo Edison Company (a wholly owned subsidiary of Centerior Energy
Corporation) as of December 31, 1993 and 1992, and the related statements of
income, retained earnings and cash flows for each of the three years in the
period ended December 31, 1993. These financial statements and the schedules
referred to below are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of The Toledo Edison Company as of
December 31, 1993 and 1992, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1993, in conformity
with generally accepted accounting principles.
As discussed further in Notes 1 and 9, changes were made in the methods of
accounting for nuclear plant depreciation in 1991 and for postretirement
benefits other than pensions in 1993.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules of The Toledo Edison
Company listed in the Index to Schedules are presented for purposes of complying
with the Securities and Exchange Commission's rules and are not part of the
basic financial statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state in all material respects the financial data required to be
set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN & CO.
Cleveland, Ohio
February 14, 1994
(except with respect to the matter discussed in Note 15, as to which the date is
March 25, 1994)
(Toledo Edison) F-48 (Toledo Edison)
101
MANAGEMENT'S
FINANCIAL ANALYSIS
- --------------------------------------------------------------------------------
Results of Operations
1993 VS. 1992
Factors contributing to the 3.1% increase in 1993 operating revenues for The
Toledo Edison Company (Company) are as follows:
Millions
Increase (Decrease) in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $ 38
Wholesale Sales (11)
Base Rates and Miscellaneous (3)
Fuel Cost Recovery Revenues 2
-----
Total $ 26
-----
-----
The net revenue increase resulted primarily from the different weather
conditions and the changes in the composition of the sales mix among customer
categories. Weather accounted for approximately $17 million of the higher 1993
revenues. Hot summer weather in 1993 boosted residential and commercial
kilowatt-hour sales. In contrast, the 1992 summer was the coolest in 56 years in
Northwestern Ohio. Residential and commercial sales also increased as a result
of colder late-winter temperatures in 1993 which increased electric
heating-related demand. Residential and commercial sales increased 5.1% and
3.2%, respectively, in 1993. Industrial sales increased 6% as a result of
increased sales to large automotive manufacturers, petroleum refiners and the
broad-based, smaller industrial customer group. Other sales decreased 18.4%
because of fewer sales to wholesale customers. Generating plant outages and
retail customer demand limited power availability for bulk power transactions.
As a result, total sales decreased 2.2% in 1993. Base rates and miscellaneous
revenues decreased in 1993 primarily from lower revenues under contracts having
reduced rates with certain large customers and a declining rate structure tied
to usage. The contracts have been negotiated to meet competition and encourage
economic growth. The net increase in 1993 fuel cost recovery revenues resulted
from changes in the fuel cost factors. The weighted average of these factors
increased about 2%.
Operating expenses increased 12.6% in 1993. The increase in total operation and
maintenance expenses resulted from the $88 million of net benefit expenses
related to an early retirement program, called the Voluntary Transition Program
(VTP), other charges totaling $19 million and a slight increase in other
operation and maintenance expenses. The VTP benefit expenses consisted of $75
million of costs for the Company plus $13 million for the Company's pro rata
share of the costs for its affiliate, Centerior Service Company (Service
Company). Other charges recorded at year-end 1993 related to a performance
improvement plan for Perry Nuclear Power Plant Unit 1 (Perry Unit 1),
postemployment benefits and other expense accruals. See Note 9 for information
on retirement and postemployment benefits. Deferred operating expenses decreased
because of the write-off of the phase-in deferred operating expenses in 1993 as
discussed in Note 7. Federal income taxes decreased as a result of lower pretax
operating income.
As discussed in Note 4(b), $232 million of our Perry Nuclear Power Plant Unit 2
(Perry Unit 2) investment was written off in 1993. Credits for carrying charges
recorded in nonoperating income decreased because of the write-off of the
phase-in deferred carrying charges in 1993 as discussed in Note 7. The federal
income tax credit for nonoperating income in 1993 resulted from the write-offs.
1992 VS. 1991
Factors contributing to the 4.8% decrease in 1992 operating revenues are as
follows:
Millions
Increase (Decrease) in Operating Revenues of Dollars
- ------------------------------------------------ -----------
Sales Volume and Mix $ (29)
Base Rates and Miscellaneous (24)
Wholesale Sales 11
-----
Total $ (42)
-----
-----
The revenue decreases resulted primarily from the different weather conditions
and the changes in the composition of the sales mix among customer categories.
Weather accounted for approximately $22 million of the lower 1992 revenues.
Winter and spring in 1992 were milder than in 1991. In addition, the cooler
summer in 1992 contrasted with the summer of 1991 which was much hotter than
normal. Total kilowatt-hour sales increased 0.2% in 1992. Residential and
commercial sales decreased 4.9% and 3.8%, respectively, as moderate temperatures
in 1992 reduced electric heating and cooling demands. Industrial sales increased
0.6% as increased sales to glass and metal manufacturers and to the broad-based,
smaller industrial customer group offset lower sales to petroleum refining and
auto manufacturing customers. Other sales increased 5.2% because of increased
sales to wholesale customers. Operating revenues in 1991 included the
recognition of $24 million of deferred revenues over the period of a refund to
customers under a provision of a January 1989 rate order. No such revenues were
reflected in 1992 as the refund period ended in December 1991.
Operating expenses decreased 4.4% in 1992. A reduction of $14 million in other
operation and maintenance expenses resulted primarily from cost-cutting
measures. Lower fuel and purchased power expense resulted from
less amortization of previously deferred fuel costs than the amount amortized in
1991. These decreases were par-
tially offset by higher depreciation and amortization, caused primarily by the
adoption of the new accounting
(Toledo Edison) F-49 (Toledo Edison)
102
standard for income taxes (SFAS 109) in 1992, and by higher taxes, other than
federal income taxes, caused by increased Ohio property taxes. Deferred
operating expenses increased as a result of the deferrals under the Rate
Stabilization Program discussed in Note 7.
The federal income tax provision for nonoperating income decreased because of a
greater tax allocation of interest charges to nonoperating activities. Credits
for carrying charges recorded in nonoperating income increased primarily because
of Rate Stabilization Program carrying charge credits. Interest charges
decreased as a result of debt refinancings at lower interest rates and lower
short-term borrowing requirements.
Outlook
RECENT ACTIONS
In January 1994, Centerior Energy Corporation (Centerior Energy), along with
the Company and The Cleveland Electric Illuminating Company (Cleveland
Electric), announced a comprehensive strategic action plan to strengthen their
financial and competitive positions. The Company and Cleveland Electric are the
two wholly owned electric utility subsidiaries of Centerior Energy. The plan
established specific objectives and was designed to guide Centerior Energy and
its subsidiaries through the year 2001. Several actions were taken at that
time. Centerior Energy reduced its quarterly common stock dividend from $.40
per share to $.20 per share effective with the dividend payable February 15,
1994. This action was taken because projected financial results did not support
continuation of the dividend at its former rate. The Company and Cleveland
Electric also wrote off their investments in Perry Unit 2 and certain deferred
charges related to a January 1989 rate agreement (phase-in deferrals). The
aggregate after-tax effect of these write-offs for the Company was $332 million
which resulted in a net loss in 1993 and a retained earnings deficit. The
write-offs are discussed in Notes 4(b) and 7. The Company also recognized other
one-time charges totaling $15 million after taxes related to a performance
improvement plan for Perry Unit 1, postemployment benefits and other expense
accruals.
Also contributing to the net loss in 1993 was a charge of $36 million after
taxes representing a portion of the VTP costs. The Company will realize
approximately $20 million of savings in annual payroll and benefit costs
beginning in 1994 as a result of the VTP.
STRATEGIC PLAN
The objectives of the strategic plan are to maximize share owner return on
Centerior Energy common stock from corporate assets and resources, achieve
profitable revenue growth, become an industry leader in customer satisfaction,
build a winning team and attain increasingly competitive power supply costs. To
achieve these objectives, the Company will continue controlling its operation
and maintenance expenses and capital expenditures, reduce its outstanding debt,
increase revenues by finding new uses for existing assets and resources,
implement a broad range of new marketing programs, increase revenues by
restructuring rates for various customers where appropriate, improve the
operating performance of its plants and take other appropriate actions.
COMMON STOCK DIVIDENDS
In recent years, the Company has retained all of its earnings available for
common stock. The Company has not paid a common stock dividend to Centerior
Energy since February 1991. Because the Company is currently prohibited from
paying a common stock dividend by a provision in its mortgage (see Note 11(b)),
the Company does not expect to pay any common stock dividends in the foreseeable
future.
COMPETITION
Our electric rates are among the highest in our region because we are recovering
the substantial investment in our nuclear construction program. Accordingly,
some of our customers continue to seek less costly alternatives, including
switching to or working to create a municipal electric system. There are a
number of rural and municipal systems in our service area. In addition, we face
threats of other municipalities in our service area establishing new systems. We
have entered into agreements with some of the communities which considered
establishing systems. Accordingly, they will not proceed with such development
at this time in return for rate concessions and/or economic development funds.
Others have determined that developing a system was not feasible. We will
continue to address municipal system threats through aggressive marketing
programs and emphasizing to our customers the value of our service and the risks
of a municipal system.
The Energy Policy Act of 1992 (Energy Act) will provide additional competition
in the electric utility industry by requiring utilities to wheel to municipal
systems in their service areas electricity from other utilities. This provision
of the Energy Act should not significantly increase the competitive threat to
us since the operating licenses for our nuclear units have required us to wheel
to municipal systems in our service area since 1977. The Energy Act also
created a class of exempt wholesale generators which may increase competition
in the wholesale power market. A further risk is the possibility that the
government could mandate that utilities deliver power from another utility or
generation source to their retail customers. We have entered into
contracts with many of our
(Toledo Edison) F-50 (Toledo Edison)
103
large industrial and commercial customers which have remaining terms of one to
five years. We will attempt to renew those contracts as they expire which will
help us compete if retail wheeling is permitted in the future.
RATE MATTERS
Our Rate Stabilization Program remains in effect. Under this program, we agreed
to freeze base rates until 1996 and limit rate increases through 1998. In
exchange, we are permitted to defer through 1995 and subsequently recover
certain costs not currently recovered in rates and to accelerate the
amortization of certain benefits. The amortization and recovery of the deferrals
will begin with future rate recognition and will continue over the average life
of the related assets, or approximately 30 years. The continued use of these
regulatory accounting measures will be dependent upon our continuing assessment
and conclusion that there will be probable recovery of such deferrals in future
rates.
The analysis leading to the year-end 1993 financial actions and strategic plan
also included an evaluation of our regulatory accounting measures. We decided
that, once the deferral of expenses and acceleration of benefits under our Rate
Stabilization Program are completed in 1995, we should no longer plan to use
regulatory accounting measures to the extent we have in the past.
NUCLEAR OPERATIONS
The Company's three nuclear units may be impacted by activities or events beyond
our control. Operating nuclear generating units have experienced unplanned
outages or extensions of scheduled outages because of equipment problems or new
regulatory requirements. A major accident at a nuclear facility anywhere in the
world could cause the Nuclear Regulatory Commission (NRC) to limit or prohibit
the operation or licensing of any nuclear unit. If one of our nuclear units is
taken out of service for an extended period of time for any reason, including an
accident at such unit or any other nuclear facility, we cannot predict whether
regulatory authorities would impose unfavorable rate treatment. Such treatment
could include taking our affected unit out of rate base or disallowing certain
construction or maintenance costs. An extended outage of one of our nuclear
units coupled with unfavorable rate treatment could have a material adverse
effect on our financial condition and results of operations.
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993, we increased our decommissioning expense accruals for
revisions in our cost estimates. We expect the increases associated with the new
estimates will be recoverable in future rates. See Note 1(f).
HAZARDOUS WASTE DISPOSAL SITES
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
as amended (Superfund) established programs addressing the cleanup of hazardous
waste disposal sites, emergency preparedness and other issues. The Company is
aware of its potential involvement in the cleanup of several sites. Although
these sites are not on the Superfund National Priorities List, they are
generally being administered by various governmental entities in the same manner
as they would be administered if they were on such list. The allegations that
the Company disposed of hazardous waste at these sites and the amounts involved
are often unsubstantiated and subject to dispute. Superfund provides that all
"potentially responsible parties" (PRPs) to a particular site can be held liable
on a joint and several basis. Consequently, if the Company were held liable for
100% of the cleanup costs of all of the sites referred to above, the cost could
be as high as $150 million. However, we believe that the actual cleanup costs
will be substantially lower than $150 million, that the Company's share of any
cleanup costs will be substantially less than 100% and that most of the other
PRPs are financially able to contribute their share. The Company has accrued a
liability totaling $6 million at December 31, 1993 based on estimates of the
costs of cleanup and its proportionate responsibility for such costs. We believe
that the ultimate outcome of these matters will not have a material adverse
effect on our financial condition or results of operations.
1993 TAX ACT
The Revenue Reconciliation Act of 1993 (1993 Tax Act), which was enacted in
August 1993, provided for a 35% income tax rate in 1993. The 1993 Tax Act did
not materially impact the results of operations for 1993, but did affect certain
Balance Sheet accounts as discussed in Note 8. The 1993 Tax Act is not expected
to materially impact future results of operations or cash flow.
INFLATION
Although the rate of inflation has eased in recent years, we are still affected
by even modest inflation which causes increases in the unit cost of labor,
materials and services.
Capital Resources and Liquidity
1991-1993 CASH REQUIREMENTS
We need cash for normal corporate operations, the mandatory retirement of
securities and an ongoing pro-
(Toledo Edison) F-51 (Toledo Edison)
104
gram of constructing new facilities and modifying existing facilities. The
construction program is needed to meet anticipated demand for electric service,
comply with governmental regulations and protect the environment. Over the
three-year period of 1991-1993, these construction and mandatory retirement
needs totaled approximately $440 million. In addition, we exercised various
options to redeem approximately $490 million of our securities.
We raised $815 million through security issues and term bank loans during the
1991-1993 period as shown in the Cash Flows statement. During the three-year
period, the Company also utilized its short-term borrowing arrangements to help
meet its cash needs.
Although the write-offs of Perry Unit 2 and the phase-in deferrals in 1993
negatively affected our earnings, they did not adversely affect our current cash
flow.
1994 AND BEYOND CASH REQUIREMENTS
Estimated cash requirements for 1994-1998 for the Company are $249 million for
its construction program and $324 million for the mandatory redemption of debt
and preferred stock. The Company expects to finance internally all of its 1994
cash requirements of approximately $109 million. About 15% of the Company's
1995-1998 requirements are expected to be financed externally. If economical,
additional securities may be redeemed under optional redemption provisions,
which will help improve the Company's capitalization structure and interest
coverage ratios.
Our capital requirements are dependent upon our implementation strategy to
achieve compliance with the Clean Air Act Amendments of 1990 (Clean Air Act).
Cash expenditures for our plan are estimated to be approximately $41 million
over the 1994-1998 period. See Note 4(a).
LIQUIDITY
Additional first mortgage bonds may be issued by the Company under its mortgage
on the basis of property additions, cash or refundable first mortgage bonds.
Under its mortgage, the Company may issue first mortgage bonds on the basis of
property additions and, under certain circumstances, refundable bonds only if
the applicable interest coverage test is met. At December 31, 1993, the Company
would have been permitted to issue approximately $323 million of additional
first mortgage bonds.
As discussed in Note 11(d), certain unsecured debt agreements contain covenants
relating to capitalization, fixed charge coverage ratios and secured financings.
The write-offs recorded at December 31, 1993 caused the Company, Cleveland
Electric and Centerior Energy to violate certain of those covenants. The
affected creditors have waived those violations in exchange for commitments to
provide them with a second mortgage security interest on property of the Company
and Cleveland Electric and other considerations. We expect to complete this
process in the second quarter of 1994. We will provide the same security
interest to certain other creditors because their agreements require equal
treatment. We expect to provide second mortgage collateral for $172 million of
unsecured debt, $228 million of bank letters of credit and a $205 million
revolving credit facility. The bank letters of credit and revolving credit
facility are joint and several obligations of the Company and Cleveland
Electric. For the next five years, the Company does not expect to raise funds
through the sale of debt junior to first mortgage bonds. However, if necessary
or desirable, we believe that the Company could raise funds through the sale of
unsecured debt or debt secured by the second mortgage referred to above. The
Company also is able to raise funds through the sale of preference stock. The
Company will be unable to issue preferred stock until it can meet the interest
and preferred dividend coverage test in its articles of incorporation.
The Company currently cannot sell commercial paper because of its low commercial
paper ratings by Standard & Poor's Corporation (S&P) and Moody's Investors
Service, Inc. (Moody's) of "B" and "Not Prime", respectively. The Company is a
party to a $205 million revolving credit facility which will run through
mid-1996. However, we currently cannot draw on this facility because the
write-offs taken at year-end 1993 caused the Company, Cleveland Electric and
Centerior Energy to fail to meet certain capitalization and fixed charge
coverage covenants. We expect to have this facility available to us again after
it is amended in the second quarter of 1994 to provide the participating
creditors with a second mortgage security interest.
These financing resources are expected to be sufficient for the Company's needs
over the next several years. The availability and cost of capital to meet the
Company's external financing needs, however, also depend upon such factors as
financial market conditions and its credit ratings. Current credit ratings for
the Company are as follows:
S&P Moody's
----------- -------------
First mortgage bonds BB Ba2
Unsecured notes B+ Ba3
Preferred stock B b1
These ratings reflect a downgrade in December 1993. In addition, S&P has issued
a negative outlook for the Company.
