<PAGE>   1

                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C.  20549

                        -----------------------------

                                   FORM 10-K

                        -----------------------------

<TABLE>
<S>   <C>
(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, 1995

                                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 _________________

</TABLE>

<TABLE>
<CAPTION>
<S>              <C>                                        <C>
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  
</TABLE>
                        -----------------------------

Indicate by check mark whether each of the registrants (1) has filed all
reports 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]

<PAGE>   2
The aggregate market value of Centerior Energy Corporation Common Stock,
without par value, held by non-affiliates was $1,258,236,538 on February 29,
1996 based on the closing sale price of $8.50 as quoted for that date on a
composite transactions basis in THE WALL STREET JOURNAL and on the 148,027,828
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.
<PAGE>   3
Securities registered pursuant to Section 12(b) of the Act:

<TABLE>
<CAPTION>
                                                        Name of Each Exchange
Registrant              Title of Each Class             on Which Registered 
----------              -------------------            ---------------------
<S>                     <C>                            <C>
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:
                          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

                        First Mortgage Bonds:
                          7-1/2% Series due 2002       New York Stock Exchange
                          8% Series due 2003           New York Stock Exchange
</TABLE>
<PAGE>   4
Securities registered pursuant to Section 12(g) of the Act:

<TABLE>
<CAPTION>
Registrant              Title of Each Class
----------              -------------------
<S>                     <C>
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                          
</TABLE>

                        -----------------------------

                      DOCUMENTS INCORPORATED BY REFERENCE
                      -----------------------------------

<TABLE>
<CAPTION>
                                                        Part of Form 10-K
                                                       Into Which Document
Description                                              Is Incorporated  
-----------                                            -------------------
<S>                                                          <C>
Portions of Proxy Statement of Centerior Energy
Corporation, dated March 12, 1996                            Part III
</TABLE>
<PAGE>   5
<TABLE>
<CAPTION>
                                TABLE OF CONTENTS


                                                                         Page
                                                                        Number
                                                                        ------
<S>                                                                       <C>
Glossary of Terms                                                         iv

PART I

  Item 1.  Business  . . . . . . . . . . . . . . . . . . . . . . . .       1

    The Centerior System . . . . . . . . . . . . . . . . . . . . . .       1

    Merger of the Operating Companies  . . . . . . . . . . . . . . .       2

    CAPCO Group  . . . . . . . . . . . . . . . . . . . . . . . . . .       3

    Construction and Financing Programs  . . . . . . . . . . . . . .       4

      Construction Program . . . . . . . . . . . . . . . . . . . . .       4
      Financing Program  . . . . . . . . . . . . . . . . . . . . . .       6

    General Regulation . . . . . . . . . . . . . . . . . . . . . . .       6

      Holding Company Regulation . . . . . . . . . . . . . . . . . .       6
      State Utility Commissions  . . . . . . . . . . . . . . . . . .       7
      Ohio Power Siting Board  . . . . . . . . . . . . . . . . . . .       8
      Federal Energy Regulatory Commission . . . . . . . . . . . . .       8
      Nuclear Regulatory Commission  . . . . . . . . . . . . . . . .       8
      Other Regulation . . . . . . . . . . . . . . . . . . . . . . .       8

    Environmental Regulation . . . . . . . . . . . . . . . . . . . .       9

      General  . . . . . . . . . . . . . . . . . . . . . . . . . . .       9
      Air Quality Control  . . . . . . . . . . . . . . . . . . . . .       9
      Water Quality Control  . . . . . . . . . . . . . . . . . . . .      10
      Waste Disposal . . . . . . . . . . . . . . . . . . . . . . . .      11

    Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . .      11

      General  . . . . . . . . . . . . . . . . . . . . . . . . . . .      11
      1995 Rate Case . . . . . . . . . . . . . . . . . . . . . . . .      12

    Operations . . . . . . . . . . . . . . . . . . . . . . . . . . .      12

      Sales of Electricity . . . . . . . . . . . . . . . . . . . . .      12
      Operating Statistics . . . . . . . . . . . . . . . . . . . . .      12
      Nuclear Units  . . . . . . . . . . . . . . . . . . . . . . . .      13
      Competitive Conditions . . . . . . . . . . . . . . . . . . . .      14

        General  . . . . . . . . . . . . . . . . . . . . . . . . . .      14
        Cleveland Electric . . . . . . . . . . . . . . . . . . . . .      15
        Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . .      16
</TABLE>


                                      -i-
<PAGE>   6
<TABLE>
<CAPTION>
                                                                         Page
                                                                        Number
                                                                        ------
<S>                                                                <C>    <C>
      Fuel Supply  . . . . . . . . . . . . . . . . . . . . . . . . .      18

        Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . .      18
        Nuclear  . . . . . . . . . . . . . . . . . . . . . . . . . .      19
        Oil  . . . . . . . . . . . . . . . . . . . . . . . . . . . .      19

    Executive Officers of the Registrants and the Service Company  .      20

  Item 2.  Properties  . . . . . . . . . . . . . . . . . . . . . . .      27

    General  . . . . . . . . . . . . . . . . . . . . . . . . . . . .      27

      The Centerior System . . . . . . . . . . . . . . . . . . . . .      27
      Cleveland Electric . . . . . . . . . . . . . . . . . . . . . .      27
      Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . .      28

    Title to Property  . . . . . . . . . . . . . . . . . . . . . . .      29

  Item 3.  Legal Proceedings . . . . . . . . . . . . . . . . . . . .      31

  Item 4.  Submission of Matters to a Vote of Security Holders . . .      31

PART II

  Item 5.  Market for Registrants' Common Equity and Related
           Stockholder Matters . . . . . . . . . . . . . . . . . . .      32

      Market Information . . . . . . . . . . . . . . . . . . . . . .      32
      Share Owners . . . . . . . . . . . . . . . . . . . . . . . . .      32
      Dividends  . . . . . . . . . . . . . . . . . . . . . . . . . .      32

  Item 6.  Selected Financial Data . . . . . . . . . . . . . . . . .      32

    Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . .      32
    Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . .      33
    Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . . .      33

  Item 7.  Management's Discussion and Analysis of Financial
           Condition and Results of Operations . . . . . . . . . . .      33

    Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . .      33
    Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . .      33
    Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . . .      33
</TABLE>





                                      -ii-
<PAGE>   7
<TABLE>
<CAPTION>
                                                                         Page
                                                                        Number
                                                                        ------
<S>                                                                      <C>
  Item 8.  Financial Statements and Supplementary Data . . . . . . .      33

    Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . .      33
    Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . .      33
    Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . . .      33

  Item 9.  Changes in and Disagreements With Accountants on
           Accounting and Financial Disclosure . . . . . . . . . . .      33

PART III

  Item 10.  Directors and Executive Officers of the Registrants  . .      34

    Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . .      34
    Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . .      34
    Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . . .      34

  Item 11.  Executive Compensation . . . . . . . . . . . . . . . . .      35

  Item 12.  Security Ownership of Certain Beneficial Owners and
            Management . . . . . . . . . . . . . . . . . . . . . . .      35

    Centerior Energy . . . . . . . . . . . . . . . . . . . . . . . .      35
    Cleveland Electric . . . . . . . . . . . . . . . . . . . . . . .      36
    Toledo Edison  . . . . . . . . . . . . . . . . . . . . . . . . .      36

  Item 13.  Certain Relationships and Related Transactions . . . . .      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
</TABLE>





                                     -iii-
<PAGE>   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:

<TABLE>
<CAPTION>
Term                             Definition
----                             ----------
<S>                              <C>
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.

Chase Brass                      Chase Brass & Copper Co., Inc.

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.

Davis-Besse                      Davis-Besse Nuclear Power Station.
</TABLE>



                                      -iv-
<PAGE>   9
<TABLE>
<CAPTION>
Term                             Definition
----                             ----------
<S>                              <C>
Detroit Edison                   Detroit Edison Company, an electric utility.

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.

Holding Company Act              Public Utility Holding Company Act of 1935.

Jersey Central                   Jersey Central Power & Light Company, an
                                 electric utility subsidiary of General Public
                                 Utilities Corporation.

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 1995 (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.
</TABLE>




                                      -v-
<PAGE>   10
<TABLE>
<CAPTION>
Term                             Definition
----                             ----------
<S>                              <C>
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 General Public
                                 Utilities Corporation.

Pennsylvania Power               Pennsylvania Power Company, an electric
                                 utility subsidiary of Ohio Edison and a
                                 member of the CAPCO Group.

Perry Unit 1                     Unit 1 of the Perry Nuclear Power 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.
</TABLE>





                                      -vi-
<PAGE>   11
<TABLE>
<CAPTION>
Term                             Definition
----                             ----------
<S>                              <C>
Superfund                        Comprehensive Environmental Response, Com-
                                 pensation and Liability Act of 1980 and the
                                 Superfund Amendments and Reauthorization Act
                                 of 1986.

Toledo Edison                    The Toledo Edison Company, an electric
                                 utility subsidiary of Centerior Energy and a
                                 member of the CAPCO Group.

USEC                             United States Enrichment Corporation,
                                 formerly a part of the DOE.

U.S. EPA                         United States Environmental Protection
                                 Agency.

Westinghouse                     Westinghouse Electric Corporation.
</TABLE>





                                     -vii-
<PAGE>   12
                                     PART I


Item 1.  Business
-----------------

                              THE CENTERIOR SYSTEM
                              --------------------

Centerior Energy is a public utility holding company and the parent company of
six wholly owned subsidiaries, including 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 population
of about 2,450,000.  At December 31, 1995, the Centerior System had 6,821
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, transmission,
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 electric utility
companies and to two municipal electric systems (directly and through AMP-Ohio)
in its service area.  Cleveland Electric serves approximately 749,000 customers
and derives approximately 77% of its total electric retail 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, 1995, Cleveland Electric had
3,636 employees of which about 55% 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 291,000 customers and derives approximately 54% of
its total electric retail revenue from customers outside the City of Toledo.
Principal industries served by Toledo Edison include 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, 1995, Toledo Edison
had 1,809 employees of which about 59% were represented by three unions having
collective bargaining agreements with Toledo Edison.



                                     - 1 -
<PAGE>   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 provides
management, financial, administrative, engineering, legal, governmental and
public relations and other services to Centerior Energy and the Operating
Companies.  At December 31, 1995, the Service Company had 1,373 employees.

Centerior's other three wholly owned subsidiaries are Centerior Properties
Company, CCO Company and Market Responsive Energy, Inc.  These three
subsidiaries, individually or in the aggregate, do not have a material impact
on the consolidated financial statements of Centerior.

                MERGER OF THE OPERATING COMPANIES
                ---------------------------------

In March 1994, Centerior Energy announced a plan 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.  In May 1994, the Operating
Companies filed a joint application for authorization and approval of the
merger with the FERC.  The PUCO, AMP-Ohio and the cities of Cleveland, Clyde
and Bryan, Ohio have intervened in the FERC proceedings.  The PUCO intervened
as the state commission having jurisdiction, but has not opposed the Cleveland
Electric and Toledo Edison application.  The PUCO approved the merger in
December 1994.  The PaPUC approved the merger in July 1994.  The other
intervenors have opposed the merger citing concerns primarily relating to the
merger's impact on competition.  In December 1994, the FERC advised the
Operating Companies by letter that the application to merge would be rejected
unless they provide additional information and file a single system open-access
transmission tariff offering comparable service.  In May 1995, Cleveland
Electric and Toledo Edison filed the additional information requested by the
FERC and an open-access transmission tariff offering comparable service.  The
FERC has deferred action on the merger application until the merits of the
Operating Companies' proposed open-access transmission tariffs are addressed in
hearings.  The Operating Companies do not expect the NRC to take action on
their request for authorization to transfer certain NRC licenses to the merged
entity until approval has been obtained from the FERC.

On June 14, 1995, special meetings of the preferred stock share owners of each
of the Operating Companies was held.  Cleveland Electric preferred stock share
owners approved the Amended Articles of Incorporation which provide for an
increased number of authorized shares of Cleveland Electric preferred stock.
Toledo Edison preferred stock share owners approved the Agreement of Merger
between Toledo Edison and Cleveland Electric.

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.





                                     - 2 -
<PAGE>   14

                                  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 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.

On October 18, 1995, Cleveland Electric filed a Demand for Arbitration seeking
unpaid operating costs of Eastlake Unit 5 which had been invoiced to Duquesne
in respect of Duquesne's partial ownership interest in that Unit.  In that
arbitration proceeding, Duquesne countered with allegations that certain
management practices of Cleveland Electric in the operation of Unit 5 have been
detrimental to Duquesne. Among the remedies sought by Duquesne is the partition
of the property held as tenants in common. On October 24, 1995, Cleveland
Electric filed a complaint for injunctive and declaratory relief against
Duquesne in Lake County (Ohio) Common Pleas Court seeking a court order
prohibiting Duquesne from taking action to partition or sell its ownership
interest in Eastlake Unit 5.  The Lake County action was removed to the United
States District Court for the Northern District of Ohio, Eastern Division.
Duquesne subsequently filed counterclaims in the federal court action restating
all claims made in the arbitration proceeding.

All of the CAPCO Group companies are members of ECAR, which is comprised of 29
major electric power suppliers and 11 associate members located in nine
east-central states, serving 36,000,000 people.  ECAR's purpose is to improve
reliability of bulk power supply through coordination of planning and operation
of member companies' generation and transmission facilities.




                                     - 3 -
<PAGE>   15
                     CONSTRUCTION AND FINANCING PROGRAMS
                     -----------------------------------

Construction Program
--------------------

The Centerior System carries on a continuous program of constructing
transmission, distribution and general facilities and modifying existing
generating facilities to meet anticipated demand for electric service and to
comply with governmental regulations.  Centerior Energy's 1995 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 of 0.5% and 1.0%, respectively, after demand-side
management considerations.  The Centerior System's integrated resource plan for
the 1990s (which is included in the long-term forecast) combines peak clipping
demand-side management programs with maximum utilization of existing generating
capacity to postpone the need for new generating units until the next decade.
Lake Shore Unit 18, a 45,000-kilowatt unit which was placed on cold standby
status in October 1993, is scheduled to resume active status in 2001.

According to the current long-term integrated resource plan, the Centerior
System does not plan to put into service any new generating capacity until
2008.

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 1993, 1994 and 1995 and the estimated cost of
their construction programs for 1996 through 2000, in each case including AFUDC
and excluding nuclear fuel:

<TABLE>
<CAPTION>
                                   Actual                Estimated 
                             ----------------   ----------------------------
                             1993  1994  1995   1996  1997  1998  1999  2000
                             ----  ----  ----   ----  ----  ----  ----  ----
     Cleveland Electric                   (Millions of Dollars)
     ------------------                                        
<S>                          <C>   <C>   <C>    <C>   <C>   <C>   <C>   <C>
Transmission, Distribution
  and General Facilities     $ 85  $ 53  $ 68   $ 93  $ 97  $ 75  $ 94  $110
Renovation and Modification
  of Generating Units
    Nuclear                    16    18    12     19    23     9    14    11
    Nonnuclear                 65    61    63     19    30    42    47    33
Clean Air Act Amendments
  Compliance                    9    24    12      2     7    14    21     2
                              ---   ---   ---    ---   ---   ---   ---   ---

                   Total     $175  $156  $155   $133  $157  $140  $176  $156
                              ===   ===   ===    ===   ===   ===   ===   ===
</TABLE>





                                     - 4 -
<PAGE>   16



<TABLE>
<CAPTION>
                                   Actual                Estimated
                             ----------------   ----------------------------
                             1993  1994  1995   1996  1997  1998  1999  2000
                             ----  ----  ----   ----  ----  ----  ----  ----
     Toledo Edison                        (Millions of Dollars)
     -------------                                             
<S>                          <C>   <C>   <C>    <C>   <C>   <C>   <C>   <C>
Transmission, Distribution
  and General Facilities     $ 22  $ 18  $ 37   $ 40  $ 36  $ 49  $ 33  $ 35
Renovation and Modification
  of Generating Units
    Nuclear                    15    10     6     14    17     8    11     9
    Nonnuclear                  6    12     9     18     6     3     3    24
Clean Air Act Amendments
  Compliance                    0     1     3      4    10     9    10     7
                              ---   ---   ---    ---   ---   ---   ---   ---

                   Total     $ 43  $ 41  $ 55   $ 76  $ 69  $ 69  $ 57  $ 75
                              ===   ===    ==     ==    ==    ==    ==    ==
</TABLE>


<TABLE>
<CAPTION>
                                   Actual                Estimated
                             ----------------    ---------------------------
                             1993 1994  1995    1996  1997  1998  1999  2000
                             ---- ----  ----    ----  ----  ----  ----  ----
     Centerior System                     (Millions of Dollars)
     ----------------                                          
<S>                          <C>   <C>  <C>     <C>   <C>   <C>   <C>   <C>
Transmission, Distribution
  and General Facilities     $107  $ 71 $105    $133  $133  $124  $127  $145
Renovation and Modification
  of Generating Units
    Nuclear                    31    28   18      33    40    17    25    20
    Nonnuclear                 71    73   72      37    36    45    50    57
Clean Air Act Amendments
  Compliance                    9    25   15       6    17    23    31     9
                              ---   ---  ---     ---   ---   ---   ---   ---

                   Total     $218  $197 $210    $209  $226  $209  $233  $231
                              ===   ===  ===     ===   ===   ===   ===   ===
</TABLE>


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 1993, 1994 and 1995 and their estimated nuclear fuel
capital costs for 1996 through 2000 are as follows:

<TABLE>
<CAPTION>
                                   Actual               Estimated
                             -----------------  --------------------------
                             1993  1994  1995  1996  1997  1998  1999  2000
                             ----  ----  ----  ----  ----  ----  ----  ----
                                          (Millions of Dollars)
<S>                          <C>   <C>   <C>   <C>   <C>   <C>   <C>   <C>
Cleveland Electric           $ 26  $ 26  $ 19  $ 40  $ 24  $ 35  $ 41  $ 34
Toledo Edison                $ 20  $ 21  $ 12  $ 32  $ 21  $ 30  $ 31  $ 29
Centerior System             $ 46  $ 47  $ 31  $ 72  $ 45  $ 65  $ 72  $ 63
</TABLE>





                                     - 5 -
<PAGE>   17
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 1995; debt and preferred stock redemption requirements during the
1996-2000 period; expected external financing needs during such period;
restrictions 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 1996, Cleveland Electric and Toledo Edison expect to complete the sale of a
AAA-rated security backed by their accounts receivable, thereby raising
approximately $150,000,000.  In addition, Cleveland Electric and Toledo Edison
plan to arrange for alternate financing to replace $234,000,000 of nuclear fuel
financing which expires in 1996 (see Note 6).

On February 28, 1996, Moody's Investors Service, Inc. announced that it had
placed its ratings of securities issued by the Operating Companies under review
for possible downgrade.  The rating agency indicated that the ratings for the
following securities were being reviewed:  first mortgage bonds, debentures and
preferred stock issued by the Operating Companies; secured pollution control
bonds and unsecured pollution control notes issued by public authorities and
secured by the Operating Companies' first mortgage bonds and notes; and secured
lease obligation bonds issued by CTC Beaver Valley Funding Corporation, Beaver
Valley II Funding Corporation and CTC Mansfield Funding Corporation which are
secured by rental payments made by Cleveland Electric and Toledo Edison.

                               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.





                                     - 6 -
<PAGE>   18
State Utility Commissions
-------------------------

The Operating Companies are subject to the jurisdiction of the PUCO with
respect 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
disciplines.  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 the forecast.  The PUCO and
the OPSB are required to consider the record of such hearings in proceedings
for approving facility sites, changing rates, approving security issues and
initiating energy conservation programs. In April 1995, the PUCO approved
Centerior Energy's 1994 long-term forecast.  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 July 1995, the PUCO approved Centerior's updated
environmental compliance plan which was filed in January 1995.

The PUCO has jurisdiction over certain transactions by companies in an electric
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.  Consequently, the Operating Companies must obtain PUCO


                                     - 7 -
<PAGE>   19
approval to invest in, lend funds to, guarantee the obligations of or otherwise
finance or transfer assets to any nonutility company in the Centerior 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, Centerior
must obtain PUCO approval to make any investment in any nonutility
subsidiaries, affiliates or associates if such investment would cause all such
capital investments to exceed 15% of Centerior's consolidated capitalization
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
customers 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
commerce, 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
considerations 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
insurance 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.



                                     - 8 -
<PAGE>   20
                            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
1996-2000, $45,809,000 and $40,850,000, 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
regulation, the affected company has filed an appeal or has applied for
permits, revisions to 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 conducted.  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 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 state implementation plan
except for some particulate matter emissions and certain sulfur dioxide
emissions.

In November 1990, the Clean Air Act Amendments imposed more stringent
restrictions on nitrogen oxide emissions and sulfur dioxide emissions beginning
in 1995.  See Note 4(a) for a description of the Operating Companies'
compliance strategy, which was included in the agreement approved by the PUCO
in April 1995 in connection with the Operating Companies' 1994 long-term
forecast.  The Clean Air Act Amendments also require studies to be conducted on
the emission of certain potentially hazardous air pollutants which could lead
to additional restrictions.


                                     - 9 -
<PAGE>   21
Global warming, or the "greenhouse effect", has been the subject of scientific
study and debate within the United States and internationally.  One area of
study involves the effect on global warming of the emissions of gases such as
those resulting from the burning of coal.  Based on a 1992 United Nations
treaty, the United States has developed a voluntary plan to reduce the
emissions of certain gases thought to contribute to global warming to 1990
levels by the year 2000.  The Operating Companies will work with the DOE and
other utilities to develop a plan for limiting such emissions.

Water Quality Control
---------------------

The Clean Water Act requires that power plants obtain permits under the NPDES
program 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.  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 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 in which a permit application is pending, the affected plant may
continue 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.

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.

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 additional effluent
limitations are not justified.

In March 1995, the U.S. EPA issued guidelines for water quality standards
applicable to all states abutting the Great Lakes, including Ohio.  These
states are required to adopt state water quality standards and procedures
consistent with the guidelines by April 1997.  Preliminary reviews indicate
that the cost of compliance could be significant.  However, the Operating
Companies cannot determine the operational impact of compliance until such
guidelines are incorporated into Ohio regulations.



                                     - 10 -
<PAGE>   22
Waste Disposal
--------------

See "Outlook--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 "Operations--Nuclear
Units" for a discussion concerning the disposal of nuclear waste.

The Resource Conservation and Recovery Act exempts certain fossil fuel
combustion waste products, such as fly ash, from hazardous waste disposal
requirements and requires the U.S. EPA to evaluate the need for future
regulation.  On August 9, 1994, the U.S. EPA issued its final regulatory
determination that regulation of coal ash as a hazardous waste is unnecessary.

                                 ELECTRIC RATES
                                 --------------
General
-------

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 construction work in progress in rate base under certain
conditions.

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
increase cannot be filed before the issuance of a final order in any prior
pending 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.

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
"Operations--Competitive Conditions--Cleveland Electric" for information on a
1994 rate reduction ordinance in Garfield Heights.





                                     - 11 -
<PAGE>   23
1995 Rate Case
--------------

In April 1995, Cleveland Electric and Toledo Edison filed requests with the
PUCO for price increases aggregating $119,000,000 annually to be effective in
1996.  Cleveland Electric's requested increase of $84,000,000 in annual
revenues reflects an average increase of 4.9% in Cleveland Electric's existing
prices.  Toledo Edison's requested increase of $35,000,000 reflects an average
increase of 4.7% in Toledo Edison's existing prices.

The rate increases are necessary to recover capital investment and increases in
costs incurred since the Operating Companies' last rate cases, which were
decided in January 1989, and to recover certain costs deferred since 1992
pursuant to a Rate Stabilization Program that was approved by the PUCO for the
Operating Companies in October 1992.

For a full discussion and analysis of the Operating Companies' 1995 rate case,
the Rate Stabilization Program, financial accounting requirements and the
potential implications of these accounting requirements for Centerior's and the
Operating Companies' results of operations and financial position, see Note 7.

                                   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.

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 3.6% of the 1995 total electric operating
revenues of Centerior Energy and Cleveland Electric, respectively.  The loss of
these facilities would reduce Centerior Energy's and Cleveland Electric's net
income by about $28,000,000 based on 1995 sales levels.

The largest customer served by Toledo Edison is a major automobile
manufacturer.  Sales to this customer accounted for 1.5% and 4.3% of the 1995
total electric operating revenues of Centerior Energy and Toledo Edison,
respectively.  The loss of this customer would reduce Centerior Energy's and
Toledo Edison's net income by about $16,000,000 based on 1995 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 1985
and 1991 through 1995, see the attached Pages F-25 and F-26 for Centerior
Energy, F-50 and F-51 for Cleveland Electric and F-76 and F-77 for Toledo
Edison.

                                     - 12 -
<PAGE>   24
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
responsibility 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, an additional 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.

In 1989, the PUCO approved nuclear plant performance standards for the
Operating Companies based on rolling three-year industry averages of
availability for pressurized water reactors and for boiling water reactors over
the 1988-1998 period.  Availability is the ratio of the number of hours a unit
is available to generate electricity (whether or not the unit is operated) to
the number of hours in the period, expressed as a percentage.  The three-year
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 would be incurred which would require the Operating Companies to
refund incremental 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 1993-1995 period (as of October 31,
1995) are 80.9% for pressurized water reactors such as Davis-Besse and Beaver
Valley Unit 2 and 76.7% for boiling water reactors such as Perry Unit 1.  The
1993-1995 combined availability average for Davis-Besse and Beaver Valley Unit
2 was 88.5% and the availability average for Perry Unit 1 was 61.6%.  At
December 31, 1995, the total banked benefit for the Operating Companies is
estimated to be between $27,000,000 and $31,000,000.

All three nuclear units have received generally favorable evaluations from the
NRC in their most recent SALP reviews, with Davis-Besse receiving the best
possible scores.  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 maintained 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.


                                     - 13 -
<PAGE>   25
The most recent review periods and SALP review scores for Beaver Valley Unit 2,
Perry Unit 1 and Davis-Besse are:

<TABLE>
<CAPTION>
                     Beaver Valley Unit 2   Perry Unit 1     Davis-Besse
                     --------------------   ------------     -----------
<S>                   <C>                   <C>             <C>
SALP Review Period    11/28/93-6/3/95       2/1/93-1/7/95   7/1/93-1/21/95
Operations                    2                   2               1
Engineering                   2                   2               1
Maintenance                   1                   2               1
Plant Support                 1                   2               1
</TABLE>

In 1980, Congress passed the Low-Level Radioactive Waste Policy Act which
provides that the disposal of low-level radioactive waste is the responsibility
of the state where such waste is generated.  The Act encourages states to form
compacts among themselves to develop regional disposal facilities.  Failure by
a state or compact to begin implementation of a program could result in access
denial to the two facilities currently accepting low-level radioactive waste.
Ohio is part of the Midwest Compact and has responsibility for siting and
constructing a disposal facility. In June 1995, the Ohio legislature authorized
the siting, construction and operation of a disposal facility.  In addition,
the South Carolina legislature voted to allow out-of-region generators (such as
Centerior's nuclear units) to resume shipments of low-level radioactive waste
to the Barnwell disposal facility.  Nonetheless, the Operating Companies'
ability to ship offsite in the future depends on whether the State of Ohio
proceeds with the development of a low-level radioactive waste disposal
facility.  As an interim solution to disposal availability, the Operating
Companies have constructed storage facilities to house the waste at each
nuclear site.

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 2017, 2013 and 2011, respectively.

See Note 4(b) for a discussion of the write-off of Perry Unit 2, and see
"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.




                                     - 14 -
<PAGE>   26
The Operating Companies also compete with municipally owned electric systems
within their respective service areas.  Several communities have evaluated
municipalization of electric service and decided to continue service from the
Operating Companies.  Officials in 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
customers to locate in their respective areas.

The Operating Companies 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 interconnections 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.

In the future, the Operating Companies will encounter an increasingly
competitive environment as a result of the structural changes taking place in
the electric utility industry.  For a discussion of these changes, including
open-access transmission, retail wheeling and stranded investment
considerations, see "Outlook--Competition" in Management's Financial Analysis
contained under Item 7 of this Report.

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 60% of the City's
geographical area (expected to increase to 100% by the end of 1999) and to
approximately 31% (about 68,000) of the electric consumers in the City--equal
to about 9% 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, the lower-cost
financing available to CPP, the continued availability to CPP of lower cost
power through short-term power purchases and CPP's access to cheaper
governmental power.

Cleveland Electric makes power available to CPP on a wholesale basis, subject
to FERC regulation.  In 1995, Cleveland Electric directly and through AMP-Ohio
provided a negligible amount of CPP's energy requirements. CPP's power is
purchased from other sources and wheeled over Cleveland Electric's transmission
system.  In cases currently pending, the FERC has ruled that Cleveland Electric
is obligated to provide an additional interconnection with CPP but has not
ruled on the terms and conditions.  Cleveland Electric has asked the FERC to
reconsider its order to provide CPP with an additional interconnection.  Also,
the FERC has not ruled 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.

                                     - 15 -
<PAGE>   27
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.
CPP's expansion has resulted in a reduction in Cleveland Electric's annual net
income by about $4,000,000 in 1993, $7,000,000 in 1994 and $8,000,000 in 1995.
Cleveland Electric estimates that its net income will continue to be reduced by
an additional $4,000,000-$5,000,000 each year in the 1996-2000 period because
of CPP's expansion, with the exception of 1997 when the reduction would be
about $10,000,000 including the loss of Medical Center Co. as discussed below.

Despite CPP's expansion efforts, Cleveland Electric has been successful in
retaining most of the large industrial and commercial customers in the
expansion areas by providing economic incentives in exchange for sole-supplier
contracts.  Cleveland Electric has similar contracts with customers in other
parts of its service area.  Approximately 91% of Cleveland Electric's
industrial revenues under contract will not be up for renewal until 1997 or
later.  As these contracts expire, Cleveland Electric expects to renegotiate
them and retain the customers.  In addition, an increasing number of CPP
customers are converting back to Cleveland Electric service.  However,
competition for such customers will continue.

In March 1995, one of Cleveland Electric's large commercial customers which has
provided annual net income to Cleveland Electric and Centerior of $6,000,000,
Medical Center Co., signed a five-year contract with CPP for electric service
provided by another utility beginning in September 1996, when its contract with
Cleveland Electric terminates.  In its appeal to the Ohio Supreme Court,
Cleveland Electric's position is that the purchase of power by this customer is
a direct purchase from another utility in violation of Ohio's certified
territory statute. Cleveland Electric has also filed a petition with the FERC
on the grounds that such a transaction is a violation of the Federal Power Act.
Cleveland Electric will continue to pursue all legal and regulatory remedies to
this situation.

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 appealed that ordinance
to the PUCO.  On June 29, 1995, the PUCO ruled that a rate reduction in the
City of Garfield Heights was not warranted.  Both parties subsequently filed
applications for rehearing concerning certain provisions of the PUCO's ruling.
On August 24, 1995, the PUCO denied the requests for rehearing.  Each party
appealed the PUCO's decision to the Ohio Supreme Court.

Currently, one commercial customer and one industrial customer of Cleveland
Electric have cogeneration installations.

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.



                                     - 16 -
<PAGE>   28
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 3% of
Toledo Edison's total electric operating revenues in 1995 were derived from
sales under the AMP-Ohio contract.

In October 1989, the City of Toledo established an Electric Franchise Review
Committee to (i) study Toledo Edison's franchise agreement with the City to
determine whether alternate energy sources may be utilized and (ii) investigate
the feasibility of establishing a municipal electric system within the City of
Toledo.  In November 1993, the City approved a non-exclusive franchise with
Toledo Edison which runs through the end of 1998.  In October 1995, the Toledo
City Council responded to a petition drive by appropriating funds to complete
the Electric Franchise Review Committee's study on whether to create a
municipal electric utility in the City of Toledo.  The Committee is also
expected to look into the aggregating of load to provide a conduit for retail
wheeling to customers.  The study is expected to be completed between late 1996
and mid 1997.