(Toledo Edison) F-52 (Toledo Edison)
105
INCOME STATEMENT THE TOLEDO EDISON COMPANY
- ----------------------------------------------------------------------
For the years ended
December 31,
-----------------------
1993 1992 1991
----- ---- ----
(millions of dollars)
OPERATING REVENUES (1) $ 871 $845 $887
----- ---- ----
OPERATING EXPENSES
Fuel and purchased power 173 169 178
Other operation and maintenance 349 342 356
Early retirement program expenses and other 107 -- --
----- ---- ----
Total operation and maintenance 629 511 534
Depreciation and amortization 76 77 72
Taxes, other than federal income taxes 91 91 89
Deferred operating expenses, net (4) (17) 1
Federal income taxes (credit) (10) 33 32
----- ---- ----
782 695 728
----- ---- ----
OPERATING INCOME 89 150 159
----- ---- ----
NONOPERATING INCOME (LOSS)
Allowance for equity funds used during construction 1 1 1
Other income and deductions, net -- 1 5
Write-off of Perry Unit 2 (232) -- --
Deferred carrying charges, net (161) 41 22
Federal income taxes -- credit (expense) 129 (1) (6)
----- ---- ----
(263) 42 22
----- ---- ----
INCOME (LOSS) BEFORE INTEREST CHARGES (174) 192 181
----- ---- ----
INTEREST CHARGES
Debt interest 116 122 132
Allowance for borrowed funds used during construction (1) (1) (1)
----- ---- ----
115 121 131
----- ---- ----
NET INCOME (LOSS) (289) 71 50
PREFERRED DIVIDEND REQUIREMENTS 23 24 25
----- ---- ----
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $(312) $ 47 $ 25
----- ---- ----
----- ---- ----
<FN>
- ---------------
(1) Includes revenues from all bulk power sales to Cleveland Electric of $120
million, $130 million and $128 million in 1993, 1992 and 1991, respectively.
RETAINED EARNINGS
- ----------------------------------------------------------------------
For the years ended
December 31,
-----------------------
1993 1992 1991
----- ---- ----
(millions of dollars)
RETAINED EARNINGS AT BEGINNING OF YEAR $ 137 $ 90 $ 83
----- ---- ----
ADDITIONS
Net income (loss) (289) 71 50
DEDUCTIONS
Dividends declared:
Common stock -- -- (18)
Preferred stock (23) (24) (25)
----- ---- ----
Net Increase (Decrease) (312) 47 7
----- ---- ----
RETAINED EARNINGS (DEFICIT) AT END OF YEAR $(175) $137 $ 90
----- ---- ----
----- ---- ----
The accompanying notes are an integral part of these statements.
(Toledo Edison) F-53 (Toledo Edison)
106
CASH FLOWS THE TOLEDO EDISON COMPANY
- ----------------------------------------------------------------------
For the years ended
December 31,
-------------------------
1993 1992 1991
----- ----- -----
(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES (1)
Net Income (Loss) $(289) $ 71 $ 50
----- ----- -----
Adjustments to Reconcile Net Income (Loss) to Cash from Operating
Activities:
Depreciation and amortization 76 77 72
Deferred federal income taxes (160) 28 32
Investment tax credits, net -- (5) 30
Deferred and unbilled revenues (4) 1 (26)
Deferred fuel -- (4) 4
Deferred carrying charges, net 161 (41) (22)
Leased nuclear fuel amortization 38 56 54
Deferred operating expenses, net (4) (17) 1
Allowance for equity funds used during construction (1) (1) (1)
Noncash early retirement program expenses, net 83 -- --
Write-off of Perry Unit 2 232 -- --
Changes in amounts due from customers and others, net (3) -- 3
Changes in inventories 10 (9) (7)
Changes in accounts payable 16 (8) (13)
Changes in working capital affecting operations 21 7 (26)
Other noncash items 14 13 14
----- ----- -----
Total Adjustments 479 97 115
----- ----- -----
Net Cash from Operating Activities 190 168 165
----- ----- -----
CASH FLOWS FROM FINANCING ACTIVITIES (2)
Bank loans, commercial paper and other short-term debt (40) 40 (23)
Notes payable to affiliates -- (30) 14
Debt issues:
First mortgage bonds 20 276 --
Secured medium-term notes 93 48 135
Term bank loans and other long-term debt -- 135 108
Maturities, redemptions and sinking funds (89) (531) (179)
Nuclear fuel lease obligations (47) (52) (52)
Dividends paid (23) (24) (43)
Premiums, discounts and expenses (1) (8) (1)
----- ----- -----
Net Cash from Financing Activities (87) (146) (41)
----- ----- -----
CASH FLOWS FROM INVESTING ACTIVITIES (2)
Cash applied to construction (42) (48) (51)
Interest capitalized as allowance for borrowed funds used during
construction (1) (1) (1)
Loans to affiliates -- 12 (12)
Sale and leaseback restructuring fees -- (43) --
Other cash received (applied) 6 (5) (3)
----- ----- -----
Net Cash from Investing Activities (37) (85) (67)
----- ----- -----
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 66 (63) 57
----- ----- -----
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR 16 79 22
----- ----- -----
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 82 $ 16 $ 79
----- ----- -----
----- ----- -----
<FN>
- ---------------
(1) Interest paid (net of amounts capitalized) was $92 million, $95 million and
$120 million in 1993, 1992 and 1991, respectively. Income taxes paid were $7
million, $3 million and $9 million in 1993, 1992 and 1991, respectively.
(2) Increases in Nuclear Fuel and Nuclear Fuel Lease Obligations in the Balance
Sheet resulting from the noncash capitalizations under nuclear fuel
agreements are excluded from this statement.
The accompanying notes are an integral part of this statement.
(Toledo Edison) F-54 (Toledo Edison)
107
[THIS PAGE INTENTIONALLY LEFT BLANK]
108
BALANCE SHEET
- ----------------------------------------------------------------------
December 31,
----------------
1993 1992
------ ------
(millions of
dollars)
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant in service $2,837 $2,847
Less: accumulated depreciation and amortization 788 760
------ ------
2,049 2,087
Construction work in progress 40 37
Perry Unit 2 -- 243
------ ------
2,089 2,367
Nuclear fuel, net of amortization 142 161
Other property, less accumulated depreciation -- 3
------ ------
2,231 2,531
------ ------
CURRENT ASSETS
Cash and temporary cash investments 82 16
Amounts due from customers and others, net 63 60
Amounts due from affiliates 16 23
Unbilled revenues 25 21
Materials and supplies, at average cost 43 40
Fossil fuel inventory, at average cost 12 25
Taxes applicable to succeeding years 71 71
Other 2 2
------ ------
314 258
------ ------
DEFERRED CHARGES AND OTHER ASSETS
Amounts due from customers for future federal income taxes 382 391
Unamortized loss from Beaver Valley Unit 2 sale 105 110
Unamortized loss on reacquired debt 32 37
Carrying charges and operating expenses 343 500
Nuclear plant decommissioning trusts 26 20
Other 77 92
------ ------
965 1,150
------ ------
Total Assets $3,510 $3,939
------ ------
------ ------
The accompanying notes are an integral part of this statement.
(Toledo Edison) F-55 (Toledo Edison)
109
The Toledo Edison Company
December 31,
-----------------
1993 1992
------ ------
(millions of
dollars)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shares, $5 par value: 60 million authorized;
39.1 million outstanding in 1993 and 1992 $ 196 $ 196
Premium on capital stock 481 481
Other paid-in capital 121 121
Retained earnings (deficit) (175) 137
------ ------
Common stock equity 623 935
Preferred stock
With mandatory redemption provisions 28 50
Without mandatory redemption provisions 210 210
Long-term debt 1,225 1,178
------ ------
2,086 2,373
------ ------
OTHER NONCURRENT LIABILITIES
Nuclear fuel lease obligations 103 126
Other 83 62
------ ------
186 188
------ ------
CURRENT LIABILITIES
Current portion of long-term debt and preferred stock 57 58
Current portion of nuclear fuel lease obligations 49 51
Notes payable to banks and others -- 40
Accounts payable 63 47
Accounts payable to affiliates 27 16
Accrued taxes 90 78
Accrued interest 27 28
Other 16 14
------ ------
329 332
------ ------
DEFERRED CREDITS
Unamortized investment tax credits 94 103
Accumulated deferred federal income taxes 471 640
Unamortized gain from Bruce Mansfield Plant sale 208 218
Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2 50 46
Other 86 39
------ ------
909 1,046
------ ------
Total Capitalization and Liabilities $3,510 $3,939
------ ------
------ ------
(Toledo Edison) F-56 (Toledo Edison)
110
STATEMENT OF
PREFERRED STOCK THE TOLEDO EDISON COMPANY
- --------------------------------------------------------------------------------
Current
Call
Price December 31,
1993 Shares Per -------------
Outstanding Share 1993 1992
----------- -------- ---- ----
(millions of
dollars)
$100 par value, 3,000,000 preferred shares authorized and
$25 par value, 12,000,000 preferred shares authorized
Subject to mandatory redemption:
$100 par $9.375 100,150 $102.47 $ 10 $ 12
25 par 2.81 1,200,000 25.94 30 50
---- ----
40 62
Less: Current maturities 12 12
---- ----
TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS $ 28 $ 50
---- ----
---- ----
Not subject to mandatory redemption:
$100 par $ 4.25 160,000 104.625 $ 16 $ 16
4.56 50,000 101.00 5 5
4.25 100,000 102.00 10 10
8.32 100,000 102.46 10 10
7.76 150,000 102.437 15 15
7.80 150,000 101.65 15 15
10.00 190,000 101.00 19 19
25 par 2.21 1,000,000 25.25 25 25
2.365 1,400,000 27.75 35 35
Series A Adjustable 1,200,000 25.75 30 30
Series B Adjustable 1,200,000 25.75 30 30
---- ----
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS $210 $210
---- ----
---- ----
The accompanying notes are an integral part of this statement.
(Toledo Edison) F-57 (Toledo Edison)
111
NOTES TO THE
FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
(1) Summary of Significant
Accounting Policies
(A) GENERAL
The Company is an electric utility and a wholly owned subsidiary of Centerior
Energy. Centerior Energy has two other wholly owned subsidiaries, Cleveland
Electric and the Service Company. The Company follows the Uniform System of
Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and
adopted by The Public Utilities Commission of Ohio (PUCO). As a rate-regulated
utility, the Company is subject to Statement of Financial Accounting Standards
(SFAS) 71 which governs accounting for the effects of certain types of rate
regulation.
The Company is a member of the Central Area Power Coordination Group (CAPCO).
Other members are Cleveland Electric, Duquesne Light Company, Ohio Edison
Company and its wholly owned subsidiary, Pennsylvania Power Company. The members
have constructed and operate generation and transmission facilities for their
use.
(B) RELATED PARTY TRANSACTIONS
Operating revenues, operating expenses and interest charges include those
amounts for transactions with affiliated companies in the ordinary course of
business operations.
The Company's transactions with Cleveland Electric are primarily for firm power,
interchange power, transmission line rentals and jointly owned power plant
operations and construction. See Notes 2 and 3.
The Service Company provides management, financial, administrative, engineering,
legal and other services at cost to the Company and other affiliated companies.
The Service Company billed the Company $76 million, $60 million and $61 million
in 1993, 1992 and 1991, respectively, for such services.
(C) REVENUES
Customers are billed on a monthly cycle basis for their energy consumption based
on rate schedules or contracts authorized by the PUCO or on ordinances of
individual municipalities. An accrual is made at the end of each month to record
the estimated amount of unbilled revenues for kilowatt-hours sold in the current
month but not billed by the end of that month.
A fuel factor is added to the base rates for electric service. This factor is
designed to recover from customers the costs of fuel and most purchased power.
It is reviewed and adjusted semiannually in a PUCO proceeding.
(D) FUEL EXPENSE
The cost of fossil fuel is charged to fuel expense based on inventory usage. The
cost of nuclear fuel, including an interest component, is charged to fuel
expense based on the rate of consumption. Estimated future nuclear fuel disposal
costs are being recovered through the base rates.
The Company defers the differences between actual fuel costs and estimated fuel
costs currently being recovered from customers through the fuel factor. This
matches fuel expenses with fuel-related revenues.
Owners of nuclear generating plants are assessed by the federal government for
the cost of decontamination and decommissioning of nuclear enrichment facilities
operated by the United States Department of Energy. The assessments are based
upon the amount of enrichment services used in prior years and cannot be imposed
for more than 15 years. The Company has accrued a liability for its share of the
total assessments. These costs have been recorded in a deferred charge account
since the PUCO is allowing the Company to recover the assessments through its
fuel cost factors.
(E) DEFERRED CARRYING CHARGES
AND OPERATING EXPENSES
The PUCO authorized the Company to defer operating expenses and carrying charges
for Perry Unit 1 and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2)
from their respective in-service dates in 1987 through December 1988. The annual
amortization and recovery of these deferrals, called pre-phase-in deferrals, are
$7 million which began in January 1989 and will continue over the lives of the
related property.
Beginning in January 1989, the Company deferred certain operating expenses and
both interest and equity carrying charges pursuant to a PUCO-approved rate
phase-in plan for its investments in Perry Unit 1 and Beaver Valley Unit 2.
These deferrals, called phase-in deferrals, were written off at December 31,
1993. See Note 7.
The Company also defers certain costs not currently recovered in rates under a
Rate Stabilization Program approved by the PUCO in October 1992. See Notes 7 and
14.
(F) DEPRECIATION AND AMORTIZATION
The cost of property, plant and equipment is depreciated over their estimated
useful lives on a straight-line basis. The annual straight-line depreciation
provision for nonnuclear property expressed as a percent of average depreciable
utility plant in service was 3.6% in both 1993 and 1992 and 3.4% in 1991.
Effective January 1, 1991, the Company, after obtaining PUCO approval, changed
its method of accounting for nuclear plant depreciation from the
units-of-production method to the straight-line method at about a 3% rate. This
change decreased 1991 depreciation expense $14 million and increased 1991 net
(Toledo Edison) F-58 (Toledo Edison)
112
income $11 million (net of $3 million of income taxes) from what they otherwise
would have been. The PUCO subsequently approved in 1991 a change to lower the 3%
rate to 2.5% retroactive to January 1, 1991.
Pursuant to a PUCO order, the Company currently uses external funding for the
future decommissioning of its nuclear units at the end of their licensed
operating lives. The estimated costs are based on the NRC's DECON method of
decommissioning (prompt decontamination). Cash contributions are made to the
trust funds on a straight-line basis over the remaining licensing period for
each unit. The current level of annual expense being recovered from customers
based on prior estimates is approximately $4 million. However, actual
decommissioning costs are expected to significantly exceed those estimates.
Current site-specific estimates for the Company's share of the future
decommissioning costs are $41 million in 1992 dollars for Beaver Valley Unit 2
and $87 million and $146 million in 1993 dollars for Perry Unit 1 and the
Davis-Besse Nuclear Power Station (Davis-Besse), respectively. The estimates for
Perry Unit 1 and Davis-Besse are preliminary and are expected to be finalized by
the end of the second quarter of 1994. The Company used these estimates to
increase its decommissioning expense accruals in 1993. It is expected that the
increases associated with the revised cost estimates will be recoverable in
future rates. In the Balance Sheet at December 31, 1993, Accumulated
Depreciation and Amortization included $34 million of decommissioning costs
previously expensed and the earnings on the external funding. This amount
exceeds the Balance Sheet amount of the external Nuclear Plant Decommissioning
Trusts because the reserve began prior to the external trust funding.
(G) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost less amounts ordered
by the PUCO to be written off. Construction costs include related payroll taxes,
pensions, fringe benefits, management and general overheads and allowance for
funds used during construction (AFUDC). AFUDC represents the estimated composite
debt and equity cost of funds used to finance construction. This noncash
allowance is credited to income. The AFUDC rate was 10.22% in 1993 and 10.96% in
both 1992 and 1991.
Maintenance and repairs are charged to expense as incurred. The cost of
replacing plant and equipment is charged to the utility plant accounts. The cost
of property retired plus removal costs, after deducting any salvage value, is
charged to the accumulated provision for depreciation.
(H) DEFERRED GAIN AND LOSS FROM
SALES OF UTILITY PLANT
The sale and leaseback transactions discussed in Note 2 resulted in a net gain
for the sale of the Bruce Mansfield Generating Plant (Mansfield Plant) and a net
loss for the sale of Beaver Valley Unit 2. The net gain and net loss were
deferred and are being amortized over the terms of leases. These amortizations
and the lease expense amounts are recorded as other operation and maintenance
expenses.
(I) INTEREST CHARGES
Debt Interest reported in the Income Statement does not include interest on
obligations for nuclear fuel under construction. That interest is capitalized.
See Note 6.
Losses and gains realized upon the reacquisition or redemption of long-term debt
are deferred, consistent with the regulatory rate treatment. Such losses and
gains are either amortized over the remainder of the original life of the debt
issue retired or amortized over the life of the new debt issue when the proceeds
of a new issue are used for the debt redemption. The amortizations are included
in debt interest expense.
(J) FEDERAL INCOME TAXES
The Financial Accounting Standards Board (FASB) issued SFAS 109, a new standard
for accounting for income taxes, in February 1992. We adopted the new standard
in 1992. The standard amended certain provisions of SFAS 96 which we had
previously adopted. Adoption of SFAS 109 in 1992 did not materially affect our
results of operations, but did affect certain Balance Sheet accounts. See Note
8.
The financial statements reflect the liability method of accounting for income
taxes. This method requires that deferred taxes be recorded for all temporary
differences between the book and tax bases of assets and liabilities. The
majority of these temporary differences are attributable to property-related
basis differences. Included in these basis differences is the equity component
of AFUDC, which will increase future tax expense when it is recovered through
rates. Since this component is not recognized for tax purposes, we must record a
liability for our tax obligation. The PUCO permits recovery of such taxes from
customers when they become payable. Therefore, the net amount due from customers
through rates has been recorded as a deferred charge and will be recovered over
the lives of the related assets.
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7 for a
discussion of the amortization of certain unrestricted excess deferred taxes and
unrestricted investment tax credits under the Rate Stabilization Program.
(Toledo Edison) F-59 (Toledo Edison)
113
(2) Utility Plant Sale and
Leaseback Transactions
The Company and Cleveland Electric are co-lessees of 18.26% (150 megawatts) of
Beaver Valley Unit 2 and 6.5% (51 megawatts), 45.9% (358 megawatts) and 44.38%
(355 megawatts) of Units 1, 2 and 3 of the Mansfield Plant, respectively, all
for terms of about 29 1/2 years. These leases are the result of sale and
leaseback transactions completed in 1987.
Under these leases, the Company and Cleveland Electric are responsible for
paying all taxes, insurance premiums, operation and maintenance expenses and all
other similar costs for their interests in the units sold and leased back. They
may incur additional costs in connection with capital improvements to the units.
The Company and Cleveland Electric have options to buy the interests back at the
end of the leases for the fair market value at that time or to renew the leases.
Additional lease provisions provide other purchase options along with conditions
for mandatory termination of the leases (and possible repurchase of the
leasehold interests) for events of default. These events include noncompliance
with several financial covenants discussed in Note 11(d).
As co-lessee with Cleveland Electric, the Company is also obligated for
Cleveland Electric's lease payments. If Cleveland Electric is unable to make its
payments under the Mansfield Plant leases, the Company would be obligated to
make such payments. No payments have been made on behalf of Cleveland Electric
to date.
In April 1992, nearly all of the outstanding Secured Lease Obligation Bonds
(SLOBs) issued by a special purpose corporation in connection with financing the
sale and leaseback of Beaver Valley Unit 2 were refinanced through a tender
offer and the sale of new bonds having a lower interest rate. As part of the
refinancing transaction, the Company paid $43 million as supplemental rent to
fund transaction expenses and part of the tender premium. This amount has been
deferred and is being amortized over the remaining lease term. The refinancing
transaction reduced the annual rental expense for the Beaver Valley Unit 2 lease
by $9 million.
Future minimum lease payments under the operating leases at December 31, 1993
are summarized as follows:
For For
the Cleveland
Year Company Electric
- ---------------------------------------- ------- ---------
(millions of
dollars)
1994.................................... $ 103 $ 63
1995.................................... 102 63
1996.................................... 125 63
1997.................................... 102 63
1998.................................... 102 63
Later Years............................. 2,021 1,391
------- ---------
Total Future Minimum Lease
Payments........................ $2,555 $ 1,706
------- ---------
------- ---------
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1993, 1992 and 1991 as annual rental expense for the
Mansfield Plant leases was $45 million. The amounts recorded in 1993, 1992 and
1991 as annual rental expense for the Beaver Valley Unit 2 lease were $63
million, $66 million and $72 million, respectively. Amounts charged to expense
in excess of the lease payments are classified as Accumulated Deferred Rents in
the Balance Sheet.
The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity
entitlement to Cleveland Electric. We anticipate that this sale will continue
indefinitely. Revenues recorded for this transaction were $103 million, $108
million and $107 million in 1993, 1992 and 1991, respectively. The future
minimum lease payments through the year 2017 associated with Beaver Valley Unit
2 aggregate $1.47 billion.
(3) Property Owned with Other Utilities and Investors
The Company owns, as a tenant in common with other utilities and those investors
who are owner-participants in various sale and leaseback transactions (Lessors),
certain generating units as listed below. Each owner owns an undivided share in
the entire unit. Each owner has the right to a percentage of the generating
capability of each unit equal to its ownership share. Each utility owner is
obligated to pay for only its respective share of the construction costs and
operating expenses. Each Lessor has leased its capacity rights to a utility
which is obligated to pay for such Lessor's share of the construction costs and
operating expenses. The Company's share of the operating expenses of these
generating units is included in the Income Statement. The Balance Sheet
classification of Property, Plant and Equipment at December 31, 1993 includes
the following facilities owned by the Company as a tenant in common with other
utilities and Lessors:
In- Plant Construction
Service Ownership Ownership Power in Work in Accumulated
Generating Unit Date Share Megawatts Source Service Progress Depreciation
- ------------------------------- ------- --------- --------- -------- ------- ------------ -----------
(millions of dollars)
Davis-Besse 1977 48.62% 429 Nuclear $ 679 $ 10 $ 163
Perry Unit 1 1987 19.91 238 Nuclear 1,051 3 186
Beaver Valley Unit 2 and
Common Facilities (Note 2) 1987 1.65 13 Nuclear 203 3 36
------- --- -----
Total $1,933 $ 16 $ 385
------- --- -----
------- --- -----
(Toledo Edison) F-60 (Toledo Edison)
114
(4) Construction and
Contingencies
(A) CONSTRUCTION PROGRAM
The estimated cost of the Company's construction program for the 1994-1998
period is $259 million, including AFUDC of $10 million and excluding nuclear
fuel.
The Clean Air Act will require, among other things, significant reductions in
the emission of sulfur dioxide in two phases over a ten-year period and nitrogen
oxides by fossil-fueled generating units.
Our compliance strategy provides for compliance with both phases through at
least 2005 primarily through greater use of low-sulfur coal at some of our units
and the banking of emission allowances. The plan will require capital
expenditures over the 1994-2003 period of approximately $57 million for nitrogen
oxide control equipment, emission monitoring equipment and plant modifications.
In addition, higher fuel and other operation and maintenance expenses may be
incurred. The anticipated rate increase associated with the capital expenditures
and higher expenses would be less than 2% over the ten-year period. The PUCO has
approved this plan. We also are seeking United States Environmental Protection
Agency (U.S. EPA) approval of the first phase of our plan.
We are continuing to monitor developments in new technologies that may be
incorporated into our compliance strategy. If a different plan is required by
the U.S. EPA, significantly higher capital expenditures could be required during
the 1994-2003 period. We believe Ohio law permits the recovery of compliance
costs from customers in rates.
(B) PERRY UNIT 2
Perry Unit 2, including its share of the facilities common with Perry Unit 1,
was approximately 50% complete when construction was suspended in 1985 pending
consideration of various options. These options included resumption of full
construction with a revised estimated cost, conversion to a nonnuclear design,
sale of all or part of our ownership share, or cancellation.
We wrote off our investment in Perry Unit 2 at December 31, 1993 after we
determined that it would not be completed or sold. The write-off totaled $232
million ($167 million after taxes) for the Company's 19.91% ownership share of
the unit. See Note 14.
(C) HAZARDOUS WASTE DISPOSAL SITES
The Company is aware of its potential involvement in the cleanup of several
hazardous waste disposal sites. The Company has accrued a liability totaling $6
million at December 31, 1993 based on estimates of the costs of cleanup and its
proportionate responsibility for such costs. We believe that the ultimate
outcome of these matters will not have a material adverse effect on our
financial condition or results of operations. See Management's Financial
Analysis -- Outlook-Hazardous Waste Disposal Sites.
(5) Nuclear Operations and
Contingencies
(A) OPERATING NUCLEAR UNITS
The Company's three nuclear units may be impacted by activities or events beyond
our control. An extended outage of one of our nuclear units for any reason,
coupled with any unfavorable rate treatment, could have a material adverse
effect on our financial condition and results of operations. See discussion of
these risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
(B) NUCLEAR INSURANCE
The Price-Anderson Act limits the liability of the owners of a nuclear power
plant to the amount provided by private insurance and an industry assessment
plan. In the event of a nuclear incident at any unit in the United States
resulting in losses in excess of the level of private insurance (currently $200
million), the Company's maximum potential assessment under that plan would be
$70 million (plus any inflation adjustment) per incident. The assessment is
limited to $9 million per year for each nuclear incident. These assessment
limits assume the other CAPCO companies contribute their proportionate share of
any assessment.
The CAPCO companies have insurance coverage for damage to property at the
Davis-Besse, Perry and Beaver Valley sites (including leased fuel and clean-up
costs). Coverage amounted to $2.75 billion for each site as of January 1, 1994.
Damage to property could exceed the insurance coverage by a substantial amount.
If it does, the Company's share of such excess amount could have a material
adverse effect on its financial condition and results of operations. Under these
policies, the Company can be assessed a maximum of $11 million during a policy
year if the reserves available to the insurer are inadequate to pay claims
arising out of an accident at any nuclear facility covered by the insurer.
The Company also has extra expense insurance coverage. It includes the
incremental cost of any replacement power purchased (over the costs which would
have been incurred had the units been operating) and other incidental expenses
after the occurrence of certain types of accidents at our nuclear units. The
amounts of the coverage are 100% of the estimated extra expense per week during
the 52-week period starting 21 weeks after an accident and 67% of such estimate
per week for the next 104 weeks. The amount and duration of extra expense could
substantially exceed the insurance coverage.
(Toledo Edison) F-61 (Toledo Edison)
115
(6) Nuclear Fuel
Nuclear fuel is financed for the Company and Cleveland Electric through leases
with a special-purpose corporation. The total amount of financing currently
available under these lease arrangements is $382 million ($232 million from
intermediate-term notes and $150 million from bank credit arrangements).
Financing in an amount up to $750 million is permitted. The intermediate-term
notes mature in the period 1994-1997, with $75 million maturing in September
1994. At December 31, 1993, $154 million of nuclear fuel was financed for the
Company. The Company and Cleveland Electric severally lease their respective
portions of the nuclear fuel and are obligated to pay for the fuel as it is
consumed in a reactor. The lease rates are based on various intermediate-term
note rates, bank rates and commercial paper rates.
The amounts financed include nuclear fuel in the Davis-Besse, Perry Unit 1 and
Beaver Valley Unit 2 reactors with remaining lease payments for the Company of
$52 million, $29 million and $20 million, respectively, at December 31, 1993.
The nuclear fuel amounts financed and capitalized also included interest charges
incurred by the lessors amounting to $6 million in both 1993 and 1992 and $9
million in 1991. The estimated future lease amortization payments based on
projected consumption are $49 million in 1994, $42 million in 1995, $37 million
in 1996, $33 million in 1997 and $30 million in 1998.
(7) Regulatory Matters
Phase-in deferrals were recorded beginning in 1989 pursuant to the phase-in plan
approved by the PUCO in a January 1989 rate order for the Company. The phase-in
plan was designed so that the projected revenues resulting from the authorized
rate increases and anticipated sales growth provided for the phase-in of certain
nuclear costs over a ten-year period. The plan required the deferral of a
portion of the operating expenses and both interest and equity carrying charges
on the Company's deferred rate-based investments in Perry Unit 1 and Beaver
Valley Unit 2 during the early years of the plan. The amortization and recovery
of such deferrals were scheduled to be completed by 1998.
As we developed our strategic plan, we evaluated the future recovery of our
deferred charges and continued application of the regulatory accounting measures
we follow pursuant to PUCO orders. We concluded that projected revenues would
not provide for the recovery of the phase-in deferrals as scheduled because of
economic and competitive pressures. Accordingly, we wrote off the cumulative
balance of the phase-in deferrals. The total phase-in deferred operating
expenses and carrying charges written off at December 31, 1993 by the Company
were $55 million and $186 million, respectively (totaling $165 million after
taxes). See Note 14. While recovery of our other regulatory deferrals remains
probable, our current assessment of business conditions has prompted us to
change our future plans. We decided that, once the deferral of expenses and
acceleration of benefits under our Rate Stabilization Program are completed in
1995, we should no longer plan to use regulatory accounting measures to the
extent we have in the past.
In October 1992, the PUCO approved a Rate Stabilization Program that was
designed to encourage economic growth in the Company's service area by freezing
the Company's base rates until 1996 and limiting subsequent rate increases to
specified annual amounts not to exceed $89 million over the 1996-1998 period.
As part of the Rate Stabilization Program, the Company is allowed to defer and
subsequently recover certain costs not currently recovered in rates and to
accelerate amortization of certain benefits. Such regulatory accounting measures
provide for rate stabilization by rescheduling the timing of rate recovery of
certain costs and the amortization of certain benefits during the 1992-1995
period. The continued use of these regulatory accounting measures will be
dependent upon our continuing assessment and conclusion that there will be
probable recovery of such deferrals in future rates.
The regulatory accounting measures we are eligible to record through December
31, 1995 include the deferral of post-in-service interest carrying charges,
depreciation expense and property taxes on assets placed in service after
February 29, 1988 and the deferral of operating expenses equivalent to an
accumulated excess rent reserve for Beaver Valley Unit 2 (which resulted from
the April 1992 refinancing of SLOBs as discussed in Note 2). The cost deferrals
recorded in 1993 and 1992 pursuant to these provisions were $39 million and $32
million, respectively. Amortization and recovery of these deferrals will occur
over the average life of the related assets and the remaining lease period, or
approximately 30 years, and will commence with future rate recognition. The
regulatory accounting measures also provide for the accelerated amortization of
certain unrestricted excess deferred tax and unrestricted investment tax credit
balances and interim spent fuel storage accrual balances for Davis-Besse. The
total amount of such regulatory benefits recognized in 1993 and 1992 pursuant to
these provisions was $18 million and $5 million, respectively.
The Rate Stabilization Program also authorized the Company to defer and
subsequently recover the incremental expenses associated with the adoption of
the accounting standard for postretirement benefits other than pensions (SFAS
106). In 1993, we deferred $37 million pursuant to this provision. Amortization
and recovery of this
(Toledo Edison) F-62 (Toledo Edison)
116
deferral will commence prior to 1998 and is expected to be completed by no later
than 2012. See Note 9(b).
(8) Federal Income Tax
Federal income tax, computed by multiplying income before taxes by the statutory
rate (35% in 1993 and 34% in both 1992 and 1991), is reconciled to the amount of
federal income tax recorded on the books as follows:
1993 1992 1991
----- ---- ----
(millions of
dollars)
Book Income (Loss) Before Federal Income
Tax $(428) $105 $88
----- ---- ----
----- ---- ----
Tax (Credit) on Book Income (Loss) at
Statutory Rate $(150) $ 36 $30
Increase (Decrease) in Tax:
Write-off of Perry Unit 2 16 -- --
Write-off of phase-in deferrals 8 -- --
Depreciation (12) (6) 3
Rate Stabilization Program (10) (2) --
Sale and leaseback transactions and
amortization 5 5 5
Other items 4 1 --
----- ---- ----
Total Federal Income Tax Expense (Credit) $(139) $ 34 $38
----- ---- ----
----- ---- ----
Federal income tax expense is recorded in the Income Statement as follows:
1993 1992 1991
----- ---- ----
(millions of
dollars)
Operating Expenses:
Current Tax Provision $ 36 $ 26 $ 14
Changes in Accumulated Deferred Federal
Income Tax:
Write-off of deferred operating
expenses (13) -- --
Accelerated depreciation and
amortization 35 7 9
Alternative minimum tax credit (37) (13) (44)
Retirement and postemployment
benefits (20) -- --
Sale and leaseback transactions and
amortization 5 4 13
Taxes, other than federal income
taxes (7) 5 --
Rate Stabilization Program (1) 2 --
Reacquired debt costs (1) 4 7
Deferred fuel costs -- 1 (4)
Other items (7) (3) 10
Investment Tax Credits -- -- 27
----- ---- ----
Total Expense (Credit) to Operating
Expenses (10) 33 32
----- ---- ----
Nonoperating Income:
Current Tax Provision (15) (20) (38)
Changes in Accumulated Deferred Federal
Income Tax:
Write-off of deferred carrying
charges (63) -- --
Write-off of Perry Unit 2 (65) -- --
Disallowed nuclear costs 14 7 --
Rate Stabilization Program 4 5 --
AFUDC and carrying charges 5 9 9
Net operating loss carryforward (7) -- 35
Other items (2) -- --
----- ---- ----
Total Expense (Credit) to
Nonoperating Income (129) 1 6
----- ---- ----
Total Federal Income Tax Expense (Credit) $(139) $ 34 $ 38
----- ---- ----
----- ---- ----
The Company joins in the filing of a consolidated federal income tax return with
its affiliated companies. The method of tax allocation reflects the benefits and
burdens realized by each company's participation in the consolidated tax return,
approximating a separate return result for each company.
In August 1993, the 1993 Tax Act was enacted. Retroactive to January 1, 1993,
the top marginal corporate income tax rate increased to 35%. The change in tax
rate increased Accumulated Deferred Federal Income Taxes for the future tax
obligation by approximately $29 million. Since the PUCO has historically
permitted recovery of such taxes from customers when they become payable, the
deferred charge, Amounts Due from Customers for Future Federal Income Taxes,
also was increased by $29 million. The 1993 Tax Act is not expected to
materially impact future results of operations or cash flow.
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $178 million and deferred tax liabilities of $649 million at December
31, 1993 and deferred tax assets of $154 million and deferred tax liabilities of
$794 million at December 31, 1992. These are summarized as follows:
December
31,
-----------
1993 1992
---- ----
(millions
of dollars)
Property, plant and equipment $534 $656
Deferred carrying charges and operating expenses 79 119
Net operating loss carryforwards (39) (56)
Investment tax credits (55) (58)
Other (48) (21)
---- ----
Net deferred tax liability $471 $640
---- ----
---- ----
For tax purposes, net operating loss (NOL) carryforwards of approximately $111
million are available to reduce future taxable income and will expire in 2003
through 2005. The 35% tax effect of the NOLs is $39 million.
The Tax Reform Act of 1986 provides for an alternative minimum tax (AMT) credit
to be used to reduce the regular tax to the AMT level should the regular tax
exceed the AMT. AMT credits of $77 million are available to offset future
regular tax. The credits may be carried forward indefinitely.
(9) Retirement and
Postemployment Benefits
(A) RETIREMENT INCOME PLAN
Prior to December 31, 1993, the Company sponsored a noncontributory pension plan
which covered all employee groups. The plan was merged with another plan which
covered employees of Cleveland Electric and the Service Company into a single
plan on December 31, 1993. The amount of retirement benefits generally depends
upon the length of service. Under certain circumstances, benefits can begin as
early as age 55. The funding policy is to
(Toledo Edison) F-63 (Toledo Edison)
117
comply with the Employee Retirement Income Security Act of 1974 guidelines.
In 1993, the Company offered the VTP, an early retirement program. Operating
expenses for 1993 included $59 million of pension plan accruals to cover
enhanced VTP benefits and an additional $3 million of pension costs for VTP
benefits paid to retirees from corporate funds. The $3 million is not included
in the pension data reported below. A credit of $15 million resulting from a
settlement of pension obligations through lump sum payments to almost all the
VTP retirees partially offset the VTP expenses.