In January 1995, the City of Clyde, which operates its own municipal electric
system, passed ordinances to force Toledo Edison to remove most of its
equipment from within the City's borders and to prevent any residential and
commercial customers within the City from obtaining service from Toledo Edison.
The City subsequently asked the PUCO to authorize the removal of Toledo Edison
equipment under the Miller Act.  The Miller Act is an Ohio statute which
provides that a utility cannot be required to withdraw or abandon its
facilities and services in a city without a demonstration that such action is
in the public interest and without the approval of the PUCO.  Toledo Edison
challenged the City of Clyde's Miller Act proceeding before the PUCO and  filed
an action in the Court of Appeals in Sandusky County, Ohio to challenge the
City's ordinance prohibiting customers from using Toledo Edison service. The
PUCO held hearings but has not issued a decision.  The Court of Appeals denied
Toledo Edison's challenge, and Toledo Edison appealed to the Ohio Supreme
Court. Toledo Edison currently serves approximately 390 customers within the
City of Clyde.

In October 1995, Chase Brass terminated its service with Toledo Edison and
began to receive its electric service from a consortium of four municipal
electric systems and AMP-Ohio.  Service is being provided over a transmission
line owned by AMP-Ohio.  Although the Ohio Constitution allows municipal
electric systems to sell and deliver limited amounts of power outside their
municipal boundaries, Toledo Edison has filed two lawsuits in Williams County
(Ohio) Common Pleas Court against the four municipalities and AMP-Ohio
contending, in part, that this arrangement violates the legal limits of such
sales and that AMP-Ohio's system design for this transaction raises certain
safety issues.  North Western Electric Cooperative, whose certified territory
is crossed by AMP-Ohio's transmission line, has also filed suit to challenge
this transaction.  The loss of Chase Brass as a customer reduced Centerior
Energy's and Toledo Edison's annual net income by about $1,600,000 based on
1994 sales levels.


                                     - 17 -
<PAGE>   29
In addition, Chase Brass and other surrounding businesses and residences in
Jefferson Township continue to seek incorporation as a municipality to be named
the Village of Holiday City. The Williams County Board of Commissioners and the
Williams County Court of Common Pleas issued an order permitting the area to be
incorporated.  Toledo Edison has appealed the Court's order to the Sixth
District Court of Appeals, thereby staying the incorporation proceedings.

If the incorporation is permitted, the municipality would be able to bargain
with other utilities for electric power.  The other businesses in the proposed
municipality terminated their service with Toledo Edison earlier and are
receiving electric service from the Village of Montpelier, one of the
consortium now supplying Chase Brass.

No commercial customer of Toledo Edison now operates a cogeneration unit.

Fuel Supply
-----------

Generation by type of fuel for 1995 was 61% coal-fired and 39% nuclear for
Cleveland Electric; 40% coal-fired and 60% nuclear for Toledo Edison; and 54%
coal-fired and 46% nuclear for the Centerior System.

Coal.  In 1995, Cleveland Electric and Toledo Edison burned 5,237,000 tons and
1,840,000 tons of coal, respectively, for electric generation.  Each utility
normally maintains a reserve supply of coal sufficient for about 20 days of
normal operations.  On February 1, 1996, this reserve was about 17 days for
plants operated by Cleveland Electric, 17 days for the plant operated by Toledo
Edison and 66 days for the Mansfield Plant, which is operated by Pennsylvania
Power.

In 1995, about 50% of Cleveland Electric's coal requirements were purchased
under long-term contracts, with the longest remaining term being almost eight
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%.  Additionally, about 25% of Cleveland Electric's coal requirements
were purchased under short-term contracts (nine to twelve month terms) with
price adjustments on the basis of coal quality.  The sulfur content of the
short-term contracts ranged from 1.5% to 1.9%.  The balance of Cleveland
Electric's coal was purchased on the spot market with sulfur content ranging
from less than 1% to 4%.

In 1995, about 66% of Toledo Edison's coal requirements were purchased under
long-term contracts, with the longest remaining term being almost five 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%.  The
balance of Toledo Edison's coal was purchased on the spot market with sulfur
content 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

                                     - 18 -
<PAGE>   30
agreement is terminated for any reason, Cleveland Electric must assume certain
of Ohio Valley's debt and lease obligations and may incur other expenses
including mine closing costs, if necessary.  At December 31, 1995, the
principal amount of debt and termination values of leased property covered by
Cleveland Electric's agreement was $15,093,000, while the unfunded costs of
closing this mine, as estimated by Ohio Valley, were $32,000,000.  The coal
supply agreement with Ohio Valley is scheduled to continue until September
1997.  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 and mine closing costs over the life of the contract.

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 is scheduled to run 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, 1995, the total dollar amount of Quarto's
debt and lease obligations guaranteed by Cleveland Electric was $23,955,000 and
by Toledo Edison was $13,992,000.  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 and updated in 1995 proceedings, calls for compliance either through
the use of low-sulfur coal or the use of high sulfur-coal in combination with
emission allowances.  Some of the low-sulfur coal required to comply with Phase
1 of the Clean Air Act Amendments was contracted for in 1992.

NUCLEAR.  The acquisition and utilization of nuclear fuel involves six distinct
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 contract with the USEC which will supply all of
the needed enrichment services for their nuclear units' fuel supply through
1996.  Beyond 1996, the amount of enrichment services under the USEC 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 and
beyond.  The additional required enrichment services are available.
Substantial additional fuel will have to be obtained in the 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.

OIL.  The Operating Companies each have adequate supplies of fuel oil for their
oil-fired electric generating units which are used primarily as reserve and
peaking capacity.


                                     - 19 -
<PAGE>   31
        EXECUTIVE OFFICERS OF THE REGISTRANTS AND THE SERVICE COMPANY
        -------------------------------------------------------------

Set forth below are the names, ages as of March 15, 1996, 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 (*).

<TABLE>
<CAPTION>
                                                      Business Experience                       
                       ---------------------------------------------------------------------------------

Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                    <C>                 <C>                   <C>                  <C>
Robert J. Farling      *Chairman of the     *Chairman of the     *Chairman of the     *Chairman of the
(59)                      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
(56)                      President            President;           (November 1993)      (November 1993)
                          (July 1988)          President-                             President (July 1988)
                                               Transmission,
                                               Services and
                                               Business Enterprises
                                               Groups (October 1995)
                                             Executive Vice
                                               President-
                                               Operations &
                                               Engineering
                                               (July 1993)
                                             Executive Vice
                                               President-Power
                                               Generation
                                               (April 1990)
</TABLE>
<PAGE>   32
<TABLE>
<CAPTION>
                                                      Business Experience                       
                       ---------------------------------------------------------------------------------

Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                    <C>                 <C>                   <C>                  <C>
Fred J. Lange, Jr.     *Senior Vice         *Senior Vice         *Vice President      *President (November
(46)                     President            President;           (April 1990)         1993)
                          (July 1993)         President-                               Vice President (April
                        Senior Vice           Centerior Electric                        1990)
                          President-Legal,    Company (October
                          Human & Corporate   1995)
                          Affairs (March     Senior Vice
                          1992)                President-Fossil &
                        Vice President-        Transmission and
                          Legal & Corporate    Distribution
                          Affairs (April       Operations (July 1993)
                          1990)              Senior Vice
                                               President-Legal,
                                               Human & Corporate
                                               Affairs
                                              (March 1992)
                                             Vice President-
                                               Legal & Corporate
                                               Affairs (April
                                               1990)

Gary R. Leidich        *Senior Vice         *Senior Vice         *Vice President      *Vice President
(45)                      President            President;          (October 1995)        (October 1995)
                          (October 1995)       President-Power    Vice President &     Vice President &
                        Vice President         Generation Group     Chief Financial      Chief Financial
                          (July 1993)          (October 1995)       Officer              Officer (July
                                             Vice President-        (July 1993)          1995)
                                               Finance &
                                               Administration
                                               (July 1993)
                                             Director-Human
                                               Resources Dept.
                                               (August 1991)
                                             Director-System
                                               Planning
                                               Engineering
                                               Dept. (December
                                               1987)
</TABLE>
<PAGE>   33
<TABLE>
<CAPTION>
                                                      Business Experience                               
                       ---------------------------------------------------------------------------------

Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                    <C>                 <C>                   <C>                   <C>
Terrence G. Linnert    *Senior Vice         *Senior Vice         *Vice President &     *Vice President &
(49)                      President, Chief     President-           Chief Financial       Chief Financial
                          Financial Officer    Corporate            Officer               Officer
                          & General Counsel    Administration       (October 1995)        (October 1995)
                          (October 1995)       Group; Chief       Vice President        Vice President
                        Vice President         Financial Officer    (July 1993)            (July 1993)
                          (July 1993)          & General Counsel
                                               (October 1995)
                                             Vice President-
                                              Legal &
                                               Governmental
                                               Affairs and
                                               General Counsel
                                               (July 1993)
                                             Vice President-
                                               Legal and
                                               General Counsel
                                               (March 1992)
                                             General Counsel
                                               and Director-
                                               Legal Services
                                               Dept. (May 1990)


Donald C. Shelton                           *Senior Vice
(62)                                           President-Nuclear
                                               and Vice President-
                                               Nuclear-Perry
                                               (January 1995)
                                             Senior Vice
                                               President-Nuclear
                                               (July 1993)
                                             Vice President-
                                               Nuclear-Davis-
                                               Besse (April
                                               1990)
</TABLE>
<PAGE>   34
<TABLE>
<CAPTION>
                                                      Business Experience                       
                       ---------------------------------------------------------------------------------

Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                                         <C>
Jacquita K. Hauserman                       *Vice President-     *Vice President
(53)                                           Business Services    (November 1993)
                                               (October 1995)     Vice President-
                                             Vice President-        Administration
                                               Customer Support     (October 1988)
                                               (July 1993)
                                             Vice President-
                                               Customer Service
                                               & Community
                                               Affairs (April
                                               1990)

Jack A. Kline                                Director-Eastern     *Regional Vice
(52)                                           Sales Region          President-
                                               (November 1994)       Eastern
                                             Director-Cleveland      (October 1995)
                                               Marketing East
                                               (October 1993)
                                             Director-Cleveland
                                               Industrial Market-
                                               ing (July 1993)
                                             General Manager-
                                               Cleveland East
                                               Operations (May
                                               1990)


David L. Monseau                            *Vice President-
(55)                                           Distribution Serv-
                                               ices (October 1995)
                                             Vice President-
                                               Transmission &
                                               Distribution
                                               Operations
                                               (April 1990)
</TABLE>
<PAGE>   35
<TABLE>
<CAPTION>
                                                      Business Experience                       
                       ---------------------------------------------------------------------------------
Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                    <C>                   <C>                 <C>                    <C>
John E. Paganie                              Director-Human                             *Regional Vice President-
(49)                                           Resources                                   West (October 1995)
                                               (July 1993)
                                             General Manager-
                                               Cleveland West
                                               Operations
                                               (August 1991)
                                             Director-Union
                                               Relations
                                               (May 1990)

John P. Stetz                               *Vice President-
(50)                                           Nuclear-Davis-Besse
                                               (July 1994)
                                             Northeast Utilities:
                                               Vice President-
                                                 Connecticut Yankee
                                                 Nuclear Power Station
                                                 (October 1993)
                                               Station Director-
                                                 Connecticut Yankee
                                                 Nuclear Power Station
                                                 (September 1990)


Stanley F. Szwed                            *Vice President-Engineering
(43)                                           & Planning (October 1995)
                                             Director-System Planning
                                               & Operations (July 1993)
                                             Director-System Planning
                                               (August 1991)
                                             Manager-Resource Planning
                                               (May 1989)
</TABLE>
<PAGE>   36

<TABLE>
<CAPTION>
                                                      Business Experience                               
                       ---------------------------------------------------------------------------------

Name (Age)             Centerior Energy     Service Company            Cleveland Electric        Toledo Edison
----                   ----------------     ---------------            ------------------        -------------
<S>                    <C>                  <C>                        <C>                      <C>
Al R. Temple                                *Vice President-
(50)                                           Sales & 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)


David W. Whitehead                           Director-                 *Regional Vice
(49)                                           Governmental              President-Central
                                               Affairs                   (October 1995)
                                               (July 1993)
                                             General Counsel-
                                               Cleveland
                                               (September 1990)


E. Lyle Pepin          *Controller and      *Controller and           *Controller and           *Controller and
(54)                      Assistant            Assistant                 Assistant                 Assistant
                          Secretary            Secretary                 Secretary                 Secretary
                          (November 1994)      (November 1994)           (November 1994)           (November 1994)
                        Secretary            Secretary                 Secretary                 Secretary
                          (February 1986)      (April 1986)              (October 1988)            (October 1988)
</TABLE>
<PAGE>   37


<TABLE>
<CAPTION>
                                                      Business Experience                               
                       ---------------------------------------------------------------------------------
Name (Age)             Centerior Energy     Service Company      Cleveland Electric        Toledo Edison
----                   ----------------     ---------------      ------------------        -------------
<S>                    <C>                  <C>                  <C>                  <C>
David M. Blank         *Treasurer           *Treasurer           *Treasurer           *Treasurer
(47)                      (November 1994)      (November 1994)      (November 1994)      (November 1994)
                                             Director of
                                               Strategic Planning
                                               (October 1993)
                                             Director of Rates &
                                               Corporate Planning
                                               (May 1990)


Janis T. Percio        *Secretary           *Secretary           *Secretary           *Secretary
(43)                      (November 1994)      (November 1994)      (November 1994)      (November 1994)
                        Assistant            Assistant            Assistant            Assistant
                          Secretary            Secretary            Secretary            Secretary
                          (April 1986)         (April 1986)         (October 1982)       (April 1986)
</TABLE>
<PAGE>   38
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 directors
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, 1996 provide
the Centerior System with a net demonstrated capability of 5,996,000 kilowatts
during the winter.  These facilities include 20 fossil-fired steam electric
generating units (3,650,000 kilowatts) at five generation stations; three
nuclear generating units (1,856,000 kilowatts); a 351,000 kilowatt share of the
Seneca Plant; seven combustion turbine generating units (135,000 kilowatts) and
one diesel generator (4,000 kilowatts). In addition, two fossil-fired
generating units (320,000 kilowatts) are currently on cold standby status.  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 1995 was
5,779,000 kilowatts and occurred on August 15.  The net seasonal capability at
the time of the 1995 peak load was 5,924,000 kilowatts.  The Centerior System's
1996 native peak load is forecasted to be 5,220,000 kilowatts, after
demand-side management considerations.  The net seasonal capability expected to
be available to serve the Centerior System's 1996 peak is 5,885,000 kilowatts.
Over the 1996-1998 period, Centerior Energy forecasts its capacity margins at
the time of the projected Centerior System peak loads to range from 10% to 12%,
excluding the capacity on cold standby.

Each Operating Company owns the electric transmission and distribution
facilities 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.

Cleveland Electric
------------------

The wholly owned, jointly owned and leased electric generating facilities of
Cleveland Electric in commercial operation as of February 28, 1996 provide a
net demonstrated capability of 4,164,000 kilowatts during the winter.  These




                                     - 27 -
<PAGE>   39

facilities include 16 fossil-fired steam electric generating units (2,725,000
kilowatts) at four generation stations; its share of three nuclear generating
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 generator
(4,000 kilowatts).  In addition, one fossil-fired generating unit (245,000
kilowatts) is currently on cold standby status.  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 1995 was
4,049,000 kilowatts and occurred on August 15.  The capacity resources
available at the time of the 1995 peak were 4,273,000 kilowatts.  Cleveland
Electric's 1996 native peak load is forecasted to be 3,700,000 kilowatts, after
demand-side management considerations.  The capacity resources expected to be
available to serve Cleveland Electric's 1996 peak are 4,234,000 kilowatts.
Over the 1996-1998 period, Cleveland Electric forecasts its capacity margins at
the time of its projected peak loads to range from 12% to 13%, excluding the
capacity on cold standby.

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
interconnections 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, 1996 provide a net
demonstrated capability of 1,832,000 kilowatts during the winter.  These
facilities include six fossil-fired steam electric generating units (925,000
kilowatts) at two generation stations; its share of three nuclear generating
units (830,000 kilowatts) and five combustion turbine generating units (77,000
kilowatts).  In addition, one fossil-fired generating unit (75,000 kilowatts)
is currently on cold standby status.  All of Toledo Edison's generating
facilities are located in Ohio and Pennsylvania.

The net 60-minute peak load of Toledo Edison's service area for 1995 was
1,738,000 kilowatts and occurred on August 15.  The capacity resources
available at the time of the 1995 peak were 1,651,000 kilowatts.  Toledo
Edison's 1996 native peak load is forecasted to be 1,540,000 kilowatts, after
demand-side management considerations.  The capacity resources expected to be
available to serve Toledo Edison's 1996 peak are 1,651,000 kilowatts.  Over the
1996-1998 period, Toledo Edison forecasts its capacity margins at the time of
its projected peak loads to range from 3.7% to 7%, excluding the capacity on
cold standby.


                                     - 28 -
<PAGE>   40
Toledo Edison owns the facilities located in the area it serves for
transmitting and distributing power to all its customers.  Toledo Edison has
interconnections with Ohio Edison, Ohio Power and Detroit Edison.  The
interconnection 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
interconnections 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 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, and an 18.26% undivided tenant-in-common interest in Beaver
     Valley Unit 2 located in Shippingport, Pennsylvania. These leases extend
     through 2017 and are the result of sale and leaseback transactions
     completed in September 1987. 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, 1995, the
     cost of Cleveland Electric's facilities, other than water intake and
     discharge facilities, located on such artificially filled land aggregated
     approximately $116,650,000.  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
     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 Electric, 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





                                     - 29 -
<PAGE>   41
     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.

Cleveland Electric has entered into an agreement with Jersey Central under
which Jersey Central will lease Cleveland Electric's ownership share of the
Seneca Plant (351,000 kilowatts).  The lease will run for a period beginning on
June 1, 1996 or on the date of receipt of appropriate regulatory approvals
(whichever occurs later) and ending May 31, 2004.

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.  As discussed under
"Item 1. Business--CAPCO Group", Duquesne is attempting to partition its
interest in Eastlake Unit 5.


                                     - 30 -
<PAGE>   42

Item 3.  Legal Proceedings
--------------------------

PROCEEDINGS REGARDING AN ATTEMPT BY THE CITY OF CLYDE, OHIO TO REMOVE TOLEDO
EDISON.  See "Item 1.  Business--Operations--Competitive Conditions--Toledo
Edison".

PROCEEDINGS BEFORE THE PUCO REGARDING ACTIONS BY THE CITY OF GARFIELD HEIGHTS,
OHIO TO REDUCE CLEVELAND ELECTRIC'S RATES WITHIN THE CITY.  See "Item 1.
Business--Operations--Competitive Conditions--Cleveland Electric".

PROCEEDINGS BEFORE THE FERC REGARDING THE PROPOSED MERGER OF THE OPERATING
COMPANIES.  See "Item 1.  Business--Merger of the Operating Companies".

PROCEEDINGS BEFORE THE PUCO REGARDING THE REQUESTS FOR RATE INCREASES FILED BY 
THE OPERATING COMPANIES.  See "Item 1.  Business--Electric Rates--1995
Rate Case".

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.  In December 1994, a jury rendered a
verdict in favor of Westinghouse on a fraud claim.  (The court had previously
dismissed four other claims against Westinghouse.)  The CAPCO Group companies
have appealed the decision to the United States Court of Appeals for the Third
Circuit.  The Operating Companies believe that the outcome of this lawsuit will
not have a materially adverse effect on their financial positions or results of
operation.

DUQUESNE LAWSUIT.  See "Item 1. Business--CAPCO Group".

PROCEEDINGS BEFORE THE PUCO AND THE FERC REGARDING THE ELECTRIC SERVICE
CONTRACT BETWEEN CPP AND MEDICAL CENTER CO.  See "Item 1. Business--
Operations--Competitive Conditions--Cleveland Electric".

PROCEEDINGS BEFORE WILLIAMS COUNTY (OHIO) COMMON PLEAS COURT RELATING TO
ELECTRIC SERVICE BEING PROVIDED TO CHASE BRASS BY FOUR MUNICIPALS AND AMP-OHIO.
See "Item 1. Business--Operations--Competitive Conditions--Toledo Edison".

Item 4.  Submission of Matters to a Vote of Security Holders
-------------------------------------------------------------

            CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
            ------------------------------------------------------

                                    None.





                                     - 31 -
<PAGE>   43
                                    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.

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 1994 and 1995 were as follows:

<TABLE>
<CAPTION>
                                 1994                        1995
                                 ----                        ----

                           High        Low             High        Low
                           ----        ---             ----        ---
     <S>                  <C>         <C>             <C>         <C>
     1st Quarter          $13-3/8     $10-5/8         $10         $ 8-11/16
     2nd Quarter           11-3/4       9-7/8           9-7/8       8-5/8
     3rd Quarter           10-5/8       8-7/8          11           9-1/2
     4th Quarter            9-1/2       8              11-1/4       8-1/2
</TABLE>


Share Owners
------------

As of March 5, 1996, Centerior Energy had 133,729 common stock share owners of
record.

Dividends
---------

See Note 14 to Centerior's Financial Statements for quarterly dividend payments
in the last two years.  Future dividend action by Centerior's 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.

At December 31, 1995, Centerior Energy had a retained earnings deficit of $336
million and capital surplus of $1.963 billion, resulting in an overall surplus
of $1.627 billion that was available to pay dividends under Ohio law.  Any
current period earnings in 1996 will increase surplus under Ohio law.  See Note
11(b) for discussions of dividend restrictions affecting Cleveland Electric and
Toledo Edison.

Dividends paid in 1995 on each of the Operating Companies' outstanding series
of preferred stock were fully taxable.

Item 6.  Selected Financial Data
--------------------------------

                                CENTERIOR ENERGY
                                ----------------

The information required by this Item is contained on Pages F-25 and F-26
attached hereto.




                                     - 32 -
<PAGE>   44
                               CLEVELAND ELECTRIC
                               ------------------

The information required by this Item is contained on Pages F-50 and F-51
attached hereto.

                                 TOLEDO EDISON
                                 -------------

The information required by this Item is contained on Pages F-76 and F-77
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-2 through F-7
attached hereto.

                               CLEVELAND ELECTRIC
                               ------------------

The information required by this Item is contained on Pages F-27 through F-32
attached hereto.


                                 TOLEDO EDISON
                                 -------------

The information required by this Item is contained on Pages F-52 through F-57
attached hereto.

Item 8.  Financial Statements and Supplementary Data
----------------------------------------------------

                                CENTERIOR ENERGY
                                ----------------

The information required by this Item is contained on Pages F-8 through F-24
attached hereto.

                               CLEVELAND ELECTRIC
                               ------------------

The information required by this Item is contained on Pages F-33 through F-49
attached hereto.

                                 TOLEDO EDISON
                                 -------------

The information required by this Item is contained on Pages F-58 through F-75
attached hereto.

Item 9.  Changes in and Disagreements With Accountants on Accounting and
------------------------------------------------------------------------
Financial Disclosure
--------------------

            CENTERIOR ENERGY, CLEVELAND ELECTRIC AND TOLEDO EDISON
            ------------------------------------------------------

                                     None.



                                     - 33 -
<PAGE>   45
                                    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 7 and Page 15 of
Centerior's definitive proxy statement dated March 12, 1996.  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 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
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 and Society National Bank.
(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.

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 and Society National Bank.
(1993)

Fred J. Lange, Jr.
------------------

(1993)

*Also a director of Centerior Energy and the Service Company.

                                     - 34 -
<PAGE>   46
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 8 and
the information concerning compensation of executive officers, stock option
transactions, long-term incentive awards and pension benefits on Pages 21
through 24 of Centerior's definitive proxy statement dated March 12, 1996.  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
1995.

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, 1996:

<TABLE>
<CAPTION>
Name of Beneficial                        Number of Common
      Owner                               Shares Owned (1)
------------------                        ----------------
<S>                                         <C>
Richard P. Anderson                           2,761
Albert C. Bersticker                          2,065
Leigh Carter                                  3,322
Thomas A. Commes                              6,065
William F. Conway                             1,556
Wayne R. Embry                                2,065
Robert J. Farling                            59,588 (2)
Richard A. Miller                            13,092
Frank E. Mosier                               2,934
Sister Mary Marthe Reinhard, SND              2,809 (3)
Robert C. Savage                              2,065
William J. Williams                           3,002
Murray R. Edelman                            18,856 (2)
Donald C. Shelton                            10,771 (2)
Fred J. Lange, Jr.                           11,890 (2)
Al R. Temple                                  5,550 (2)
All directors and executive
  officers as a group                       198,735 (2)

<FN>
(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, 1996, 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.

</TABLE>

                                     - 35 -
<PAGE>   47
(2) Includes the following numbers of shares which are not owned but could
    have been purchased within 60 days after February 28, 1996 upon exercise
    of options to purchase shares of Centerior common stock:  Mr. Farling -
    10,000; Mr. Edelman - 5,000; Mr. Shelton - 3,400; Mr. Lange - 3,000; Mr.
    Temple - 2,150; and all directors and executive officers as a group -
    33,550.  None of those options have been exercised as of March 22, 1996.

(3) Owned by the Sisters of Notre Dame.


                               CLEVELAND ELECTRIC
                               ------------------

Individual directors of Cleveland Electric, the named executive officers  and
all directors and executive officers of Cleveland Electric as a group
beneficially owned the following number of shares of Centerior common stock as
of February 28, 1996:

<TABLE>
<CAPTION>
Name of Beneficial                        Number of Common
      Owner                               Shares Owned (1)
------------------                        ----------------
<S>                                         <C>
Robert J. Farling                            59,588 (2)
Murray R. Edelman                            18,856 (2)
Donald C. Shelton                            10,771 (2)
Fred J. Lange, Jr.                           11,890 (2)
Al R. Temple                                  5,550 (2)
All directors and executive
  officers as a group                       144,465 (2)

<FN>
(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, 1996, all directors and executive officers of Cleveland
    Electric as a group were considered to own beneficially 0.1% 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, 1996 upon exercise
    of options to purchase shares of Centerior common stock:  Mr. Farling -
    10,000; Mr. Edelman - 5,000; Mr. Shelton - 3,400; Mr. Lange - 3,000; Mr.
     Temple - 2,150; and all directors and executive officers as a group -
    30,675. None of those options have been exercised as of March 22, 1996.

</TABLE>
                                 TOLEDO EDISON
                                 -------------

Individual directors of Toledo Edison, the named executive officers and all
directors and executive officers of Toledo Edison as a group beneficially owned
the following number of shares of Centerior common stock as of February 28,
1996:



                                     - 36 -
<PAGE>   48
<TABLE>
<CAPTION>
Name of Beneficial                        Number of Common
      Owner                               Shares Owned (1)
------------------                        ----------------
<S>                                         <C>
Robert J. Farling                            59,588 (2)
Murray R. Edelman                            18,856 (2)
Donald C. Shelton                            10,771 (2)
Fred J. Lange, Jr.                           11,890 (2)
Al R. Temple                                  5,550 (2)
All directors and executive
  officers as a group                       129,248 (2)


<FN>
(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, 1996, all directors and executive officers of Toledo Edison
    as a group were considered to own beneficially 0.09% of Centerior's common
    stock and none of Toledo Edison's cumulative 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, 1996 upon exercise
    of options to purchase shares of Centerior common stock:  Mr. Farling -
    10,000; Mr. Edelman - 5,000; Mr. Shelton - 3,400; Mr. Lange - 3,000; Mr.
    Temple - 2,150; and all other executive officers as a group - 28,275.
    None of those options have been exercised as of March 22, 1996.

</TABLE>

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.

     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.



                                     - 37 -
<PAGE>   49
     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, 1995, Centerior Energy, Cleveland
     Electric and Toledo Edison did not file any Current Reports on Form 8-K.



                                     - 38 -
<PAGE>   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 28, 1996                    By J. T. PERCIO
                                     -------------------------
                                     J. T. Percio, Secretary

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated:

<TABLE>
<CAPTION>
     Signature                         Title                       Date
     ---------                         -----                       ----
<S>                               <C>                         <C>
Principal Executive Officer:                             )
*ROBERT J. FARLING                Chairman of the Board, )
                                    President and Chief  )
                                    Executive Officer    )
Principal Financial Officer:                             )
*TERRENCE G. LINNERT              Senior Vice President, )
                                    Chief Financial      )
                                    Officer and General  )
                                    Counsel              )
Principal Accounting Officer:
*E. LYLE PEPIN                    Controller             )

Directors:                                               )
*RICHARD P. ANDERSON              Director               )
*ALBERT C. BERSTICKER             Director               )
*LEIGH CARTER                     Director               )
*THOMAS A. COMMES                 Director               )    March 28, 1996
*WILLIAM F. CONWAY                Director               )
*WAYNE R. EMBRY                   Director               )
*ROBERT J. FARLING                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
</TABLE>

                                     - 39 -
<PAGE>   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 28, 1996                    By J. T. PERCIO
                                     -------------------------
                                     J. T. Percio, Secretary

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated:

<TABLE>
<CAPTION>
     Signature                         Title                       Date
     ---------                         -----                       ----
<S>                               <C>                         <C>
Principal Executive Officer:                             )

*ROBERT J. FARLING                Chairman of the Board  )
                                    and Chief Executive  )
                                    Officer              )

Principal Financial Officer:                             )

*TERRENCE G. LINNERT              Vice President and     )
                                    Chief Financial      )    March 28, 1996
                                    Officer              )

Principal Accounting Officer:                            )

*E. LYLE PEPIN                    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
</TABLE>


                                     - 40 -
<PAGE>   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 28, 1996                    By J. T. PERCIO
                                     -----------------------
                                     J. T. Percio, Secretary

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated:

<TABLE>
<CAPTION>
     Signature                         Title                       Date
     ---------                         -----                       ----
<S>                               <C>                         <C>
Principal Executive Officer:                             )

*ROBERT J. FARLING                Chairman of the Board  )
                                    and Chief Executive  )
                                    Officer              )

Principal Financial Officer:                             )

*TERRENCE G. LINNERT              Vice President and     )
                                    Chief Financial      )
                                    Officer              )

Principal Accounting Officer:                            )    March 28, 1996

*E. LYLE PEPIN                    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
</TABLE>


                                    - 41 -
<PAGE>   53

                                    INDEX TO
                                    --------
                SELECTED FINANCIAL DATA; MANAGEMENT'S DISCUSSION
                ------------------------------------------------
               AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
               -------------------------------------------------
                      OPERATIONS; AND FINANCIAL STATEMENTS
                      ------------------------------------

<TABLE>
<CAPTION>
                                                                        Page
                                                                        ----
<S>                                                                      <C>
Centerior Energy Corporation and Subsidiaries:
--------------------------------------------- 

Management's Financial Analysis  . . . . . . . . . . . . . . . . .      F-2
Report of Independent Public Accountants . . . . . . . . . . . . .      F-8
Income Statement for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-9
Retained Earnings for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-9
Balance Sheet as of December 31, 1995 and 1994 . . . . . . . . . .      F-10
Cash Flows for the Years Ended December 31, 1995, 1994 and 1993  .      F-12
Statement of Preferred Stock at December 31, 1995 and 1994 . . . .      F-13
Notes to the Financial Statements  . . . . . . . . . . . . . . . .      F-14
Financial and Statistical Review . . . . . . . . . . . . . . . . .      F-25

The Cleveland Electric Illuminating Company and Subsidiaries:
------------------------------------------------------------ 

Management's Financial Analysis  . . . . . . . . . . . . . . . . .      F-27
Income Statement for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-33
Retained Earnings for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-33
Balance Sheet as of December 31, 1995 and 1994 . . . . . . . . . .      F-34
Cash Flows for the Years Ended December 31, 1995, 1994 and 1993  .      F-36
Statement of Preferred Stock at December 31, 1995 and 1994 . . . .      F-37
Notes to the Financial Statements  . . . . . . . . . . . . . . . .      F-38
Report of Independent Public Accountants . . . . . . . . . . . . .      F-49
Financial and Statistical Review . . . . . . . . . . . . . . . . .      F-50

The Toledo Edison Company:
------------------------- 

Management's Financial Analysis  . . . . . . . . . . . . . . . . .      F-52
Income Statement for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-58
Retained Earnings for the Years Ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      F-58
Balance Sheet as of December 31, 1995 and 1994 . . . . . . . . . .      F-60
Cash Flows for the Years Ended December 31, 1995, 1994 and 1993  .      F-62
Statement of Preferred Stock at December 31, 1995 and 1994 . . . .      F-63
Notes to the Financial Statements  . . . . . . . . . . . . . . . .      F-64
Report of Independent Public Accountants . . . . . . . . . . . . .      F-75
Financial and Statistical Review . . . . . . . . . . . . . . . . .      F-76
</TABLE>





                                     F-1
<PAGE>   54
 
MANAGEMENT'S FINANCIAL ANALYSIS
 
OUTLOOK
 
STRATEGIC PLAN
 
We continued to make progress during the second year of our eight-year strategic
plan, but we remain keenly aware of the magnitude of the problems that face us.
The strategic plan was created to achieve two major goals: strengthening our
financial condition and improving our competitive position. Its objectives are
to maximize share owner return, achieve profitable revenue growth, become a
leader in customer satisfaction, build a winning employee team and attain
increasingly competitive power supply costs. We are not yet positioned to
compete in a less regulated electric utility industry, but every major action
being taken -- strategic planning, revenue enhancement, cost reduction,
improvement of work practices and application for increased prices -- is part of
a comprehensive effort to succeed in an increasingly competitive environment.
 
A primary objective of the strategic plan is continued and significant revenue
growth even as our markets become more competitive. Retail revenues adjusted for
weather and fuel costs have grown about 1% annually since 1990. During 1995, we
took aggressive steps to increase revenues through enhanced marketing
strategies. Also, our economic development efforts proved successful in
attracting major new customers and supporting the expansion of existing ones.
Although we are not satisfied with our growth rate, we expect that our marketing
activity will improve revenue growth.
 
The rate case we filed with The Public Utilities Commission of Ohio (PUCO) in
April 1995 is a critical factor to the success of the strategic plan. We do not
see this rate case as a continuation of business as usual but as an important
turning point which should, if we are successful in accomplishing the objectives
discussed below, bring an end to price increases for the foreseeable future. A
successful conclusion of the case would speed our transition to a more
competitive company by providing additional cash to lower costs by accelerating
the pay-down of debt and preferred stock. In our view, a successful conclusion
would include approval of the full price increase requested with a regulatory
commitment to maintain the established price levels over an appropriate
transition period. This should be coupled with a means to accelerate recognition
of regulatory assets (described in Note 7(a)) and nuclear generating assets
concurrent with our cost control and revenue enhancement efforts in order to
earn a fair return for share owners over time.
 
Another key part of our strategy is offering long-term contracts to those large
customers who could have incentives to change power suppliers. In 1995, 68% of
our industrial kilowatt-hour sales and 15% of our commercial kilowatt-hour sales
were under long-term contracts. We are renegotiating contracts before they
expire and in most cases are retaining customers under new long-term contracts.
 
We are continuing efforts to reduce fixed financing costs in order to strengthen
our financial condition. During 1995, utilizing strong cash flow and refinancing
at favorable terms, we reduced interest expense and preferred dividends by $8
million and outstanding debt and preferred stock by $134 million.
 
Our overall costs are high relative to many of our neighboring utilities as a
result of our substantial nuclear investment. The strategic plan calls for
making us more competitive by continuing to reduce operating expenses and
capital expenditures. In 1995, to improve our focus on cost reduction and other
strategic plan objectives, we restructured into six business groups. The new
organization includes groups to manage our generation, distribution and
transmission businesses; provide services and administrative functions; and
invest in nonregulated enterprises. This arrangement will also enhance each
group's ability to identify cost reductions by focusing on margins and improving
work practices and customer service. We will also continue to aggressively
pursue initiatives to reduce the heavy tax burden imposed upon us by the state
and local tax structure in Ohio.
 
RATE CASE AND REGULATORY ACCOUNTING
 
In April 1995, our subsidiaries, The Cleveland Electric Illuminating Company
(Cleveland Electric) and The Toledo Edison Company (Toledo Edison)
(collectively, Operating Companies), filed requests with the PUCO for price
increases aggregating $119 million annually to be effective in 1996. The price
increases are necessary to recover cost increases and amortization of certain
costs deferred since 1992 pursuant to the Rate Stabilization Program discussed
below and in Note 7. If their requests are approved, the Operating Companies
intend to freeze prices until at least 2002 with the expectation that increased
sales and cost control measures will obviate the need for further price
increases. If circumstances make it impossible to earn a fair return for share
owners over time, we would ask for a further increase -- but only after taking
all appropriate actions to make such a request unnecessary.
 
 (Centerior Energy)                    F-2                    (Centerior Energy)
<PAGE>   55
 
In December 1995, the PUCO ordered an investigation into the financial
conditions, rates and practices of the Operating Companies.
 
In its report on the Operating Companies' rate request, the PUCO Staff
recommended approval of the $119 million requested, subject to a commitment by
the Operating Companies to significantly revalue their assets. In late January
1996, the Staff proposed that the Operating Companies significantly revalue
their nuclear plant and regulatory assets within a five-year period. The Staff's
asset revaluation proposal is inconsistent with the Ohio statutes that define
the rate-making process. The PUCO is not bound by the Staff's recommendations. A
decision by the PUCO is anticipated in the second quarter of 1996.
 
The outcome of the rate case could affect the Operating Companies' ability to
meet the criteria of Statement of Financial Accounting Standards (SFAS) 71 for
all or part of their operations which could result in the write-off of all or a
part of the regulatory assets shown in Note 7(a). In our changing industry,
other events independent of the outcome of the rate case could also result in
write-offs or write-downs of assets.
 
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and
other financial accounting requirements and the potential implications of these
accounting requirements for our results of operations and financial position.
 
RATE STABILIZATION PROGRAM
 
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to
freeze base rates until 1996 and limit rate increases through 1998. In exchange,
we were permitted to defer through 1995 and subsequently recover certain costs
not currently recovered in rates and to accelerate amortization of certain
benefits. Deferral of those costs and amortization of those benefits were
completed in November 1995 and aggregated $159 million in 1995. Recovery is
expected to begin with the effective date of the PUCO's orders in the pending
rate case. Annual amortization of the deferred costs is $25 million which began
in December 1995. Consequently, earnings in 1996 will be sharply lower than in
1995. Also contributing to lower earnings are the expectations that the
requested price increase will not be effective until the second quarter of 1996
and results from increased marketing and cost reduction efforts will take time
to achieve.
 
COMPETITION
 
Major structural changes are taking place in the electric utility industry which
are expected to place downward pressure on prices and to increase competition
for customers' business. The changes are coming from both federal and state
authorities. Many of the changes began when the Energy Policy Act of 1992
permitted competition in the electric utility industry through broader access to
a utility's transmission system. In March 1995, the Federal Energy Regulatory
Commission (FERC) issued proposed rules relating to open access transmission
services by public utilities, recovery of stranded investment and other related
matters. The open access transmission rules require utilities to deliver power
from other utilities or generation sources to their wholesale customers. In May
1995, the Operating Companies filed open access transmission tariffs with the
FERC which used the proposed rules as a guideline. These tariffs are currently
pending.
 
Several groups in Ohio are studying the possible application of retail wheeling.
Retail wheeling occurs when a customer obtains power from a utility company
other than its local utility. The PUCO is sponsoring informal discussions among
a group of business, utility and consumer interests to explore ways of promoting
competitive options without unduly harming the interests of utility company
share owners or customers. Legislative proposals are being drafted for
submission to the Ohio House of Representatives and several utilities in the
state have offered their own proposed transition plans for introduction of
retail wheeling. The current retail wheeling efforts in Ohio are exploratory and
we cannot predict when and to what extent retail wheeling will be implemented in
Ohio.
 
The term "stranded investment" generally refers to fixed costs approved for
recovery under traditional regulatory methods that would become unrecoverable,
or "stranded", as a result of wider competition. Although competitive pressures
are increasing, the traditional regulatory framework remains in place and is
expected to continue for the foreseeable future. We cannot predict when and to
what extent competition will be allowed. We believe that pure competition
(unrestricted retail wheeling for all customer classifications) is at least
several years away and that any transition to pure competition will be in
phases. The FERC and the PUCO have acknowledged the need to provide at least
partial recovery of stranded investment as greater competition is permitted and,
therefore, we believe that there will be a mechanism developed for the recovery
of stranded investment.
 
 (Centerior Energy)                    F-3                    (Centerior Energy)
<PAGE>   56
 
However, due to the uncertainty involved, there is a risk that some of our
assets may not be fully recovered.
 
In 1995, we continued to experience significant competition from municipal
electric systems. Cleveland Public Power (CPP), the largest municipal system in
our service area, continued to construct new distribution facilities extending
into additional portions of Cleveland. Their progress has slowed significantly
during the past year because of the discovery of a large number of safety
violations in the CPP system resulting in substantial cost overruns. In Toledo,
the City Council responded to a petition drive by appropriating funds to
complete a consultant's study on whether to create a municipal electric utility.
This study is expected to be completed by mid-1996.
 
In March 1995, one of Cleveland Electric's large commercial customers which has
provided annual net income of $6 million, Medical Center Co., signed a five-year
contract with CPP for electric service beginning in September 1996, when its
contract with Cleveland Electric terminates. In both our appeal to the Ohio
Supreme Court and petition to the FERC, it is our position that the purchase of
power from CPP by this customer is in reality a direct purchase from another
utility in violation of Ohio's certified territory statute. In October 1995,
Chase Brass & Copper Co. Inc., which has provided annual net income of $2
million, terminated its service from Toledo Edison and began to receive its
electric service from a consortium of other providers. Toledo Edison has filed
lawsuits contending that this arrangement violates the legal limits of sales and
delivery of power by municipal electric systems outside their boundaries. We
will continue to pursue all legal and regulatory remedies to these situations.
 
In 1995, our economic development efforts proved successful in attracting major
new customers, such as North Star BHP Steel, Worthington Steel and Aluminum
Company of America, while supporting the expansion of existing ones, for
example, American Steel & Wire and Ford Motor Company. We expect that our
continued emphasis on economic development along with a newly developed market
segment focus will be major ingredients in providing improved revenue growth.
 
NUCLEAR OPERATIONS
 
We have interests in three nuclear generating units -- Davis-Besse Nuclear Power
Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry Unit 1) and
Beaver
Valley Power Station Unit 2 (Beaver Valley Unit 2) -- and operate the first two.
Davis-Besse and Beaver Valley Unit 2 both operated extremely well in 1995. Their
average three-year unit availability factors at year-end 1995 of 90% and 87%,
respectively, exceeded the industry average of 81% for similar reactors. In
1995, the availability factor for Davis-Besse was 100%. The plant continues to
have its best run ever operating at or near full capacity for 463 straight days
through February 21, 1996.
 
In 1995, Perry Unit 1 improved its average three-year unit availability factor
to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near
capacity for 506 of 531 days since the end of its last refueling and maintenance
outage in August 1994. Work on the comprehensive course of action plan developed
in 1993 to improve the operating performance of Perry Unit 1 will be completed
during the current refueling outage which began January 27, 1996.
 
A significant part of the strategic plan involves ongoing efforts to increase
the availability and lower the cost of production of our nuclear units. In 1995,
we made great progress regarding unit availability while continuing to lower
production costs. The goal of our nuclear improvement program is to replicate
Davis-Besse's operational excellence and cost reduction gains at Perry Unit 1
while improving performance ratings.
 
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993 and 1994, we increased our decommissioning expense
accruals because of revisions in our cost estimates. See Note 1(d).
 
Our nuclear units may be impacted by activities or events beyond our control.
Operating nuclear 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 to limit or prohibit the operation or licensing of
any domestic nuclear unit. If one of our nuclear units is taken out of service
for an extended period 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, thereby not permitting us to recover our
investment in and earn a return on it, or disallowing certain construction or
maintenance costs. An extended outage coupled with unfavorable rate treatment
could have a material adverse effect on our financial condition
 
 (Centerior Energy)                    F-4                    (Centerior Energy)
<PAGE>   57
 
and results of operations. Premature plant closings could also have a material
adverse effect on our financial condition and results of operations because the
estimated cost to decommission the plant exceeds the current funding in the
decommissioning trust.
 
HAZARDOUS WASTE DISPOSAL SITES
 
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. Allegations that the Operating Companies disposed of
hazardous waste at these sites, and the amount involved, are often
unsubstantiated and subject to dispute. Federal law provides that all PRPs for a
particular site be held liable on a joint and several basis. 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 $500 million. However, we
believe that the actual cleanup costs will be substantially lower than $500
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 $12 million at December 31, 1995, 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.
 
MERGER OF THE OPERATING COMPANIES
 
We continue to seek the necessary regulatory approvals to complete the merger of
the Operating Companies which we announced in 1994. The FERC has deferred action
on the merger application until the merits of the Operating Companies' proposed
open access transmission tariffs are addressed in hearings.
 
CAPITAL RESOURCES AND LIQUIDITY
 
1993-1995 CASH REQUIREMENTS
 
A key part of our strategic plan is to significantly reduce the Operating
Companies' level of debt and preferred stock. In 1995, we were able to continue
the reduction pattern begun in 1994. These obligations were reduced by
$136 million in 1994 and by $134 million in 1995. We intend to continue and to
accelerate redemptions.
 
We need cash for normal corporate operations, retirement of maturing securities,
and an ongoing program of constructing and improving facilities to meet demand
for electric service and to comply with government regulations. Our cash
construction expenditures totaled $209 million in 1993, $205 million in 1994 and
$201 million in 1995. Our debt and preferred stock maturities and sinking fund
requirements totaled $368 million in 1993, $120 million in 1994 and $377 million
in 1995. In addition, we optionally redeemed approximately $470 million in the
period 1993-1995. This amount includes $237 million of tax-exempt issues
refunded in 1995 resulting in approximately $7 million of interest savings. In
May 1995, Cleveland Electric issued $300 million of first mortgage bonds due in
2005 with an interest rate of 9.50%. The embedded cost of the Operating
Companies' debt at the end of 1995 was 8.98% versus 9.12% in 1994 and 9.06% in
1993. In 1995, the Operating Companies renewed for a four-year term
approximately $225 million in bank letters of credit supporting the equity owner
participants in the Beaver Valley Unit 2 lease. See Note 11(d).
 
1996 AND BEYOND CASH REQUIREMENTS
 
Our 1996 cash requirements for construction are
$128 million for Cleveland Electric and $74 million for Toledo Edison and for
debt and preferred stock maturities and sinking fund requirements are $177
million for Cleveland Electric and $58 million for Toledo Edison. We expect to
meet these requirements with internal cash generation, cash reserves and about
$150 million from the sale of a AAA-rated security backed by our accounts
receivable.
 
We expect to meet all of our 1997-2000 cash requirements with internal cash
generation. Estimated cash requirements for our construction program during this
period total $603 million for Cleveland Electric and $262 million for Toledo
Edison. Debt and preferred stock maturities and sinking fund requirements total
$400 million and $233 million for Cleveland Electric and Toledo Edison,
respectively, for the same period. If economical, additional securities may be
redeemed under optional redemption provisions, with funding expected to be
provided through internal cash generation. Additional funding may be required to
support investments in nonregulated business opportunities.
 
 (Centerior Energy)                    F-5                    (Centerior Energy)
<PAGE>   58
 
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. If the applicable interest coverage test is
met, each Operating Company may issue first mortgage bonds on the basis of
property additions and, under certain circumstances, refundable bonds. At
December 31, 1995, Cleveland Electric and Toledo Edison would have been
permitted to issue approximately $379 million and $288 million of additional
first mortgage bonds, respectively.
 
The Operating Companies also are able to raise funds through the sale of debt
and preferred and preference stock. Under its articles of incorporation, Toledo
Edison cannot issue preferred stock unless certain earnings coverage
requirements are met. At December 31, 1995, Toledo Edison would have been
permitted to issue approximately $158 million of additional preferred stock at
an assumed dividend rate of 10.5%. There are no restrictions on Cleveland
Electric's ability to issue preferred or preference stock or Toledo Edison's
ability to issue preference stock. Centerior Energy may raise funds through the
sale of common stock under various employee and share owner plans.
 
The Operating Companies have $307 million in financing vehicles available to
support their nuclear fuel leases, portions of which mature this year. See Note
6. We plan to renew a $125 million revolving credit facility which matures in
May 1996. See Note 12. At the end of 1995, we had $179 million in cash and
temporary investments.
 
The foregoing financing resources are expected to be sufficient for the
Operating Companies' needs over the next several years. However, the
availability and cost of capital to meet external financing needs also depend
upon such factors as financial market conditions and their credit ratings.
Current credit ratings for the Operating Companies are as follows:
 
<TABLE>
<CAPTION>
                                        Standard       Moody's
                                        & Poor's      Investors
                                       Corporation  Service, Inc.
                                       -----------  -------------
<S>                                    <C>          <C>
First mortgage bonds                        BB           Ba2
Subordinated debt for Cleveland
  Electric                                   B+          Ba3
Subordinated debt for Toledo Edison          B+           B1
Preferred stock                              B            b2
</TABLE>
 
RESULTS OF OPERATIONS
 
1995 VS. 1994
 
Factors contributing to the 3.9% increase in 1995 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                            $81
  Wholesale Revenues                                   13
  Fuel Cost Recovery Revenues                           9
  Miscellaneous Revenues                               (8)
                                                      ---
      Total                                           $95
                                                      ---
</TABLE>
 
For the third year in a row, industrial kilowatt-hour sales increased. The
increase in 1995 was 0.8%, but sales grew 2.2% excluding reductions at two
low-margin steel producers (representing 5% of industrial revenues). Residential
and commercial sales increased 3.5% and 2.8%, respectively, primarily because of
the hot summer weather, although there was about 1% nonweather-related growth in
commercial sales. Other sales increased 26% because of a 43% increase in
wholesale sales due principally to the hot summer and good availability of our
generating units. Weather accounted for approximately $38 million of the $61
million increase in 1995 base rate (nonfuel) revenues. Higher 1995 fuel cost
recovery revenues resulted from an increase in the fuel cost factor for
Cleveland Electric. The weighted average of these fuel cost factors increased 7%
for Cleveland Electric but decreased 6% for Toledo Edison.
 
For 1995, operating revenues were 32% residential, 30% commercial, 31%
industrial and 7% other and kilowatt-hour sales were 23% residential, 25%
commercial, 40% industrial and 12% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.10 and $.06,
respectively.
 
Operating expenses increased 4.5% in 1995. Fuel and purchased power expenses
increased as higher fuel expense was partially offset by lower purchased power
expense. The higher fuel expense was attributable to increased generation and
more amortization of previously deferred fuel costs than the amount amortized in
1994. The higher other operation and maintenance expenses resulted primarily
from charges for an ongoing inventory reduction program and the recognition of
costs associated with preliminary engineering studies. Federal income taxes
increased as a result of higher pretax operating income. Taxes, other than
federal income taxes, increased primarily due to property tax increases
resulting from plant additions, real estate valuation increases and a
nonrecurring tax credit recorded in 1994.
 
 (Centerior Energy)                    F-6                    (Centerior Energy)
<PAGE>   59
 
1994 VS. 1993
 
Factors contributing to the 2.1% decrease in 1994 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                           $  10
  Wholesale Revenues                                   (47)
  Fuel Cost Recovery Revenues                          (22)
  Miscellaneous Revenues                                 6
                                                      ----
      Total                                          $ (53)
                                                      ----
</TABLE>
 
We experienced good retail kilowatt-hour sales growth in the industrial and
commercial categories in 1994; the sales growth for the residential category was
lessened by weather conditions, particularly during the summer. The revenue
decrease resulted primarily from milder weather conditions in 1994 and 39% lower
wholesale sales. Weather reduced base rate revenues approximately $15 million
from the 1993 amount. Although total sales decreased by 1.9%, industrial sales
increased 3.3% on the strength of increased sales to large automotive
manufacturers and the broad-based, smaller industrial customer group. This
growth substantiated an economic resurgence in our service area, particularly in
Northwestern Ohio. Residential and commercial sales increased 0.1% and 2.4%,
respectively. Other sales decreased by 28% because of the lower sales to
wholesale customers attributable to expiration of a wholesale power agreement,
softer wholesale market conditions and limited power availability for bulk power
transactions at certain times because of generating plant outages. Lower 1994
fuel cost recovery revenues resulted from favorable changes in the fuel cost
factors. The weighted averages of these factors dropped by 5% and 6% for
Cleveland Electric and Toledo Edison, respectively.
 
For 1994, operating revenues were 31% residential, 30% commercial, 31%
industrial and 8% other and kilowatt-hour sales were 24% residential, 25%
commercial, 41% industrial and 10% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.10 and $.06,
respectively. The changes from 1993 were not significant.
 
Operating expenses were 15% lower in 1994. Operation and maintenance expenses
for 1993 included $218 million of net benefit expenses related to an early
retirement program, called the Voluntary Transition Program (VTP), and other
charges totaling $54 million. A smaller work force and ongoing cost reduction
measures also lowered operation and maintenance expenses. More nuclear
generation and less coal-fired generation accounted for a large part of the
lower fuel and purchased power expenses in 1994. Depreciation and amortization
expenses increased primarily because of higher nuclear plant decommissioning
expenses as discussed in Note 1(d). Deferred operating expenses were greater
primarily because of the write-off of $172 million of phase-in deferred
operating expenses in 1993 as discussed in Note 7(e). The 1993 deferrals also
included $84 million of postretirement benefit curtailment cost deferrals
related to the VTP. See Note 9(b). Federal income taxes increased as a result of
higher pretax operating income.
 
As discussed in Note 4(b), $583 million of our Perry Unit 2 investment was
written off in 1993. Also, as discussed in Note 7, phase-in deferred carrying
charges of $705 million were written off in 1993. The change in the federal
income tax credit amounts for nonoperating income was attributable to these
write-offs.
 
 (Centerior Energy)                    F-7                    (Centerior Energy)
<PAGE>   60
 
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
 
To the Share Owners and
Board of Directors of
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, 1995 and 1994, and the related
consolidated statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1995. These financial
statements and the schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and the schedule 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
 
As discussed further in Note 9, a change was made in the method of accounting
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 schedule of Centerior Energy
Corporation and subsidiaries listed in the Index to Schedules is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states 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 LLP
 
Cleveland, Ohio
February 21, 1996
 
 (Centerior Energy)                    F-8                    (Centerior Energy)
<PAGE>   61
 
INCOME STATEMENT                   Centerior Energy Corporation and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                       For the years ended December
                                                                                   31,
                                                                       ----------------------------
                                                                        1995       1994       1993
                                                                       ------     ------     ------
                                                                          (millions of dollars,
                                                                        except per share amounts)
<S>                                                                    <C>        <C>        <C>
OPERATING REVENUES                                                     $2,516     $2,421     $2,474
                                                                       ------     ------     ------
OPERATING EXPENSES
  Fuel and purchased power                                                465        442        474
  Other operation and maintenance                                         617        595        652
  Generation facilities rental expense, net                               160        160        159
  Early retirement program expenses and other                              --         --        272
                                                                       ------     ------     ------
     Total operation and maintenance                                    1,242      1,197      1,557
  Depreciation and amortization                                           281        278        258
  Taxes, other than federal income taxes                                  322        309        312
  Deferred operating expenses, net                                        (53)       (55)        23
  Federal income taxes                                                    135        114         11
                                                                       ------     ------     ------
                                                                        1,927      1,843      2,161
                                                                       ------     ------     ------
OPERATING INCOME                                                          589        578        313
                                                                       ------     ------     ------
NONOPERATING INCOME (LOSS)
  Allowance for equity funds used during construction                       3          5          5
  Other income and deductions, net                                          6          8         (6)
  Write-off of Perry Unit 2                                                --         --       (583)
  Deferred carrying charges, net                                           43         40       (649)
  Federal income taxes -- credit (expense)                                 (5)        (6)       398
                                                                       ------     ------     ------
                                                                           47         47       (835)
                                                                       ------     ------     ------
INCOME (LOSS) BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS             636        625       (522)
                                                                       ------     ------     ------
INTEREST CHARGES AND PREFERRED DIVIDENDS
  Debt interest                                                           358        361        359
  Allowance for borrowed funds used during construction                    (3)        (6)        (5)
  Preferred dividend requirements of subsidiaries                          61         66         67
                                                                       ------     ------     ------
                                                                          416        421        421
                                                                       ------     ------     ------
NET INCOME (LOSS)                                                      $  220     $  204     $ (943)
                                                                       ------     ------     ------
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (MILLIONS)                  148.0      147.8      144.9
                                                                       ------     ------     ------
EARNINGS (LOSS) PER COMMON SHARE                                       $ 1.49     $ 1.38     $(6.51)
                                                                       ------     ------     ------
DIVIDENDS DECLARED PER COMMON SHARE                                    $  .80     $  .80     $ 1.60
                                                                       ------     ------     ------
</TABLE>
 
RETAINED EARNINGS
 
<TABLE>
<CAPTION>
                                                                           For the years ended
                                                                              December 31,
                                                                       ---------------------------
                                                                       1995      1994       1993
                                                                       -----     -----     -------
                                                                          (millions of dollars)
<S>                                                                    <C>       <C>       <C>
RETAINED EARNINGS (DEFICIT) AT BEGINNING OF YEAR                       $(438)    $(523)    $   652
                                                                       -----     ------      -----        
ADDITIONS
  Net income (loss)                                                      220       204        (943)
DEDUCTIONS
  Common stock dividends                                                (118)     (118)       (231)
  Other, primarily preferred stock redemption expenses of
     subsidiaries                                                          -        (1)         (1)
                                                                       -----     ------      -----
                                                                                                  
     Net Increase (Decrease)                                             102        85      (1,175)
                                                                       -----     ------      -----
                                                                                                  
RETAINED EARNINGS (DEFICIT) AT END OF YEAR                             $(336)    $(438)    $  (523)
                                                                       -----     ------      -----                       
</TABLE>
 
The accompanying notes are an integral part of these statements.
 
 (Centerior Energy)                    F-9                    (Centerior Energy)
<PAGE>   62
 
BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                                        December 31,
                                                                                     ------------------
                                                                                      1995       1994
                                                                                     -------    -------
                                                                                        (millions of
                                                                                          dollars)
<S>                                                                                  <C>        <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
  Utility plant in service                                                           $ 9,768    $ 9,770
     Less: accumulated depreciation and amortization                                   3,036      2,906
                                                                                     -------    -------
                                                                                       6,732      6,864
  Construction work in progress                                                          101        129
                                                                                     -------    -------
                                                                                       6,833      6,993
  Nuclear fuel, net of amortization                                                      200        293
  Other property, less accumulated depreciation                                          102         50
                                                                                     -------    -------
                                                                                       7,135      7,336
                                                                                     -------    -------
CURRENT ASSETS
  Cash and temporary cash investments                                                    179        186
  Amounts due from customers and others, net                                             223        211
  Unbilled revenues                                                                      100         93
  Materials and supplies, at average cost                                                120        139
  Fossil fuel inventory, at average cost                                                  31         29
  Taxes applicable to succeeding years                                                   255        252
  Other                                                                                   18         16
                                                                                     -------    -------
                                                                                         926        926
                                                                                     -------    -------
REGULATORY AND OTHER ASSETS
  Amounts due from customers for future federal income taxes, net                      1,067      1,046
  Unamortized loss from Beaver Valley Unit 2 sale                                         96        101
  Unamortized loss on reacquired debt                                                     89         86
  Carrying charges and operating expenses                                              1,053        957
  Nuclear plant decommissioning trusts                                                   114         82
  Other                                                                                  163        157
                                                                                     -------    -------
                                                                                       2,582      2,429
                                                                                     -------    -------
       Total Assets                                                                  $10,643    $10,691
                                                                                     -------    -------
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Centerior Energy)                    F-10                   (Centerior Energy)
<PAGE>   63
 
                                   Centerior Energy Corporation and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                                        December 31,
                                                                                     ------------------
                                                                                      1995       1994
                                                                                     -------    -------
                                                                                        (millions of
                                                                                          dollars)
<S>                                                                                  <C>        <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
  Common shares, without par value (stated value of $357 million for both 1995 and
     1994):
     180 million authorized; 148 million (excluding 2.7 million shares in Treasury)
     outstanding in both 1995 and 1994                                               $ 2,320    $ 2,320
  Retained earnings (deficit)                                                           (336)      (438)
                                                                                     -------    -------
     Common stock equity                                                               1,984      1,882
  Preferred stock
     With mandatory redemption provisions                                                220        253
     Without mandatory redemption provisions                                             451        451
  Long-term debt                                                                       3,734      3,697
                                                                                     -------    -------
                                                                                       6,389      6,283
                                                                                     -------    -------
CURRENT LIABILITIES
  Current portion of long-term debt and preferred stock                                  235        373
  Current portion of nuclear fuel lease obligations                                       95         83
  Accounts payable                                                                       153        144
  Accrued taxes                                                                          374        384
  Accrued interest                                                                        83         90
  Other                                                                                   87         75
                                                                                     -------    -------
                                                                                       1,027      1,149
                                                                                     -------    -------
DEFERRED CREDITS AND OTHER LIABILITIES
  Unamortized investment tax credits                                                     263        279
  Accumulated deferred federal income taxes                                            1,875      1,778
  Unamortized gain from Bruce Mansfield Plant sale                                       499        525
  Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2          145        139
  Nuclear fuel lease obligations                                                         137        219
  Retirement benefits                                                                    179        176
  Other                                                                                  129        143
                                                                                     -------    -------
                                                                                       3,227      3,259
                                                                                     -------    -------
          Total Capitalization and Liabilities                                       $10,643    $10,691
                                                                                     -------    -------
</TABLE>
 
 (Centerior Energy)                    F-11                   (Centerior Energy)
<PAGE>   64
 
CASH FLOWS                         Centerior Energy Corporation and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                            For the years ended December
                                                                                         31,
                                                                            -----------------------------
                                                                             1995       1994       1993
                                                                            ------     ------     -------
                                                                                (millions of dollars)
<S>                                                                         <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES (1)
  Net Income (Loss)                                                         $  220     $  204     $  (943)
                                                                              ----     ------      ------
  Adjustments to Reconcile Net Income (Loss) to Cash from Operating
     Activities:
     Depreciation and amortization                                             281        278         258
     Deferred federal income taxes                                              72         95        (452)
     Unbilled revenues                                                          (7)        31         (10)
     Deferred fuel                                                               6        (17)          5
     Deferred carrying charges, net                                            (43)       (40)        649
     Leased nuclear fuel amortization                                          125         98          86
     Deferred operating expenses, net                                          (53)       (55)         23
     Allowance for equity funds used during construction                        (3)        (5)         (5)
     Noncash early retirement program expenses, net                             --         --         208
     Write-off of Perry Unit 2                                                  --         --         583
     Changes in amounts due from customers and others, net                     (12)        10           1
     Changes in inventories                                                     17         --          26
     Changes in accounts payable                                                 9        (44)         45
     Changes in working capital affecting operations                           (10)        --          25
     Other noncash items                                                         9         14          18
                                                                              ----     ------      ------
       Total Adjustments                                                       391        365       1,460
                                                                              ----     ------      ------
          Net Cash from Operating Activities                                   611        569         517
                                                                              ----     ------      ------
CASH FLOWS FROM FINANCING ACTIVITIES (2)
  Bank loans, commercial paper and other short-term debt                        --         --         (50)
  First mortgage bond issues                                                   542         77         300
  Secured medium-term note issues                                               --         --         128
  Term bank loans and other long-term debt issues                               --         --          40
  Preferred stock issues                                                        --         --         100
  Common stock issues                                                           --         12          71
  Reacquired common stock                                                       --         --           1
  Maturities, redemptions and sinking funds                                   (683)      (214)       (434)
  Nuclear fuel lease obligations                                              (102)      (110)       (106)
  Common stock dividends paid                                                 (118)      (118)       (231)
  Premiums, discounts and expenses                                             (17)        (1)        (13)
                                                                              ----     ------      ------
          Net Cash from Financing Activities                                  (378)      (354)       (194)
                                                                              ----     ------      ------
CASH FLOWS FROM INVESTING ACTIVITIES (2)
  Cash applied to construction                                                (201)      (205)       (209)
  Interest capitalized as allowance for borrowed funds used during
     construction                                                               (3)        (6)         (5)
  Contributions to nuclear plant decommissioning trusts                        (24)       (26)         (9)
  Other cash received (applied)                                                (12)       (17)         32
                                                                              ----     ------      ------
          Net Cash from Investing Activities                                  (240)      (254)       (191)
                                                                              ----     ------      ------
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS                               (7)       (39)        132
                                                                              ----     ------      ------
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR                       186        225          93
                                                                              ----     ------      ------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR                          $  179     $  186     $   225
                                                                              ----     ------      ------
</TABLE>
 
---------------
 
<TABLE>
<S>                                                                         <C>        <C>        <C>
(1) Interest paid (net of amounts capitalized)                              $  306     $  300     $   295
                                                                            ------     ------     -------
    Income taxes paid                                                       $   89     $    6     $    50
                                                                            ------     ------     -------
</TABLE>
 
(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-12                   (Centerior Energy)
<PAGE>   65
 
STATEMENT OF PREFERRED STOCK       Centerior Energy Corporation and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                          Current       December 31,
                                                         1995 Shares     Call Price     -------------
                                                         Outstanding     Per Share      1995     1994
                                                         -----------     ----------     ----     ----
                                                                                        (millions of
                                                                                          dollars)
<S>                          <C>                         <C>             <C>            <C>      <C>
CLEVELAND ELECTRIC
  Without par value, 4,000,000 preferred shares authorized
     Subject to mandatory redemption:
                      $7.35  Series C                       130,000      $  101.00      $ 13     $ 14
                      88.00  Series E                        15,000       1,015.30        15       18
                 Adjustable  Series M                            --          --           --       10
                      9.125  Series N                       300,000         101.00        30       41
                      91.50  Series Q                        64,286       1,000.00        64       75
                      88.00  Series R                        50,000          --           50       50
                      90.00  Series S                        74,000          --           73       74
                                                                                        ----     ----
                                                                                         245      282
     Less: Current maturities                                                             30       36
                                                                                        ----     ----
                                                                                         215      246
                                                                                        ----     ----
     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         100.00        49       49
                      42.40  Series T                       200,000          --           97       97
                                                                                        ----     ----
                                                                                         241      241
                                                                                        ----     ----
TOLEDO EDISON
  $100 par value, 3,000,000 preferred shares authorized;
     $25 par value, 12,000,000 preferred shares authorized
     Subject to mandatory redemption:
                      $100 par
                             $9.375                          66,850         101.48         7        8
                        25 par
                              2.81                               --          --           --       10
                                                                                        ----     ----
                                                                                           7       18
     Less: Current maturities                                                              2       11
                                                                                        ----     ----
                                                                                           5        7
                                                                                        ----     ----
     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          25.00        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                             $220     $253
                                                                                        ====     ====
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS                          $451     $451
                                                                                        ====     ====
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Centerior Energy)                    F-13                   (Centerior Energy)
<PAGE>   66
 
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, with service areas in Northern Ohio. The
consolidated financial statements also include the accounts of Centerior
Energy's wholly owned subsidiary, Centerior Service Company (Service Company),
and its three other wholly owned subsidiaries, which in the aggregate are not
material. The Service Company provides management, financial, administrative,
engineering, legal and other services at cost to Centerior Energy, the Operating
Companies and the other subsidiaries. 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 FERC and adopted by the PUCO. Rate-regulated
utilities are subject to SFAS 71 which governs accounting for the effects of
certain types of rate regulation. Pursuant to SFAS 71, certain incurred costs
are deferred for recovery in future rates. See Note 7. The Service Company
follows the Uniform System of Accounts for Mutual Service Companies prescribed
by the Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935.
 