Net pension and VTP costs for 1991 through 1993 were comprised of the following
components:
1993 1992 1991
---- ---- ----
(millions of
dollars)
Pension Costs:
Service cost for benefits earned
during the
period $ 5 $ 5 $ 5
Interest cost on projected benefit
obligation 11 11 11
Actual return on plan assets (15) (5) (30)
Net amortization and deferral 2 (10) 15
---- ---- ----
Net pension costs 3 1 1
VTP cost 59 -- --
Settlement gain (15) -- --
---- ---- ----
Net costs $ 47 $ 1 $ 1
---- ---- ----
---- ---- ----
The following table presents a reconciliation of the funded status of the
Company's former plan at December 31, 1992 with comparable information for a
portion of the merged plan at December 31, 1993. The December 31, 1993 benefit
obligation estimates were derived from information for the former plans. Plan
assets of the merged plan were allocated based on a pro rata share of the
projected benefit obligation.
1993 1992
---- ----
(millions of
dollars)
Actuarial present value of benefit obligations:
Vested benefits $102 $ 95
Nonvested benefits 11 12
---- ----
Accumulated benefit obligation 113 107
Effect of future compensation levels 16 35
---- ----
Total projected benefit obligation 129 142
Plan assets at fair market value 118 169
---- ----
Funded status (11) 27
Unrecognized net gain from variance between
assumptions and experience (50) (33)
Unrecognized prior service cost 4 5
Transition asset at January 1, 1987 being
amortized over 19 years (8) (17)
---- ----
Net accrued pension liability included in
Deferred Credits - Other in the Balance
Sheet $(65) $(18)
---- ----
---- ----
At December 31, 1993, the settlement (discount) rate and long-term rate of
return on plan assets assumptions
were 7.25% and 8.75%, respectively. The long-term rate of
annual compensation increase assumption was 4.25%. At
December 31, 1992, the settlement rate and long-term rate of return on plan
assets assumptions were 8.5% and the long-term rate of annual compensation
increase assumption was 5%.
Plan assets consist primarily of investments in common stock, bonds, guaranteed
investment contracts, cash equivalent securities and real estate.
(B) OTHER POSTRETIREMENT BENEFITS
Centerior Energy sponsors jointly with its subsidiaries a postretirement benefit
plan which provides all employee groups certain health care, death and other
postretirement benefits other than pensions. The plan is contributory, with
retiree contributions adjusted annually. The plan is not funded. A policy
limiting the employer's contribution for retiree medical coverage for employees
retiring after March 31, 1993 was implemented in February 1993.
The Company adopted SFAS 106, the accounting standard for postretirement
benefits other than pensions, effective January 1, 1993. The standard requires
the accrual of the expected costs of such benefits during the employees' years
of service. Previously, the costs of these benefits were expensed as paid, which
is consistent with ratemaking practices. Such costs for the Company totaled $4
million in both 1992 and 1991, which included medical benefits of $3 million in
both years. The total amount accrued by the Company for SFAS 106 costs for 1993
was $42 million, of which $1 million was capitalized and $41 million was
expensed as other operation and maintenance expenses. In 1993, the Company
deferred incremental SFAS 106 expenses totaling $37 million pursuant to a
provision of the Rate Stabilization Program. See Note 7.
The components of the total postretirement benefit costs for 1993 were as
follows:
Millions
of Dollars
----------
Service cost for benefits earned $ 1
Interest cost on accumulated postretirement
benefit obligation 6
Amortization of transition obligation at January
1, 1993 of $63 million over 20 years 3
VTP curtailment cost (includes $6 million
transition obligation adjustment) 32
---
Total costs $ 42
---
---
These amounts included costs for the Company and a pro rata share of the Service
Company's costs.
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost at December 31, 1993
(Toledo Edison) F-64 (Toledo Edison)
118
for the Company and its share of the Service Company's obligation are summarized
as follows:
Millions
of Dollars
----------
Accumulated postretirement benefit obligation
attributable to:
Retired participants $(88)
Other active plan participants (9)
-----
Accumulated postretirement benefit obligation (97)
Unrecognized net loss from variance between
assumptions and experience 5
Unamortized transition obligation 54
-----
Accrued postretirement benefit cost $(38)
-----
-----
The Balance Sheet classification of Other Noncurrent Liabilities at December 31,
1993 includes only the Company's accrued postretirement benefit cost of $33
million and excludes the Service Company's portion since the Service Company's
total accrued cost is carried on its books.
At December 31, 1993, the settlement rate and the long-term rate of annual
compensation increase assumptions were 7.25% and 4.25%, respectively. The
assumed annual health care cost trend rates (applicable to gross eligible
charges) are 9.5% for medical and 8% for dental in 1994. Both rates reduce
gradually to a fixed rate of 4.75% in 1996 and later years. Elements of the
obligation affected by contribution caps are significantly less sensitive to the
health care cost trend rate than other elements. If the assumed health care cost
trend rates were increased by 1% in each future year, the accumulated
postretirement benefit obligation as of December 31, 1993 would increase by $4
million and the aggregate of the service and interest cost components of the
annual postretirement benefit cost would increase by $0.3 million.
(C) POSTEMPLOYMENT BENEFITS
In 1993, the Company adopted SFAS 112, the new accounting standard which
requires the accrual of postemployment benefit costs. Postemployment benefits
are the benefits provided to former or inactive employees after employment but
before retirement, such as worker's compensation, disability benefits and
severance pay. The adoption of this accounting method did not materially affect
the Company's 1993 results of operations or financial position.
(10) Guarantees
The Company has guaranteed certain loan and lease obligations of a mining
company under a long-term coal purchase arrangement. This arrangement requires
payments to the mining company for any actual expenses (as advance payments for
coal) when the mines are idle for reasons beyond the control of the mining
company. At December 31, 1993, the principal amount of the mining company's loan
and lease obligations guaranteed by the Company was $20 million.
(11) Capitalization
(A) CAPITAL STOCK TRANSACTIONS
Preferred stock shares retired during the three years ended December 31, 1993
are listed in the following table.
1993 1992 1991
---- --- ---
(thousands of
shares)
Subject to Mandatory Redemption:
$100 par $11.00 -- (25) (10)
9.375 (17) (17) (17)
25 par 2.81 (800) -- --
---- --- ---
Total (817) (42) (27)
---- --- ---
---- --- ---
(B) EQUITY DISTRIBUTION RESTRICTIONS
Federal law prohibits the Company from paying dividends out of capital accounts.
However, the Company may pay dividends out of appropriated retained earnings and
current earnings. At December 31, 1993, the Company had $42 million of
appropriated retained earnings for the payment of preferred stock dividends. The
Company is currently prohibited from paying a common stock dividend by a
provision in its mortgage.
(C) PREFERRED AND PREFERENCE STOCK
Amounts to be paid for preferred stock which must be redeemed during the next
five years are $12 million in each year 1994 through 1996 and $2 million in both
1997 and 1998.
The annual preferred stock mandatory redemption provisions are as follows:
Shares Price
To Be Beginning Per
Redeemed in Share
-------- --------- -----
$100 par $9.375 16,650 1985 $100
25 par 2.81 400,000 1993 25
The annualized preferred dividend requirement at December 31, 1993 was $21
million.
The preferred dividend rates on the Company's Series A and B fluctuate based on
prevailing interest rates and market conditions. The dividend rates for these
issues averaged 7.41% and 8.22%, respectively, in 1993.
Preference stock authorized for the Company is 5,000,000 shares with a $25 par
value. No preference shares are currently outstanding.
With respect to dividend and liquidation rights, the Company's preferred stock
is prior to its preference stock and common stock, and its preference stock is
prior to its common stock.
(Toledo Edison) F-65 (Toledo Edison)
119
(D) LONG-TERM DEBT AND OTHER
BORROWING ARRANGEMENTS
Long-term debt, less current maturities, was as follows:
Actual
or Average
Interest
Rate at December 31,
December 31, ---------------
Year of Maturity 1993 1993 1992
- -------------------------------- ------------ ------ ------
(millions of
dollars)
First mortgage bonds:
1997 6.125% $ 31 $ 31
1998 10.00 1 1
1999-2003 7.46 162 162
2004-2008 7.88 145 145
2009-2013 2.50 31 31
2019-2023 7.06 215 215
------ ------
585 585
Secured medium term notes due
1995-2021 8.44 250 182
Term bank loans due 1995-1996 8.77 109 113
Notes due 1995-1997 9.63 43 60
Debentures due 2002 8.70 135 135
Pollution control notes due
1995-2015 12.02 105 105
Other -- net -- (2) (2)
------ ------
Total Long-Term Debt $1,225 $1,178
------ ------
------ ------
Long-term debt matures during the next five years as follows: $45 million in
1994, $71 million in 1995, $91 million in 1996 and $39 million in both 1997 and
1998.
The Company issued $275 million aggregate principal amount of secured
medium-term notes during the 1991-1993 period. The notes are secured by first
mortgage bonds.
The Company's mortgage constitutes a direct first lien on substantially all
property owned and franchises held by the Company. Excluded from the lien, among
other things, are cash, securities, accounts receivable, fuel, supplies and
automotive equipment.
Certain unsecured loan agreements of the Company contain covenants relating to
capitalization ratios, fixed charge coverage ratios and limitations on secured
financing other than through first mortgage bonds or certain other transactions.
Two reimbursement agreements relating to separate letters of credit issued in
connection with the sale and leaseback of Beaver Valley Unit 2 contain several
financial covenants affecting the Company, Cleveland Electric and Centerior
Energy. Among these are covenants relating to fixed charge coverage ratios and
capitalization ratios. The write-offs recorded at December 31, 1993 caused the
Company, Cleveland Electric and Centerior Energy to violate certain covenants
contained in the two reimbursement agreements. The affected creditors have
waived those violations in exchange for commitments to provide them with a
second mortgage security interest on property of the Company and Cleveland
Electric and other considerations. We expect to complete this process in the
second quarter of 1994. We will provide the same security interest to certain
other creditors because their agreements require equal treatment. We expect to
provide second mortgage collateral for $172 million of unsecured debt, $228
million of bank letters of credit and a $205 million revolving credit facility.
The bank letters of credit and revolving credit facility are joint and several
obligations of the Company and Cleveland Electric.
(12) Short-Term Borrowing Arrangements
In May 1993, Centerior Energy arranged for a $205 million, three-year revolving
credit facility. The facility may be renewed twice for one-year periods at the
option of the participating banks. Centerior Energy and the Service Company may
borrow under the facility, with all borrowings jointly and severally guaranteed
by the Company and Cleveland Electric. Centerior Energy plans to transfer any of
its borrowed funds to the Company and Cleveland Electric, while the Service
Company may borrow up to $25 million for its own use. The banks' fee is 0.5% per
annum payable quarterly in addition to interest on any borrowings. That fee is
expected to increase to 0.625% when the facility agreement is amended as
discussed below. There were no borrowings under the facility at December 31,
1993. The facility agreement contains covenants relating to capitalization and
fixed charge coverage ratios for the Company, Cleveland Electric and Centerior
Energy. The write-offs recorded at December 31, 1993 caused the ratios to fall
below those covenant requirements. The revolving credit facility is expected to
be available for borrowings after the facility agreement is amended in the
second quarter of 1994 to provide the participating creditors with a second
mortgage security interest.
Short-term borrowing capacity authorized by the PUCO annually is $150 million
for the Company. The Company and Cleveland Electric are authorized by the PUCO
to borrow from each other on a short-term basis.
At December 31, 1993, the Company had no commercial paper outstanding. The
Company is unable to rely on the sale of commercial paper to provide short-term
funds because of its below investment grade commercial paper credit ratings.
(Toledo Edison) F-66 (Toledo Edison)
120
(13) Financial Instruments'
Fair Value
The estimated fair values at December 31, 1993 and 1992 of financial instruments
that do not approximate their carrying amounts are as follows:
December 31,
----------------------------------
1993 1992
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- ------
(millions of dollars)
Nuclear Plant Decommissioning
Trusts $ 26 $ 27 $ 20 $ 21
Preferred Stock, with Mandatory
Redemption Provisions
(including current portion) 40 42 62 66
Long-Term Debt (including
current portion) 1,271 1,314 1,225 1,221
The fair value of the nuclear plant decommissioning trusts is estimated based on
the quoted market prices for the investment securities. The fair value of the
Company's preferred stock with mandatory redemption provisions and long-term
debt is estimated based on the quoted market prices for the respective or
similar issues or on the basis of the discounted value of future cash flows. The
discounted value used current dividend or interest rates (or other appropriate
rates) for similar issues and loans with the same remaining maturities.
The estimated fair values of all other financial instruments approximate their
carrying amounts in the Balance Sheet at December 31, 1993 and 1992 because of
their short-term nature.
(14) Quarterly Results of Operations (Unaudited)
The following is a tabulation of the unaudited quarterly results of operations
for the two years ended December 31, 1993.
Quarters Ended
----------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
(millions of dollars)
1993
Operating Revenues $ 215 $210 $ 239 $ 207
Operating Income (Loss) 39 42 17 (10)
Net Income (Loss) 18 20 (5) (323)
Earnings (Loss)
Available for Common
Stock 12 14 (10) (328)
1992
Operating Revenues $ 207 $202 $ 225 $ 210
Operating Income 38 29 52 31
Net Income 11 4 36 20
Earnings (Loss)
Available for Common
Stock 5 (3) 30 14
Earnings for the quarter ended September 30, 1993 were decreased by $35 million
as a result of the recording of $54 million of VTP pension-related benefits.
Earnings for the quarter ended December 31, 1993 were decreased as a result of
year-end adjustments for the $232 million write-off of Perry Unit 2 (see Note
4(b)), the $241 million write-off of the phase-in deferrals (see Note 7) and $19
million of other charges. These adjustments decreased quarterly earnings by $345
million.
Earnings for the quarter ended September 30, 1992 were increased by $15 million
as a result of the recording of deferred operating expenses and carrying charges
for the first nine months of 1992 totaling $22 million under the Rate
Stabilization Program approved by the PUCO in October 1992. See Note 7.
(15) Pending Merger of the Company
with Cleveland Electric
On March 25, 1994, Centerior Energy announced that its operating utility
subsidiaries, the Company and Cleveland Electric, plan to merge into a single
operating entity. Since the Company and Cleveland Electric affiliated in 1986,
efforts have been made to consolidate operations and administration as much as
possible to achieve maximum cost savings. The merger of the two companies into a
single entity is the completion of this consolidation process. Various aspects
of the merger are subject to the approval of the FERC, the PUCO and other
regulatory authorities. The merger must be approved by share owners of the
Company's preferred stock. Share owners of Cleveland Electric's preferred stock
must approve the authorization of additional shares of preferred stock. Share
owners of the Company's preferred stock will exchange their shares for preferred
stock shares of the successor corporation having substantially the same terms,
while Cleveland Electric's preferred stock will automatically become shares of
the successor corporation. Debt holders of the merging companies will become
debt holders of the successor corporation. The merging companies plan to seek
preferred stock share owner approval in the summer of 1994. The merger is
expected to be effective in late 1994.
For the merging companies, the combined pro forma operating revenues were $2.475
billion, $2.439 billion and $2.561 billion and the combined pro forma net income
(loss) was $(876) million, $276 million and $296 million for the years ended
December 31, 1993, 1992 and 1991, respectively. The pro forma data is based on
accounting for the merger on a method similar to a pooling of interests. The pro
forma data is not necessarily indicative of the results of operations which
would have been reported had the merger been in effect during those years or
which may be reported in the future. The pro forma data should be read in
conjunction with the audited financial statements of both the Company and
Cleveland Electric.
(Toledo Edison) F-67 (Toledo Edison)
121
FINANCIAL AND
STATISTICAL REVIEW
- ----------------------------------------------------------------------
Operating Revenues (millions of dollars)
Steam
Total Total Heating
Year Residential Commercial Industrial Other Retail Wholesale Electric & Gas
- -----------------------------------------------------------------------------------------------------------------------
1993 $ 229 180 244 71 724 147 871 --
1992 215 175 236 61 687 158 845 --
1991 230 184 236 90 740 147 887 --
1990 224 175 236 78 713 150 863 --
1989 216 164 227 99 706 160 866 --
1983 161 105 170 42 478 21 499 9
Operating
Year Revenues
- ---------- ----------
1993 $ 871
1992 845
1991 887
1990 863
1989 866
1983 508
- --------------------------------------------------------------------------------
Operating Expenses (millions of dollars)
Other Deferred Federal
Fuel & Operation Depreciation Taxes, Operating Income Total
Purchased & & Other Than Expenses, Taxes Operating
Year Power Maintenance Amortization FIT Net (Credit) Expenses
- ------------------------------------------------------------------------------------------------------------------
1993 $ 173 456(a) 76 91 (4)(b) (10) $ 782
1992 169 342 77 91 (17) 33 695
1991 178 356 72(c) 89 1 32 728
1990 174 373 73 79 (10) 21 710
1989 172 373 85 72 (16) 37 723
1983 125 115 51 45 -- 57 393
- --------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Federal Income
Other Deferred Income (Loss)
Income & Carrying Taxes-- Before
Operating AFUDC-- Deductions, Charges, Credit Interest
Year Income Equity Net Net (Expense) Charges
- ----------------------------------------------------------------------------------------------
1993 $ 89 1 (232)(d) (161)(b) 129 $ (174)
1992 150 1 1 41 (1) 192
1991 159 1 5 22 (6) 181
1990 153 3 5 43 9 213
1989 143 9 20 82 (22) 232
1983 115 66 1 -- 24 206
- --------------------------------------------------------------------------------
Income (Loss) (millions of dollars)
Earnings
(Loss)
Net Preferred Available for
Debt AFUDC-- Income Stock Common
Year Interest Debt (Loss) Dividends Stock
- --------------------------------------------------------------------------------
1993 $116 (1) (289) 23 $(312)
1992 122 (1) 71 24 47
1991 132 (1) 50 25 25
1990 135 (3) 81 25 56
1989 145 (5) 92 25 67
1983 104 (26) 128 30 98
- --------------------------------------------------------------------------------
(a) Includes early retirement program expenses and other charges of $107 million
in 1993.
(b) Includes write-off of phase-in deferrals of $241 million in 1993, consisting
of $55 million of deferred operating expenses and $186 million of deferred
carrying charges.
(c) In 1991, a change in accounting for nuclear plant depreciation was adopted,
changing from the units-of-production method to the straight-line method at
a 2.5% rate.