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and
the disclosure of contingent assets and liabilities. The estimates are based on
an analysis of the best information available. Actual results could differ from
those estimates.
 
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 joint
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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
 
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 1995, 3.4% in 1994 and 3.5% in 1993. The
annual straight-line depreciation rate for nuclear property is 2.5%. In
conjunction with the Operating Companies' pending rate case, we have asked the
PUCO to approve an increase of this depreciation rate to approximately 3%.
 
The Operating Companies accrue the estimated costs of decommissioning their
three nuclear generating units.
 
 (Centerior Energy)                    F-14                   (Centerior Energy)
<PAGE>   67
 
The accruals are required to be funded in an external trust. The PUCO requires
that the expense and payments to the external trusts be determined on a
levelized basis by dividing the unrecovered decommissioning costs in current
dollars by the remaining years in the licensing period of each unit. This
methodology requires that the net earnings on the trusts be reinvested therein
with the intent of having net earnings offset inflation. The PUCO requires that
the estimated costs of decommissioning and the funding level be reviewed at
least every five years.
 
In 1994, the Operating Companies increased their annual decommissioning expense
accruals to $24 million from the $12 million level in 1993. The accruals are
reflected in current rates. The increased accruals in 1994 were derived from
updated, site-specific studies for each of the units. The revised estimates
reflect the DECON method of decommissioning (prompt decontamination), and the
locations and cost characteristics specific to the units, and include costs
associated with decontamination, dismantlement and site restoration.
 
The revised estimates for the units in 1993 and 1992 dollars and in dollars at
the time of license expiration, assuming a 4% annual inflation rate, are as
follows:
 
<TABLE>
<CAPTION>
                                    License
                                   Expiration                Future
        Generating Unit               Year        Amount     Amount
-------------------------------    ----------     ------     ------
                                                    (millions of
                                                      dollars)
<S>                                <C>            <C>        <C>
Davis-Besse                           2017         $346(1)   $ 862
Perry Unit 1                          2026          256(1)     908
Beaver Valley Unit 2                  2027          114(2)     423
                                                   ----      ------
      Total                                        $716      $2,193
                                                   ----      ------
</TABLE>
 
---------------
 
(1) Dollar amounts in 1993 dollars.
(2) Dollar amount in 1992 dollars.
 
The updated estimates reflect substantial increases from the prior
PUCO-recognized aggregate estimates of $257 million
in 1987 and 1986 dollars.
 
The classification, Accumulated Depreciation and Amortization, in the Balance
Sheet at December 31, 1995 includes $130 million of decommissioning costs
previously expensed and the earnings on the external trust 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. The trust
earnings are recorded as an increase to the trust assets and the related
component of the decommissioning reserve (included in Accumulated Depreciation
and Amortization).
 
The staff of the SEC has questioned certain of the current accounting practices
of the electric utility industry, including those of the Operating Companies,
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating stations in the financial statements. In response
to these questions, the Financial Accounting Standards Board (FASB) is reviewing
the accounting for removal costs, including decommissioning. If current
accounting practices are changed, the annual provision for decommissioning could
increase; the estimated cost for decommissioning could be recorded as a
liability rather than as accumulated depreciation; and trust fund income from
the external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense. The FASB issued an
exposure draft on the subject on February 7, 1996.
 
(E) PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment are stated at original cost less amounts
disallowed by the PUCO. Construction costs include related payroll taxes,
retirement benefits, 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 11.5% in
1995, 9.8% in 1994 and 9.9% in 1993.
 
Maintenance and repairs for plant and equipment 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.
 
(F) 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. See Note 7(a). These
amortizations and the lease expense amounts are reported in the Income Statement
as Generation Facilities Rental Expense, Net.
 
(G) 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
 
 (Centerior Energy)                    F-15                   (Centerior Energy)
<PAGE>   68
 
with the regulatory rate treatment. See Note 7(a). 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.
 
(H) FEDERAL INCOME TAXES
We use the liability method of accounting for income taxes in accordance with
SFAS 109. See Note 8. 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. See Note
7(a).
 
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7(d) 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. These
leases extend through 2017 and 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 renew the leases. The leases
include conditions for mandatory termination (and possible repurchase of the
leasehold interest) for events of default.
 
Future minimum lease payments under the operating leases at December 31, 1995
are summarized as follows:
 
<TABLE>
<CAPTION>
                      Year
-------------------------------------------------     Amount
                                                   ------------
                                                   (millions of
                                                     dollars)
<S>                                                <C>
1996                                                  $  188
1997                                                     165
1998                                                     165
1999                                                     178
2000                                                     187
Later Years                                            3,052
                                                      ------
      Total Future Minimum Lease Payments             $3,935
                                                      ------
</TABLE>
 
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1995, 1994 and 1993 as annual rental expense for the
Mansfield Plant leases was $115 million. The amounts recorded in 1995, 1994 and
1993 as annual rental expense for the Beaver Valley Unit 2 lease were $63
million, $64 million and $63 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.
 
(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, 1995 includes the following
 
 (Centerior Energy)                    F-16                   (Centerior Energy)
<PAGE>   69
 
facilities owned by the Operating Companies as tenants in common with other
utilities and Lessors:
 
<TABLE>
<CAPTION>
                                          Property,
                                          Plant and
                         Ownership        Equipment
                         Megawatts      (Exclusive of     Accumulated
    Generating Unit      (% Share)      Nuclear Fuel)     Depreciation
------------------------ ----------     -------------     ------------
                                        (millions of dollars)
<S>                      <C>            <C>               <C>
Seneca Pumped Storage    351 (80.00%)      $    65            $ 22
Eastlake Unit 5          411 (68.80)           159              --
Perry Unit 1             609 (51.02)         2,831             575
Beaver Valley Unit 2 and
  Common Facilities
  (Note 2)               214 (26.12)         1,485             332
                                            ------          ------
      Total                                $ 4,540            $929
                                            ------          ------
</TABLE>
 
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 1996-2000 period is
$1.107 billion, including AFUDC of $40 million and excluding nuclear fuel.
 
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other
things, significant reductions in the emission of sulfur dioxide and nitrogen
oxides by fossil-fueled generating units. Our strategy provides for compliance
primarily through greater use of low-sulfur coal at some of our units and the
use of emission allowances. Total capital expenditures from 1991 through 1995 in
connection with Clean Air Act compliance amounted to $50 million. The plan will
require additional capital expenditures over the 1996-2005 period of
approximately $90 million for nitrogen oxide control equipment and other plant
process modifications. In addition, higher fuel and other operation and
maintenance expenses will be incurred. 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.
 
(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. 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.
 
(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 sites. The
Operating Companies have accrued a liability totaling $12 million at December
31, 1995 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.
 
(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 the discussion of these and
other risks in Management's Financial Analysis -- Outlook-Nuclear Operations.
 
(B) NUCLEAR INSURANCE
 
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have
insurance coverage for damage to property at these sites (including leased fuel
and cleanup costs). Coverage amounted to $2.75 billion for each site as of
January 1, 1996. 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. In
addition, we can be assessed a maximum of $42 million under these policies
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.
 
 (Centerior Energy)                    F-17                   (Centerior Energy)
<PAGE>   70
 
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 80% 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 $307 million ($157 million from
intermediate-term notes and $150 million from bank credit arrangements). The
intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996
and $73 million in September 1997). The bank credit arrangements terminate in
October 1996. The special-purpose corporation plans to obtain alternate
financing in 1996 to replace the $234 million of financing expiring in 1996. At
December 31, 1995, $236 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 $79 million, $55
million and $35 million, respectively, at December 31, 1995. The nuclear fuel
amounts financed and capitalized also included interest charges incurred by the
lessors amounting to $5 million in 1995, $11 million in 1994 and $14 million in
1993. The estimated future lease amortization payments based on projected
consumption are $96 million in 1996, $82 million in 1997, $68 million in 1998,
$65 million in 1999 and $62 million in 2000.
 
(7) REGULATORY MATTERS
 
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
 
The Operating Companies are subject to the provisions of SFAS 71 and have
complied with its provisions. SFAS 71 provides, among other things, for the
deferral of certain incurred costs that are probable of future recovery in
rates. We monitor changes in market and regulatory conditions and consider the
effects of such changes in assessing the continuing applicability of SFAS 71.
Criteria that could give rise to discontinuation of the application of SFAS 71
include: (1) increasing competition which significantly restricts the Operating
Companies' ability to charge prices which allow us to recover operating costs,
earn a fair return on invested capital and recover the amortization of
regulatory assets and (2) a significant change in the manner in which rates are
set by the PUCO from cost-based regulation to some other form of regulation.
Regulatory assets represent probable future revenues to the Operating Companies
associated with certain incurred costs, which they will recover from customers
through the rate-making process.
 
Effective January 1, 1996, the Operating Companies adopted SFAS 121 which
imposes stricter criteria for carrying regulatory assets than SFAS 71 by
requiring that such assets be probable of recovery at each balance sheet date.
The criteria under SFAS 121 for plant assets require such assets to be written
down only if the book value exceeds the projected net future cash flows.
 
Regulatory assets in the Balance Sheet are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                               ---------------
                                                1995     1994
                                               ------   ------
                                                (millions of
                                                  dollars)
<S>                                            <C>      <C>
Amounts due from customers for future federal
  income taxes, net                            $1,067   $1,046
Unamortized loss from Beaver Valley Unit 2
  sale                                             96      101
Unamortized loss on reacquired debt                89       86
Pre-phase-in deferrals*                           553      570
Rate Stabilization Program deferrals              500      387
                                               ------   ------
    Total                                      $2,305   $2,190
                                               ------   ------
</TABLE>
 
* Represent deferrals of operating expenses and carrying charges for Perry Unit
  1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the
  lives of the related property.
 
As of December 31, 1995, customer rates provide for recovery of all the above
regulatory assets, except those related to the Rate Stabilization Program
discussed below. The remaining recovery periods for all of the regulatory assets
listed above range from 16 to 33 years.
 
(B) RATE CASE
 
In April 1995, the Operating Companies filed requests with the PUCO for price
increases aggregating $119 million annually to be effective in 1996. The price
increases are necessary to recover cost increases and amortization of certain
costs deferred since 1992 pursuant to the Rate Stabilization Program. If their
requests are approved, the Operating Companies intend to freeze prices until at
least 2002 with the expectation that increased sales and cost control measures
will preclude the need for further price increases. If circumstances make it
impossible to earn a fair return for share owners
 
 (Centerior Energy)                    F-18                   (Centerior Energy)
<PAGE>   71
 
over time, we would ask for a further increase, but only after taking all
appropriate actions to make such a request unnecessary.
 
In November 1995, the PUCO Staff issued its report addressing the Operating
Companies' rate case. The Staff recommended that the PUCO grant the full $119
million price increase requested. However, the Staff also recommended that the
price increase be conditioned upon the Operating Companies' commitment "to a
significant revaluation of their asset bases over some finite period of time."
 
In December 1995, the PUCO ordered an investigation into the financial
condition, rates and practices of the Operating Companies to identify outcomes
and remedies other than those routinely applied during the rate case process.
 
In late January 1996, the Staff proposed an incremental reduction (currently,
$1.25 billion) beyond the normal level in nuclear plant and regulatory assets
within five years. The Staff proposed that the Operating Companies have
flexibility to determine how to achieve this incremental asset revaluation, but
no additional price increases to recover the accelerated asset revaluation were
proposed. Any incremental revaluation of assets would be for regulatory purposes
and would cause prices and revenues after the five-year period to be lower than
they otherwise would be in conjunction with any rate case following such
revaluation. The Staff's asset revaluation proposal represents a substantial
change in the form of rate-making traditionally followed by the PUCO and is
inconsistent with the Ohio statutes that define the rate-making process. The
PUCO is not bound by the recommendations of the Staff. A decision by the PUCO is
anticipated in the second quarter of 1996.
 
(C) ASSESSMENT OF POTENTIAL OUTCOMES
 
We continually assess the effects of competition and the changing industry and
regulatory environment on operations, our ability to recover regulatory assets
and our ability to continue application of SFAS 71. If, as a result of the
pending rate case or other events, we determine that the Operating Companies no
longer meet the criteria for SFAS 71, we would be required to record a
before-tax charge to write off the regulatory assets shown above and evaluate
whether property, plant and equipment should be written down. In the more likely
event that only a portion of operations (such as nuclear operations) no longer
meets the criteria of SFAS 71, a write-off would be limited to regulatory
assets, if any, that are not reflected in our cost-based prices established for
the remaining regulated operations. In addition, we would be required to
evaluate whether the changes in the competitive and regulatory environment which
led to discontinuing the application of SFAS 71 to a portion of our operations
would also result in a write-down of property, plant and equipment pursuant to
SFAS 121.
 
We believe application of SFAS 121 in that event will not result in a write-off
of regulatory assets unless the PUCO denies recovery of such assets or if we
conclude, as a result of the outcome of our pending rate case or some other
event, that recovery is not probable for some or all of the regulatory assets.
Furthermore, a write-down under SFAS 121 of property, plant and equipment is not
expected.
 
(D) RATE STABILIZATION PROGRAM
 
The Rate Stabilization Program that the PUCO approved in October 1992 allowed
the Operating Companies to defer and subsequently amortize and recover certain
costs not currently recovered in rates and to accelerate amortization of certain
benefits during the 1992-1995 period. Recovery of the deferrals will begin with
the effective date of the PUCO's orders in the pending rate case. The regulatory
assets recorded included the deferral of post-in-service interest carrying
charges, depreciation expense and property taxes on assets placed in service
after February 29, 1988, the deferral of incremental expenses resulting from the
adoption of SFAS 106 (see Note 9(b)), and the deferral by Toledo Edison of the
operating expenses equivalent to an accumulated excess rent reserve for Beaver
Valley Unit 2 (which resulted from the April 1992 refinancing of Secured Lease
Obligation Bonds issued by a special purpose corporation). The cost deferrals
recorded in 1995, 1994 and 1993 pursuant to these provisions were $113 million,
$112 million and $191 million, respectively. The regulatory accounting measures
also provided for the accelerated amortization of certain unrestricted excess
deferred tax and unrestricted investment tax credit balances and an excess
interim spent fuel storage accrual balance for Davis-Besse. The total annual
amount of such accelerated benefits was $46 million in 1995, 1994 and 1993.
 
(E) PHASE-IN DEFERRALS
 
In 1993, upon completing a comprehensive study which led to our strategic plan,
we concluded that projected revenues would not provide for recovery of deferrals
recorded pursuant to phase-in plans approved by the PUCO in 1989 and,
consequently, that the deferrals would have to be written off. Such deferrals
were scheduled to be recovered in 1994 through 1998. The total
 
 (Centerior Energy)                    F-19                   (Centerior Energy)
<PAGE>   72
 
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).
 
(8) FEDERAL INCOME TAX
The components of federal income tax expense (credit) recorded in the Income
Statement were as follows:
 
<TABLE>
<CAPTION>
                                         1995    1994    1993
                                         -----   -----   -----
                                         (millions of dollars)
<S>                                      <C>     <C>     <C>
Operating Expenses:
  Current                                $ 88    $ 70    $  99
  Deferred                                 47      44      (88)
                                         ----    ----    -----
    Total Charged to Operating Expenses   135     114       11
                                         ----    ----    -----
Nonoperating Income:
  Current                                 (20 )   (45 )    (34)
  Deferred                                 25      51     (364)
                                         ----    ----    -----
    Total Expense (Credit) to
      Nonoperating Income                   5       6     (398)
                                         ----    ----    -----
Total Federal Income Tax Expense
  (Credit)                               $140    $120    $(387)
                                         ----    ----    -----
</TABLE>
 
The deferred federal income tax expense results from the temporary differences
that arise from the different years certain expenses are recognized for tax
purposes as opposed to financial reporting purposes. Such temporary differences
affecting operating expenses relate principally to depreciation and deferred
operating expenses whereas those affecting nonoperating income principally
relate to deferred carrying charges and the 1993 write-offs.
 
Federal income tax, computed by multiplying the income before taxes and
preferred dividend requirements of subsidiaries by the 35% statutory rate, is
reconciled to the amount of federal income tax recorded on the books as follows:
 
<TABLE>
<CAPTION>
                                          1995   1994    1993
                                          ----   ----   -------
                                          (millions of dollars)
<S>                                       <C>    <C>    <C>
Book Income (Loss) Before Federal
  Income Tax                              $421   $390   $(1,263)
                                          ----   ----     -----
Tax (Credit) on Book Income (Loss) at
  Statutory Rate                          $147   $137   $  (442)
Increase (Decrease) in Tax:
    Write-off of Perry Unit 2               --     --        46
    Write-off of phase-in deferrals         --     --        28
    Depreciation                             7      3        (6)
    Rate Stabilization Program             (27)   (27)      (30)
    Other items                             13      7        17
                                          ----   ----     -----
Total Federal Income Tax Expense
  (Credit)                                $140   $120   $  (387)
                                          ----   ----     -----
</TABLE>
 
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994
and resulted in a $327 million loss with a corresponding $114 million reduction
in federal income tax liability. Because of the alternative minimum tax (AMT),
$65 million of the $114 million was realized in 1994. The remaining $49 million
will not be realized until 1999. Additionally, a repayment of approximately $29
million of previously allowed investment tax credits was recognized in 1994.
 
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $604 million and deferred tax liabilities of $2.479 billion at
December 31, 1995 and deferred tax assets of $596 million and deferred tax
liabilities of $2.374 billion at December 31, 1994. These are summarized as
follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                               ---------------
                                                1995     1994
                                               ------   ------
                                                (millions of
                                                  dollars)
<S>                                            <C>      <C>
Property, plant and equipment                  $2,095   $2,035
Deferred carrying charges and operating           224      215
  expenses
Net operating loss carryforwards                 (113)    (144)
Investment tax credits                           (145)    (156)
Sale and leaseback transactions                  (127)    (128)
Other                                             (59)     (44)
                                               ------   ------
    Net deferred tax liability                 $1,875   $1,778
                                               ------   ------
</TABLE>
 
For tax purposes, net operating loss (NOL) carryforwards of approximately $322
million are available to reduce future taxable income and will expire in 2005
through 2009. The 35% tax effect of the NOLs is $113 million. Additionally, AMT
credits of $213 million that may be carried forward indefinitely are available
to reduce future tax.
 
(9) RETIREMENT BENEFITS
 
(A) RETIREMENT INCOME PLAN
 
We sponsor a noncontributing pension plan which covers all employee groups. 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 offset by a credit of $81 million resulting from a settlement of
pension obligations through lump sum payments to almost all the VTP retirees.
 
Pension and VTP costs (credits) for 1993 through 1995 were comprised of the
following components:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Pension Costs (Credits):
  Service cost for benefits earned
    during the period                     $ 10    $ 13    $ 15
  Interest cost on projected benefit
    obligation                              26      26      37
  Actual return on plan assets             (53)     (2)    (65)
  Net amortization and deferral              9     (34)      4
                                           ---     ---     ---
    Net pension costs (credits)             (8)      3      (9)
  VTP cost                                  --      --     205
  Settlement gain                           --      --     (81)
                                           ---     ---     ---
    Net costs (credits)                   $ (8)   $  3    $115
                                           ---     ---     ---
</TABLE>
 
 (Centerior Energy)                    F-20                   (Centerior Energy)
<PAGE>   73
 
The following table presents a reconciliation of the funded status of the plan.
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Actuarial present value of benefit
  obligations:
  Vested benefits                               $304     $278
  Nonvested benefits                               2        2
                                                ----     ----
    Accumulated benefit obligation               306      280
  Effect of future compensation levels            54       37
                                                ----     ----
    Total projected benefit obligation           360      317
Plan assets at fair market value                 394      362
                                                ----     ----
    Funded status                                 34       45
Unrecognized net gain from variance
  between assumptions and experience             (68)     (79)
Unrecognized prior service cost                   15       10
Transition asset at January 1, 1987 being
  amortized
  over 19 years                                  (36)     (39)
                                                ----     ----
    Net accrued pension liability included in
      Retirement Benefits in the Balance Sheet  $(55)    $(63)
                                                ----     ----
</TABLE>
 
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995, the settlement (discount) rate and long-term rate of return
on plan assets assumptions were 8% and 11%, respectively. The long-term rate of
annual compensation increase assumption was 3.5% in 1996 and 1997 and 4%
thereafter. At December 31, 1994, the settlement rate and long-term rate of
return on plan assets assumptions were 8.5% and 10%, respectively. The long-term
rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and
4% thereafter.
Plan assets consist primarily of investments in common stock, bonds, guaranteed
investment contracts, cash equivalent securities and real estate.
 
(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. 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. Prior to 1993, the costs of these benefits were
expensed as paid, which was consistent with rate-making practices.
 
The components of the total postretirement benefit costs for 1993 through 1995
were as follows:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Service cost for benefits earned during
  the period                              $ 2     $ 2     $  3
Interest cost on accumulated
  postretirement benefit obligation        18      18       16
Amortization of transition obligation
  at January 1, 1993 of $167 million
  over 20 years                             7       8        8
Amortization of gain                       (1 )    --       --
VTP curtailment cost (includes $16
  million transition obligation
  adjustment)                              --      --       84
                                          ---     ---      ---
  Total costs                             $26     $28     $111
                                          ---     ---      ---
</TABLE>
 
In 1995, 1994 and 1993, we deferred incremental SFAS 106 expenses (in excess of
the amounts paid) of $4 million, $6 million and $96 million, respectively,
pursuant to a provision of the Rate Stabilization Program. See Note 7(d).
 
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995    1994
                                                -----   -----
                                                (millions of
                                                  dollars)
<S>                                             <C>     <C>
Accumulated postretirement benefit obligation
  attributable to:
  Retired participants                          $(200)  $(203)
  Fully eligible active plan participants          (3)     (1)
  Other active plan participants                  (28)    (21)
                                                -----   -----
    Accumulated postretirement benefit
      obligation                                 (231)   (225)
Unrecognized net gain from variance between
  assumptions and experience                      (21)    (23)
Unamortized transition obligation                 128     135
                                                -----   -----
    Accrued postretirement benefit cost
      included in Retirement Benefits in the
      Balance Sheet                             $(124)  $(113)
                                                -----   -----
</TABLE>
 
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995 and 1994, the settlement rate and the long-term rate of annual
compensation increase assumptions were the same as those discussed for pension
reporting in Note 9(a). At December 31, 1995, the assumed annual health care
cost trend rates (applicable to gross eligible charges) were 8% for medical and
7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by
2003. 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 one percentage point in
each future year, the accumulated postretirement benefit obligation as of
December 31, 1995 would increase by $6 million and the aggregate of the service
and interest cost
 
 (Centerior Energy)                    F-21                   (Centerior Energy)
<PAGE>   74
 
components of the annual postretirement benefit cost would increase by $0.5
million.
 
(10) GUARANTEES
 
Cleveland Electric has guaranteed certain loan and lease obligations of two coal
suppliers under two long-term coal supply contracts. Toledo Edison is a party to
one of these contracts. At December 31, 1995, the principal amount of the loan
and lease obligations guaranteed by the Operating Companies under both contracts
was $53 million. In addition, under the contract to which Toledo Edison is not a
party, Cleveland Electric may be responsible for mine closing costs when the
contract is terminated. At December 31, 1995, the unfunded costs of closing this
mine as estimated by the supplier were $32 million.
 
The prices under both contracts which include certain minimum payments are
sufficient to satisfy the loan and lease obligations and mine closing costs over
the lives of the contracts. If either contract is terminated early for any
reason, the Operating Companies would attempt to reduce the termination charges
and would ask the PUCO to allow recovery of such charges from customers through
the fuel factor of the respective Operating Company.
 
(11) CAPITALIZATION
 
(A) CAPITAL STOCK TRANSACTIONS AND COMMON SHARES RESERVED FOR ISSUE
 
Shares sold, retired and purchased for treasury during the three years ended
December 31, 1995 are listed in the following table.
 
<TABLE>
<CAPTION>
                                      1995      1994      1993
                                      ----     ------     -----
                                        (thousands of shares)
<S>                                   <C>      <C>        <C>
Centerior Energy Common Stock:
  Dividend Reinvestment and Stock
    Purchase Plan                       --        683     3,542
  Employee Savings Plan                 --        259       544
  Employee Purchase Plan                --         46        52
                                      ----       ----     -----
    Total Common Stock Sales            --        988     4,138
  Treasury Shares                       (3)        --        26
                                      ----       ----     -----
    Net Increase (Decrease)             (3)       988     4,164
                                      ----       ----     -----
Preferred Stock of Subsidiaries
  Subject to Mandatory Redemption:
    Cleveland Electric Retirements
      $ 7.35 Series C                  (10)       (10)      (10)
       88.00 Series E                   (3)        (3)       (3)
      Adjustable Series M             (100)      (100)     (100)
        9.125 Series N                (111)      (189)     (150)
       91.50 Series Q                  (11)        --        --
       90.00 Series S                   (1)        --        --
    Toledo Edison Retirements
      $100 par $9.375                  (17)       (17)      (17)
        25 par  2.81                  (400)      (800)     (800)
Preferred Stock of Subsidiaries Not
  Subject to Mandatory Redemption:
    Cleveland Electric Sales
      $42.40 Series T                   --         --       200
                                      ----       ----     -----
      Net (Decrease)                  (653)    (1,119)     (880)
                                      ----       ----     -----
</TABLE>
 
Shares of common stock required for our stock plans in 1995 were acquired in the
open market.
 
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, 1996. As of December 31,
1995, 225,500 shares had been purchased at a total cost of $4 million. Such
shares are being held as treasury stock.
 
The number of common stock shares reserved for issue under the Employee Savings
Plan and the Employee Purchase Plan was 1,702,849 and 423,797, respectively, at
December 31, 1995.
 
Under an Equity Compensation Plan (Plan) adopted in 1994, options to purchase
shares of common stock and awards of restricted common stock were granted to
management employees. In 1995, options were issued for 285,000 shares at an
exercise price of $14.58. In 1994, options were issued for 264,900 shares at an
exercise price of $13.20 but options for 9,500 shares were surrendered in 1995.
The options expire 10 years from the date of the grant and vest over four years.
The number of shares available for issuance under the Plan each year is
determined by formula, generally 0.5% of outstanding shares. Shares of common
stock required for the Plan may be either issued as new shares, issued from
treasury stock or acquired in the open market specifically for distribution
under the Plan.
 
In 1995, the FASB issued SFAS 123, a new accounting standard for stock-based
compensation, effective for 1996. The standard encourages accounting for
stock-based compensation awards based on their fair value at the grant date with
the resulting cost recorded as an expense. Entities electing not to record the
cost are required to disclose in the notes to the financial statements what the
impact on net income and earnings per share would have been had they followed
the suggested accounting. We expect to adopt the disclosure method of
implementing SFAS 123, which will have no impact on our results of operations.
 
(B) EQUITY DISTRIBUTION RESTRICTIONS
 
The Operating Companies can make cash available for the funding of Centerior
Energy's common stock dividends by paying dividends on their respective common
stock, which is 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, 1995,
Cleveland Electric and
 
 (Centerior Energy)                    F-22                   (Centerior Energy)
<PAGE>   75
 
Toledo Edison had $212 million and $183 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
that essentially requires such dividends to be paid out of the total balance of
retained earnings, which currently is a deficit.
(C) PREFERRED AND PREFERENCE STOCK
 
Amounts to be paid for preferred stock which must be redeemed during the next
five years are $32 million in 1996, $32 million in 1997, $16 million in 1998,
$35 million in 1999 and $33 million in 2000.
The annual mandatory redemption provisions are as follows:
 
<TABLE>
<CAPTION>
                                   Shares                Price
                                   To Be     Beginning    Per
                                  Redeemed      in       Share
                                  --------   ---------   ------
<S>                               <C>        <C>         <C>
Cleveland Electric Preferred:
  $ 7.35 Series C                  10,000       1984     $  100
   88.00 Series E                   3,000       1981      1,000
    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
</TABLE>
 
* All outstanding shares to be redeemed on December 1, 2001.
In 1995, Cleveland Electric purchased 1,000 shares of Serial Preferred Stock,
$90.00 Series S, which will reduce the 2002 redemption requirement shown in the
above table.
 