(Toledo Edison) F-68 (Toledo Edison)
122
The Toledo Edison Company
Electric Sales (millions of KWH) Electric Customers (year end)
Industrial
Year Residential Commercial Industrial Wholesale Other Total Residential Commercial & Other
- --------------------------------------------------------------------------------------- ---------------------------------------
1993 2 039 1 672 3 776 2 146 490 10 123 255 109 26 049 4 076
1992 1 941 1 619 3 563 2 753 478 10 354 255 299 25 870 4 372
1991 2 041 1 683 3 543 2 587 482 10 336 254 500 26 044 4 444
1990 1 950 1 614 3 617 2 333 496 10 010 253 965 25 822 4 555
1989 2 017 1 622 3 740 3 138 495 11 012 253 234 25 803 4 434
1983 1 915 1 341 3 127 476 428 7 287 242 959 23 694 3 864
Residential Usage
Average Average
Average Price Revenue
KWH Per Per Per
Year Total Customer KWH Customer
- ------- --------- ---------------------------------
1993 285 234 7 997 11.23c $897.65
1992 285 541 7 632 11.08 845.99
1991 284 988 7 990 11.26 897.41
1990 284 342 7 692 11.48 882.99
1989 283 471 7 989 10.71 855.29
1983 270 517 7 900 8.44 665.43
- --------------------------------------------------------------------------------
Load (MW & %) Energy (millions of KWH) Fuel
Operable
Capacity Company Generated
at Time Peak Capacity Load ----------------------------- Purchased Fuel Cost
Year of Peak Load Margin Factor Fossil Nuclear Total Power Total Per KWH
- -------------------------------------------------------- --------------------------------------------------------- ---------
1993 1 874 1 568 16.3% 64.3% 5 548 4 791 10 339 196 10 535 1.42c
1992 1 727 1 514 12.3 63.2 4 656 6 293 10 949 (82) 10 867 1.41
1991 1 758 1 510 14.1 64.5 4 848 6 003 10 851 95 10 946 1.44
1990 1 752 1 516 13.5 63.0 5 535 4 219 9 754 902 10 656 1.50
1989 1 894 1 526 19.4 65.2 5 206 5 552 10 758 788 11 546 1.42
1983 1 777 1 325 25.4 65.6 4 683 2 383 7 066 749 7 815 1.67
Efficiency--
BTU Per
Year KWH
- ------------ ----------
1993 10 146
1992 10 284
1991 10 327
1990 10 220
1989 10 293
1983 10 337
- --------------------------------------------------------------------------------
Investment (millions of dollars)
Construction
Utility Work In Total
Plant Accumulated Progress Nuclear Property, Utility
In Depreciation & Net & Perry Fuel and Plant and Plant Total
Year Service Amortization Plant Unit 2 Other Equipment Additions Assets
- ----------------------------------------------------------------------------------------------- --------- -------
1993 $2 837 788 2 049 40 142 $ 2 231 $ 43 $3 510
1992 2 847 760 2 087 280 164 2 531 44 3 939
1991 2 692 709 1 983 308 198 2 489 54 3 926
1990 2 604 640 1 964 349 224 2 537 87 3 913
1989 2 528 565 1 963 342 237 2 542 73 4 051
1983 1 342 325 1 017 1 094 164(e) 2 275 294 2 501
- --------------------------------------------------------------------------------
<Caption
Capitalization (millions of dollars & %)
Preferred
Preferred Stock,
Stock, without
with Mandatory Mandatory
Common Stock Redemption Redemption
Year Equity Provisions Provisions Long-Term Debt Total
- -----------------------------------------------------------------------------------------------------
1993 $623 30% 28 1% 210 10% 1 225 59% $2 086
1992 935 39 50 2 210 9 1 178 50 2 373
1991 888 38 64 3 210 9 1 158 50 2 320
1990 881 39 66 3 210 9 1 097 49 2 254
1989 898 38 69 3 210 9 1 197 50 2 374
1983 716 36 94 5 200 10 985 49 1 995
- --------------------------------------------------------------------------------
(d) Includes write-off of Perry Unit 2 of $232 million in 1993.
(e) Restated for effects of capitalization of nuclear fuel lease and financing
arrangements pursuant to Statement of Financial Accounting Standards 71.
(Toledo Edison) F-69 (Toledo Edison)
123
INDEX TO SCHEDULES
Page
Centerior Energy Corporation and Subsidiaries:
Schedule V Property, Plant and Equipment for the Years S-2
Ended December 31, 1993, 1992 and 1991
Schedule VI Accumulated Depreciation and Amortization of S-5
Property, Plant and Equipment for the Years
Ended December 31, 1993, 1992 and 1991
Schedule VII Guarantees of Securities of Other Issuers for S-8
the Year Ended December 31, 1993
Schedule VIII Valuation and Qualifying Accounts for the S-9
Years Ended December 31, 1993, 1992 and 1991
Schedule IX Short-Term Borrowings for the Years Ended S-10
December 31, 1993, 1992 and 1991
Schedule X Supplementary Income Statement Information for S-11
the Years Ended December 31, 1993, 1992 and 1991
The Cleveland Electric Illuminating Company and Subsidiaries:
Schedule V Property, Plant and Equipment for the Years S-12
Ended December 31, 1993, 1992 and 1991
Schedule VI Accumulated Depreciation and Amortization of S-15
Property, Plant and Equipment for the Years
Ended December 31, 1993, 1992 and 1991
Schedule VII Guarantees of Securities of Other Issuers for S-18
the Year Ended December 31, 1993
Schedule VIII Valuation and Qualifying Accounts for the S-19
Years Ended December 31, 1993, 1992 and 1991
Schedule IX Short-Term Borrowings for the Years Ended S-20
December 31, 1993, 1992 and 1991
Schedule X Supplementary Income Statement Information for S-21
the Years Ended December 31, 1993, 1992 and 1991
The Toledo Edison Company:
Schedule V Property, Plant and Equipment for the Years S-22
Ended December 31, 1993, 1992 and 1991
Schedule VI Accumulated Depreciation and Amortization of S-25
Property, Plant and Equipment for the Years
Ended December 31, 1993, 1992 and 1991
Schedule VII Guarantees of Securities of Other Issuers for S-28
the Year Ended December 31, 1993
Schedule VIII Valuation and Qualifying Accounts for the S-29
Years Ended December 31, 1993, 1992 and 1991
Schedule IX Short-Term Borrowings for the Years Ended S-30
December 31, 1993, 1992 and 1991
Schedule X Supplementary Income Statement Information for S-31
the Years Ended December 31, 1993, 1992 and 1991
<FN>
Schedules other than those listed above are omitted for the reason that they
are not required or are not applicable, or the required information is shown
in the financial statements or notes thereto.
S-1
124
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
- -------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $35,040 ($72) $0 $0 $34,968
Production:
Steam 1,401,660 53,173 (5,251) (44,745)(a) 1,404,837
Nuclear 5,648,748 35,382 (17,782) 0 5,666,348
Hydraulic 59,857 4,335 (1) 0 64,191
Other 14,750 33 (10) 0 14,773
Transmission 736,331 27,952 (1,625) 1,010 (a) 763,668
Distribution 1,330,851 73,245 (6,731) 0 1,397,365
General 221,763 4,062 (852) 1 224,974
------------ ------------ ------------ ------------ ------------
Total Utility Plant 9,449,000 198,110 (32,252) (43,734) 9,571,124
Perry Unit 2 (b) 826,674 (31,436) 0 (795,238)(c) 0
Construction Work in
Progress 167,139 26,082 (72) (12,218)(a) 180,931
Nuclear Fuel 1,038,327 45,823 0 0 1,084,150
Other Property 47,343 51 (18) 55,953 (a) 103,329
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $11,528,483 $238,630 ($32,342) ($795,237) $10,939,534
============ ============ ============ ============ ============
<FN>
(a) Transfer of Acme Plant Unit 2 to future use and nonutility property and reclassification
of future use property.
(b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
(c) Write-off of Perry Unit 2 investment.
S-2
125
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
-------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $34,774 $266 $0 $0 $35,040
Production:
Steam 1,413,761 45,619 (72,212) 14,492 (a) 1,401,660
Nuclear 5,227,393 78,403 (12,128) 355,080 (a) 5,648,748
Hydraulic 55,427 5,024 (594) 0 59,857
Other 14,750 0 0 0 14,750
Transmission 710,217 19,467 (1,051) 7,698 (a) 736,331
Distribution 1,233,176 99,503 (3,948) 2,120 (a) 1,330,851
General 198,721 24,809 (1,767) 0 221,763
------------ ------------ ------------ ------------ ------------
Total Utility Plant 8,888,219 273,091 (91,700) 379,390 9,449,000
Perry Unit 2 (b) 850,573 (23,899) 0 0 826,674
Construction Work in
Progress 215,855 (48,434) (282) 0 167,139
Nuclear Fuel 985,781 52,546 0 0 1,038,327
Other Property 64,763 (671) (16,749) 0 47,343
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $11,005,191 $252,633 ($108,731) $379,390 $11,528,483
============ ============ ============ ============ ============
<FN>
(a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a
pre-tax basis. Such amounts were previously stated on a net-of-tax basis.
(b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-3
126
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
-------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $22,035 $12,739 $0 $0 $34,774
Production:
Steam 1,338,332 80,909 (5,480) 0 1,413,761
Nuclear 5,123,492 105,296 (1,395) 0 5,227,393
Hydraulic 56,354 (557) (370) 0 55,427
Other 14,693 48 9 0 14,750
Transmission 694,181 16,667 (631) 0 710,217
Distribution 1,199,941 37,674 (4,439) 0 1,233,176
General 187,191 18,174 (6,644) 0 198,721
------------ ------------ ------------ ------------ ------------
Total Utility Plant 8,636,219 270,950 (18,950) 0 8,888,219
Perry Unit 2 (a) 865,149 (14,576) 0 0 850,573
Construction Work in
Progress 268,386 (52,531) 0 0 215,855
Nuclear Fuel 927,268 58,513 0 0 985,781
Other Property 63,524 1,254 (15) 0 64,763
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $10,760,546 $263,610 ($18,965) $0 $11,005,191
============ ============ ============ ============ ============
<FN>
(a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-4
127
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $2,466,961 $276,251 ($47,780)(a)(b) ($32,095) ($14,782) $2,648,555
- Amortization 21,476 7,337 0 0 0 28,813
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 2,488,437 283,588 (c) (47,780) (32,095) (14,782) 2,677,368
Other Property - Depreciation 8,166 1,480 (d) 52,875 (b) 0 0 62,521
------------ ------------ ------------ ------------ ------------ ------------
Total $2,496,603 $285,068 $5,095 ($32,095) ($14,782) $2,739,889
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $653,776 $85,732 (e) $0 $0 $0 $739,508
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged
to construction work in progress.
(b) Transfer of accumulated depreciation for Acme Plant Unit 2 and reclassification of accumulated depreciation
for future use property.
(c) Depreciation and amortization, as reported in the Income Statement, includes approximately $27 million of
amortization of investment tax credits.
(d) Nonutility plant expense charged to other income and deductions, net.
(e) Charged to fuel and purchased power expense.
S-5
128
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $2,260,186 $261,943 $52,593 (a) ($91,982) ($15,779) $2,466,961
- Amortization 14,303 7,173 0 0 0 21,476
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 2,274,489 269,116 (b) 52,593 (91,982) (15,779) 2,488,437
Other Property - Depreciation 20,250 2,049 (c) 0 (14,129) (4) 8,166
------------ ------------ ------------ ------------ ------------ ------------
Total $2,294,739 $271,165 $52,593 ($106,111) ($15,783) $2,496,603
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $527,367 $126,409 (d) $0 $0 $0 $653,776
============ ============ ============ ============ ============ ============
<FN>
(a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($48.1 million), nuclear plant
decommissioning trust earnings charged to the trust accounts, and depreciation charged to
construction work in progress.
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $13 million of
amortization of investment tax credits.
(c) Nonutility plant expense charged to other income and deductions, net.
(d) Charged to fuel and purchased power expense.
S-6
129
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $2,030,437 $248,231 $3,555 (a)(b) ($18,950) ($3,087) $2,260,186
- Amortization 8,073 5,679 551 (b) 0 0 14,303
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 2,038,510 253,910 (c) 4,106 (18,950) (3,087) 2,274,489
Other Property - Depreciation 18,072 2,178 (d) 0 0 0 20,250
------------ ------------ ------------ ------------ ------------ ------------
Total $2,056,582 $256,088 $4,106 ($18,950) ($3,087) $2,294,739
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $404,596 $122,771 (e) $0 $0 $0 $527,367
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation
charged to construction work in progress.
(b) Transfer from accumulated depreciation to accumulated amortization.
(c) Depreciation and amortization, as reported in the Income Statement, includes approximately $11 million of
amortization of investment tax credits.
(d) Nonutility plant expense charged to other income and deductions, net.
(e) Charged to fuel and purchased power expense.
S-7
130
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Principal Amount
Name of Issuer of Guaranteed and
Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee
- -------------------------------- ----------------------------- --------------- -------------------
Quarto Mining Company (b) Guaranteed Mortgage Bonds,
due 2000
Series A 8.25% $821 Principal and Interest
Series B 9.70% 801 Principal and Interest
Series C 9.40% 4,007 Principal and Interest
Series EA 10.25% 954 Principal and Interest
Series FA 10.50% 731 Principal and Interest
Series G 9.05% 12,098 Principal and Interest
Series HA 7.75% 9,308 Principal and Interest
Series HB 8.31% 5,395 Principal and Interest
Guaranteed Refunding Bonds,
Series I, 7.45%, due 1997 7,381 Principal and Interest
Unsecured Note, interest at prime
(6% effective 7/1/93 and
applicable through 12/31/93)
plus 2%, due 2000 2,849 Principal and Interest
Equipment Leases 8,557 Termination Value per
Agreements
--------
52,902
--------
The 0hio Valley Coal Company First Mortgage Notes,
Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest
Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest
Equipment Leases 4,129 Stipulated Loss Value
per Agreements
Term Notes,
9.53%, due 1994 to 1996 1,525 Principal and Interest
10.85%, due 1994 to 1997 13,952 Principal and Interest
--------
27,116
--------
$80,018
========
<FN>
(a) None of the securities were owned by the Operating Companies; none were held in the treasury of
the issuer; and none were in default.
(b) The Operating Companies and the other CAPCO Group Companies have agreed to guarantee severally,
and not jointly, their proportionate shares of Quarto Mining Company debt and lease
obligations incurred while developing and equipping the mines. The amounts shown are
the Operating Companies' proportionate share of the total obligations.
S-8
131
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Additions Deductions
---------------------------------------- ------------------------
Balance at Charged to Deductions Balance at
Beginning Income from End of
Description of Period Statement Other Reserves Other Period
- ----------- ---------- --------- ------- ---------- ------- --------
Reflected as Reductions
to the Related Assets:
Accumulated Provision
for Uncollectible Accounts
(Deduction from Amounts Due
from Customers and Others)
1993 $3,723 $14,139 (a) $3,516 (b) $17,675 (a)(c) $0 $3,703
1992 3,703 19,673 (a) 2,376 (b) 22,029 (a)(c) 0 3,723
1991 3,026 20,567 (a) 3,192 (b) 23,082 (a)(c) 0 3,703
Reserve for Perry Unit 2
Allowance for Funds Used
During Construction
(Deduction from Perry
Unit 2)
1993 $212,693 $0 $0 $212,693 (d) $0 $0
1992 212,693 0 0 0 0 212,693
1991 212,693 0 0 0 0 212,693
<FN>
(a) Includes a provision and corresponding write-off of uncollectible accounts
of $4,550,000, $5,968,000 and $6,020,000 in 1993, 1992 and 1991, respectively,
relating to customers which qualify for the PUCO mandated Percentage of Income
Payment Plan (PIPP). Such uncollectible accounts are recovered through a
separate approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and
deferral of PIPP uncollectibles in excess of the amount included in the last
base rate cases. The amounts deferred for future recovery were $971,000 and
$37,000 in 1993 and 1992, respectively.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-9
132
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Average
Weighted Daily Average
Average Maximum Weighted Daily
Balance Interest Amount Amount Weighted
at End Rate at Outstanding Outstanding Interest
of End of During the During the Rate During
Category Period Period Period Period the Period
-------- ------------ ------------ ------------- ------------ ------------
Commercial Paper
----------------
1993 $0 0.0% $36,900 $2,688 (a) 4.1% (b)
1992 0 0.0 101,800 16,823 (a) 4.5 (b)
1991 0 0.0 170,900 61,781 (a) 7.4 (b)
Uncommitted Financing Facility
------------------------------
1993 $0 0.0% $80,001 $19,710 (a) 3.8% (b)
1992 49,502 4.4 80,003 38,952 (a) 4.1 (b)
Not applicable for 1991.
<FN>
(a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992).
(b) Computed by dividing total interest expense for the year by the average daily balance outstanding.
S-10
133
CENTERIOR ENERGY CORPORATION AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item 1993 1992 1991
---- ------------ ------------ ------------
Maintenance and Repairs --
Charged to Operating Expenses $174,332 $184,183 $174,121
============ ============ ============
Taxes, Other Than Payroll and
Income Taxes:
Charged to Operating Expenses:
Real and Personal Property Taxes $170,346 $171,603 $163,123
Ohio State Excise Taxes 109,865 111,316 106,672
Other 9,371 11,452 11,883
------------ ------------ ------------
Total Charged to Operating
Expenses 289,582 294,371 281,678
Total Charged to Nonoperating Income 622 129 684
------------ ------------ ------------
Total $290,204 $294,500 $282,362
============ ============ ============
S-11
134
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
-------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $22,647 ($21) $0 $0 $22,626
Production:
Steam 1,121,056 50,631 (4,177) 0 1,167,510
Nuclear 3,737,103 19,314 (11,474) 0 3,744,943
Hydraulic 59,857 4,335 (1) 0 64,191
Other 8,075 0 0 0 8,075
Transmission 584,813 23,935 (1,038) 0 607,710
Distribution 923,022 52,425 (5,797) 0 969,650
General 145,223 4,983 (781) 0 149,425
------------ ------------ ------------ ------------ ------------
Total Utility Plant 6,601,796 155,602 (23,268) 0 6,734,130
Perry Unit 2 (a) 495,296 (20,361) 0 (474,935)(b) 0
Construction Work in
Progress 130,327 21,783 (72) (10,616)(c) 141,422
Nuclear Fuel 582,380 26,053 0 0 608,433
Other Property 43,260 50 (18) 10,616 (c) 53,908
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $7,853,059 $183,127 ($23,358) ($474,935) $7,537,893
============ ============ ============ ============ ============
<FN>
(a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
(b) Write-off of Perry Unit 2 investment.