The annualized preferred dividend requirement for the Operating Companies at
December 31, 1995 was $59 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 7.23%, 7.02%, 7.75% and
8.58%, respectively, in 1995.
 
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.
 
(D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
 
Long-term debt, less current maturities, for the Operating Companies was as
follows:
 
<TABLE>
<CAPTION>
                                 Actual
                               or Average
                                Interest
                                Rate at          December 31,
                              December 31,     -----------------
      Year of Maturity            1995          1995       1994
----------------------------  ------------     ------     ------
                                                 (millions of
                                                   dollars)
<S>                           <C>              <C>        <C>
First mortgage bonds:
  1997-2000                      13.75 %       $   --     $   21
  1997-2000                       7.00              3          4
  1997-2000                      10.88             24         24
  1997                            6.125            31         31
  1998                           10.00              1          1
  1999-2000                       6.20              4          4
  1999                            7.25            100        100
  2001-2005                       8.38            962        671
  2006-2010                       7.99            122        122
  2011-2015                       7.25            381        480
  2016-2020                       8.24            690        635
  2021-2025                       8.25            615        472
                                               ------     ------
                                                2,933      2,565
Secured medium-term notes
  due 1997-2021*                  8.50            613        766
Term bank loans                  --                --         63
Notes due 1997**                  8.75              8         25
Debentures due 2002               8.70            135        135
Pollution control notes due
  1997-2012                       6.64             53        151
Other -- net                     --                (8)        (8)
                                               ------     ------
    Total Long-Term Debt                       $3,734     $3,697
                                               ------     ------
</TABLE>
 
 * Secured by first mortgage bonds.
 
** Secured by subordinated mortgage collateral.
 
Long-term debt matures during the next five years as follows: $203 million in
1996, $90 million in 1997, $113 million in 1998, $273 million in 1999 and $41
million in 2000.
 
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 credit agreements of the Operating Companies contain covenants relating
to fixed charge coverage ratios and limitations on secured financing other than
through first mortgage bonds or certain other transactions. In June 1995, the
Operating Companies replaced letters of credit in connection with the sale and
leaseback of Beaver Valley Unit 2 that were due to expire with new letters of
credit expiring in June 1999. The letters of credit are in an aggregate amount
of approximately $225 million and are secured by first mortgage bonds of
Cleveland Electric and
 
 (Centerior Energy)                    F-23                   (Centerior Energy)
<PAGE>   76
 
Toledo Edison in the proportion of 40% and 60%, respectively. At December 31,
1995, the Operating Companies had outstanding $54 million of bank loans and
notes secured by subordinated mortgage collateral.
 
(12) SHORT-TERM BORROWING ARRANGEMENTS
 
Centerior Energy has a $125 million revolving credit facility through May 1996.
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. The credit agreement is secured with first mortgage bonds of
Cleveland Electric and Toledo Edison in the proportion of 40% and 60%,
respectively. The banks' fee is 0.625% per annum payable quarterly in addition
to interest on any borrowings. There were no borrowings under the facility at
December 31, 1995. Also, the Operating Companies may borrow from each other on a
short-term basis.
 
(13) FINANCIAL INSTRUMENTS
 
The estimated fair values at December 31, 1995 and 1994 of financial instruments
that do not approximate their carrying amounts in the Balance Sheet are as
follows:
 
<TABLE>
<CAPTION>
                                           December 31,
                                ----------------------------------
                                      1995              1994
                                ----------------  ----------------
                                Carrying   Fair   Carrying   Fair
                                 Amount   Value    Amount   Value
                                --------  ------  --------  ------
                                      (millions of dollars)
<S>                             <C>       <C>     <C>       <C>
Capitalization and Liabilities:
  Preferred Stock, with
    Mandatory Redemption
    Provisions (including
    current portion)             $  252   $  239   $  300   $  264
  Long-Term Debt (including
    current portion)              3,945    3,961    4,031    3,628
</TABLE>
 
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized
in the following table.
 
<TABLE>
<CAPTION>
                                               December 31,
                                             ----------------
                                              1995      1994
                                             ------    ------
                                               (millions of
                                                 dollars)
<S>                                          <C>       <C>
Type of Securities:
  Federal Government                          $ 47      $ 46
  Municipal                                     25        31
                                               ---       ---
    Total                                     $ 72      $ 77
                                               ---       ---
Maturities:
  Due within one year                         $  1      $ 19
  Due in one to five years                      22        16
  Due in six to 10 years                        24        17
  Due after 10 years                            25        25
                                               ---       ---
    Total                                     $ 72      $ 77
                                               ---       ---
</TABLE>
 
The fair value of these trusts is estimated based on the quoted market prices
for the investment securities. As a result of adopting the new accounting
standard for certain investments in debt and equity securities, SFAS 115, in
1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
 
<TABLE>
<CAPTION>
                                        Quarters Ended
                           ----------------------------------------
                           March 31,  June 30,  Sept. 30,  Dec. 31,
                           ---------  --------  ---------  --------
                                    (millions of dollars,
                                  except per share amounts)
<S>                        <C>        <C>       <C>        <C>
1995
  Operating Revenues         $ 588      $607      $ 740      $581
  Operating Income           $ 130      $137      $ 205      $118
  Net Income                 $  38      $ 44      $ 109      $ 29
  Average Common Shares
   (millions)                148.0     148.0      148.0     148.0
  Earnings Per Common
    Share                    $ .26      $.30      $ .74      $.20
  Dividends Paid Per
    Common Share             $ .20      $.20      $ .20      $.20
1994
  Operating Revenues         $ 588      $596      $ 667      $570
  Operating Income           $ 129      $134      $ 186      $129
  Net Income                 $  35      $ 42      $  92      $ 35
  Average Common Shares
   (millions)                147.4     147.9      148.0     148.0
  Earnings Per Common
    Share                    $ .24      $.28      $ .62      $.24
  Dividends Paid Per
    Common Share             $ .20      $.20      $ .20      $.20
</TABLE>
 
 (Centerior Energy)                    F-24                   (Centerior Energy)
<PAGE>   77
 
FINANCIAL AND STATISTICAL REVIEW
 
                 OPERATING REVENUES (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                                                                Steam        Total
                                                                          Total                    Total       Heating     Operating
     Year         Residential     Commercial     Industrial     Other     Retail    Wholesale     Electric      & Gas      Revenues
<S>               <C>             <C>            <C>            <C>       <C>       <C>           <C>          <C>         <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                 $ 797            747            777         136      2 457         59          2 516         --        $ 2 516
1994                   758            722            758         137      2 375         46          2 421         --          2 421
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
1985                   567            485            668          73      1 793         26          1 819         19          1 838
</TABLE>
 
--------------------------------------------------------------------------------
 
                 OPERATING EXPENSES (millions of dollars)
 
<TABLE>
<CAPTION>
                                   Other         Generation                                      Deferred
                   Fuel &        Operation       Facilities      Depreciation       Taxes,       Operating     Federal      Total
                  Purchased          &             Rental             &           Other Than     Expenses,     Income     Operating
     Year           Power       Maintenance     Expense, Net     Amortization        FIT            Net        Taxes      Expenses
<S>               <C>           <C>             <C>              <C>              <C>            <C>           <C>        <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                $ 465            617             160              281             322           (53)         135       $ 1 927
1994                  442            595             160              278             309           (55)         114         1 843
1993                  474            924(a)          159              258             312            23(b)        11         2 161
1992                  473            623             161              256             318           (52)         122         1 901
1991                  500            633             168              243(c)          305            (6)         138         1 981
1985                  521            451              --              141             181            --          155         1 449
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                        Federal        Income
                                             Other        Deferred       Income        (Loss)
                                            Income &      Carrying      Taxes--        Before
                  Operating     AFUDC--    Deductions,    Charges,       Credit       Interest       Debt
     Year          Income       Equity        Net           Net        (Expense)      Charges      Interest
<S>               <C>           <C>        <C>            <C>          <C>            <C>          <C>
-----------------------------------------------------------------------------------------------------------
1995                $ 589           3            6            43            (5)          636          358
1994                  578           5            8            40            (6)          625          361
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
1985                  389         268            5            --            87           749          367
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)    COMMON STOCK (dollars
per share & %)
<TABLE>
<CAPTION>
                                                                                              Return on
                             Preferred &                       Average                         Average
                             Preference          Net            Shares                         Common
                  AFUDC--       Stock          Income        Outstanding       Earnings         Stock        Dividends
     Year          Debt       Dividends        (Loss)         (millions)        (Loss)         Equity         Declared
<S>               <C>        <C>             <C>             <C>              <C>             <C>           <C>
-------------------------------------------------------
  ---------------------------------------------------------------------
1995              $ (3)           61            $    220         148.0          $  1.49           11.4%        $  .80
1994                (6)           66                 204         147.8             1.38           11.1            .80
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
1985              (102)           83                 401         121.9(e)          3.29(e)        15.7           2.20(e)
 
<CAPTION>
 
                   Book
     Year         Value
<S>               <C>
---------------
  -------------
1995              $13.40
1994               12.71
1993               12.14
1992               20.22
1991               20.37
1985               21.50(e)
</TABLE>
 
--------------------------------------------------------------------------------
 
NOTE: 1985 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.
(b) Includes write-off of phase-in deferrals of $877 million, consisting of $172
    million of deferred operating expenses and $705 million of deferred carrying
    charges.
(c) 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-25                   (Centerior Energy)
<PAGE>   78
 
                                   Centerior Energy Corporation and Subsidiaries
<TABLE>
<CAPTION>
                                                 ELECTRIC SALES (millions of KWH)
                                                        ELECTRIC CUSTOMERS
                                                         RESIDENTIAL USAGE
                                                      (thousands at year end)

                                                                                                                          Industrial
  Year       Residential    Commercial    Industrial    Wholesale     Other       Total      Residential    Commercial     & Other
<S>          <C>            <C>           <C>           <C>           <C>        <C>         <C>            <C>           <C>
-------------------------------------------------------------------- ---------------------------------------
  ---------------------------
1995            7 227          7 694        12 168         2 626       1 050      30 765         930            99            11
1994            6 980          7 481        12 069         1 842       1 074      29 446         925            98            11
1993            6 974          7 306        11 687         3 027       1 022      30 016         924            97            12
1992            6 666          7 086        11 551         2 814       1 011      29 128         925            97            13
1991            6 981          7 176        11 559         2 690       1 048      29 454         922            96            13
1985            6 309          5 952        11 410           716         865      25 252         893            87            12


<CAPTION>
                                  Average     Average
  Year     Total     Customer       KWH       Customer
<S>          <C>     <C>          <C>         <C>
---------
  -------
1995       1 040       7 791       11.02c     $858.66
1994       1 034       7 556       10.86       820.89
1993       1 033       7 546       11.01       830.99
1992       1 035       7 227       10.98       793.68
1991       1 031       7 410       11.16       827.10
1985         992       6 900        8.98       622.08
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                           LOAD (MW & %)       ENERGY (millions of KWH)
                                                               FUEL

                 Net                                                Company Generated
               Seasonal     Peak      Capacity      Load      -----------------------------     Purchased                Fuel Cost
    Year       Capability   Load       Margin      Factor     Fossil(f)  Nuclear     Total        Power       Total       Per KWH
<S>            <C>          <C>       <C>          <C>        <C>        <C>         <C>        <C>           <C>        <C>
--------------------------------------------------------   ----------------------------------------------------
  -----------------------
1995             5 924      5 779        2.4%       60.0%     17 260     14 936      32 196          338      32 534        1.38c
1994             6 226      5 291       15.0        63.9      18 000     11 824      29 824          922      30 746        1.35
1993             6 226      5 397       13.3        61.6      21 105     10 435      31 540          273      31 813        1.39
1992             6 463      5 091       21.2        63.4      17 371     13 814      31 185         (122)     31 063        1.45
1991             6 460      5 361       17.0        62.9      17 971     13 454      31 425           40      31 465        1.48
1985             4 539      4 512        0.6        69.1      21 457      1 964      23 421        3 668      27 089        1.85
 
<CAPTION>
             Efficiency
               BTU Per
    Year         KWH
<S>            <C>
------------
  ----------
1995            10 447
1994            10 454
1993            10 276
1992            10 395
1991            10 442
1985            10 313
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                 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
<S>            <C>        <C>                <C>        <C>              <C>          <C>           <C>           <C>
 
----------------------------------------------------------------------------------------------------------
  -------       -----------
1995           $9 768          3 036          6 732           101           302        $ 7 135        $ 210       $10 643
1994            9 770          2 906          6 864           129           343          7 336          197        10 691
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
1985            4 481          1 265          3 216         4 261           564          8 041          994         8 992
</TABLE>
 
--------------------------------------------------------------------------------
 
               CAPITALIZATION (millions of dollars & %)
 
<TABLE>
<CAPTION>
                                       Preferred &
                                        Preference         Preferred
                                       Stock, with       Stock, without
                                        Mandatory          Mandatory
                   Common Stock         Redemption         Redemption
    Year              Equity            Provisions         Provisions        Long-Term Debt      Total
<S>              <C>          <C>     <C>        <C>     <C>        <C>     <C>          <C>     <C>
-------------------------------------------------------------------------------------------------------
1995             $1 984        31%     220         3%     451         7%     3 734        59%    $6 389
1994              1 882        30      253         4      451         7      3 697        59      6 283
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
1985              2 710        39      468         7      374         5      3 439        49      6 991
</TABLE>
 
--------------------------------------------------------------------------------
 
(d) Includes write-off of Perry Unit 2 of $583 million.
 
(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) Reduced by net energy used by the Seneca Pumped Storage Plant for pumping.
 
 (Centerior Energy)                    F-26                   (Centerior Energy)
<PAGE>   79
 
MANAGEMENT'S FINANCIAL ANALYSIS
 
OUTLOOK
 
STRATEGIC PLAN
 
We continued to make progress during the second year of our eight-year strategic
plan, but we remain keenly aware of the magnitude of the problems that face us.
The strategic plan was created by Centerior Energy Corporation (Centerior
Energy), along with The Cleveland Electric Illuminating Company (Company) and
The Toledo Edison Company (Toledo Edison), to achieve two major goals:
strengthening their financial conditions and improving their competitive
positions. The Company and Toledo Edison are the two wholly owned electric
utility subsidiaries of Centerior Energy. The plan's objectives relate to the
combined operations of all three companies. The objectives are to achieve
profitable revenue growth, become a leader in customer satisfaction, build a
winning employee team, attain increasingly competitive power supply costs and
maximize share owner return on Centerior Energy common stock. We are not yet
positioned to compete in a less regulated electric utility industry, but every
major action being taken -- strategic planning, revenue enhancement, cost
reduction, improvement of work practices and application for increased prices --
is part of a comprehensive effort to succeed in an increasingly competitive
environment.
 
A primary objective of the strategic plan is continued and significant revenue
growth even as our markets become more competitive. The Company's retail
revenues adjusted for weather and fuel costs have grown about 1% annually since
1990. During 1995, we took aggressive steps to increase revenues through
enhanced marketing strategies. Also, our economic development efforts proved
successful in attracting new customers and supporting the expansion of existing
ones. Although we are not satisfied with our growth rate, we expect that our
marketing activity will improve revenue growth.
 
The rate case which the Company and Toledo Edison filed with The Public
Utilities Commission of Ohio (PUCO) in April 1995 is a critical factor to the
success of the strategic plan. We do not see this rate case as a continuation of
business as usual but as an important turning point which should, if we are
successful in accomplishing the objectives discussed below, bring an end to
price increases for the foreseeable future. A successful conclusion of the case
would speed our transition to a more competitive company by providing 
additional cash to lower costs by accelerating the pay-down of debt and 
preferred stock. In our view, a successful conclusion would include approval of
the full price increase requested with a regulatory commitment to maintain the 
established price levels over an appropriate transition period. This should be 
coupled with a means to accelerate recognition of regulatory assets (described 
in Note 7(a)) and nuclear generating assets concurrent with our cost control 
and revenue enhancement efforts in order to earn a fair return for Centerior 
Energy common stock share owners over time.
 
Another key part of our strategy is offering long-term contracts to those large
customers who could have incentives to change power suppliers. In 1995, 64% of
our industrial kilowatt-hour sales and 24% of our commercial kilowatt-hour sales
were under long-term contracts. We are renegotiating contracts before they
expire and in most cases are retaining customers under new long-term contracts.
 
We are continuing efforts to reduce fixed financing costs in order to strengthen
our financial condition. During 1995, utilizing strong cash flow and refinancing
at favorable terms, the Company reduced interest expense and preferred dividends
by $1 million and outstanding debt and preferred stock by $13 million.
 
Our overall costs are high relative to many of our neighboring utilities as a
result of our substantial nuclear investment. The strategic plan calls for
making us more competitive by continuing to reduce operating expenses and
capital expenditures. In 1995, to improve the focus on cost reduction and other
strategic plan objectives, Centerior Energy and its subsidiaries restructured
into six business groups. The new organization includes groups to manage the
generation, distribution and transmission businesses; provide services and
administrative functions; and invest in nonregulated enterprises. This
arrangement will also enhance each group's ability to identify cost reductions
by focusing on margins and improving work practices and customer service. We
will also continue to aggressively pursue initiatives to reduce the heavy tax
burden imposed upon us by the state and local tax structure in Ohio.
 
RATE CASE AND REGULATORY ACCOUNTING
 
In April 1995, the Company and Toledo Edison filed requests with the PUCO for
price increases aggregating
 
 (Cleveland Electric)                  F-27                 (Cleveland Electric)
<PAGE>   80
 
$119 million annually to be effective in 1996. The price increases are necessary
to recover cost increases and amortization of certain costs deferred since 1992
pursuant to the Rate Stabilization Program discussed below and in Note 7. If
their requests are approved, the Company and Toledo Edison intend to freeze
prices until at least 2002 with the expectation that increased sales and cost
control measures will obviate the need for further price increases. If
circumstances make it impossible to earn a fair return for Centerior Energy
common stock share owners over time, the Company and Toledo Edison would ask for
a further increase -- but only after taking all appropriate actions to make such
a request unnecessary.
 
In December 1995, the PUCO ordered an investigation into the financial
conditions, rates and practices of the Company and Toledo Edison.
 
In its report on the rate request, the PUCO Staff recommended approval of the
$119 million requested ($84 million for the Company and $35 million for Toledo
Edison), subject to a commitment by the Company and Toledo Edison to
significantly revalue their assets. In late January 1996, the Staff proposed
that the Company and Toledo Edison significantly revalue their nuclear plant and
regulatory assets within a five-year period. The Staff's asset revaluation
proposal is inconsistent with the Ohio statutes that define the rate-making
process. The PUCO is not bound by the Staff's recommendations. A decision by the
PUCO is anticipated in the second quarter of 1996.
 
The outcome of the rate case could affect the Company's ability to meet the
criteria of Statement of Financial Accounting Standards (SFAS) 71 for all or
part of its operations which could result in the write-off of all or a part of
the regulatory assets shown in Note 7(a). In our changing industry, other events
independent of the outcome of the rate case could also result in write-offs or
write-downs of assets.
 
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and
other financial accounting requirements and the potential implications of these
accounting requirements for the Company's results of operations and financial
position.
 
RATE STABILIZATION PROGRAM
 
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to
freeze base rates until 1996 and limit rate increases through 1998. In exchange,
we were permitted to defer through 1995 and subsequently recover certain costs 
not currently recovered in rates and to accelerate amortization of certain 
benefits. Deferral of those costs and amortization of those benefits were 
completed in November 1995 and aggregated $103 million for the Company in 1995.
Recovery is expected to begin with the effective date of the PUCO's order in 
the pending rate case. Annual amortization of the deferred costs for the 
Company is $15 million which began in December 1995. Consequently, earnings in 
1996 will be sharply lower than in 1995. Also contributing to lower earnings 
are the expectations that the requested price increase will not be effective 
until the second quarter of 1996 and results from increased marketing and cost 
reduction efforts will take time to achieve.
 
COMPETITION
 
Major structural changes are taking place in the electric utility industry which
are expected to place downward pressure on prices and to increase competition
for customers' business. The changes are coming from both federal and state
authorities. Many of the changes began when the Energy Policy Act of 1992
permitted competition in the electric utility industry through broader access to
a utility's transmission system. In March 1995, the Federal Energy Regulatory
Commission (FERC) issued proposed rules relating to open access transmission
services by public utilities, recovery of stranded investment and other related
matters. The open access transmission rules require utilities to deliver power
from other utilities or generation sources to their wholesale customers. In May
1995, the Company and Toledo Edison filed open access transmission tariffs with
the FERC which used the proposed rules as a guideline. These tariffs are
currently pending.
 
Several groups in Ohio are studying the possible application of retail wheeling.
Retail wheeling occurs when a customer obtains power from a utility company
other than its local utility. The PUCO is sponsoring informal discussions among
a group of business, utility and consumer interests to explore ways of promoting
competitive options without unduly harming the interests of utility company
share owners or customers. Legislative proposals are being drafted for
submission to the Ohio House of Representatives and several utilities in the
state have offered their own proposed transition plans for introduction of
retail wheeling. The current retail wheeling efforts in Ohio
 
 (Cleveland Electric)                  F-28                 (Cleveland Electric)
<PAGE>   81
 
are exploratory and we cannot predict when and to what extent retail wheeling
will be implemented in Ohio.
 
The term "stranded investment" generally refers to fixed costs approved for
recovery under traditional regulatory methods that would become unrecoverable,
or "stranded", as a result of wider competition. Although competitive pressures
are increasing, the traditional regulatory framework remains in place and is
expected to continue for the foreseeable future. We cannot predict when and to
what extent competition will be allowed. We believe that pure competition
(unrestricted retail wheeling for all customer classifications) is at least
several years away and that any transition to pure competition will be in
phases. The FERC and the PUCO have acknowledged the need to provide at least
partial recovery of stranded investment as greater competition is permitted and,
therefore, we believe that there will be a mechanism developed for the recovery
of stranded investment. However, due to the uncertainty involved, there is a
risk that some of our assets may not be fully recovered.
 
In 1995, we continued to experience significant competition from Cleveland
Public Power (CPP), the largest municipal electric system in our service area.
CPP continued to construct new distribution facilities extending into additional
portions of Cleveland. CPP's progress has slowed significantly during the past
year because of the discovery of a large number of safety violations in its
system resulting in substantial cost overruns.
 
In March 1995, one of our large commercial customers which has provided annual
net income of $6 million, Medical Center Co., signed a five-year contract with
CPP for electric service beginning in September 1996, when its contract with us
terminates. In both our appeal to the Ohio Supreme Court and petition to the
FERC, it is our position that the purchase of power from CPP by this customer is
in reality a direct purchase from another utility in violation of Ohio's
certified territory statute. We will continue to pursue all legal and regulatory
remedies to this situation.
 
In 1995, our economic development efforts proved successful in attracting new
customers, while supporting the expansion of existing ones, for example,
American Steel & Wire and Ford Motor Company. We expect that our continued
emphasis on economic development along with a newly developed market segment
focus will be major ingredients in providing improved revenue growth.
 
NUCLEAR OPERATIONS
 
The Company has interests in three nuclear generating units -- Davis-Besse
Nuclear Power Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry
Unit 1) and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2). Toledo
Edison operates Davis-Besse and the Company operates Perry Unit 1. Davis-Besse
and Beaver Valley Unit 2 both operated extremely well in 1995. Their average
three-year unit availability factors at year-end 1995 of 90% and 87%,
respectively, exceeded the industry average of 81% for similar reactors. In
1995, the availability factor for Davis-Besse was 100%. The plant continues to
have its best run ever operating at or near full capacity for 463 straight days
through February 21, 1996.
 
In 1995, Perry Unit 1 improved its average three-year unit availability factor
to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near
capacity for 506 of 531 days since the end of its last refueling and maintenance
outage in August 1994. Work on the comprehensive course of action plan developed
in 1993 to improve the operating performance of Perry Unit 1 will be completed
during the current refueling outage which began January 27, 1996.
 
A significant part of the strategic plan involves ongoing efforts to increase
the availability and lower the cost of production of our nuclear units. In 1995,
we made great progress regarding unit availability while continuing to lower
production costs. The goal of our nuclear improvement program is to replicate
Davis-Besse's operational excellence and cost reduction gains at Perry Unit 1
while improving performance ratings.
 
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993 and 1994, we increased our decommissioning expense
accruals because of revisions in our cost estimates. See Note 1(e).
 
Our nuclear units may be impacted by activities or events beyond our control.
Operating nuclear 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 domestic nuclear unit. If one of our nuclear units is taken out
of service for an extended period for any reason, including an accident at such
unit or any other nuclear facility, we cannot predict whether
 
 (Cleveland Electric)                  F-29                 (Cleveland Electric)
<PAGE>   82
 
regulatory authorities would impose unfavorable rate treatment. Such treatment
could include taking our affected unit out of rate base, thereby not permitting
us to recover our investment in and earn a return on it, or disallowing certain
construction or maintenance costs. An extended outage coupled with unfavorable
rate treatment could have a material adverse effect on our financial condition
and results of operations. Premature plant closings could also have a material
adverse effect on our financial condition and results of operations because the
estimated cost to decommission the plant exceeds the current funding in the
decommissioning trust.
 
HAZARDOUS WASTE DISPOSAL SITES
 
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.
Allegations that the Company disposed of hazardous waste at these sites, and the
amount involved, are often unsubstantiated and subject to dispute. Federal law
provides that all PRPs for a particular site be held liable on a joint and
several basis. 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 $350 million.
However, we believe that the actual cleanup costs will be substantially lower
than $350 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 $7
million at December 31, 1995, 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.
 
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. In 1994, Centerior Energy lowered its
common stock dividend which reduced its cash outflow by over $110 million
annually. This action, in turn, reduced the common stock cash dividend demand on
the Company. The Company is using the increased retained cash to redeem debt and
preferred stock more quickly than would otherwise be the case.
 
MERGER OF TOLEDO EDISON INTO THE COMPANY
 
We continue to seek the necessary regulatory approvals to complete the merger of
Toledo Edison into the Company which was announced in 1994. The FERC has
deferred action on the merger application until the merits of the open access
transmission tariffs proposed by the Company and Toledo Edison are addressed in
hearings. See Note 15.
 
CAPITAL RESOURCES AND LIQUIDITY
 
1993-1995 CASH REQUIREMENTS
 
A key part of the strategic plan is to significantly reduce the Company's level
of debt and preferred stock. In 1995, we were able to continue the reduction
pattern begun in 1994. The Company's obligations were reduced by $77 million in
1994 and by $13 million in 1995. We intend to continue and to accelerate
redemptions.
 
We need cash for normal corporate operations, retirement of maturing securities,
and an ongoing program of constructing and improving facilities to meet demand
for electric service and to comply with government regulations. Our cash
construction expenditures totaled $167 million in 1993, $164 million in 1994 and
$148 million in 1995. Our debt and preferred stock maturities and sinking fund
requirements totaled $310 million in 1993, $62 million in 1994 and $286 million
in 1995. In addition, we optionally redeemed approximately $270 million in the
period 1993-1995. This amount includes $143 million of tax-exempt issues
refunded in 1995 resulting in approximately $3 million of interest savings. In
May 1995, the Company issued $300 million of first mortgage bonds due in 2005
with an interest rate of 9.50%. The embedded cost of the Company's debt at the
end of 1995 was 8.88% versus 8.96% in 1994 and 8.82% in 1993. In 1995, the
Company and Toledo Edison renewed for a four-year term approximately $225
million in bank letters of credit supporting the equity owner participants in
the Beaver Valley Unit 2 lease. See Note 11(d).
 
The Company also utilized short-term borrowings to help meet its cash needs. The
Company had $5 million of notes payable to affiliates at December 31, 1995. See
Note 12.
 
1996 AND BEYOND CASH REQUIREMENTS
 
The Company's 1996 cash requirements for construction are $128 million and for
debt and preferred stock maturities and sinking fund requirements are $177
million. We
 
 (Cleveland Electric)                  F-30                 (Cleveland Electric)
<PAGE>   83
 
expect to meet these requirements with internal cash generation, cash reserves
and about $110 million from the sale of a AAA-rated security backed by our
accounts receivable.
 
We expect to meet all of our 1997-2000 cash requirements with internal cash
generation. Estimated cash requirements for the Company's construction program
during this period total $603 million. Debt and preferred stock maturities and
sinking fund requirements total $400 million for the same period. If economical,
additional securities may be redeemed under optional redemption provisions, with
funding expected to be provided through internal cash generation.
 
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. If
the applicable interest coverage test is met, the Company may issue first
mortgage bonds on the basis of property additions and, under certain
circumstances, refundable bonds. At December 31, 1995, the Company would have
been permitted to issue approximately $379 million of additional first mortgage
bonds.
 
The Company also is able to raise funds through the sale of debt and preferred
and preference stock. There are no restrictions on the Company's ability to
issue preferred or preference stock.
 
The Company and Toledo Edison have $307 million in financing vehicles available
to support their nuclear fuel leases, portions of which mature this year. See
Note 6. The Company is a party to a $125 million revolving credit facility which
is expected to be renewed when it matures in May 1996. See Note 12. At the end
of 1995, the Company had $70 million in cash and temporary investments.
 
The foregoing financing resources are expected to be sufficient for the
Company's needs over the next several years. However, the availability and cost
of capital to meet the Company's external financing needs also depend upon such
factors as financial market conditions and its credit ratings. Current credit
ratings for the Company are as follows:
 
<TABLE>
<CAPTION>
                                     Standard          Moody's
                                     & Poor's         Investors
                                    Corporation     Service, Inc.
                                    -----------     -------------
<S>                                 <C>             <C>
First mortgage bonds                     BB              Ba2
Subordinated debt                         B+             Ba3
Preferred stock                           B               b2
</TABLE>
 
RESULTS OF OPERATIONS
 
1995 VS. 1994
 
Factors contributing to the 4.2% increase in 1995 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                           $  52
  Wholesale Revenues                                    11
  Fuel Cost Recovery Revenues                           19
  Miscellaneous Revenues                               (11)
                                                       ---
      Total                                          $  71
                                                       ---
</TABLE>
 
For the second year in a row, industrial kilowatt-hour sales increased. The
increase in 1995 was 0.3%, but sales grew 2.4% excluding reductions at two
low-margin steel producers (representing 7.6% of industrial revenues).
Residential and commercial sales increased 2.8% and 3%, respectively, primarily
because of the hot summer weather, although there was about 2%
nonweather-related growth in commercial sales. Other sales increased 36% because
of a 58% increase in wholesale sales due principally to the hot summer and good
availability of our generating units. Weather accounted for approximately $24
million of the $41 million increase in 1995 base rate (nonfuel) revenues. Higher
1995 fuel cost recovery revenues resulted from an increase in the fuel cost
factors. The weighted average of these fuel cost factors increased approximately
7%. Miscellaneous revenues decreased in 1995 primarily because the 1994 amount
included the billings to other utility owners and lessees for overhead expenses
related to the 1994 refueling and maintenance outage of the jointly owned Perry
Unit 1.
 
For 1995, operating revenues were 32% residential, 32% commercial, 29%
industrial and 7% other and kilowatt-hour sales were 24% residential, 28%
commercial, 38% industrial and 10% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.09 and $.07,
respectively.
 
Operating expenses increased 5.3% in 1995. Fuel and purchased power expenses
increased as higher fuel expense was partially offset by lower purchased power
expense. The higher fuel expense was attributable to increased generation and
more amortization of previously deferred fuel costs than the amount amortized in
1994. The higher other operation and maintenance expenses resulted primarily
from charges for an ongoing inventory reduction program and the recognition of
costs associated with preliminary engineering studies. Federal income taxes
increased as a result of higher pretax operating income. Taxes, other than
federal income taxes, increased primarily due to property tax increases
resulting from
 
 (Cleveland Electric)                  F-31                 (Cleveland Electric)
<PAGE>   84
 
plant additions, real estate valuation increases and a nonrecurring tax credit
recorded in 1994.
 