(c) Reclassification of future use property.
S-12
135
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
-------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $22,462 $185 $0 $0 $22,647
Production:
Steam 1,104,815 38,830 (35,012) 12,423 (a) 1,121,056
Nuclear 3,461,108 51,556 (6,298) 230,737 (a) 3,737,103
Hydraulic 55,427 5,024 (594) 0 59,857
Other 8,075 0 0 0 8,075
Transmission 561,188 17,597 (1,028) 7,056 (a) 584,813
Distribution 857,392 66,747 (3,038) 1,921 (a) 923,022
General 125,478 20,512 (767) 0 145,223
------------ ------------ ------------ ------------ ------------
Total Utility Plant 6,195,945 200,451 (46,737) 252,137 6,601,796
Perry Unit 2 (b) 507,806 (12,510) 0 0 495,296
Construction Work in
Progress 161,890 (31,281) (282) 0 130,327
Nuclear Fuel 551,934 30,446 0 0 582,380
Other Property 60,667 (688) (16,719) 0 43,260
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $7,478,242 $186,418 ($63,738) $252,137 $7,853,059
------------ ------------ ------------ ------------ ------------
<FN>
(a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a
pre-tax basis. Such amounts were previously stated on a net-of-tax basis.
(b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-13
136
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
- -------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $18,499 $3,963 $0 $0 $22,462
Production:
Steam 1,046,921 63,374 (5,480) 0 1,104,815
Nuclear 3,405,230 56,601 (723) 0 3,461,108
Hydraulic 56,354 (557) (370) 0 55,427
Other 7,967 99 9 0 8,075
Transmission 547,300 14,518 (630) 0 561,188
Distribution 833,153 27,823 (3,584) 0 857,392
General 116,912 11,184 (2,618) 0 125,478
------------ ------------ ------------ ------------ ------------
Total Utility Plant 6,032,336 177,005 (13,396) 0 6,195,945
Perry Unit 2 (a) 521,464 (13,658) 0 0 507,806
Construction Work in
Progress 175,232 (13,342) 0 0 161,890
Nuclear Fuel 520,762 31,172 0 0 551,934
Other Property 60,221 461 (15) 0 60,667
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $7,310,015 $181,638 ($13,411) $0 $7,478,242
============ ============ ============ ============ ============
<FN>
(a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-14
137
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $1,711,620 $193,085 ($1,762)(a)(b) ($23,111) ($11,456) $1,868,376
- Amortization 16,496 4,712 0 0 0 21,208
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 1,728,116 197,797 (c) (1,762) (23,111) (11,456) 1,889,584
Other Property - Depreciation 6,694 1,409 (d) 4,764 (b) 0 0 12,867
------------ ------------ ------------ ------------ ------------ ------------
Total $1,734,810 $199,206 $3,002 ($23,111) ($11,456) $1,902,451
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $358,861 $47,372 (e) $0 $0 $0 $406,233
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged
to construction work in progress.
(b) Reclassification of accumulated depreciation for future use property.
(c) Depreciation and amortization, as reported in the Income Statement, includes approximately $17 million of
amortization of investment tax credits.
(d) Nonutility plant expense charged to other income and deductions, net.
(e) Charged to fuel and purchased power expense.
S-15
138
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $1,552,870 $182,706 $34,385 (a) ($47,019) ($11,322) $1,711,620
- Amortization 12,114 4,382 0 0 0 16,496
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 1,564,984 187,088 (b) 34,385 (47,019) (11,322) 1,728,116
Other Property - Depreciation 18,833 1,960 (c) 0 (14,099) 0 6,694
------------ ------------ ------------ ------------ ------------ ------------
Total $1,583,817 $189,048 $34,385 ($61,118) ($11,322) $1,734,810
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $288,805 $70,056 (d) $0 $0 $0 $358,861
============ ============ ============ ============ ============ ============
<FN>
(a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($31.5 million), nuclear plant
decommissioning trust earnings charged to the trust accounts, and depreciation charged to
construction work in progress.
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $8 million of
amortization of investment tax credits.
(c) Nonutility plant expense charged to other income and deductions, net.
(d) Charged to fuel and purchased power expense.
S-16
139
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Additions Deductions
---------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $1,391,080 $173,126 $1,794 (a)(b) ($13,396) $266 $1,552,870
- Amortization 7,178 4,385 551 (b) 0 0 12,114
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 1,398,258 177,511 (c) 2,345 (13,396) 266 1,564,984
Other Property - Depreciation 16,793 2,040 (d) 0 0 0 18,833
------------ ------------ ------------ ------------ ------------ ------------
Total $1,415,051 $179,551 $2,345 ($13,396) $266 $1,583,817
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $219,938 $68,867 (e) $0 $0 $0 $288,805
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation
charged to construction work in progress.
(b) Transfer from accumulated depreciation to accumulated amortization.
(c) Depreciation and amortization, as reported in the Income Statement, includes approximately $7 million of
amortization of investment tax credits.
(d) Nonutility plant expense charged to other income and deductions, net.
(e) Charged to fuel and purchased power expense.
S-17
140
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Principal Amount
Name of Issuer of Guaranteed and
Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee
- ------------------------------ ------------------------------- ---------------- -----------------------
Quarto Mining Company (b) Guaranteed Mortgage Bonds,
due 2000
Series A 8.25% $550 Principal and Interest
Series B 9.70% 537 Principal and Interest
Series C 9.40% 2,684 Principal and Interest
Series EA 10.25% 596 Principal and Interest
Series FA 10.50% 457 Principal and Interest
Series G 9.05% 7,448 Principal and Interest
Series HA 7.75% 5,730 Principal and Interest
Series HB 8.31% 3,321 Principal and Interest
Guaranteed Refunding Bonds,
Series I, 7.45%, due 1997 4,544 Principal and Interest
Unsecured Note, interest at prime
(6% effective 7/1/93 and
applicable through 12/31/93)
plus 2%, due 2000 1,781 Principal and Interest
Equipment Leases 5,732 Termination Value per
Agreements
--------
33,380
--------
The 0hio Valley Coal Company First Mortgage Notes,
Series D, 8.00%, due 1994 to 1997 5,200 Principal and Interest
Series E, 10.25%, due 1994 to 1997 2,310 Principal and Interest
Equipment Leases 4,129 Stipulated Loss Value
per Agreements
Term Notes,
9.53%, due 1994 to 1996 1,525 Principal and Interest
10.85%, due 1994 to 1997 13,952 Principal and Interest
--------
27,116
--------
$60,496
--------
<FN>
(a) None of the securities were owned by Cleveland Electric; none were held in the treasury of
the issuer; and none were in default.
(b) Cleveland Electric and the other CAPCO Group Companies have agreed to guarantee severally,
and not jointly, their proportionate shares of Quarto Mining Company debt and lease
obligations incurred while developing and equipping the mines. The amounts shown are
Cleveland Electric's proportionate share of the total obligations.
S-18
141
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Additions Deductions
---------------------------------------- ------------------------
Balance at Charged to Deductions Balance
Beginning Income from End of
Description of Period Statement Other Reserves Other Period
- ----------- ---------- --------- ------- ---------- ------- --------
Reflected as Reductions
to the Related Assets:
Accumulated Provision
for Uncollectible Accounts
(Deduction from Amounts Due
from Customers and Others)
1993 $2,333 $9,280 (a) $1,813 (b) $11,113 (a)(c) $0 $2,313
1992 2,313 16,359 (a) 1,309 (b) 17,648 (a)(c) 0 2,333
1991 1,826 15,669 (a) 1,686 (b) 16,868 (a)(c) 0 2,313
Reserve for Perry Unit 2
Allowance for Funds Used
During Construction
(Deduction from Perry
Unit 2)
1993 $124,398 $0 $0 $124,398 (d) $0 $0
1992 124,398 0 0 0 0 124,398
1991 124,398 0 0 0 0 124,398
<FN>
(a) Includes a provision and corresponding write-off of uncollectible accounts
of $2,447,000, $5,269,000 $5,616,000 in 1993, 1992 and 1991, respectively,
relating to customers which qualify for the PUCO mandated Percentage of
Income Payment Plan (PIPP). Such uncollectible accounts are recovered
through a separate PUCO approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and
deferral of PIPP uncollectibles in excess of the amount included in the last
base rate case. The amount deferred for future recovery was $507,000 in
1993.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-19
142
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Average
Weighted Daily Average
Average Maximum Weighted Daily
Balance Interest Amount Amount Weighted
at End Rate at Outstanding Outstanding Interest
of End of During the During the Rate During
Category Period Period Period Period the Period
- -------- ------ -------- ------------- ------------ -----------
Commercial Paper
- ----------------
1993 $0 0.0% $36,900 $2,688 (a) 4.1% (b)
1992 0 0.0 75,000 9,473 (a) 4.3 (b)
1991 0 0.0 133,100 45,825 (a) 7.5 (b)
Uncommitted Financing Facility
- ------------------------------
1993 $0 0.0% $40,001 $8,303 (a) 3.6% (b)
1992 10,000 4.3 40,001 17,180 (a) 4.1 (b)
Not applicable for 1991.
<FN>
(a) Computed by dividing the total of the daily outstanding balances for the
year by 365 days (366 for 1992).
(b) Computed by dividing total interest expense for the year by the average
daily balance outstanding.
S-20
143
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item 1993 1992 1991
- ---- ---------- ---------- ----------
Maintenance and Repairs --
Charged to Operating Expenses $114,915 $122,789 $115,816
========== ========== ==========
Taxes, Other Than Payroll and
Income Taxes:
Charged to Operating Expenses:
Real and Personal Property Taxes $122,405 $125,200 $119,613
Ohio State Excise Taxes 77,647 78,518 73,644
Other 9,608 10,560 11,366
---------- ---------- ----------
Total Charged to Operating
Expenses 209,660 214,278 204,623
Total Charged to Nonoperating Income 551 38 593
---------- ---------- ----------
Total $210,211 $214,316 $205,216
========== ========== ==========
S-21
144
THE TOLEDO EDISON COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
- -------------- ------------ --------- ------------ ------- -----------
Utility Plant (Electric):
Intangible $12,393 ($51) $0 $0 $12,342
Production:
Steam 280,604 2,542 (1,074) (44,745)(a) 237,327
Nuclear 1,911,645 16,068 (6,308) 0 1,921,405
Other 6,675 33 (10) 0 6,698
Transmission 151,518 4,017 (587) 1,010 (a) 155,958
Distribution 407,829 20,820 (934) 0 427,715
General 76,540 (921) (71) 0 75,548
------------ --------- ------------ -------- -----------
Total Utility Plant 2,847,204 42,508 (8,984) (43,735) 2,836,993
Perry Unit 2 (b) 331,378 (11,075) 0 (320,303)(c) 0
Construction Work in
Progress 36,812 4,299 0 (1,602)(a) 39,509
Nuclear Fuel 455,947 19,770 0 0 475,717
Other Property 4,083 1 0 45,337 (a) 49,421
------------ --------- ------------ -------- -----------
Total Property, Plant
and Equipment $3,675,424 $55,503 ($8,984) ($320,303) $3,401,640
============ ========= ============ ======== ===========
<FN>
(a) Transfer of Acme Plant Unit 2 to future use and nonutility property and
reclassification of future use property.
(b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
(c) Write-off of Perry Unit 2 investment.
S-22
145
THE TOLEDO EDISON COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
- -------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $12,312 $81 $0 $0 $12,393
Production:
Steam 308,946 6,789 (37,200) 2,069 (a) 280,604
Nuclear 1,766,285 26,847 (5,830) 124,343 (a) 1,911,645
Other 6,675 0 0 0 6,675
Transmission 149,029 1,870 (23) 642 (a) 151,518
Distribution 375,784 32,756 (910) 199 (a) 407,829
General 73,243 4,297 (1,000) 0 76,540
------------ ------------ ------------ ------------ ------------
Total Utility Plant 2,692,274 72,640 (44,963) 127,253 2,847,204
Perry Unit 2 (b) 342,767 (11,389) 0 0 331,378
Construction Work in
Progress 53,965 (17,153) 0 0 36,812
Nuclear Fuel 433,847 22,100 0 0 455,947
Other Property 4,096 17 (30) 0 4,083
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $3,526,949 $66,215 ($44,993) $127,253 $3,675,424
============ ============ ============ ============ ============
<FN>
(a) Results from adoption of SFAS 109 in 1992, which requires the presentation of amounts on a
pre-tax basis. Such amounts were previously stated on a net-of-tax basis.
(b) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-23
146
THE TOLEDO EDISON COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Balance at Retirements Balance at
Beginning of Additions or End of
Classification Period at Cost Sales Other Period
- -------------- ------------ ------------ ------------ ------------ ------------
Utility Plant (Electric):
Intangible $3,536 $8,776 $0 $0 $12,312
Production:
Steam 291,411 17,535 0 0 308,946
Nuclear 1,718,262 48,695 (672) 0 1,766,285
Other 6,726 (51) 0 0 6,675
Transmission 146,881 2,149 (1) 0 149,029
Distribution 366,788 9,851 (855) 0 375,784
General 70,279 6,990 (4,026) 0 73,243
------------ ------------ ------------ ------------ ------------
Total Utility Plant 2,603,883 93,945 (5,554) 0 2,692,274
Perry Unit 2 (a) 343,685 (918) 0 0 342,767
Construction Work in
Progress 93,154 (39,189) 0 0 53,965
Nuclear Fuel 406,506 27,341 0 0 433,847
Other Property 3,303 793 0 0 4,096
------------ ------------ ------------ ------------ ------------
Total Property, Plant and
Equipment $3,450,531 $81,972 ($5,554) $0 $3,526,949
============ ============ ============ ============ ============
<FN>
(a) Includes Perry Unit 2 AFUDC. See Schedule VIII.
S-24
147
THE TOLEDO EDISON COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND
EQUIPMENT
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Additions Deductions
------------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $755,341 $83,166 ($46,018)(a)(b) ($8,984) ($3,326) $780,179
- Amortization 4,980 2,625 0 0 0 7,605
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 760,321 85,791 (c) (46,018) (8,984) (3,326) 787,784
Other Property - Depreciation 1,472 72 (d) 48,111 (b) 0 0 49,655
------------ ------------ ------------ ------------ ------------ ------------
Total $761,793 $85,863 $2,093 ($8,984) ($3,326) $837,439
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $294,915 $38,360 (e) $0 $0 $0 $333,275
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation charged
to construction work in progress.
(b) Transfer of accumulated depreciation for Acme Plant Unit 2.
(c) Depreciation and amortization, as reported in the Income Statement, includes approximately $10 million of
amortization of investment tax credits.
(d) Nonutility plant expense charged to other income and deductions, net.
(e) Charged to fuel and purchased power expense.
S-25
148
THE TOLEDO EDISON COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
Additions Deductions
------------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $707,316 $79,237 $18,208 (a) ($44,963) ($4,457) $755,341
- Amortization 2,189 2,791 0 0 0 4,980
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 709,505 82,028 (b) 18,208 (44,963) (4,457) 760,321
Other Property - Depreciation 1,417 89 (c) 0 (30) (4) 1,472
------------ ------------ ------------ ------------ ------------ ------------
Total $710,922 $82,117 $18,208 ($44,993) ($4,461) $761,793
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $238,562 $56,353 (d) $0 $0 $0 $294,915
============ ============ ============ ============ ============ ============
<FN>
(a) Includes adjustment resulting from adoption of SFAS 109 in 1992 ($16.6 million), nuclear plant
decommissioning trust earnings charged to the trust accounts, and depreciation charged to
construction work in progress.
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $5 million of
amortization of investment tax credits.
(c) Nonutility plant expense charged to other income and deductions, net.
(d) Charged to fuel and purchased power expense.
S-26
149
THE TOLEDO EDISON COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR ENDED DECEMBER 31, 1991
(Thousands of Dollars)
Additions Deductions
------------------------------- ------------------------------
Balance at Charged to Removal Cost Balance at
Beginning of Income Net of Salvage End of
Description Period Statement Other Retirements Add/(Deduct) Period
- ----------- ------------ ------------ ------------ ------------ -------------- ------------
Utility Plant:
Electric - Depreciation $639,357 $75,105 $1,761 (a) ($5,554) ($3,353) $707,316
- Amortization 895 1,294 0 0 0 2,189
------------ ------------ ------------ ------------ ------------ ------------
Total Utility Plant 640,252 76,399 (b) 1,761 (5,554) (3,353) 709,505
Other Property - Depreciation 1,279 138 (c) 0 0 0 1,417
------------ ------------ ------------ ------------ ------------ ------------
Total $641,531 $76,537 $1,761 ($5,554) ($3,353) $710,922
============ ============ ============ ============ ============ ============
Nuclear Fuel - Amortization $184,658 $53,904 (d) $0 $0 $0 $238,562
============ ============ ============ ============ ============ ============
<FN>
(a) Includes nuclear plant decommissioning trust earnings charged to the trust accounts and depreciation
charged to construction work in progress.
(b) Depreciation and amortization, as reported in the Income Statement, includes approximately $4 million of
amortization of investment tax credits.
(c) Nonutility plant expense charged to other income and deductions, net.
(d) Charged to fuel and purchased power expense.
S-27
150
THE TOLEDO EDISON COMPANY
SCHEDULE VII - GUARANTEES OF SECURITIES OF OTHER ISSUERS
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
Principal Amount
Name of Issuer of Guaranteed and
Securities Guaranteed Title of Issue (a) Outstanding (a) Nature of Guarantee
- -------------------------------- ----------------------------------- --------------- --------------------
Quarto Mining Company (b) Guaranteed Mortgage Bonds,
due 2000
Series A 8.25% $271 Principal and Interest
Series B 9.70% 264 Principal and Interest
Series C 9.40% 1,323 Principal and Interest
Series EA 10.25% 358 Principal and Interest
Series FA 10.50% 274 Principal and Interest
Series G 9.05% 4,650 Principal and Interest
Series HA 7.75% 3,578 Principal and Interest
Series HB 8.31% 2,074 Principal and Interest
Guaranteed Refunding Bonds,
Series I, 7.45%, due 1997 2,837 Principal and Interest
Unsecured Note, interest at
prime (6% effective
7/1/93 and applicable
through 12/31/93) plus 2%,
due 2000 1,068 Principal and Interest
Equipment Leases 2,825 Termination Value per
Agreements
--------
$19,522
========
<FN>
(a) None of the securities were owned by Toledo Edison; none were held in the treasury of
the issuer; and none were in default.
(b) Toledo Edison and the other CAPCO Group Companies have agreed to guarantee severally,
and not jointly, their proportionate shares of Quarto Mining Company debt and lease
obligations incurred while developing and equipping the mines. The amounts shown are
Toledo Edison's proportionate share of the total obligations.
S-28
151
THE TOLEDO EDISON COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Additions Deductions
---------------------------- ----------------------------
Balance at Charged to Deductions Balance at
Beginning Income from End of
Description of Period Statement Other Reserves Other Period
----------- ------------ ------------ ------------ ------------ --------- ------------
Reflected as Reductions
to the Related Assets:
Accumulated Provision
for Uncollectible Accounts
(Deduction from Amounts Due
from Customers and Others)
1993 $1,390 $4,859 (a) $1,703 (b) $6,562 (a)(c) $0 $1,390
1992 1,390 3,314 (a) 1,067 (b) 4,381 (a)(c) 0 1,390
1991 1,200 4,898 (a) 1,506 (b) 6,214 (a)(c) 0 1,390
Reserve for Perry Unit 2
Allowance for Funds Used
During Construction
(Deduction from Perry
Unit 2)
1993 $88,295 $0 $0 $88,295 (d) $0 $0
1992 88,295 0 0 0 0 88,295
1991 88,295 0 0 0 0 88,295
<FN>
(a) Includes a provision and corresponding write-off of uncollectible accounts of $2,103,000, $699,000 and
$404,000 in 1993, 1992 and 1991, respectively, relating to customers which qualify for the PUCO mandated
Percentage of Income Payment Plan (PIPP). Such uncollectible accounts are recovered through a separate PUCO
approved surcharge tariff.
(b) Includes amounts for collection of accounts previously written off and deferral of PIPP uncollectibles in
excess of the amount included in the last base rate case. The amounts deferred for future recovery were
$464,000 and $37,000 in 1993 and 1992, respectively.
(c) Uncollectible accounts written off.
(d) Write-off of Perry Unit 2 investment.
S-29
152
THE TOLEDO EDISON COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Average
Weighted Daily Average
Average Maximum Weighted Daily
Balance Interest Amount Amount Weighted
at End Rate at Outstanding Outstanding Interest
of End of During the During the Rate During
Category Period Period Period Period the Period
- -------- ------------ ------------ ------------ ------------ ------------
Commercial Paper
- ----------------
1993 $0 0.0% $0 $0 (a) 0.0%(b)
1992 0 0.0 31,000 7,350 (a) 4.7 (b)
1991 0 0.0 45,000 15,956 (a) 7.1 (b)
Uncommitted Financing Facility
- ------------------------------
1993 $0 0.0% $40,001 $11,407 (a) 3.9%(b)
1992 39,502 4.4 40,003 21,772 (a) 4.0 (b)
Not applicable for 1991.
<FN>
(a) Computed by dividing the total of the daily outstanding balances for the year by 365 days (366 for 1992).
(b) Computed by dividing total interest expense for the year by the average daily balance outstanding.
S-30
153
THE TOLEDO EDISON COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands of Dollars)
Item 1993 1992 1991
- ---- ------------ ------------ ------------
Maintenance and Repairs --
Charged to Operating Expenses $59,417 $61,394 $58,305
============ ============ ============
Taxes, Other Than Payroll and
Income Taxes:
Charged to Operating Expenses:
Real and Personal Property Taxes $47,941 $46,403 $43,510
Ohio State Excise Taxes 32,218 32,798 33,028
Other 3,568 5,014 4,217
------------ ------------ ------------
Total Charged to Operating
Expenses 83,727 84,215 80,755
Total Charged to Nonoperating Income 71 91 91
------------ ------------ ------------
Total $83,798 $84,306 $80,846
============ ============ ============
S-31
154
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
AND THE TOLEDO EDISON COMPANY
COMBINED PRO FORMA CONDENSED FINANCIAL STATEMENTS
The following pro forma condensed balance sheets and income statements
give effect to the agreement between Cleveland Electric and Toledo Edison to
merge Toledo Edison into Cleveland Electric. These statements are unaudited
and based on accounting for the merger on a method similar to a pooling of
interests. These statements combine the two companies' historical balance
sheets at December 31, 1993 and December 31, 1992 and their historical income
statements for each of the three years ended December 31, 1993.
The following pro forma data is not necessarily indicative of the
results of operations or the financial condition which would have been reported
had the merger been in effect during those periods or which may be reported in
the future. The statements should be read in conjunction with the accompanying
notes and with the audited financial statements of both Cleveland Electric and
Toledo Edison.
COMBINED PRO FORMA CONDENSED BALANCE SHEETS
OF CLEVELAND ELECTRIC AND TOLEDO EDISON
(Unaudited)
(Millions of Dollars)
At December 31, 1993
------------------------------------------------------
Historical
-----------------------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
------ ------- -------- -------
Assets
Property, Plant and Equipment $7,538 $3,402 $ - $10,940
Less: Accumulated Depreciation
and Amortization 2,309 1,171 - 3,480
------ ------ -------- -------
Net Property, Plant and
Equipment 5,229 2,231 - 7,460
Current Assets 632 314 (20)(A) 926
Deferred Charges and
Other Assets 1,298 965 (9)(B) 2,254
------ ------ -------- -------
Total Assets $7,159 $3,510 $(29) $10,640
====== ====== ======== =======
P-1
155
At December 31, 1993
-----------------------------------------------------
Historical
----------------------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
--------- ------ -------- -------
Capitalization and Liabilities
Capitalization:
Common Stock Equity $1,040 $ 623 $ (1)(R) $ 1,662
Preferred Stock:
With Mandatory Redemption
Provisions 285 28 - 313
Without Mandatory Redemption
Provisions 241 210 - 451
Long-Term Debt 2,793 1,225 1(R) 4,019
------ ------ -------- -------
Total Capitalization 4,359 2,086 - 6,445
Other Noncurrent Liabilities 247 186 - 433
Current Liabilities 733 329 (21)(A) 1,041
Deferred Credits 1,820 909 (8)(A,B) 2,721
------ ------ -------- -------
Total Capitalization and
Liabilities $7,159 $3,510 $(29) $10,640
====== ====== ======== =======
At December 31, 1992
------------------------------------------------------
Historical
---------------------------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
------ ------ -------- -------
Assets
Property, Plant and Equipment $7,729 $3,587 $ - $11,316
Less: Accumulated Depreciation
and Amortization 2,093 1,056 1(R) 3,150
------ ------ -------- -------
Net Property, Plant and
Equipment 5,636 2,531 (1) 8,166
Current Assets 607 258 (33)(A,R) 832
Deferred Charges and
Other Assets 1,880 1,150 (17)(A,B) 3,013
------ ------ -------- -------
Total Assets $8,123 $3,939 $(51) $12,011
====== ====== ======== =======
Capitalization and Liabilities
Capitalization:
Common Stock Equity $1,865 $ 935 $ (1)(R) $ 2,799
Preferred Stock:
With Mandatory Redemption
Provisions 314 50 - 364
Without Mandatory Redemption
Provisions 144 210 - 354
Long-Term Debt 2,515 1,178 1(R) 3,694
------ ------ -------- -------
Total Capitalization 4,838 2,373 - 7,211
Other Noncurrent Liabilities 234 188 - 422
Current Liabilities 924 332 (32)(A) 1,224
Deferred Credits 2,127 1,046 (19)(B) 3,154
------ ------ -------- -------
Total Capitalization and
Liabilities $8,123 $3,939 $(51) $12,011
====== ====== ======== =======
P-2
156
COMBINED PRO FORMA CONDENSED INCOME STATEMENTS
OF CLEVELAND ELECTRIC AND TOLEDO EDISON
(Unaudited)
(Millions of Dollars)
Year Ended December 31, 1993
----------------------------
Historical
----------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
Operating Revenues $1,751 $ 871 $(147)(C) $2,475
Operating Expenses 1,529 782 (148)(C,D) 2,163
------ ----- ------ ------
Operating Income 222 89 1 312
Nonoperating (Loss) (569) (263) (1)(D) (833)
------ ----- ------ ------
(Loss) Before Interest Charges (347) (174) - (521)
Interest Charges 240 115 - 355
------ ----- ------ ------
Net (Loss) (587) (289) - (876)
Preferred Dividend Requirements 45 23 - 68
------ ----- ------ ------
(Loss) Available for Common
Stock $ (632) $(312) $ - $ (944)
====== ===== ===== ======
Year Ended December 31, 1992
----------------------------
Historical
----------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
-------- ------ ----- ------
Operating Revenues $1,743 $ 845 $(149)(C) $2,439
Operating Expenses 1,358 695 (150)(C,D) 1,903
------ ------ ------ ------
Operating Income 385 150 1 536
Nonoperating Income 63 42 (1)(D) 104
------ ------ ------ ------
Income Before Interest Charges 448 192 - 640
Interest Charges 243 121 - 364
------ ------ ------ ------
Net Income 205 71 - 276
Preferred Dividend Requirements 41 24 - 65
------ ------ ------ ------
Earnings Available for Common
Stock $ 164 $ 47 $ - $ 211
====== ===== ===== ======
Year Ended December 31, 1991
----------------------------
Historical
----------
Cleveland Toledo Adjust- Pro Forma
Electric Edison ments Totals
-------- ------ ----- ------
Operating Revenues $1,826 $ 887 $(152)(C) $2,561
Operating Expenses 1,411 728 (153)(C,D) 1,986
------ ------ ------ ------
Operating Income 415 159 1 575
Nonoperating Income 78 22 (2)(D,E) 98
------ ------ ------ ------
Income Before Interest Charges 493 181 (1) 673
Interest Charges 247 131 (1)(E) 377
------ ------ ------ ------
Net Income 246 50 - 296
Preferred Dividend Requirements 36 25 - 61
------ ------ ------ ------
Earnings Available for Common
Stock $ 210 $ 25 $ - $ 235
====== ===== ===== ======
P-3
157
NOTES TO COMBINED PRO FORMA CONDENSED BALANCE SHEETS AND INCOME
STATEMENTS (Unaudited)
The Pro Forma Financial Statements include the following adjustments:
(A) Elimination of intercompany accounts and notes receivable and accounts and
notes
payable.
(B) Reclassification of prepaid pension costs or pension liabilities.
(C) Elimination of intercompany operating revenues and operating expenses.
(D) Elimination of intercompany working capital transactions.
(E) Elimination of intercompany interest income and interest expense.
(R) Rounding adjustments.
P-4
158
EXHIBIT INDEX
The exhibits designated with an asterisk (*) are filed herewith. The exhibits
not so designated have previously been filed with the SEC in the file indi-
cated in parenthesis following the description of such exhibits and are in-
corporated herein by reference. An exhibit designated with a pound sign (#)
is a management contract or compensatory plan or arrangement.
COMMON EXHIBITS
(The following documents are exhibits to the reports of Centerior Energy,
Cleveland Electric and Toledo Edison.)
Exhibit Number Document
10b(1)(a) CAPCO Administration Agreement dated November 1, 1971, as
of September 14, 1967, among the CAPCO Group members re-
garding the organization and procedures for implementing
the objectives of the CAPCO Group (Exhibit 5(p), Amendment
No. 1, File No. 2-42230, filed by Cleveland Electric).
10b(1)(b) Amendment No. 1, dated January 4, 1974, to CAPCO Adminis-
tration Agreement among the CAPCO Group members (Exhibit
5(c)(3), File No. 2-68906, filed by Ohio Edison).
10b(2) CAPCO Transmission Facilities Agreement dated November 1,
1971, as of September 14, 1967, among the CAPCO Group
members regarding the installation, operation and mainte-
nance of transmission facilities to carry out the objec-
tives of the CAPCO Group (Exhibit 5(q), Amendment No. 1,
File No. 2-42230, filed by Cleveland Electric).
10b(2)(1) *Amendment No. 1 to CAPCO Transmission Facilities Agree-
ment, dated December 23, 1993 and effective as of
January 1, 1993, among the CAPCO Group members regarding
requirements for payment of invoices at specified times,
for payment of interest on non-timely paid invoices, for
restricting adjustment of invoices after a four-year
period, and for revising the method for computing the
Investment Responsibility charge for use of a member's
transmission facilities.
10b(3) *CAPCO Basic Operating Agreement As Amended January 1, 1993
among the CAPCO Group members regarding coordinated
operation of the members' systems.
10b(4) *Agreement for the Termination or Construction of Certain
Agreements By and Among the CAPCO Group members, dated
December 23, 1993 and effective as of September 1, 1980.
10b(5) Construction Agreement, dated July 22, 1974, among the
CAPCO Group members and relating to the Perry Nuclear
Plant (Exhibit 5(yy), File No. 2-52251, filed by Toledo
Edison).
10b(6) Contract, dated as of December 5, 1975, among the CAPCO
Group members for the construction of Beaver Valley Unit
No. 2 (Exhibit 5(g), File No. 2-52996, filed by Cleveland
Electric).
E-1
159
Exhibit Number Document
10b(7) Amendment No. 1, dated May 1, 1977, to Contract, dated as
of December 5, 1975, among the CAPCO Group members for the
construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4),
File No. 2-60109, filed by Ohio Edison).
10d(1)(a) Form of Collateral Trust Indenture among CTC Beaver Valley
Funding Corporation, Cleveland Electric, Toledo Edison and
Irving Trust Company, as Trustee (Exhibit 4(a), File No.
33-18755, filed by Cleveland Electric and Toledo Edison).
10d(1)(b) Form of Supplemental Indenture to Collateral Trust In-
denture constituting Exhibit 10d(1)(a) above, including
form of Secured Lease Obligation Bond (Exhibit 4(b), File
No. 33-18755, filed by Cleveland Electric and Toledo
Edison).
10d(1)(c) Form of Collateral Trust Indenture among Beaver Valley II
Funding Corporation, The Cleveland Electric Illuminating
Company and The Toledo Edison Company and The Bank of New
York, as Trustee (Exhibit (4)(a), File No. 33-46665, filed
by Cleveland Electric and Toledo Edison).
10d(1)(d) Form of Supplemental Indenture to Collateral Trust
Indenture constituting Exhibit 10d(1)(c) above, including
form of Secured Lease Obligation Bond (Exhibit (4)(b),
File No. 33-46665, filed by Cleveland Electric and Toledo
Edison).
10d(2)(a) Form of Collateral Trust Indenture among CTC Mansfield
Funding Corporation, Cleveland Electric, Toledo Edison and
IBJ Schroder Bank & Trust Company, as Trustee (Exhibit
4(a), File No. 33-20128, filed by Cleveland Electric and
Toledo Edison).
10d(2)(b) Form of Supplemental Indenture to Collateral Trust In-
denture constituting Exhibit 10d(2)(a) above, including
forms of Secured Lease Obligation Bonds (Exhibit 4(b),
File No. 33-20128, filed by Cleveland Electric and Toledo
Edison).
10d(3)(a) Form of Facility Lease dated as of September 15, 1987 be-
tween The First National Bank of Boston, as Owner Trustee
under a Trust Agreement dated as of September 15, 1987
with the limited partnership Owner Participant named
therein, Lessor, and Cleveland Electric and Toledo Edison,
Lessees (Exhibit 4(c), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
10d(3)(b) Form of Amendment No. 1 to Facility Lease constituting
Exhibit 10d(3)(a) above (Exhibit 4(e), File No. 33-18755,
filed by Cleveland Electric and Toledo Edison).
10d(4)(a) Form of Facility Lease dated as of September 15, 1987
between The First National Bank of Boston, as Owner
Trustee under a Trust Agreement dated as of September 15,
1987 with the corporate Owner Participant named therein,
Lessor, and Cleveland Electric and Toledo Edison, Lessees
(Exhibit 4(d), File No. 33-18755, filed by Cleveland
Electric and Toledo Edison).
10d(4)(b) Form of Amendment No. 1 to Facility Lease constituting
Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755,
filed by Cleveland Electric and Toledo Edison).
E-2
160
Exhibit Number Document
10d(5)(a) Form of Facility Lease dated as of September 30, 1987 be-
tween Meridian Trust Company, as Owner Trustee under a
Trust Agreement dated as of September 30, 1987 with the
Owner Participant named therein, Lessor, and Cleveland
Electric and Toledo Edison, Lessees (Exhibit 4(c), File
No. 33-20128, filed by Cleveland Electric and Toledo
Edison).
10d(5)(b) Form of Amendment No. 1 to the Facility Lease constituting
Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128,
filed by Cleveland Electric and Toledo Edison).
10d(6)(a) Form of Participation Agreement dated as of September 15,
1987 among the limited partnership Owner Participant named
therein, the Original Loan Participants listed in Schedule
1 thereto, as Original Loan Participants, CTC Beaver
Valley Funding Corporation, as Funding Corporation, The
First National Bank of Boston, as Owner Trustee, Irving
Trust Company, as Indenture Trustee, and Cleveland
Electric and Toledo Edison, as Lessees (Exhibit 28(a),
File No. 33-18755, filed by Cleveland Electric and Toledo
Edison).
10d(6)(b) Form of Amendment No. 1 to Participation Agreement consti-
tuting Exhibit 10d(6)(a) above (Exhibit 28(c), File No.
33-18755, filed by Cleveland Electric and Toledo Edison).