1994 VS. 1993
 
Factors contributing to the 3% decrease in 1994 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                           $   2
  Wholesale Revenues                                   (48)
  Fuel Cost Recovery Revenues                          (13)
  Miscellaneous Revenues                                 6
                                                      ----
      Total                                          $ (53)
                                                      ----
</TABLE>
 
The Company experienced good retail kilowatt-hour sales growth in the commercial
and industrial categories in 1994; the residential category was negatively
impacted by weather conditions, particularly during the summer. The revenue
decrease resulted primarily from milder weather conditions in 1994 and 53% lower
wholesale sales. Weather reduced base rate revenues approximately $8 million
from the 1993 amount. Although total sales decreased by 4.6%, commercial sales
increased 2.4%. Industrial sales increased 0.7% on the strength of increased
sales to large automotive manufacturers and the broad-based, smaller industrial
customer group. This growth substantiated an economic resurgence in Northeastern
Ohio. Residential sales declined 0.2% because of the weather factor. Other sales
decreased by 42% because of the lower sales to wholesale customers attributable
to expiration of a wholesale power agreement, softer wholesale market conditions
and limited power availability for bulk power transactions at certain times
because of generating plant outages. Lower 1994 fuel cost recovery revenues
resulted from favorable changes in the fuel cost factors. The weighted average
of these fuel cost factors dropped by approximately 5%.
 
For 1994, operating revenues were 31% residential, 32% commercial, 30%
industrial and 7% other and kilowatt-hour sales were 24% residential, 29%
commercial, 39% industrial and 8% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.09 and $.06,
respectively. The changes from 1993 were not significant.
 
Operating expenses were 15% lower in 1994. Operation and maintenance expenses
for 1993 included $130 million of net benefit expenses related to an early
retirement program, called the Voluntary Transition Program (VTP), and other
charges totaling $35 million. The VTP benefit expenses in 1993 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). A smaller work force and ongoing cost reduction measures also lowered
operation and maintenance expenses. More nuclear generation and less coal-fired
generation accounted for a large part of the lower fuel and purchased power
expenses in 1994. Depreciation and amortization expenses increased primarily
because of higher nuclear plant decommissioning expenses as discussed in Note
1(e). Deferred operating expenses were greater primarily because of the
write-off of $117 million of phase-in deferred operating expenses in 1993 as
discussed in Note 7(e). The 1993 deferrals also included $52 million of
postretirement benefit curtailment cost deferrals related to the VTP. See Note
9(b). Federal income taxes increased as a result of higher pretax operating
income.
 
As discussed in Note 4(b), $351 million of our Perry Unit 2 investment was
written off in 1993. Also, as discussed in Note 7(e), phase-in deferred carrying
charges of $519 million were written off in 1993. The change in the federal
income tax credit amounts for nonoperating income was attributable to these
write-offs.
 
 (Cleveland Electric)                  F-32                 (Cleveland Electric)
<PAGE>   85
 
INCOME STATEMENT    The Cleveland Electric Illuminating Company and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                       For the years ended December
                                                                                   31,
                                                                       ----------------------------
                                                                        1995       1994       1993
                                                                       ------     ------     ------
                                                                          (millions of dollars)
<S>                                                                    <C>        <C>        <C>
OPERATING REVENUES                                                     $1,769     $1,698     $1,751
                                                                       ------     ------     ------
OPERATING EXPENSES
  Fuel and purchased power (1)                                            413        391        423
  Other operation and maintenance                                         418        394        433
  Generation facilities rental expense, net                                56         56         56
  Early retirement program expenses and other                              --         --        165
                                                                       ------     ------     ------
     Total operation and maintenance                                      887        841      1,077
  Depreciation and amortization                                           196        195        182
  Taxes, other than federal income taxes                                  230        218        221
  Deferred operating expenses, net                                        (36)       (34)        27
  Federal income taxes                                                     94         82         22
                                                                       ------     ------     ------
                                                                        1,371      1,302      1,529
                                                                       ------     ------     ------
OPERATING INCOME                                                          398        396        222
                                                                       ------     ------     ------
NONOPERATING INCOME (LOSS)
  Allowance for equity funds used during construction                       2          4          4
  Other income and deductions, net                                          2          6         (5)
  Write-off of Perry Unit 2                                                --         --       (351)
  Deferred carrying charges, net                                           29         25       (487)
  Federal income taxes -- credit (expense)                                 (2)        (4)       270
                                                                       ------     ------     ------
                                                                           31         31       (569)
                                                                       ------     ------     ------
INCOME (LOSS) BEFORE INTEREST CHARGES                                     429        427       (347)
                                                                       ------     ------     ------
INTEREST CHARGES
  Debt interest                                                           248        247        244
  Allowance for borrowed funds used during construction                    (3)        (5)        (4)
                                                                       ------     ------     ------
                                                                          245        242        240
                                                                       ------     ------     ------
NET INCOME (LOSS)                                                         184        185       (587)
PREFERRED DIVIDEND REQUIREMENTS                                            43         45         45
                                                                       ------     ------     ------
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK                             $  141     $  140     $ (632)
                                                                       ------     ------     ------
</TABLE>
 
---------------
 
(1) Includes purchased power expense of $102 million, $111 million and $120
    million in 1995, 1994 and 1993, respectively, for all purchases from Toledo
    Edison.
 
RETAINED EARNINGS
 
<TABLE>
<CAPTION>
                                                                          For the years ended
                                                                             December 31,
                                                                       -------------------------
                                                                       1995      1994      1993
                                                                       -----     -----     -----
                                                                         (millions of dollars)
<S>                                                                    <C>       <C>       <C>
RETAINED EARNINGS (DEFICIT) AT BEGINNING OF YEAR                       $(262)    $(280)    $ 545
                                                                       -----     ------    -----
ADDITIONS
  Net income (loss)                                                      184       185      (587)
DEDUCTIONS
  Dividends declared:
     Common stock                                                        (74)     (122)     (189)
     Preferred stock                                                     (41)      (45)      (48)
  Other, primarily preferred stock redemption expenses                    --        --        (1)
                                                                       -----     ------    -----
                                                                                                
     Net Increase (Decrease)                                              69        18      (825)
                                                                       -----     ------    -----
                                                                                                
RETAINED EARNINGS (DEFICIT) AT END OF YEAR                             $(193)    $(262)    $(280)
                                                                       -----     ------    -----
                                                                                                
</TABLE>
 
The accompanying notes are an integral part of these statements.
 
 (Cleveland Electric)                  F-33                 (Cleveland Electric)
<PAGE>   86
 
BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                                       ----------------
                                                                                        1995      1994
                                                                                       ------    ------
                                                                                         (millions of
                                                                                           dollars)
<S>                                                                                    <C>       <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
  Utility plant in service                                                             $6,872    $6,871
     Less: accumulated depreciation and amortization                                    2,094     2,014
                                                                                       -------   -------
                                                                                        4,778     4,857
  Construction work in progress                                                            73        99
                                                                                       -------   -------
                                                                                        4,851     4,956
  Nuclear fuel, net of amortization                                                       122       174
  Other property, less accumulated depreciation                                            58        21
                                                                                       -------   -------
                                                                                        5,031     5,151
                                                                                       -------   -------
CURRENT ASSETS
  Cash and temporary cash investments                                                      70        66
  Amounts due from customers and others, net                                              152       146
  Amounts due from affiliates                                                               5         5
  Unbilled revenues                                                                        79        72
  Materials and supplies, at average cost                                                  80        95
  Fossil fuel inventory, at average cost                                                   21        16
  Taxes applicable to succeeding years                                                    184       180
  Other                                                                                     7         4
                                                                                       -------   -------
                                                                                          598       584
                                                                                       -------   -------
REGULATORY AND OTHER ASSETS
  Amounts due from customers for future federal income taxes, net                         651       641
  Unamortized loss on reacquired debt                                                      61        58
  Carrying charges and operating expenses                                                 644       578
  Nuclear plant decommissioning trusts                                                     61        44
  Other                                                                                   106        95
                                                                                       -------   -------
                                                                                        1,523     1,416
                                                                                       -------   -------
       Total Assets                                                                    $7,152    $7,151
                                                                                       -------   -------
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Cleveland Electric)                  F-34                 (Cleveland Electric)
<PAGE>   87
 
                    The Cleveland Electric Illuminating Company and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                                       ----------------
                                                                                        1995      1994
                                                                                       ------    ------
                                                                                         (millions of
                                                                                           dollars)
<S>                                                                                    <C>       <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
  Common shares, without par value: 105 million authorized;
     79.6 million outstanding in 1995 and 1994                                         $1,241    $1,241
  Other paid-in capital                                                                    79        79
  Retained earnings (deficit)                                                            (193)     (262)
                                                                                       ------    ------
     Common stock equity                                                                1,127     1,058
  Preferred stock
     With mandatory redemption provisions                                                 215       246
     Without mandatory redemption provisions                                              241       241
  Long-term debt                                                                        2,666     2,543
                                                                                       ------    ------
                                                                                        4,249     4,088
                                                                                       ------    ------
CURRENT LIABILITIES
  Current portion of long-term debt and preferred stock                                   177       282
  Current portion of nuclear fuel lease obligations                                        55        47
  Accounts payable                                                                         89        88
  Accounts and notes payable to affiliates                                                 64       118
  Accrued taxes                                                                           296       310
  Accrued interest                                                                         59        62
  Other                                                                                    56        51
                                                                                       ------    ------
                                                                                          796       958
                                                                                       ------    ------
DEFERRED CREDITS AND OTHER LIABILITIES
  Unamortized investment tax credits                                                      184       192
  Accumulated deferred federal income taxes                                             1,298     1,234
  Unamortized gain from Bruce Mansfield Plant sale                                        311       327
  Accumulated deferred rents for Bruce Mansfield Plant                                     92        84
  Nuclear fuel lease obligations                                                           86       132
  Retirement benefits                                                                      65        59
  Other                                                                                    71        77
                                                                                       ------    ------
                                                                                        2,107     2,105
                                                                                       ------    ------
       Total Capitalization and Liabilities                                            $7,152    $7,151
                                                                                       ------    ------
</TABLE>
 
 (Cleveland Electric)                  F-35                 (Cleveland Electric)
<PAGE>   88
 
CASH FLOWS          The Cleveland Electric Illuminating Company and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                                 For the years ended
                                                                                    December 31,
                                                                              -------------------------
                                                                              1995      1994      1993
                                                                              -----     -----     -----
                                                                                (millions of dollars)
<S>                                                                           <C>       <C>       <C>
CASH FLOWS FROM OPERATING ACTIVITIES (1)
  Net Income (Loss)                                                           $ 184     $ 185     $(587)
                                                                               ----     ------    ------
  Adjustments to Reconcile Net Income (Loss) to Cash from Operating
     Activities:
     Depreciation and amortization                                              196       195       182
     Deferred federal income taxes                                               56        50      (292)
     Unbilled revenues                                                           (7)       27        (6)
     Deferred fuel                                                                9       (20)        4
     Deferred carrying charges, net                                             (29)      (25)      487
     Leased nuclear fuel amortization                                            71        55        47
     Deferred operating expenses, net                                           (36)      (34)       27
     Allowance for equity funds used during construction                         (2)       (4)       (4)
     Noncash early retirement program expenses, net                              --        --       125
     Write-off of Perry Unit 2                                                   --        --       351
     Changes in amounts due from customers and others, net                       (6)       10         5
     Changes in inventories                                                      10         2        17
     Changes in accounts payable                                                  1       (34)       18
     Changes in working capital affecting operations                            (17)        3        29
     Other noncash items                                                         --         4         5
                                                                               ----     ------    ------
       Total Adjustments                                                        246       229       995
                                                                               ----     ------    ------
          Net Cash from Operating Activities                                    430       414       408
                                                                               ----     ------    ------
CASH FLOWS FROM FINANCING ACTIVITIES (2)
  Bank loans, commercial paper and other short-term debt                         --        --       (10)
  Notes payable to affiliates                                                   (53)       58       (11)
  First mortgage bond issues                                                    443        46       280
  Secured medium-term note issues                                                --        --        35
  Term bank loan                                                                 --        --        40
  Preferred stock issues                                                         --        --       100
  Maturities, redemptions and sinking funds                                    (460)     (116)     (345)
  Nuclear fuel lease obligations                                                (58)      (60)      (59)
  Dividends paid                                                               (117)     (142)     (232)
  Premiums, discounts and expenses                                              (11)       (1)      (11)
                                                                               ----     ------    ------
          Net Cash from Financing Activities                                   (256)     (215)     (213)
                                                                               ----     ------    ------
CASH FLOWS FROM INVESTING ACTIVITIES (2)
  Cash applied to construction                                                 (148)     (164)     (167)
  Interest capitalized as allowance for borrowed funds used during
     construction                                                                (3)       (5)       (4)
  Contributions to nuclear plant decommissioning trusts                         (13)      (14)       (5)
  Other cash received (applied)                                                  (6)      (27)       24
                                                                               ----     ------    ------
          Net Cash from Investing Activities                                   (170)     (210)     (152)
                                                                               ----     ------    ------
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS                                 4       (11)       43
                                                                               ----     ------    ------
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR                         66        77        34
                                                                               ----     ------    ------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR                            $  70     $  66     $  77
                                                                               ----     ------    ------
</TABLE>
 
---------------
 
<TABLE>
<S>                                                                           <C>       <C>       <C>
(1) Interest paid (net of amounts capitalized)                                $ 214     $ 208     $ 204
                                                                              -----     -----     -----
    Income taxes paid                                                         $  66     $  15     $  28
                                                                              -----     -----     -----
</TABLE>
 
(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-36                 (Cleveland Electric)
<PAGE>   89
 
STATEMENT OF PREFERRED STOCK
                    The Cleveland Electric Illuminating Company and Subsidiaries
 
<TABLE>
<CAPTION>
                                                                          Current       December 31,
                                                         1995 Shares     Call Price     -------------
                                                         Outstanding     Per Share      1995     1994
                                                         -----------     ----------     ----     ----
                                                                                        (millions of
                                                                                          dollars)
<S>                          <C>                         <C>             <C>            <C>      <C>
Without par value, 4,000,000 preferred shares authorized
  Subject to mandatory redemption:
                      $7.35  Series C                      130,000       $  101.00      $ 13     $ 14
                      88.00  Series E                       15,000        1,015.30        15       18
                 Adjustable  Series M                           --           --           --       10
                      9.125  Series N                      300,000          101.00        30       41
                      91.50  Series Q                       64,286        1,000.00        64       75
                      88.00  Series R                       50,000           --           50       50
                      90.00  Series S                       74,000           --           73       74
                                                                                        ----     ----
                                                                                         245      282
  Less: Current maturities                                                                30       36
                                                                                        ----     ----
TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS                             $215     $246
                                                                                        ====     ====
  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          100.00        49       49
                      42.40  Series T                      200,000           --           97       97
                                                                                        ----     ----
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS                          $241     $241
                                                                                        ====     ====
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Cleveland Electric)                  F-37                 (Cleveland Electric)
<PAGE>   90
 
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. The Company's financial statements have historically included the
accounts of the Company's wholly owned subsidiaries, which in the aggregate were
not material. In 1995, the Company formed a wholly owned subsidiary to serve as
the transferor in connection with an asset-backed securitization expected to be
completed in 1996. At December 31, 1995, the subsidiary was not yet funded. In
1994, the Company transferred its investments in three wholly owned subsidiaries
to Centerior Energy at cost ($26 million) via property dividends.
 
The Company follows the Uniform System of Accounts prescribed by the FERC and
adopted by the PUCO. Rate-regulated utilities are subject to SFAS 71 which
governs accounting for the effects of certain types of rate regulation. Pursuant
to SFAS 71, certain incurred costs are deferred for recovery in future rates.
See Note 7.
 
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and
the disclosure of contingent assets and liabilities. The estimates are based on
an analysis of the best information available. Actual results could differ from
those estimates.
 
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 joint
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 $141 million, $136 million and $167
million in 1995, 1994 and 1993, 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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
 
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 1995 and 3.4% in both 1994 and 1993. The
annual straight-line depreciation rate for nuclear property is 2.5%. In
conjunction with its pending rate case, the Company has asked the PUCO to
 
 (Cleveland Electric)                  F-38                 (Cleveland Electric)
<PAGE>   91
 
approve an increase of this depreciation rate to approximately 3%.
 
The Company accrues the estimated costs of decommissioning its three nuclear
generating units. The accruals are required to be funded in an external trust.
The PUCO requires that the expense and payments to the external trusts be
determined on a levelized basis by dividing the unrecovered decommissioning
costs in current dollars by the remaining years in the licensing period of each
unit. This methodology requires that the net earnings on the trusts be
reinvested therein with the intent of having net earnings offset inflation. The
PUCO requires that the estimated costs of decommissioning and the funding level
be reviewed at least every five years.
 
In 1994, the Company increased its annual decommissioning expense accruals to
$13 million from the $6 million level in 1993. The accruals are reflected in
current rates. The increased accruals in 1994 were derived from updated,
site-specific studies for each of the units. The revised estimates reflect the
DECON method of decommissioning (prompt decontamination), and the locations and
cost characteristics specific to the units, and include costs associated with
decontamination, dismantlement and site restoration.
 
The revised estimates for the units in 1993 and 1992 dollars and in dollars at
the time of license expiration, assuming a 4% annual inflation rate, are as
follows:
 
<TABLE>
<CAPTION>
                                    License
                                   Expiration                Future
        Generating Unit               Year        Amount     Amount
-------------------------------    ----------     ------     ------
                                                    (millions of
                                                      dollars)
<S>                                <C>            <C>        <C>
Davis-Besse                           2017         $178(1)   $ 443
Perry Unit 1                          2026          156(1)     554
Beaver Valley Unit 2                  2027           63(2)     233
                                                   ----      ------
      Total                                        $397      $1,230
                                                   ----      ------
</TABLE>
 
---------------
 
(1) Dollar amounts in 1993 dollars.
(2) Dollar amount in 1992 dollars.
 
The updated estimates reflect substantial increases from the prior
PUCO-recognized aggregate estimates of $142 million
in 1987 and 1986 dollars.
 
The classification, Accumulated Depreciation and Amortization, in the Balance
Sheet at December 31, 1995 includes $71 million of decommissioning costs
previously expensed and the earnings on the external trust 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. The trust
earnings are recorded as an increase to the trust assets and the related
component of the decommissioning reserve (included in Accumulated Depreciation
and Amortization).
 
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
those of the Company, regarding the recognition, measurement and classification
of decommissioning costs for nuclear generating stations in the financial
statements. In response to these questions, the Financial Accounting Standards
Board (FASB) is reviewing the accounting for removal costs, including
decommissioning. If current accounting practices are changed, the annual
provision for decommissioning could increase; the estimated cost for decommis-
sioning could be recorded as a liability rather than as accumulated
depreciation; and trust fund income from the external decommissioning trusts
could be reported as investment income rather than as a reduction to
decommissioning expense. The FASB issued an exposure draft on the subject on
February 7, 1996.
 
(F) PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment are stated at original cost less amounts
disallowed by the PUCO. Construction costs include related payroll taxes,
retirement benefits, 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 10.33% in 1995,
9.68% in 1994 and 9.63% in 1993.
 
Maintenance and repairs for plant and equipment 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 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 the leases. The
amortization and the lease expense amounts are reported in the Income Statement
as Generation Facilities Rental Expense, Net.
 
 (Cleveland Electric)                  F-39                 (Cleveland Electric)
<PAGE>   92
 
(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. See Note 7(a). 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.
 
(I) FEDERAL INCOME TAXES
 
The Company uses the liability method of accounting for income taxes in
accordance with SFAS 109. See Note 8. 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, the Company must record a liability for its 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. See Note 7(a).
 
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7(d) 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. These
leases extend through 2017 and 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 renew the leases. The
leases include conditions for mandatory termination (and possible repurchase of
the leasehold interest) for events of default.
 
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 such payments have been made on behalf of
Toledo Edison.
 
Future minimum lease payments under the operating leases at December 31, 1995
are summarized as follows:
 
<TABLE>
<CAPTION>
                                             For        For
                                             the       Toledo
                  Year                     Company     Edison
-----------------------------------------  -------     ------
                                              (millions of
                                                dollars)
<S>                                        <C>         <C>
1996                                       $   63      $ 125
1997                                           63        102
1998                                           63        102
1999                                           70        108
2000                                           76        111
Later Years                                 1,245      1,807
                                           ------     ------
      Total Future Minimum Lease Payments  $1,580     $2,355
                                           ------     ------
</TABLE>
 
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1995, 1994 and 1993 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. Purchased power expense for this transaction was
$98 million, $108 million and $103 million in 1995, 1994 and 1993, respectively.
We anticipate that this purchase will continue indefinitely. The future minimum
lease payments through 2017 associated with Beaver Valley Unit 2 aggregate $1.35
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
 
 (Cleveland Electric)                  F-40                 (Cleveland Electric)
<PAGE>   93
 
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, 1995 includes the following facilities owned by the
Company as a tenant in common with other utilities and Lessors:
 
<TABLE>
<CAPTION>
                                          Property,
                                          Plant and
                         Ownership        Equipment
                         Megawatts      (Exclusive of     Accumulated
    Generating Unit      (% Share)      Nuclear Fuel)     Depreciation
------------------------ ----------     -------------     -----------
                                        (millions of dollars)
<S>                      <C>            <C>               <C>
Seneca Pumped Storage    351 (80.00%)      $    65           $  22
Eastlake Unit 5          411 (68.80)           159              --
Davis-Besse              454 (51.38)           668             216
Perry Unit 1             371 (31.11)         1,781             355
Beaver Valley Unit 2 and
  Common Facilities
  (Note 2)               201 (24.47)         1,278             284
                                            ------          ------
      Total                                $ 3,951           $ 877
                                            ------          ------
</TABLE>
 
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 the Company's construction program for the 1996-2000
period is $761 million, including AFUDC of $30 million and excluding nuclear
fuel.
 
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other
things, significant reductions in the emission of sulfur dioxide and nitrogen
oxides by fossil-fueled generating units. Our strategy provides for compliance
primarily through greater use of low-sulfur coal at some of our units and the
use of emission allowances. Total capital expenditures from 1991 through 1995 in
connection with Clean Air Act compliance amounted to $46 million. The plan will
require additional capital expenditures over the 1996-2005 period of
approximately $49 million for nitrogen oxide control equipment and other plant
process modifications. In addition, higher fuel and other operation and
maintenance expenses will be incurred. 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.
 
(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. 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.
 
(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 sites. The Company has accrued a
liability totaling $7 million at December 31, 1995 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 the discussion
of these and other risks in Management's Financial Analysis -- Outlook-Nuclear
Operations.
 
(B) NUCLEAR INSURANCE
 
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have
insurance coverage for damage to property at these sites (including leased fuel
and cleanup costs). Coverage amounted to $2.75 billion for each site
 
 (Cleveland Electric)                  F-41                 (Cleveland Electric)
<PAGE>   94
 
as of January 1, 1996. 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. In addition, the Company can be assessed a maximum of $23 million
under these policies 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 80% 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 $307 million ($157 million from
intermediate-term notes and $150 million from bank credit arrangements). The
intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996
and $73 million in September 1997). The bank credit arrangements terminate in
October 1996. The special-purpose corporation plans to obtain alternate
financing in 1996 to replace the $234 million of financing expiring in 1996. At
December 31, 1995, $142 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
$41 million, $34 million and $20 million, respectively, at December 31, 1995.
The nuclear fuel amounts financed and capitalized also included interest charges
incurred by the lessors amounting to $4 million in 1995, $7 million in 1994 and
$9 million in 1993. The estimated future lease amortization payments for the
Company based on projected consumption are $55 million in 1996, $48 million in
1997, $40 million in 1998, $37 million in 1999 and $35 million in 2000.
 
(7) REGULATORY MATTERS
 
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
 
The Company is subject to the provisions of SFAS 71 and has complied with its
provisions. SFAS 71 provides, among other things, for the deferral of certain
incurred costs that are probable of future recovery in rates. We monitor changes
in market and regulatory conditions and consider the effects of such changes in
assessing the continuing applicability of SFAS 71. Criteria that could give rise
to discontinuation of the application of SFAS 71 include: (1) increasing
competition which significantly restricts the Company's ability to charge prices
which allow it to recover operating costs, earn a fair return on invested
capital and recover the amortization of regulatory assets and (2) a significant
change in the manner in which rates are set by the PUCO from cost-based
regulation to some other form of regulation. Regulatory assets represent
probable future revenues to the Company associated with certain incurred costs,
which it will recover from customers through the rate-making process.
 
Effective January 1, 1996, the Company adopted SFAS 121 which imposes stricter
criteria for carrying regulatory assets than SFAS 71 by requiring that such
assets be probable of recovery at each balance sheet date. The criteria under
SFAS 121 for plant assets require such assets to be written down only if the
book value exceeds the projected net future cash flows.
 
Regulatory assets in the Balance Sheet are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                               ---------------
                                                1995     1994
                                               ------   ------
                                                (millions of
                                                  dollars)
<S>                                            <C>      <C>
Amounts due from customers for future federal
  income taxes, net                            $  651   $  641
Unamortized loss on reacquired debt                61       58
Pre-phase-in deferrals*                           331      341
Rate Stabilization Program deferrals              313      237
                                               ------   ------
    Total                                      $1,356   $1,277
                                               ------   ------
</TABLE>
 
* Represent deferrals of operating expenses and carrying charges for Perry Unit
  1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the
  lives of the related property.
 
As of December 31, 1995, customer rates provide for recovery of all the above
regulatory assets, except those related to the Rate Stabilization Program
discussed below. The remaining recovery periods for all of the regulatory assets
listed above range from 16 to 33 years.
 
 (Cleveland Electric)                  F-42                 (Cleveland Electric)
<PAGE>   95
 
(B) RATE CASE
 
In April 1995, the Company and Toledo Edison filed requests with the PUCO for
price increases aggregating $119 million annually to be effective in 1996. The
price increases are necessary to recover cost increases and amortization of
certain costs deferred since 1992 pursuant to the Rate Stabilization Program. If
their requests are approved, the Company and Toledo Edison intend to freeze
prices until at least 2002 with the expectation that increased sales and cost
control measures will preclude the need for further price increases. If
circumstances make it impossible to earn a fair return for Centerior Energy
common stock share owners over time, the Company and Toledo Edison would ask for
a further increase, but only after taking all appropriate actions to make such a
request unnecessary.
 
In November 1995, the PUCO Staff issued its report addressing the rate case. The
Staff recommended that the PUCO grant the full $119 million price increase
requested ($84 million for the Company and $35 million for Toledo Edison).
However, the Staff also recommended that the price increase be conditioned upon
the commitment by the Company and Toledo Edison "to a significant revaluation of
their asset bases over some finite period of time."
 
In December 1995, the PUCO ordered an investigation into the financial
conditions, rates and practices of the Company and Toledo Edison to identify
outcomes and remedies other than those routinely applied during the rate case
process.
 
In late January 1996, the Staff proposed an incremental reduction (currently, an
aggregate of $1.25 billion for the Company and Toledo Edison) beyond the normal
level in nuclear plant and regulatory assets within five years. The Staff
proposed that the Company and Toledo Edison have flexibility to determine how to
achieve this incremental asset revaluation, but no additional price increases to
recover the accelerated asset revaluation were proposed. Any incremental
revaluation of assets would be for regulatory purposes and would cause prices
and revenues after the five-year period to be lower than they otherwise would be
in conjunction with any rate case following such revaluation. The Staff's asset
revaluation proposal represents a substantial change in the form of rate-making
traditionally followed by the PUCO and is inconsistent with the Ohio statutes
that define the rate-making process. The PUCO is not bound by the
recommendations of the Staff. A decision by the PUCO is anticipated in the
second quarter of 1996.
 
(C) ASSESSMENT OF POTENTIAL OUTCOMES
 
We continually assess the effects of competition and the changing industry and
regulatory environment on operations, the Company's ability to recover
regulatory assets and the Company's ability to continue application of SFAS 71.
If, as a result of the pending rate case or other events, we determine that the
Company no longer meets the criteria for SFAS 71, the Company would be required
to record a before-tax charge to write off the regulatory assets shown above and
evaluate whether the Company's property, plant and equipment should be written
down. In the more likely event that only a portion of operations (such as
nuclear operations) no longer meets the criteria of SFAS 71, a write-off would
be limited to regulatory assets, if any, that are not reflected in the Company's
cost-based prices established for the remaining regulated operations. In
addition, we would be required to evaluate whether the changes in the
competitive and regulatory environment which led to discontinuing the
application of SFAS 71 to a portion of the Company's operations would also
result in a write-down of the Company's property, plant and equipment pursuant
to SFAS 121.
 
We believe application of SFAS 121 in that event will not result in a write-off
of regulatory assets unless the PUCO denies recovery of such assets or if we
conclude, as a result of the outcome of the Company's pending rate case or some
other event, that recovery is not probable for some or all of the regulatory
assets. Furthermore, a write-down under SFAS 121 of the Company's property,
plant and equipment is not expected.
 
(D) RATE STABILIZATION PROGRAM
 
The Rate Stabilization Program that the PUCO approved in October 1992 allowed
the Company to defer and subsequently amortize and recover certain costs not
currently recovered in rates and to accelerate amortization of certain benefits
during the 1992-1995 period. Recovery of the deferrals will begin with the
effective date of the PUCO's order in the pending rate case. The regulatory
assets recorded included 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 incremental expenses resulting from
the adoption of SFAS 106 (see Note 9(b)). The cost deferrals recorded in 1995,
1994 and 1993 pursuant to these provisions were $75 million, $70 million and
$116 million, respectively. The regulatory accounting measures also provided for
the accelerated amortization of certain unrestricted excess deferred tax and
unrestricted investment tax credit balances and an excess interim spent fuel
 
 (Cleveland Electric)                  F-43                 (Cleveland Electric)
<PAGE>   96
 
storage accrual balance for Davis-Besse. The total annual amount of such
accelerated benefits was $28 million in 1995, 1994 and 1993.
 
(E) PHASE-IN DEFERRALS
 
In 1993, upon completing a comprehensive study which led to our strategic plan,
we concluded that projected revenues would not provide for recovery of deferrals
recorded pursuant to a phase-in plan approved by the PUCO in 1989 and,
consequently, that the deferrals would have to be written off. Such deferrals
were scheduled to be recovered in 1994 through 1998. 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).
 
(8) FEDERAL INCOME TAX
 
The components of federal income tax expense (credit) recorded in the Income
Statement were as follows:
 
<TABLE>
<CAPTION>
                                         1995    1994    1993
                                         -----   -----   -----
                                         (millions of dollars)
<S>                                      <C>     <C>     <C>
Operating Expenses:
  Current                                 $49    $ 53    $  64
  Deferred                                 45      29      (42)
                                         ----    ----    -----
    Total Charged to Operating Expenses    94      82       22
                                         ----    ----    -----
Nonoperating Income:
  Current                                  (9)    (17 )    (20)
  Deferred                                 11      21     (250)
                                         ----    ----    -----
    Total Expense (Credit) to
      Nonoperating Income                   2       4     (270)
                                         ----    ----    -----
Total Federal Income Tax Expense
  (Credit)                                $96    $ 86    $(248)
                                         ----    ----    -----
</TABLE>
 
The deferred federal income tax expense results from the temporary differences
that arise from the different years certain expenses are recognized for tax
purposes as opposed to financial reporting purposes. Such temporary differences
affecting operating expenses relate principally to depreciation and deferred
operating expenses whereas those affecting nonoperating income principally
relate to deferred carrying charges and the 1993 write-offs.
 
Federal income tax, computed by multiplying income before taxes by the 35%
statutory rate, is reconciled to the amount of federal income tax recorded on
the books as follows:
 
<TABLE>
<CAPTION>
                                         1995    1994    1993
                                         -----   -----   -----
                                         (millions of dollars)
<S>                                      <C>     <C>     <C>
Book Income (Loss) Before Federal
  Income Tax                             $280    $271    $(835)
                                         ----    ----    -----
Tax (Credit) on Book Income (Loss) at
  Statutory Rate                         $ 98    $ 95    $(292)
Increase (Decrease) in Tax:
    Write-off of Perry Unit 2              --      --       30
    Write-off of phase-in deferrals        --      --       20
    Depreciation                            8       6        6
    Rate Stabilization Program            (18 )   (18 )    (20)
    Other items                             8       3        8
                                         ----    ----    -----
Total Federal Income Tax Expense
  (Credit)                               $ 96    $ 86    $(248)
                                         ----    ----    -----
</TABLE>
 
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.
 
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994
and resulted in a $204 million loss with a corresponding $71 million reduction
in federal income tax liability. Because of the alternative minimum tax (AMT),
$40 million of the $71 million was realized in 1994. The remaining $31 million
will not be realized until 1999. Additionally, a repayment of approximately $29
million of previously allowed investment tax credits was recognized in 1994.
 
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $425 million and deferred tax liabilities of $1.723 billion at
December 31, 1995 and deferred tax assets of $418 million and deferred tax
liabilities of $1.652 billion at December 31, 1994. These are summarized as
follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                               ---------------
                                                1995     1994
                                               ------   ------
                                                (millions of
                                                  dollars)
<S>                                            <C>      <C>
Property, plant and equipment                  $1,468   $1,429
Deferred carrying charges and operating           139      132
  expenses
Net operating loss carryforwards                  (67)     (88)
Investment tax credits                            (99)    (105)
Sale and leaseback transactions                  (123)    (125)
Other                                             (20)      (9)
                                               ------   ------
    Net deferred tax liability                 $1,298   $1,234
                                               ------   ------
</TABLE>
 
For tax purposes, net operating loss (NOL) carryforwards of approximately $192
million are available to reduce future taxable income and will expire in 2005
through 2009. The 35% tax effect of the NOLs is $67 million. Additionally, AMT
credits of $133 million that may be carried forward indefinitely are available
to reduce future tax.
 
(9) RETIREMENT BENEFITS
 
(A) RETIREMENT INCOME PLAN
 
Centerior Energy sponsors jointly with its subsidiaries a noncontributing
pension plan (Centerior Pension Plan) which covers all employee groups. 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 comply with the Employee Retirement Income Security Act of 1974
guidelines.
 
In 1993, eligible employees were offered the VTP, an early retirement program.
Operating expenses for Center-
 
 (Cleveland Electric)                  F-44                 (Cleveland Electric)
<PAGE>   97
 
ior Energy and its subsidiaries in 1993 included $205 million of pension plan
accruals to cover enhanced VTP benefits offset by a credit of $81 million
resulting from a settlement of pension obligations through lump sum payments to
almost all the VTP retirees.
 
Pension and VTP costs (credits) for Centerior Energy and its subsidiaries for
1993 through 1995 were comprised of the following components:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Pension Costs (Credits):
  Service cost for benefits earned
    during the period                     $ 10    $ 13    $ 15
  Interest cost on projected benefit
    obligation                              26      26      37
  Actual return on plan assets             (53)     (2)    (65)
  Net amortization and deferral              9     (34)      4
                                           ---     ---     ---
    Net pension costs (credits)             (8)      3      (9)
  VTP cost                                  --      --     205
  Settlement gain                           --      --     (81)
                                           ---     ---     ---
    Net costs (credits)                   $ (8)   $  3    $115
                                           ---     ---     ---
</TABLE>
 
Pension and VTP costs (credits) for the Company and its pro rata share of the
Service Company's costs were $(5) million, $2 million and $62 million for 1995,
1994 and 1993, respectively.
 
The following table presents a reconciliation of the funded status of the
Centerior Pension Plan. The Company's share of the Centerior Pension Plan's
total projected benefit obligation approximates 50%.
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Actuarial present value of benefit
  obligations:
  Vested benefits                               $304     $278
  Nonvested benefits                               2        2
                                                ----     ----
    Accumulated benefit obligation               306      280
  Effect of future compensation levels            54       37
                                                ----     ----
    Total projected benefit obligation           360      317
Plan assets at fair market value                 394      362
                                                ----     ----
    Funded status                                 34       45
Unrecognized net gain from variance
  between assumptions and experience             (68)     (79)
Unrecognized prior service cost                   15       10
Transition asset at January 1, 1987 being
  amortized
  over 19 years                                  (36)     (39)
                                                ----     ----
    Net accrued pension liability               $(55)    $(63)
                                                ----     ----
</TABLE>
 
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995, the settlement (discount) rate and long-term rate of return
on plan assets assumptions were 8% and 11%, respectively. The long-term rate of
annual compensation increase assumption was 3.5% in 1996 and 1997 and 4%
thereafter. At December 31, 1994, the settlement rate and long-term rate of
return on plan assets assumptions were 8.5% and 10%, respectively. The long-term
rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and
4% thereafter. At December 31, 1995 and 1994, the Company's net prepaid pension
cost included in Regulatory and Other Assets -- Other in the Balance Sheet was
$11 million and $7 million, respectively.
 
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. 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. Prior to
1993, the costs of these benefits were expensed as paid, which was consistent
with rate-making practices.
 
The components of the total postretirement benefit costs for 1993 through 1995
were as follows:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Service cost for benefits earned during
  the period                              $ 1     $ 1     $ 2
Interest cost on accumulated
  postretirement benefit obligation        11      11      10
Amortization of transition obligation
  at January 1, 1993 of $104 million
  over 20 years                             5       5       5
Amortization of gain                       (1 )    --      --
VTP curtailment cost (includes $10
  million transition obligation
  adjustment)                              --      --      52
                                          ---     ---     ---
  Total costs                             $16     $17     $69
                                          ---     ---     ---
</TABLE>
 
These amounts included costs for the Company and its pro rata share of the
Service Company's costs.
 
In 1995, 1994 and 1993, the Company deferred incremental SFAS 106 expenses (in
excess of the amounts paid) of $3 million, $4 million and $60 million,
respectively, pursuant to a provision of the Rate Stabilization Program. See
Note 7(d).
 
 (Cleveland Electric)                  F-45                 (Cleveland Electric)
<PAGE>   98
 
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost for the Company and its share of the Service Company's obligation
are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995    1994
                                                -----   -----
                                                (millions of
                                                  dollars)
<S>                                             <C>     <C>
Accumulated postretirement benefit obligation
  attributable to:
  Retired participants                          $(124)  $(124)
  Fully eligible active plan participants          (2)     (1)
  Other active plan participants                  (19)    (14)
                                                -----   -----
    Accumulated postretirement benefit
      obligation                                 (145)   (139)
Unrecognized net gain from variance between
  assumptions and experience                      (12)    (16)
Unamortized transition obligation                  79      84
                                                -----   -----
    Accrued postretirement benefit cost         $ (78)  $ (71)
                                                -----   -----
</TABLE>
 
The Balance Sheet classification of Retirement Benefits at December 31, 1995 and
1994 includes only the Company's accrued postretirement benefit cost of $65
million and $59 million, respectively, and excludes the Service Company's
portion since the Service Company's total accrued cost is carried on its books.
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995 and 1994, the settlement rate and the long-term rate of annual
compensation increase assumptions were the same as those discussed for pension
reporting in Note 9(a). At December 31, 1995, the assumed annual health care
cost trend rates (applicable to gross eligible charges) were 8% for medical and
7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by
2003. 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 one percentage point in
each future year, the accumulated postretirement benefit obligation as of
December 31, 1995 would increase by $3 million and the aggregate of the service
and interest cost components of the annual postretirement benefit cost would
increase by $0.3 million.
 
(10) GUARANTEES
 
The Company has guaranteed certain loan and lease obligations of two coal
suppliers under two long-term coal supply contracts. At December 31, 1995, the
principal amount of the loan and lease obligations guaranteed by the Company
under both contracts was $39 million. In addition, the Company may be
responsible for mine closing costs when one of the contracts is terminated. At
December 31, 1995, the unfunded costs of closing this mine as estimated by the
supplier were $32 million.
 
The prices under both contracts which include certain minimum payments are
sufficient to satisfy the loan and lease obligations and mine closing costs over
the lives of the contracts. If either contract is terminated early for any
reason, the Company would attempt to reduce the termination charges and would
ask the PUCO to allow recovery of such charges from customers through the fuel
factor.
 
(11) CAPITALIZATION
 
(A) CAPITAL STOCK TRANSACTIONS
 
Preferred stock shares sold and retired during the three years ended December
31, 1995 are listed in the following table.
 
<TABLE>
<CAPTION>
                                        1995     1994     1993
                                        ----     ----     ----
                                        (thousands of shares)
<S>                                     <C>      <C>      <C>
Subject to Mandatory Redemption:
  Retirements
    $ 7.35 Series C                      (10)     (10)     (10)
     88.00 Series E                       (3)      (3)      (3)
    Adjustable Series M                 (100)    (100)    (100)
      9.125 Series N                    (111)    (189)    (150)
     91.50 Series Q                      (11)      --       --
     90.00 Series S                       (1)      --       --
Not Subject to Mandatory Redemption:
  Sales
    $42.40 Series T                       --       --      200
                                        ----     ----     -----
      Net (Decrease)                    (236)    (302)     (63)
                                        ----     ----     -----
</TABLE>
 
(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, 1995, the
Company had $212 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 $30 million in both 1996 and 1997, $15 million in 1998 and $33
million in both 1999 and 2000.
 
The annual preferred stock mandatory redemption provisions are as follows:
 
<TABLE>
<CAPTION>
                                   Shares                Price
                                   To Be     Beginning    Per
                                  Redeemed      in       Share
                                  --------   ---------   ------
<S>                               <C>        <C>         <C>
$ 7.35 Series C                    10,000       1984     $  100
 88.00 Series E                     3,000       1981      1,000
  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
</TABLE>
 
* All outstanding shares to be redeemed on December 1, 2001.
 
 (Cleveland Electric)                  F-46                 (Cleveland Electric)
<PAGE>   99
 
In 1995, the Company purchased 1,000 shares of Serial Preferred Stock, $90.00
Series S, which will reduce the 2002 redemption requirement shown in the above
table.
 
The annualized preferred dividend requirement at December 31, 1995 was $41
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 these
issues averaged 7.23% and 7.02%, respectively, in 1995.
 
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:
 
<TABLE>
<CAPTION>
                                 Actual
                               or Average
                                Interest
                                Rate at          December 31,
                              December 31,     -----------------
      Year of Maturity            1995          1995       1994
----------------------------  ------------     ------     ------
                                                 (millions of
                                                   dollars)
<S>                           <C>              <C>        <C>
First mortgage bonds:
  1997-2000                       13.75%       $   --     $   21
  1997-2000                        7.00             3          4
  1997-2000                       10.88            24         24
  1999-2000                        6.20             4          4
  2001-2005                        8.52           756        464
  2006-2010                        7.99           122        122
  2011-2015                        7.56           349        449
  2016-2020                        8.38           524        568
  2021-2025                        8.42           467        324
                                               ------     ------
                                                2,249      1,980
Secured medium-term notes
  due 1997-2021*                   8.56           376        516
Term bank loans                      --            --          2
Pollution control notes due
  1997-2012                        6.64            48         52
Other -- net                         --            (7)        (7)
                                               ------     ------
    Total Long-Term Debt                       $2,666     $2,543
                                               ------     ------
</TABLE>
 
* Secured by first mortgage bonds.
Long-term debt matures during the next five years as follows: $147 million in
1996, $51 million in 1997, $74 million in 1998, $154 million in 1999 and $10
million in 2000.
 
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.
 
Certain credit agreements of the Company contain covenants relating to fixed
charge coverage ratios and limitations on secured financing other than through
first mortgage bonds or certain other transactions. In June 1995, the Company
and Toledo Edison replaced letters of credit in connection with the sale and
leaseback of Beaver Valley Unit 2 that were due to expire with new letters of
credit expiring in June 1999. The letters of credit are in an aggregate amount
of approximately $225 million and are secured by first mortgage bonds of the
Company and Toledo Edison in the proportion of 40% and 60%, respectively. At
December 31, 1995, the Company had outstanding $2 million of bank loans secured
by subordinated mortgage collateral.
 
(12) SHORT-TERM BORROWING ARRANGEMENTS
 
Centerior Energy has a $125 million revolving credit facility through May 1996.
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. The credit agreement is secured with first mortgage bonds of the
Company and Toledo Edison in the proportion of 40% and 60%, respectively. The
banks' fee is 0.625% per annum payable quarterly in addition to interest on any
borrowings. There were no borrowings under the facility at December 31, 1995.
Also, the Company and Toledo Edison may borrow from each other on a short-term
basis. At December 31, 1995, the Company had total short-term borrowings of $5
million from its affiliates with an interest rate of 6.25%.
 
(13) FINANCIAL INSTRUMENTS
 
The estimated fair values at December 31, 1995 and 1994 of financial instruments
that do not approximate their carrying amounts in the Balance Sheet are as
follows:
 
<TABLE>
<CAPTION>
                                           December 31,
                                ----------------------------------
                                      1995              1994
                                ----------------  ----------------
                                Carrying   Fair   Carrying   Fair
                                 Amount   Value    Amount   Value
                                --------  ------  --------  ------
                                      (millions of dollars)
<S>                             <C>       <C>     <C>       <C>
Capitalization and Liabilities:
  Preferred Stock, with
    Mandatory Redemption
    Provisions (including
    current portion)             $  245   $  232   $  282   $  245
  Long-Term Debt (including
    current portion)              2,819    2,824    2,795    2,503
</TABLE>
 
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized
in the following table.
 
 (Cleveland Electric)                  F-47                 (Cleveland Electric)
<PAGE>   100
 
<TABLE>
<CAPTION>
                                               December 31,
                                             ----------------
                                              1995      1994
                                             ------    ------
                                               (millions of
                                                 dollars)
<S>                                          <C>       <C>
Type of Securities:
  Federal Government                          $ 26      $ 25
  Municipal                                     14        17
                                               ---       ---
    Total                                     $ 40      $ 42
                                               ---       ---
Maturities:
  Due within one year                         $  1      $ 11
  Due in one to five years                      12         8
  Due in six to 10 years                        13        10
  Due after 10 years                            14        13
                                               ---       ---
    Total                                     $ 40      $ 42
                                               ---       ---
</TABLE>
 
The fair value of these trusts is estimated based on the quoted market prices
for the investment securities. As a result of adopting the new accounting
standard for certain investments in debt and equity securities, SFAS 115, in
1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
 
<TABLE>
<CAPTION>
                                        Quarters Ended
                           ----------------------------------------
                           March 31,  June 30,  Sept. 30,  Dec. 31,
                           ---------  --------  ---------  --------
                                    (millions of dollars)
<S>                        <C>        <C>       <C>        <C>
1995
  Operating Revenues         $ 410      $424      $ 526      $408
  Operating Income              85        91        145        77
  Net Income                    34        38         90        23
  Earnings Available for
    Common Stock                23        27         80        12
1994
  Operating Revenues         $ 408      $415      $ 474      $401
  Operating Income              86        91        132        88
  Net Income                    33        38         79        35
  Earnings Available for
    Common Stock                21        27         68        24
</TABLE>
 
(15) PENDING MERGER OF TOLEDO EDISON INTO THE COMPANY
 
In March 1994, Centerior Energy announced a plan to merge Toledo Edison into the
Company. 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.
 
Various aspects of the merger are subject to the approval of the FERC and other
regulatory authorities. The FERC has deferred action on the merger application
until the merits of the open access transmission tariffs proposed by the Company
and Toledo Edison are addressed in hearings. The PUCO and the Pennsylvania
Public Utility Commission have approved the merger. NRC action on the request by
the Company and Toledo Edison for authorization to transfer certain NRC licenses
to the merged entity is not expected until approval has been obtained from the
FERC.
 
In June 1995, share owners of Toledo Edison's preferred stock approved the
merger and share owners of the Company's preferred stock approved the
authorization of additional shares of preferred stock. When the merger becomes
effective, share owners of Toledo Edison's preferred stock will exchange their
shares for preferred stock shares of the Company having substantially the same
terms. Debt holders of the merging companies will become debt holders of the
Company.
 
For the merging companies, the combined pro forma operating revenues were $2.516
billion, $2.422 billion and $2.475 billion and the combined pro forma net income
(loss) was $281 million, $268 million and $(876) million for the years 1995,
1994 and 1993, 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-48                 (Cleveland Electric)
<PAGE>   101
 
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
 
To the Share Owners and
Board of Directors of
The Cleveland Electric 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, 1995 and 1994, and the related consolidated statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1995. These financial statements and the schedule referred to below
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and the schedule 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1995, in conformity with generally accepted
accounting principles.
 
As discussed further in Note 9, a change was made in the method of accounting
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 schedule of The Cleveland Electric
Illuminating Company and subsidiaries listed in the Index to Schedules is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states 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 LLP
 
Cleveland, Ohio
February 21, 1996
 
 (Cleveland Electric)                  F-49                 (Cleveland Electric)
<PAGE>   102
 
FINANCIAL AND STATISTICAL REVIEW
 
                 OPERATING REVENUES (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                                                                             Total
                                                                          Total                    Total        Steam      Operating
     Year         Residential     Commercial     Industrial     Other     Retail    Wholesale     Electric     Heating     Revenues
<S>               <C>             <C>            <C>            <C>       <C>       <C>           <C>          <C>         <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                 $ 559            563            523          93      1 738         31          1 769         --        $ 1 769
1994                   531            541            508          98      1 678         20          1 698         --          1 698
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
1985                   382            356            454          48      1 240          6          1 246         13          1 259
</TABLE>
 
--------------------------------------------------------------------------------
 
                 OPERATING EXPENSES (millions of dollars)
 
<TABLE>
<CAPTION>
                                   Other         Generation                                      Deferred
                   Fuel &        Operation       Facilities      Depreciation       Taxes,       Operating     Federal      Total
                  Purchased          &             Rental             &           Other Than     Expenses,     Income     Operating
     Year           Power       Maintenance     Expense, Net     Amortization        FIT            Net        Taxes      Expenses
<S>               <C>           <C>             <C>              <C>              <C>            <C>           <C>        <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                $ 413            418              56              196             230           (36)          94       $ 1 371
1994                  391            394              56              195             218           (34)          82         1 302
1993                  423            598(a)           56              182             221            27(b)        22         1 529
1992                  434            410              55              179             226           (35)          89         1 358
1991                  455            414              56              171(c)          216            (7)         106         1 411
1985                  357            311              --               97             133            --          102         1 000
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                        Federal        Income
                                             Other        Deferred       Income        (Loss)
                                            Income &      Carrying      Taxes--        Before
                  Operating     AFUDC--    Deductions,    Charges,       Credit       Interest
     Year          Income       Equity        Net           Net        (Expense)      Charges
<S>               <C>           <C>        <C>            <C>          <C>            <C>
----------------------------------------------------------------------------------------------
1995                $ 398           2            2            29            (2)         $429
1994                  396           4            6            25            (4)          427
1993                  222           4         (356)(d)      (487)(b)       270          (347)
1992                  385           1            8            59            (5)          448
1991                  415           8            6            88           (24)          493
1985                  259         163           (5)           --            49           466
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                         Earnings
                                                      Preferred &         (Loss)
                                           Net        Preference       Available for
                    Debt       AFUDC--    Income         Stock            Common
     Year         Interest      Debt      (Loss)       Dividends           Stock
<S>               <C>          <C>        <C>        <C>               <C>
------------------------------------------------------------------------------------
1995                $248         (3)        184            43              $ 141
1994                 247         (5)        185            45                140
1993                 244         (4)       (587 )          45               (632)
1992                 243          --        205            41                164
1991                 251         (4)        246            36                210
1985                 212        (57)        311            42                269
</TABLE>
 
--------------------------------------------------------------------------------
 
(a) Includes early retirement program expenses and other charges of $165
    million.
(b) Includes write-off of phase-in deferrals of $636 million, consisting of $117
    million of deferred operating expenses and $519 million of deferred carrying
    charges.
(c) 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-50                 (Cleveland Electric)
<PAGE>   103
 
                    The Cleveland Electric Illuminating Company and Subsidiaries
 
<TABLE>
<CAPTION>
                                                 ELECTRIC SALES (millions of KWH)
                                                        ELECTRIC CUSTOMERS
                                                         RESIDENTIAL USAGE
                                                      (thousands at year end)
                                                                                                                        Industrial
  Year       Residential    Commercial    Industrial    Wholesale     Other     Total      Residential    Commercial     & Other
<S>          <C>            <C>           <C>           <C>           <C>       <C>        <C>            <C>           <C>
-------------------------------------------------------------------- ---------------------------------------
  ---------------------------
1995            5 063          5 946        7 994         1 694        550      21 247         670            72            7
1994            4 924          5 770        7 970         1 073        575      20 312         668            72            7
1993            4 934          5 634        7 911         2 290        532      21 301         669            71            8
1992            4 725          5 467        7 988         1 989        533      20 702         670            71            8
1991            4 940          5 493        8 017         2 442        565      21 457         668            70            8
1985            4 408          4 516        7 981           153        414      17 472         647            63            9
 
<CAPTION>
                                Average     Average
  Year     Total   Customer       KWH       Customer
<S>              <C>            <C>         <C>
---------
  -------
1995       749       7 570       11.04c     $835.40
1994       747       7 370       10.79       795.11
1993       748       7 373       10.93       805.68
1992       749       7 071       10.94       773.77
1991       746       7 170       11.08       797.25
1985       719       6 567        8.70       571.03
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                           LOAD (MW & %)       ENERGY (millions of KWH)
                                                               FUEL

                 Net                                                Company Generated
               Seasonal     Peak      Capacity      Load      -----------------------------     Purchased                Fuel Cost
    Year       Capability   Load       Margin      Factor     Fossil(e)  Nuclear     Total        Power       Total       Per KWH
<S>            <C>          <C>       <C>          <C>        <C>        <C>         <C>        <C>           <C>        <C>
--------------------------------------------------------   ----------------------------------------------------
  -----------------------
1995             4 273      4 049        5.2%       58.8%     12 684      8 175      20 859        1 673      22 532        1.42c
1994             4 500      3 740       16.9        62.4      12 840      6 405      19 245        2 022      21 267        1.35
1993             4 500      3 862       14.2        59.9      15 557      5 644      21 201        1 454      22 655        1.37
1992             4 704      3 605       23.4        63.0      12 715      7 521      20 236        1 649      21 885        1.47
1991             4 703      3 886       17.4        61.8      13 123      7 451      20 574        2 144      22 718        1.49
1985             3 244      3 257       (0.4)       67.5      15 713      1 012      16 725        2 033      18 758        1.81
 
<CAPTION>
              Efficiency
               BTU Per
    Year         KWH
<S>            <C>
------------
  ----------
1995            10 504
1994            10 538
1993            10 339
1992            10 456
1991            10 503
1985            10 387
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                 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
<S>            <C>        <C>                <C>        <C>              <C>          <C>           <C>           <C>
 
-----------------------------------------------------------------------------------------------------------
  -------        --------
1995           $6 872          2 094          4 778            73           180        $ 5 031        $ 155       $7 152
1994            6 871          2 014          4 857            99           195          5 151          156        7 151
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
1985            3 089            874          2 215         2 506           336          5 057          606        5 633
</TABLE>
 
--------------------------------------------------------------------------------
 
               CAPITALIZATION (millions of dollars & %)
 
<TABLE>
<CAPTION>
                                       Preferred &
                                        Preference         Preferred
                                       Stock, with       Stock, without
                                        Mandatory          Mandatory
                   Common Stock         Redemption         Redemption
    Year              Equity            Provisions         Provisions        Long-Term Debt      Total
<S>              <C>          <C>     <C>        <C>     <C>        <C>     <C>          <C>     <C>
-------------------------------------------------------------------------------------------------------
1995             $1 127        26%     215         5%     241         6%     2 666        63%    $4 249
1994              1 058        26      246         6      241         6      2 543        62      4 088
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
1985              1 764        41      315         7      144         3      2 099        49      4 322
</TABLE>
 
--------------------------------------------------------------------------------
 
(d) Includes write-off of Perry Unit 2 of $351 million.
 
(e) Reduced by net energy used by the Seneca Pumped Storage Plant for pumping.
 
 (Cleveland Electric)                  F-51                 (Cleveland Electric)
<PAGE>   104
 
MANAGEMENT'S FINANCIAL ANALYSIS
 
OUTLOOK
 
STRATEGIC PLAN
 
We continued to make progress during the second year of our eight-year strategic
plan, but we remain keenly aware of the magnitude of the problems that face us.
The strategic plan was created by Centerior Energy Corporation (Centerior
Energy), along with The Toledo Edison Company (Company) and The Cleveland
Electric Illuminating Company (Cleveland Electric), to achieve two major goals:
strengthening their financial conditions and improving their competitive
positions. The Company and Cleveland Electric are the two wholly owned electric
utility subsidiaries of Centerior Energy. The plan's objectives relate to the
combined operations of all three companies. The objectives are to achieve
profitable revenue growth, become a leader in customer satisfaction, build a
winning employee team, attain increasingly competitive power supply costs and
maximize share owner return on Centerior Energy common stock. We are not yet
positioned to compete in a less regulated electric utility industry, but every
major action being taken -- strategic planning, revenue enhancement, cost
reduction, improvement of work practices and application for increased prices --
is part of a comprehensive effort to succeed in an increasingly competitive
environment.
 
A primary objective of the strategic plan is continued and significant revenue
growth even as our markets become more competitive. The Company's retail
revenues adjusted for weather and fuel costs have grown about 1% annually since
1990. During 1995, we took aggressive steps to increase revenues through
enhanced marketing strategies. Also, our economic development efforts proved
successful in attracting major new customers and supporting the expansion of
existing ones. Although we are not satisfied with our growth rate, we expect
that our marketing activity will improve revenue growth.
 
The rate case which the Company and Cleveland Electric filed with The Public
Utilities Commission of Ohio (PUCO) in April 1995 is a critical factor to the
success of the strategic plan. We do not see this rate case as a continuation of
business as usual but as an important turning point which should, if we are
successful in accomplishing the objectives discussed below, bring an end to
price increases for the foreseeable future. A successful conclusion of the case
would speed our transition to a more competitive company by providing additional
cash to lower costs by accelerating the pay-down of debt and preferred stock. In
our view, a successful conclusion would include approval of the full price
increase requested with a regulatory commitment to maintain the established
price levels over an appropriate transition period. This should be coupled with
a means to accelerate recognition of regulatory assets (described in Note 7(a))
and nuclear generating assets concurrent with our cost control and revenue
enhancement efforts in order to earn a fair return for Centerior Energy common
stock share owners over time.
 
Another key part of our strategy is offering long-term contracts to those large
customers who could have incentives to change power suppliers. In 1995, 74% of
our industrial kilowatt-hour sales and 13% of our commercial kilowatt-hour sales
were under long-term contracts. We are renegotiating contracts before they
expire and in most cases are retaining customers under new long-term contracts.
 
We are continuing efforts to reduce fixed financing costs in order to strengthen
our financial condition. During 1995, utilizing strong cash flow and refinancing
at favorable terms, the Company reduced interest expense and preferred dividends
by $7 million and outstanding debt and preferred stock by $113 million.
 
Our overall costs are high relative to many of our neighboring utilities as a
result of our substantial nuclear investment. The strategic plan calls for
making us more competitive by continuing to reduce operating expenses and
capital expenditures. In 1995, to improve the focus on cost reduction and other
strategic plan objectives, Centerior Energy and its subsidiaries restructured
into six business groups. The new organization includes groups to manage the
generation, distribution and transmission businesses; provide services and
administrative functions; and invest in nonregulated enterprises. This
arrangement will also enhance each group's ability to identify cost reductions
by focusing on margins and improving work practices and customer service. We
will also continue to aggressively pursue initiatives to reduce the heavy tax
burden imposed upon us by the state and local tax structure in Ohio.
 
RATE CASE AND REGULATORY ACCOUNTING
 
In April 1995, the Company and Cleveland Electric filed requests with the PUCO
for price increases aggregating $119 million annually to be effective in 1996.
The price increases are necessary to recover cost increases and amortization of
certain costs deferred since 1992 pursuant to the Rate Stabilization Program
discussed below and in
 
 (Toledo Edison)                       F-52                      (Toledo Edison)
<PAGE>   105
 
Note 7. If their requests are approved, the Company and Cleveland Electric
intend to freeze prices until at least 2002 with the expectation that increased
sales and cost control measures will obviate the need for further price
increases. If circumstances make it impossible to earn a fair return for
Centerior Energy common stock share owners over time, the Company and Cleveland
Electric would ask for a further increase -- but only after taking all
appropriate actions to make such a request unnecessary.
 
In December 1995, the PUCO ordered an investigation into the financial
conditions, rates and practices of the Company and Cleveland Electric.
 
In its report on the rate request, the PUCO Staff recommended approval of the
$119 million requested ($35 million for the Company and $84 million for
Cleveland Electric), subject to a commitment by the Company and Cleveland
Electric to significantly revalue their assets. In late January 1996, the Staff
proposed that the Company and Cleveland Electric significantly revalue their
nuclear plant and regulatory assets within a five-year period. The Staff's asset
revaluation proposal is inconsistent with the Ohio statutes that define the
rate-making process. The PUCO is not bound by the Staff's recommendations. A
decision by the PUCO is anticipated in the second quarter of 1996.
 
The outcome of the rate case could affect the Company's ability to meet the
criteria of Statement of Financial Accounting Standards (SFAS) 71 for all or
part of its operations which could result in the write-off of all or a part of
the regulatory assets shown in Note 7(a). In our changing industry, other events
independent of the outcome of the rate case could also result in write-offs or
write-downs of assets.
 
See Note 7 for a full discussion and analysis of the rate case, SFAS 71 and
other financial accounting requirements and the potential implications of these
accounting requirements for the Company's results of operations and financial
position.
 
RATE STABILIZATION PROGRAM
 
Under a Rate Stabilization Program approved by the PUCO in 1992, we agreed to
freeze base rates until 1996 and limit rate increases through 1998. In exchange,
we were permitted to defer through 1995 and subsequently recover certain costs
not currently recovered in rates and to accelerate amortization of certain
benefits. Deferral of those costs and amortization of those benefits were
completed in November 1995 and aggregated $56 million for the Company in 1995.
Recovery is expected to begin with the effective date of the PUCO's order in the
pending rate case. Annual amortization of the deferred costs for the Company is
$10 million which began in December 1995. Consequently, earnings in 1996 will be
sharply lower than in 1995. Also contributing to lower earnings are the
expectations that the requested price increase will not be effective until the
second quarter of 1996 and results from increased marketing and cost reduction
efforts will take time to achieve.
 
COMPETITION
 
Major structural changes are taking place in the electric utility industry which
are expected to place downward pressure on prices and to increase competition
for customers' business. The changes are coming from both federal and state
authorities. Many of the changes began when the Energy Policy Act of 1992
permitted competition in the electric utility industry through broader access to
a utility's transmission system. In March 1995, the Federal Energy Regulatory
Commission (FERC) issued proposed rules relating to open access transmission
services by public utilities, recovery of stranded investment and other related
matters. The open access transmission rules require utilities to deliver power
from other utilities or generation sources to their wholesale customers. In May
1995, the Company and Cleveland Electric filed open access transmission tariffs
with the FERC which used the proposed rules as a guideline. These tariffs are
currently pending.
 
Several groups in Ohio are studying the possible application of retail wheeling.
Retail wheeling occurs when a customer obtains power from a utility company
other than its local utility. The PUCO is sponsoring informal discussions among
a group of business, utility and consumer interests to explore ways of promoting
competitive options without unduly harming the interests of utility company
share owners or customers. Legislative proposals are being drafted for
submission to the Ohio House of Representatives and several utilities in the
state have offered their own proposed transition plans for introduction of
retail wheeling. The current retail wheeling efforts in Ohio are exploratory and
we cannot predict when and to what extent retail wheeling will be implemented in
Ohio.
 
The term "stranded investment" generally refers to fixed costs approved for
recovery under traditional regulatory methods that would become unrecoverable,
or "stranded", as a result of wider competition. Although
 
 (Toledo Edison)                       F-53                      (Toledo Edison)
<PAGE>   106
 
competitive pressures are increasing, the traditional regulatory framework
remains in place and is expected to continue for the foreseeable future. We
cannot predict when and to what extent competition will be allowed. We believe
that pure competition (unrestricted retail wheeling for all customer
classifications) is at least several years away and that any transition to pure
competition will be in phases. The FERC and the PUCO have acknowledged the need
to provide at least partial recovery of stranded investment as greater
competition is permitted and, therefore, we believe that there will be a
mechanism developed for the recovery of stranded investment. However, due to the
uncertainty involved, there is a risk that some of our assets may not be fully
recovered.
 