10d(7)(a) Form of Participation Agreement dated as of September 15,
1987 among the corporate Owner Participant named therein,
the Original Loan Participants listed in Schedule 1
thereto, as Original Loan Participants, CTC Beaver Valley
Funding Corporation, as Funding Corporation, The First
National Bank of Boston, as Owner Trustee, Irving Trust
Company, as Indenture Trustee, and Cleveland Electric and
Toledo Edison, as Lessees (Exhibit 28(b), File No.
33-18755, filed by Cleveland Electric and Toledo Edison).
10d(7)(b) Form of Amendment No. 1 to Participation Agreement consti-
tuting Exhibit 10d(7)(a) above (Exhibit 28(d), File No.
33-18755, filed by Cleveland Electric and Toledo Edison).
10d(8)(a) Form of Participation Agreement dated as of September 30,
1987 among the Owner Participant named therein, the Origi-
nal Loan Participants listed in Schedule II thereto, as
Original Loan Participants, CTC Mansfield Funding Corpora-
tion, Meridian Trust Company, as Owner Trustee, IBJ
Schroder Bank & Trust Company, as Indenture Trustee, and
Cleveland Electric and Toledo Edison, as Lessees (Exhibit
28(a), File No. 33-20128, filed by Cleveland Electric and
Toledo Edison).
10d(8)(b) Form of Amendment No. 1 to the Participation Agreement
constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File
No. 33-20128, filed by Cleveland Electric and Toledo
Edison).
E-3
161
Exhibit Number Document
10d(9) Form of Ground Lease dated as of September 15, 1987 be-
tween Toledo Edison, Ground Lessor, and The First National
Bank of Boston, as Owner Trustee under a Trust Agreement
dated as of September 15, 1987 with the Owner Participant
named therein, Tenant (Exhibit 28(e), File No. 33-18755,
filed by Cleveland Electric and Toledo Edison).
10d(10) Form of Site Lease dated as of September 30, 1987 between
Toledo Edison, Lessor, and Meridian Trust Company, as
Owner Trustee under a Trust Agreement dated as of
September 30, 1987 with the Owner Participant named
therein, Tenant (Exhibit 28(c), File No. 33-20128, filed
by Cleveland Electric and Toledo Edison).
10d(11) Form of Site Lease dated as of September 30, 1987 between
Cleveland Electric, Lessor, and Meridian Trust Company, as
Owner Trustee under a Trust Agreement dated as of
September 30, 1987 with the Owner Participant named
therein, Tenant (Exhibit 28(d), File No. 33-20128, filed
by Cleveland Electric and Toledo Edison).
10d(12) Form of Amendment No. 1 to the Site Leases constituting
Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No.
33-20128, filed by Cleveland Electric and Toledo Edison).
10d(13) Form of Assignment, Assumption and Further Agreement dated
as of September 15, 1987 among The First National Bank of
Boston, as Owner Trustee under a Trust Agreement dated as
of September 15, 1987 with the Owner Participant named
therein, Cleveland Electric, Duquesne, Ohio Edison,
Pennsylvania Power and Toledo Edison (Exhibit 28(f), File
No. 33-18755, filed by Cleveland Electric and Toledo
Edison).
10d(14) Form of Additional Support Agreement dated as of
September 15, 1987 between The First National Bank of
Boston, as Owner Trustee under a Trust Agreement dated as
of September 15, 1987 with the Owner Participant named
therein, and Toledo Edison (Exhibit 28(g), File No.
33-18755, filed by Cleveland Electric and Toledo Edison).
10d(15) Form of Support Agreement dated as of September 30, 1987
between Meridian Trust Company, as Owner Trustee under a
Trust Agreement dated as of September 30, 1987 with the
Owner Participant named there, Toledo Edison, Cleveland
Electric, Duquesne, Ohio Edison and Pennsylvania Power
(Exhibit 28(e), File No. 33-20128, filed by Cleveland
Electric and Toledo Edison).
10d(16) Form of Indenture, Bill of Sale, Instrument of Transfer
and Severance Agreement dated as of September 30, 1987
between Toledo Edison, Seller, and The First National Bank
of Boston, as Owner Trustee under a Trust Agreement dated
as of September 15, 1987 with the Owner Participant named
therein, Buyer (Exhibit 28(h), File No. 33-18755, filed by
Cleveland Electric and Toledo Edison).
E-4
162
Exhibit Number Document
10d(17) Form of Bill of Sale, Instrument of Transfer and Severance
Agreement dated as of September 30, 1987 between Toledo
Edison, Seller, and Meridian Trust Company, as Owner
Trustee under a Trust Agreement dated as of September 30,
1987 with the Owner Participant named therein, Buyer
(Exhibit 28(f), File No. 33-20128, filed by Cleveland
Electric and Toledo Edison).
10d(18) Form of Bill of Sale, Instrument of Transfer and Severance
Agreement dated as of September 30, 1987 between Cleveland
Electric, Seller, and Meridian Trust Company, as Owner
Trustee under a Trust Agreement dated as of September 30,
1987 with the Owner Participant named therein, Buyer
(Exhibit 28(g), File No. 33-20128, filed by Cleveland
Electric and Toledo Edison).
10d(19) Forms of Refinancing Agreement, including exhibits
thereto, among the Owner Participant named therein, as
Owner Participant, CTC Beaver Valley Funding Corporation,
as Funding Corporation, Beaver Valley II Funding
Corporation, as New Funding Corporation, The Bank of New
York, as Indenture Trustee, The Bank of New York, as
Collateral Trust Trustee, The Bank of New York, as New
Collateral Trust Trustee, and The Cleveland Electric
Illuminating Company and The Toledo Edison Company, as
Lessees (Exhibit (28)(e)(i), File No. 33-46665, filed by
Cleveland Electric and Toledo Edison).
10e(1) *#Employment agreement, dated May 25, 1993, between
Centerior Service Company and Donald C. Shelton effective
June 4, 1993 and extending until June 30, 1995.
10e(2) *#Employment agreement, dated February 2, 1994 and accepted
on February 8, 1994, between Centerior Energy and Al R.
Temple effective through December 1996.
18a Letter regarding change in accounting principles (Exhibit
18, June 30, 1991 Form 10-Q, File Nos. 1-9130, 1-2323 and
1-3583).
99a Financial Statements of the Centerior Energy Corporation
Employee Savings Plan for the fiscal year ended
December 31, 1993 (to be filed by amendment).
E-5
163
CENTERIOR ENERGY EXHIBITS
Exhibit Number Document
3a Amended Articles of Incorporation of Centerior Energy ef-
fective April 29, 1986 (Exhibit 4(a), File No. 33-4790).
3b Regulations of Centerior Energy effective April 28, 1987
(Exhibit 3b, 1987 Form 10-K, File No. 1-9130).
10a *Indemnity Agreements between Centerior and certain of its
current directors and officers.
10e #Employment and Consulting Agreement, dated November 30,
1989, with P. M. Smart regarding his employment with
Toledo Edison through August 31, 1990 and his providing
consulting services to Centerior and Toledo Edison for the
period September 1, 1990 through January 31, 1994 (Exhibit
10e(2), 1989 Form 10-K, File No. 1-9130).
21 List of subsidiaries (Exhibit 22, 1986 Form 10-K, File No.
1-9130).
23a *Consent of Independent Accountants.
23b *Consent of Counsel for Centerior Energy.
24a Power of Attorney of Centerior Energy and certified
resolution of Centerior Energy's Board of Directors
authorizing the signing on behalf of Centerior pursuant to
a power of attorney (Exhibit 25(a), March 31, 1993 Form
10-Q, File No. 1-9130).
24b *Powers of Attorney of Centerior Energy directors and
officers required to sign the Report.
CLEVELAND ELECTRIC EXHIBITS
Exhibit Number Document
3a *Amended Articles of Incorporation of Cleveland Electric,
as amended, effective May 28, 1993.
3b Regulations of Cleveland Electric, dated April 29, 1981,
as amended effective October 1, 1988 and April 24, 1990
(Exhibit 3b, 1990 Form 10-K, File No. 1-2323).
4b(1) Mortgage and Deed of Trust between Cleveland Electric and
Guaranty Trust Company of New York (now Morgan Guaranty
Trust Company of New York), as Trustee, dated July 1, 1940
(Exhibit 7(a), File No. 2-4450).
Supplemental Indentures between Cleveland Electric and the
Trustee, supplemental to Exhibit 4b(1), dated as follows:
E-6
164
Exhibit Number Document
4b(2) July 1, 1940 (Exhibit 7(b), File No. 2-4450).
4b(3) August 18, 1944 (Exhibit 4(c), File No. 2-9887).
4b(4) December 1, 1947 (Exhibit 7(d), File No. 2-7306).
4b(5) September 1, 1950 (Exhibit 7(c), File No. 2-8587).
4b(6) June 1, 1951 (Exhibit 7(f), File No. 2-8994).
4b(7) May 1, 1954 (Exhibit 4(d), File No. 2-10830).
4b(8) March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839).
4b(9) April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753).
4b(10) December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759).
4b(11) January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759).
4b(12) November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008).
4b(13) June 1, 1970 (Exhibit 2(a)(4), File No. 2-37235).
4b(14) November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460).
4b(15) May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537).
4b(16) April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995).
4b(17) April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309).
4b(18) May 28, 1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File
No. 1-2323).
4b(19) February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10-K, File
No. 1-2323).
4b(20) November 23, 1976 (Exhibit 2(a)(4), File No. 2-57375).
4b(21) July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401).
4b(22) September 27, 1977 (Exhibit 2(a)(5), File No. 2-67221).
4b(23) May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File
No. 1-2323).
4b(24) September 1, 1979 (Exhibit 2(a), September 30, 1979 Form
10-Q, File No. 1-2323).
4b(25) April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form
10-Q, File No. 1-2323).
4b(26) April 15, 1980 (Exhibit 4(b), September 30, 1980 Form
10-Q, File No. 1-2323).
4b(27) May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No.
2-67221).
4b(28) June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q,
File No. 1-2323).
4b(29) December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File
No. 1-2323).
4b(30) July 28, 1981 (Exhibit 4(a), September 30, 1981, Form
10-Q, File No. 1-2323).
4b(31) August 1, 1981 (Exhibit 4(b), September 30, 1981, Form
10-Q, File No. 1-2323).
4b(32) March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No.
2-76029).
4b(33) July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q,
File No. 1-2323).
4b(34) September 1, 1982 (Exhibit 4(a)(1), September 30, 1982
Form 10-Q, File No. 1-2323).
4b(35) November 1, 1982 (Exhibit 4(a)(2), September 30, 1982 Form
10-Q, File No. 1-2323).
4b(36) November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File
No. 1-2323).
E-7
165
Exhibit Number Document
4b(37) May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File
No. 1-2323).
4b(38) May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q, File No.
1-2323).
4b(39) May 23, 1984 (Exhibit 4, May 22, 1984 Form 8-K, File No.
1-2323).
4b(40) June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No.
1-2323).
4b(41) September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File
No. 1-2323).
4b(42) November 14, 1984 (Exhibit 4b(42), 1984 Form 10-K, File
No. 1-2323).
4b(43) November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File
No. 1-2323).
4b(44) April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File
No. 1-2323).
4b(45) May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No.
1-2323).
4b(46) August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q,
File No. 1-2323).
4b(47) September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K,
File No. 1-2323).
4b(48) November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K,
File No. 1-2323).
4b(49) April 15, 1986 (Exhibit 4, March 31, 1986 Form 10-Q, File
No. 1-2323).
4b(50) May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File
No. 1-2323).
4b(51) May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File
No. 1-2323).
4b(52) February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File
No. 1-2323).
4b(53) October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q,
File No. 1-2323).
4b(54) February 24, 1988 (Exhibit 4b(54), 1987 Form 10-K, File
No. 1-2323).
4b(55) September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K, File
No. 1-2323).
4b(56) May 15, 1989 (Exhibit 4(a)(2)(i), File No. 33-32724).
4b(57) June 13, 1989 (Exhibit 4(a)(2)(ii), File No. 33-32724).
4b(58) October 15, 1989 (Exhibit 4(a)(2)(iii), File No.
33-32724).
4b(59) January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No.
1-2323).
4b(60) June 1, 1990 (Exhibit 4(a), September 30, 1990 Form 10-Q,
File No. 1-2323).
4b(61) August 1, 1990 (Exhibit 4(b), September 30, 1990 Form
10-Q, File No. 1-2323).
4b(62) May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File
No. 1-2323).
E-8
166
Exhibit Number Document
4b(63) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845).
4b(64) July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292).
4b(65) January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No.
1-2323).
4b(66) February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No.
1-2323).
4b(67) May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File
No. 1-2323).
4b(68) June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File
No. 1-2323).
10a Indemnity Agreements between Cleveland Electric and cer-
tain of its current directors (Exhibit 10a, 1988 Form
10-K, File No. 1-2323).
10a(1) #1978 Key Employee Stock Option Plan (Exhibit 1, File No.
2-61712).
21 List of subsidiaries (Exhibit 22, 1991 Form 10-K, File No.
1-2323).
24a Power of Attorney of Cleveland Electric and certified
resolution of Cleveland Electric's Board of Directors
authorizing the signing on behalf of Cleveland Electric
pursuant to a power of attorney (Exhibit 25(b), March 31,
1993 Form 10-Q, File No. 1-2323).
24b *Powers of Attorney of Cleveland Electric directors and
officers required to sign the Report.
TOLEDO EDISON EXHIBITS
Exhibit Number Document
3a Amended Articles of Incorporation of Toledo Edison, as
amended effective October 2, 1992 (Exhibit 3a, 1992 Form
10-K, File No. 1-3583).
3b Code of Regulations of Toledo Edison dated January 28,
1987, as amended effective July 1 and October 1, 1988 and
April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No.
1-3583).
4b(1) Indenture, dated as of April 1, 1947, between the Company
and The Chase National Bank of the City of New York (now
The Chase Manhattan Bank (National Association)) (Exhibit
2(b), File No. 2-26908).
Supplemental Indentures between Toledo Edison and the
Trustee, Supplemental to Exhibit 4b(1), dated as follows:
E-9
167
Exhibit Number Document
4b(2) September 1, 1948 (Exhibit 2(d), File No. 2-26908).
4b(3) April 1, 1949 (Exhibit 2(e), File No. 2-26908).
4b(4) December 1, 1950 (Exhibit 2(f), File No. 2-26908).
4b(5) March 1, 1954 (Exhibit 2(g), File No. 2-26908).
4b(6) February 1, 1956 (Exhibit 2(h), File No. 2-26908).
4b(7) May 1, 1958 (Exhibit 5(g), File No. 2-59794).
4b(8) August 1, 1967 (Exhibit 2(c), File No. 2-26908).
4b(9) November 1, 1970 (Exhibit 2(c), File No. 2-38569).
4b(10) August 1, 1972 (Exhibit 2(c), File No. 2-44873).
4b(11) November 1, 1973 (Exhibit 2(c), File No. 2-49428).
4b(12) July 1, 1974 (Exhibit 2(c), File No. 2-51429).
4b(13) October 1, 1975 (Exhibit 2(c), File No. 2-54627).
4b(14) June 1, 1976 (Exhibit 2(c), File No. 2-56396).
4b(15) October 1, 1978 (Exhibit 2(c), File No. 2-62568).
4b(16) September 1, 1979 (Exhibit 2(c), File No. 2-65350).
4b(17) September 1, 1980 (Exhibit 4(s), File No. 2-69190).
4b(18) October 1, 1980 (Exhibit 4(c), File No. 2-69190).
4b(19) April 1, 1981 (Exhibit 4(c), File No. 2-71580).
4b(20) November 1, 1981 (Exhibit 4(c), File No. 2-74485).
4b(21) June 1, 1982 (Exhibit 4(c), File No. 2-77763).
4b(22) September 1, 1982 (Exhibit 4(x), File No. 2-87323).
4b(23) April 1, 1983 (Exhibit 4(c), March 31, 1983 Form 10-Q,
File No. 1-3583).
4b(24) December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No.
1-3583).
4b(25) April 1, 1984 (Exhibit 4(c), File No. 2-90059).
4b(26) October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No.
1-3583).
4b(27) October 15, 1984 (Exhibit 4(aa), 1984 Form 10-K, File No.
1-3583).
4b(28) August 1, 1985 (Exhibit 4(dd), File No. 33-1689).
4b(29) August 1, 1985 (Exhibit 4(ee), File No. 33-1689).
4b(30) December 1, 1985 (Exhibit 4(c), File No. 33-1689).
4b(31) March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No.
1-3583).
4b(32) October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q,
File No. 1-3583).
4b(33) September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File
No. 1-3583).
4b(34) June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No.
1-3583).
4b(35) October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No.
1-3583).
4b(36) May 15, 1990 (Exhibit 4, June 30, 1990 Form 10-Q, File No.
1-3583).
4b(37) March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File
No. 1-3583).
4b(38) May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844).
4b(39) August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No.
1-3583).
E-10
168
Exhibit Number Document
4b(40) October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No.
1-3583).
4b(41) January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No.
1-3583).
10a Indemnity Agreements between Toledo Edison and certain of
its current directors (Exhibit 10a, 1988 Form 10-K, File
No. 1-3583).
24a Powers of Attorney of Toledo Edison and certified
resolution of Toledo Edison's Board of Directors
authorizing the signing on behalf of Toledo Edison
pursuant to a power of attorney (Exhibit 25(c), March 31,
1993 Form 10-Q, File No. 1-3583).
24b *Powers of Attorney of Toledo Edison directors and officers
required to sign the Report.
Pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Regis-
trants have not filed as an exhibit to this Form 10-K any instrument with
respect to long-term debt if the total amount of securities authorized there-
under does not exceed 10% of the total assets of the applicable Registrant and
its subsidiaries on a consolidated basis, but each hereby agrees to furnish to
the Securities and Exchange Commission on request any such instruments.
Pursuant to Rule 14a-3(b)(10) under the Securities Exchange Act of 1934,
copies of exhibits filed by the Registrants with this Form 10-K will be fur-
nished by the Registrants to share owners upon written request and upon re-
ceipt in advance of the aggregate fee for preparation of such exhibits at a
rate of $.25 per page, plus any postage or shipping expenses which would be
incurred by the Registrants.
E-11