In 1995, we continued to experience significant competition from municipal
electric systems. Also, in Toledo, the City Council responded to a petition
drive by appropriating funds to complete a consultant's study on whether to
create a municipal electric utility. This study is expected to be completed by
mid-1996.
 
In October 1995, Chase Brass & Copper Co. Inc., which has provided annual net
income of $2 million, terminated its service from the Company and began to
receive its electric service from a consortium of other providers. We have filed
lawsuits contending that this arrangement violates the legal limits of sales and
delivery of power by municipal electric systems outside their boundaries. We
will continue to pursue all legal and regulatory remedies to this situation.
 
In 1995, our economic development efforts proved successful in attracting major
new customers, such as North Star BHP Steel, Worthington Steel and Aluminum
Company of America, while supporting the expansion of existing ones. We expect
that our continued emphasis on economic development along with a newly developed
market segment focus will be major ingredients in providing improved revenue
growth.
 
NUCLEAR OPERATIONS
 
The Company has interests in three nuclear generating units -- Davis-Besse
Nuclear Power Station (Davis-Besse), Perry Nuclear Power Plant Unit 1 (Perry
Unit 1) and Beaver Valley Power Station Unit 2 (Beaver Valley Unit 2) -- and
operates the first one. Cleveland Electric operates Perry Unit 1. Davis-Besse
and Beaver Valley Unit 2 both operated extremely well in 1995. Their average
three-year unit availability factors at year-end 1995 of 90% and 87%,
respectively, exceeded the industry average of 81% for similar reactors. In
1995, the availability factor for Davis-Besse was 100%. The plant continues to
have its best run ever operating at or near full capacity for 463 straight days
through February 21, 1996.
 
In 1995, Perry Unit 1 improved its average three-year unit availability factor
to 62% with a 1995 availability factor of 93%. Perry Unit 1 operated at or near
capacity for 506 of 531 days since the end of its last refueling and maintenance
outage in August 1994. Work on the comprehensive course of action plan developed
in 1993 for Cleveland Electric to improve the operating performance of Perry
Unit 1 will be completed during the current refueling outage which began January
27, 1996.
 
A significant part of the strategic plan involves ongoing efforts to increase
the availability and lower the cost of production of our nuclear units. In 1995,
we made great progress regarding unit availability while continuing to lower
production costs. The goal of our nuclear improvement program is for Cleveland
Electric to replicate Davis-Besse's operational excellence and cost reduction
gains at Perry Unit 1 while improving performance ratings.
 
We externally fund the estimated costs for the future decommissioning of our
nuclear units. In 1993 and 1994, we increased our decommissioning expense
accruals because of revisions in our cost estimates. See Note 1(e).
 
Our nuclear units may be impacted by activities or events beyond our control.
Operating nuclear 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 domestic nuclear unit. If one of our nuclear units is taken out
of service for an extended period 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, thereby not permitting us to
recover our investment in and earn a return on it, or disallowing certain
construction or maintenance costs. An extended outage coupled with unfavorable
rate treatment could have a material adverse effect on our financial condition
and results of operations. Premature plant closings could also have a material
adverse effect on our financial condition and results of operations because the
estimated cost to decommission the plant exceeds the current funding in the
decommissioning trust.
 
 (Toledo Edison)                       F-54                      (Toledo Edison)
<PAGE>   107
 
HAZARDOUS WASTE DISPOSAL SITES
 
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. Allegations
that the Company disposed of hazardous waste at these sites, and the amount
involved, are often unsubstantiated and subject to dispute. Federal law provides
that all "potentially responsible parties" (PRPs) for a particular site be held
liable on a joint and several basis. 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 $5 million at December 31, 1995, 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.
 
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. 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 prior to its merger
into Cleveland Electric, as discussed below.
 
MERGER OF THE COMPANY INTO CLEVELAND ELECTRIC
 
We continue to seek the necessary regulatory approvals to complete the merger of
the Company into Cleveland Electric which was announced in 1994. The FERC has
deferred action on the merger application until the merits of the open access
transmission tariffs proposed by the Company and Cleveland Electric are
addressed in hearings. See Note 15.
 
CAPITAL RESOURCES AND LIQUIDITY
 
1993-1995 CASH REQUIREMENTS
 
A key part of the strategic plan is to significantly reduce the Company's level
of debt and preferred stock. In 1995, we were able to continue the reduction
pattern begun in 1994. The Company's obligations were reduced by $66 million in
1994 and by $113 million in 1995. We intend to continue and to accelerate
redemptions.
 
We need cash for normal corporate operations, retirement of maturing securities,
and an ongoing program of constructing and improving facilities to meet demand
for electric service and to comply with government regulations. Our cash
construction expenditures totaled $42 million in 1993, $41 million in 1994 and
$53 million in 1995. Our debt and preferred stock maturities and sinking fund
requirements totaled $58 million in both 1993 and 1994 and $83 million in 1995.
In addition, we optionally redeemed approximately $200 million in the period
1993-1995. This amount includes $94 million of tax-exempt issues refunded in
1995 resulting in approximately $4 million of interest savings. The embedded
cost of the Company's debt at the end of 1995 was 9.23% versus 9.48% in 1994 and
9.59% in 1993. In 1995, the Company and Cleveland Electric renewed for a
four-year term approximately $225 million in bank letters of credit supporting
the equity owner participants in the Beaver Valley Unit 2 lease. See Note 11(d).
 
The Company also utilized short-term borrowings to help meet its cash needs. The
Company had $21 million of notes payable to affiliates at December 31, 1995. See
Note 12.
 
1996 AND BEYOND CASH REQUIREMENTS
 
The Company's 1996 cash requirements for construction are $74 million and for
debt and preferred stock maturities and sinking fund requirements are $58
million. We expect to meet these requirements with internal cash generation,
cash reserves and about $40 million from the sale of a AAA-rated security backed
by our accounts receivable.
 
We expect to meet all of our 1997-2000 cash requirements with internal cash
generation. Estimated cash requirements for the Company's construction program
during this period total $262 million. Debt and preferred stock maturities and
sinking fund requirements total $233 million for the same period. If economical,
additional securities may be redeemed under optional redemption
 
 (Toledo Edison)                       F-55                      (Toledo Edison)
<PAGE>   108
 
provisions, with funding expected to be provided through internal cash
generation.
 
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. If
the applicable interest coverage test is met, the Company may issue first
mortgage bonds on the basis of property additions and, under certain
circumstances, refundable bonds. At December 31, 1995, the Company would have
been permitted to issue approximately $288 million of additional first mortgage
bonds.
 
The Company also is able to raise funds through the sale of debt and preferred
and preference stock. Under its articles of incorporation, the Company cannot
issue preferred stock unless certain earnings coverage requirements are met. At
December 31, 1995 the Company would have been permitted to issue approximately
$158 million of additional preferred stock at an assumed dividend rate of 10.5%.
There are no restrictions on the Company's ability to issue preference stock.
 
The Company and Cleveland Electric have $307 million in financing vehicles
available to support their nuclear fuel leases, portions of which mature this
year. See Note 6. The Company is a party to a $125 million revolving credit
facility which is expected to be renewed when it matures in May 1996. See Note
12. At the end of 1995, the Company had $94 million in cash and temporary
investments.
 
The foregoing financing resources are expected to be sufficient for the
Company's needs over the next several years. However, the availability and cost
of capital to meet the Company's external financing needs also depend upon such
factors as financial market conditions and its credit ratings. Current credit
ratings for the Company are as follows:
 
<TABLE>
<CAPTION>
                                     Standard          Moody's
                                     & Poor's         Investors
                                    Corporation     Service, Inc.
                                    -----------     -------------
<S>                                 <C>             <C>
First mortgage bonds                     BB              Ba2
Subordinated debt                         B+              B1
Preferred stock                           B               b2
</TABLE>
 
RESULTS OF OPERATIONS
 
1995 VS. 1994
 
Factors contributing to the 1% increase in 1995 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                           $  29
  Wholesale Revenues                                    (9)
  Fuel Cost Recovery Revenues                          (10)
  Miscellaneous Revenues                                (1)
                                                       ---
      Total                                          $   9
                                                       ---
</TABLE>
 
For the second year in a row, total kilowatt-hour sales increased. Total sales
increased 2.2% in 1995 primarily because of the hot summer weather. Residential
and commercial sales increased 5.2% and 2.2%, respectively, which included about
1% nonweather-related growth in residential sales. Industrial sales increased
1.8% on the strength of increased sales to large glass manufacturers and the
broad-based, smaller industrial customer group. Other sales increased 0.5%.
Weather accounted for approximately $13 million of the $21 million increase in
1995 base rate (nonfuel) revenues. Wholesale revenues decreased because of the
lower revenues associated with the Beaver Valley Unit 2 capacity sale to
Cleveland Electric. See Note 2. Lower 1995 fuel costs recovery revenues resulted
from favorable changes in the fuel cost factors. The weighted average of these
fuel cost factors decreased approximately 6%.
 
For 1995, operating revenues were 27% residential, 21% commercial, 29%
industrial and 23% other and kilowatt-hour sales were 19% residential, 16%
commercial, 37% industrial and 28% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.11 and $.06,
respectively.
 
Operating expenses increased 0.1% in 1995. Federal income taxes increased as a
result of higher pretax operating income. Fuel and purchased power expenses
decreased because of lower purchased power requirements resulting from the
increased availability of the nuclear generating units in 1995.
 
Interest charges and preferred dividends decreased in 1995 because of the
redemption of securities and refinancing at favorable terms.
 
 (Toledo Edison)                       F-56                      (Toledo Edison)
<PAGE>   109
 
1994 VS. 1993
 
Factors contributing to the 0.7% decrease in 1994 operating revenues are as
follows:
 
<TABLE>
<CAPTION>
                                                   Millions
   Increase (Decrease) in Operating Revenues      of Dollars
------------------------------------------------  -----------
<S>                                               <C>
  KWH Sales Volume and Mix                            $ 8
  Wholesale Revenues                                   (5)
  Fuel Cost Recovery Revenues                          (9)
                                                     ----
      Total                                           $(6)
                                                     ----
</TABLE>
 
The Company experienced good retail kilowatt-hour sales growth in the industrial
and commercial categories in 1994; the sales growth for the residential category
was lessened by weather conditions, particularly during the summer. The revenue
decrease resulted from milder weather conditions in 1994 and both lower
wholesale and fuel cost recovery revenues. Weather reduced base rate revenues
approximately $7 million from the 1993 amount. Total sales increased 7.8%.
Industrial sales increased 8.6% on the strength of increased sales to large
automotive manufacturers and the broad-based, smaller industrial customer group.
This growth substantiated an economic resurgence in Northwestern Ohio.
Residential and commercial sales increased 0.8% and 2.3%, respectively. Other
sales increased 16% because of increased sales to wholesale customers, although
the softer wholesale market conditions in 1994 resulted in lower wholesale
revenues. Lower 1994 fuel cost recovery revenues resulted from favorable changes
in the fuel cost factors. The weighted average of these fuel cost factors
dropped by 6%.
 
For 1994, operating revenues were 26% residential, 21% commercial, 29%
industrial and 24% other and kilowatt-hour sales were 19% residential, 16%
commercial, 37% industrial and 28% other. The average prices per kilowatt-hour
for residential, commercial and industrial customers were $.11, $.11 and $.06,
respectively. The changes from 1993 were not significant.
 
Operating expenses were 12% lower in 1994. Operation and maintenance expenses
for 1993 included $88 million of net benefit expenses related to an early
retirement program, called the Voluntary Transition Program (VTP), and other
charges totaling $19 million. The VTP benefit expenses in 1993 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). A smaller work force and ongoing cost reduction measures also lowered
operation and maintenance expenses. Lower purchased power costs helped reduce
fuel and purchased power expenses in 1994 despite an increase in the amount of
power purchased. More nuclear generation and less coal-fired generation also
accounted for a part of the lower fuel and purchased power expenses.
Depreciation and amortization expenses increased primarily because of higher
nuclear plant decommissioning expenses as discussed in Note 1(e). Deferred
operating expenses were greater primarily because of the write-off of $55
million of phase-in deferred operating expenses in 1993 as discussed in Note
7(e). The 1993 deferrals also included $32 million of postretirement benefit
curtailment cost deferrals related to the VTP. See Note 9(b). Federal income
taxes increased as a result of higher pretax operating income.
 
As discussed in Note 4(b), $232 million of our Perry Unit 2 investment was
written off in 1993. Also, as discussed in Note 7(e), phase-in deferred carrying
charges of $186 million were written off in 1993. The change in the federal
income tax credit amounts for nonoperating income was attributable to these
write-offs.
 
 (Toledo Edison)                       F-57                      (Toledo Edison)
<PAGE>   110
 
INCOME STATEMENT                                       The Toledo Edison Company
 
<TABLE>
<CAPTION>
                                                                         For the years ended
                                                                            December 31,
                                                                       -----------------------
                                                                       1995     1994     1993
                                                                       ----     ----     -----
                                                                        (millions of dollars)
<S>                                                                    <C>      <C>      <C>
OPERATING REVENUES (1)                                                 $874     $865     $ 871
                                                                       ----     ----     -----
OPERATING EXPENSES
  Fuel and purchased power                                              157      167       173
  Other operation and maintenance                                       225      229       245
  Generation facilities rental expense, net                             104      104       104
  Early retirement program expenses and other                            --       --       107
                                                                       ----     ----     -----
     Total operation and maintenance                                    486      500       629
  Depreciation and amortization                                          84       83        76
  Taxes, other than federal income taxes                                 91       90        91
  Deferred operating expenses, net                                      (17)     (21)       (4)
  Federal income taxes (credit)                                          42       33       (10)
                                                                       ----     ----     -----
                                                                        686      685       782
                                                                       ----     ----     -----
OPERATING INCOME                                                        188      180        89
                                                                       ----     ----     -----
NONOPERATING INCOME (LOSS)
  Allowance for equity funds used during construction                     1        1         1
  Other income and deductions, net                                        6        3        --
  Write-off of Perry Unit 2                                              --       --      (232)
  Deferred carrying charges, net                                         14       15      (161)
  Federal income taxes -- credit (expense)                               (2)      (2)      129
                                                                       ----     ----     -----
                                                                         19       17      (263)
                                                                       ----     ----     -----
INCOME (LOSS) BEFORE INTEREST CHARGES                                   207      197      (174)
                                                                       ----     ----     -----
INTEREST CHARGES
  Debt interest                                                         111      116       116
  Allowance for borrowed funds used during construction                  (1)      (1)       (1)
                                                                       ----     ----     -----
                                                                        110      115       115
                                                                       ----     ----     -----
NET INCOME (LOSS)                                                        97       82      (289)
PREFERRED DIVIDEND REQUIREMENTS                                          18       20        23
                                                                       ----     ----     -----
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK                             $ 79     $ 62     $(312)
                                                                       ----     ----     -----
</TABLE>
 
---------------
 
(1) Includes revenues from all bulk power sales to Cleveland Electric of $102
    million, $111 million and $120 million in 1995, 1994 and 1993, respectively.
 
RETAINED EARNINGS
 
<TABLE>
<CAPTION>
                                                                          For the years ended
                                                                             December 31,
                                                                       -------------------------
                                                                       1995      1994      1993
                                                                       -----     -----     -----
                                                                         (millions of dollars)
<S>                                                                    <C>       <C>       <C>
RETAINED EARNINGS (DEFICIT) AT BEGINNING OF YEAR                       $(113)    $(175)    $ 137
                                                                       -----     ------    -----            
ADDITIONS
  Net income (loss)                                                       97        82      (289)
DEDUCTIONS
  Preferred stock dividends declared and other                           (19)      (20)      (23)
                                                                       -----     ------    -----
                                                                                                
     Net Increase (Decrease)                                              78        62      (312)
                                                                       -----     ------    -----
                                                                                                
RETAINED EARNINGS (DEFICIT) AT END OF YEAR                             $ (35)    $(113)    $(175)
                                                                       -----     ------    -----                   
</TABLE>
 
The accompanying notes are an integral part of these statements.
 
 (Toledo Edison)                       F-58                      (Toledo Edison)
<PAGE>   111
 
                      (This page intentionally left blank)
 
 (Toledo Edison)                       F-59                      (Toledo Edison)
<PAGE>   112
 
BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                                       ----------------
                                                                                        1995      1994
                                                                                       ------    ------
                                                                                         (millions of
                                                                                           dollars)
<S>                                                                                    <C>       <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
  Utility plant in service                                                             $2,896    $2,899
     Less: accumulated depreciation and amortization                                      942       892
                                                                                       -------   -------
                                                                                        1,954     2,007
  Construction work in progress                                                            28        30
                                                                                       -------   -------
                                                                                        1,982     2,037
  Nuclear fuel, net of amortization                                                        78       119
  Other property, less accumulated depreciation                                            20         6
                                                                                       -------   -------
                                                                                        2,080     2,162
                                                                                       -------   -------
CURRENT ASSETS
  Cash and temporary cash investments                                                      94        88
  Amounts due from customers and others, net                                               68        62
  Amounts due from affiliates                                                              19        19
  Unbilled revenues                                                                        22        22
  Materials and supplies, at average cost                                                  40        45
  Fossil fuel inventory, at average cost                                                    9        12
  Taxes applicable to succeeding years                                                     71        72
  Other                                                                                     4         2
                                                                                       -------   -------
                                                                                          327       322
                                                                                       -------   -------
REGULATORY AND OTHER ASSETS
  Amounts due from customers for future federal income taxes, net                         416       405
  Unamortized loss from Beaver Valley Unit 2 sale                                          96       101
  Unamortized loss on reacquired debt                                                      28        28
  Carrying charges and operating expenses                                                 410       379
  Nuclear plant decommissioning trusts                                                     52        38
  Other                                                                                    65        67
                                                                                       -------   -------
                                                                                        1,067     1,018
                                                                                       -------   -------
       Total Assets                                                                    $3,474    $3,502
                                                                                       -------   -------
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Toledo Edison)                       F-60                      (Toledo Edison)
<PAGE>   113
 
                                                       The Toledo Edison Company
 
<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                                       ----------------
                                                                                        1995      1994
                                                                                       ------    ------
                                                                                         (millions of
                                                                                           dollars)
<S>                                                                                    <C>       <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
  Common shares, $5 par value: 60 million authorized;
     39.1 million outstanding in 1995 and 1994                                         $  196    $  196
  Premium on capital stock                                                                481       481
  Other paid-in capital                                                                   121       121
  Retained earnings (deficit)                                                             (35)     (113)
                                                                                       ------    ------
     Common stock equity                                                                  763       685
  Preferred stock
     With mandatory redemption provisions                                                   5         7
     Without mandatory redemption provisions                                              210       210
  Long-term debt                                                                        1,068     1,154
                                                                                       ------    ------
                                                                                        2,046     2,056
                                                                                       ------    ------
CURRENT LIABILITIES
  Current portion of long-term debt and preferred stock                                    58        83
  Current portion of nuclear fuel lease obligations                                        40        36
  Accounts payable                                                                         56        48
  Accounts and notes payable to affiliates                                                 53        31
  Accrued taxes                                                                            78        75
  Accrued interest                                                                         24        27
  Other                                                                                    20        16
                                                                                       ------    ------
                                                                                          329       316
                                                                                       ------    ------
DEFERRED CREDITS AND OTHER LIABILITIES
  Unamortized investment tax credits                                                       79        87
  Accumulated deferred federal income taxes                                               573       541
  Unamortized gain from Bruce Mansfield Plant sale                                        188       198
  Accumulated deferred rents for Bruce Mansfield Plant and Beaver Valley Unit 2            54        54
  Nuclear fuel lease obligations                                                           52        87
  Retirement benefits                                                                     103       103
  Other                                                                                    50        60
                                                                                       ------    ------
                                                                                        1,099     1,130
                                                                                       ------    ------
       Total Capitalization and Liabilities                                            $3,474    $3,502
                                                                                       ------    ------
</TABLE>
 
 (Toledo Edison)                       F-61                      (Toledo Edison)
<PAGE>   114
 
CASH FLOWS                                             The Toledo Edison Company
 
<TABLE>
<CAPTION>
                                                                                 For the years ended
                                                                                    December 31,
                                                                              -------------------------
                                                                              1995      1994      1993
                                                                              -----     -----     -----
                                                                                (millions of dollars)
<S>                                                                           <C>       <C>       <C>
CASH FLOWS FROM OPERATING ACTIVITIES (1)
  Net Income (Loss)                                                           $  97     $  82     $(289)
                                                                               ----     ------    ------
  Adjustments to Reconcile Net Income (Loss) to Cash from Operating
     Activities:
     Depreciation and amortization                                               84        83        76
     Deferred federal income taxes                                               16        46      (160)
     Unbilled revenues                                                           --         3        (4)
     Deferred fuel                                                               (3)        3        --
     Deferred carrying charges, net                                             (14)      (15)      161
     Leased nuclear fuel amortization                                            54        44        38
     Deferred operating expenses, net                                           (17)      (21)       (4)
     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                       (6)        1        (3)
     Changes in inventories                                                       8        (2)       10
     Changes in accounts payable                                                  8       (15)       16
     Changes in working capital affecting operations                              4       (16)       21
     Other noncash items                                                          9        10        14
                                                                               ----     ------    ------
       Total Adjustments                                                        142       120       479
                                                                               ----     ------    ------
          Net Cash from Operating Activities                                    239       202       190
                                                                               ----     ------    ------
CASH FLOWS FROM FINANCING ACTIVITIES (2)
  Bank loans, commercial paper and other short-term debt                         --        --       (40)
  Notes payable to affiliates                                                    21        --        --
  First mortgage bond issues                                                     99        31        20
  Secured medium-term note issues                                                --        --        93
  Maturities, redemptions and sinking funds                                    (215)      (98)      (89)
  Nuclear fuel lease obligations                                                (44)      (49)      (47)
  Dividends paid                                                                (18)      (20)      (23)
  Premiums, discounts and expenses                                               (6)       --        (1)
                                                                               ----     ------    ------
          Net Cash from Financing Activities                                   (163)     (136)      (87)
                                                                               ----     ------    ------
CASH FLOWS FROM INVESTING ACTIVITIES (2)
  Cash applied to construction                                                  (53)      (41)      (42)
  Interest capitalized as allowance for borrowed funds used during
     construction                                                                (1)       (1)       (1)
  Contributions to nuclear plant decommissioning trusts                         (11)      (12)       (4)
  Other cash received (applied)                                                  (5)       (6)       10
                                                                               ----     ------    ------
          Net Cash from Investing Activities                                    (70)      (60)      (37)
                                                                               ----     ------    ------
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS                                 6         6        66
                                                                               ----     ------    ------
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR                         88        82        16
                                                                               ----     ------    ------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR                            $  94     $  88     $  82
                                                                               ----     ------    ------
</TABLE>
 
---------------
 
<TABLE>
<S>                                                                           <C>       <C>       <C>
(1) Interest paid (net of amounts capitalized)                                $  93     $  94     $  92
                                                                              -----     -----     -----
    Income taxes paid                                                         $  23     $   5     $   7
                                                                              -----     -----     -----
</TABLE>
 
(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-62                      (Toledo Edison)
<PAGE>   115
 
STATEMENT OF PREFERRED STOCK                           The Toledo Edison Company
 
<TABLE>
<CAPTION>
                                                                          Current
                                                                           Call        December 31,
                                                         1995 Shares       Price       -------------
                                                         Outstanding     Per Share     1995     1994
                                                         -----------     ---------     ----     ----
                                                                                       (millions of
                                                                                         dollars)
<S>                          <C>                         <C>             <C>           <C>      <C>
$100 par value, 3,000,000 preferred shares authorized;
  $25 par value, 12,000,000 preferred shares authorized
     Subject to mandatory redemption:
                     $100 par
                             $9.375                          66,850      $ 101.48      $  7     $  8
                        25 par  
                              2.81                               --         --           --       10
                                                                                       ----     ----
                                                                                          7       18
     Less: Current maturities                                                             2       11
                                                                                       ----     ----
TOTAL PREFERRED STOCK, WITH MANDATORY REDEMPTION PROVISIONS                            $  5     $  7
                                                                                       ====     ====
     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         25.00        30       30
                             Series B Adjustable          1,200,000         25.75        30       30
                                                                                       ----     ----
TOTAL PREFERRED STOCK, WITHOUT MANDATORY REDEMPTION PROVISIONS                         $210     $210
                                                                                       ====     ====
</TABLE>
 
The accompanying notes are an integral part of this statement.
 
 (Toledo Edison)                       F-63                      (Toledo Edison)
<PAGE>   116
 
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. The Company follows the Uniform System of Accounts prescribed by the
FERC and adopted by the PUCO. Rate-regulated utilities are subject to SFAS 71
which governs accounting for the effects of certain types of rate regulation.
Pursuant to SFAS 71, certain incurred costs are deferred for recovery in future
rates. See Note 7.
 
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and
the disclosure of contingent assets and liabilities. The estimates are based on
an analysis of the best information available. Actual results could differ from
those estimates.
 
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
joint 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 $67 million, $59 million and $71 million
in 1995, 1994 and 1993, 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 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 (to 2007). 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) DEPRECIATION AND DECOMMISSIONING
 
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 3.8% in 1995, 3.5% in 1994 and 3.6% in 1993. The
annual straight-line depreciation rate for nuclear property is 2.5%. In
conjunction with its pending rate case, the Company has asked the PUCO to
approve an increase of this depreciation rate to approximately 3%.
 
The Company accrues the estimated costs of decommissioning its three nuclear
generating units. The accruals are required to be funded in an external trust.
The PUCO requires that the expense and payments to the external trusts be
determined on a levelized basis by dividing the unrecovered decommissioning
costs in current dollars by the remaining years in the licensing period of each
unit. This methodology requires that the net earnings on the
 
 (Toledo Edison)                       F-64                      (Toledo Edison)
<PAGE>   117
 
trusts be reinvested therein with the intent of having net earnings offset
inflation. The PUCO requires that the estimated costs of decommissioning and the
funding level be reviewed at least every five years.
 
In 1994, the Company increased its annual decommissioning expense accruals to
$11 million from the $5 million level in 1993. The accruals are reflected in
current rates. The increased accruals in 1994 were derived from updated,
site-specific studies for each of the units. The revised estimates reflect the
DECON method of decommissioning (prompt decontamination), and the locations and
cost characteristics specific to the units, and include costs associated with
decontamination, dismantlement and site restoration.
 
The revised estimates for the units in 1993 and 1992 dollars and in dollars at
the time of license expiration, assuming a 4% annual inflation rate, are as
follows:
 
<TABLE>
<CAPTION>
                                    License
                                   Expiration                Future
        Generating Unit               Year        Amount     Amount
-------------------------------    ----------     ------     ------
                                                    (millions of
                                                      dollars)
<S>                                <C>            <C>        <C>
Davis-Besse                           2017         $168(1)    $419
Perry Unit 1                          2026          100(1)     354
Beaver Valley Unit 2                  2027           51(2)     190
                                                   ----       ----
      Total                                        $319       $963
                                                   ----       ----
</TABLE>
 
---------------
 
(1) Dollar amounts in 1993 dollars.
(2) Dollar amount in 1992 dollars.
 
The updated estimates reflect substantial increases from the prior
PUCO-recognized aggregate estimates of $115 million
in 1987 and 1986 dollars.
 
The classification, Accumulated Depreciation and Amortization, in the Balance
Sheet at December 31, 1995 includes $59 million of decommissioning costs
previously expensed and the earnings on the external trust 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. The trust
earnings are recorded as an increase to the trust assets and the related
component of the decommissioning reserve (included in Accumulated Depreciation
and Amortization).
 
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
those of the Company, regarding the recognition, measurement and classification
of decommissioning costs for nuclear generating stations in the financial
statements. In response to these questions, the Financial Accounting Standards
Board (FASB) is reviewing the accounting for removal costs, including
decommissioning. If current accounting practices are changed, the annual
provision for decommissioning could increase; the estimated cost for decommis-
sioning could be recorded as a liability rather than as accumulated
depreciation; and trust fund income from the external decommissioning trusts
could be reported as investment income rather than as a reduction to
decommissioning expense. The FASB issued an exposure draft on the subject on
February 7, 1996.
 
(F) PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment are stated at original cost less amounts
disallowed by the PUCO. Construction costs include related payroll taxes,
retirement benefits, 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 12.6% in 1995,
9.87% in 1994 and 10.22% in 1993.
 
Maintenance and repairs for plant and equipment 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 the leases. See Note 7(a).
These amortizations and the lease expense amounts are reported in the Income
Statement as Generation Facilities Rental Expense, Net.
 
(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. See Note 7(a). 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.
 
 (Toledo Edison)                       F-65                      (Toledo Edison)
<PAGE>   118
 
(I) FEDERAL INCOME TAXES
 
The Company uses the liability method of accounting for income taxes in
accordance with SFAS 109. See Note 8. 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, the Company must record a liability for its 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. See Note 7(a).
 
Investment tax credits are deferred and amortized over the lives of the
applicable property as a reduction of depreciation expense. See Note 7(d) 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 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. These
leases extend through 2017 and 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 renew the leases.
The leases include conditions for mandatory termination (and possible repurchase
of the leasehold interest) for events of default.
 
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 such payments have been made on behalf of Cleveland
Electric.
 
Future minimum lease payments under the operating leases at December 31, 1995
are summarized as follows:
 
<TABLE>
<CAPTION>
                                          For          For
                                          the       Cleveland
                 Year                   Company     Electric
--------------------------------------  -------     ---------
                                        (millions of dollars)
<S>                                     <C>         <C>
1996                                    $  125       $    63
1997                                       102            63
1998                                       102            63
1999                                       108            70
2000                                       111            76
Later Years                              1,807         1,245
                                        ------        ------
      Total Future Minimum Lease
        Payments                        $2,355        $1,580
                                        ------        ------
</TABLE>
 
Rental expense is accrued on a straight-line basis over the terms of the leases.
The amount recorded in 1995, 1994 and 1993 as annual rental expense for the
Mansfield Plant leases was $45 million. The amounts recorded in 1995, 1994 and
1993 as annual rental expense for the Beaver Valley Unit 2 lease were $63
million, $64 million and $63 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. Revenues recorded for this transaction were
$98 million, $108 million and $103 million in 1995, 1994 and 1993, respectively.
We anticipate that this sale will continue indefinitely. The future minimum
lease payments through 2017 associated with Beaver Valley Unit 2 aggregate $1.35
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, 1995
 
 (Toledo Edison)                       F-66                      (Toledo Edison)
<PAGE>   119
 
includes the following facilities owned by the Company as a tenant in common
with other utilities and Lessors:
 
<TABLE>
<CAPTION>
                                           Property,
                                           Plant and
                          Ownership        Equipment
                          Megawatts      (Exclusive of     Accumulated
    Generating Unit       (% Share)      Nuclear Fuel)     Depreciation
------------------------ -----------     -------------     -----------
                                         (millions of dollars)
<S>                      <C>             <C>               <C>
Davis-Besse               429 (48.62%)      $   649           $ 202
Perry Unit 1              238 (19.91)         1,050             221
Beaver Valley Unit 2 and
  Common Facilities
  (Note 2)                 13  (1.65)           207              48
                                             ------          ------
      Total                                 $ 1,906           $ 471
                                             ------          ------
</TABLE>
 
(4) CONSTRUCTION AND CONTINGENCIES
 
(A) CONSTRUCTION PROGRAM
 
The estimated cost of the Company's construction program for the 1996-2000
period is $345 million, including AFUDC of $10 million and excluding nuclear
fuel.
 
The Clean Air Act Amendments of 1990 (Clean Air Act) requires, among other
things, significant reductions in the emission of sulfur dioxide and nitrogen
oxides by fossil-fueled generating units. Our strategy provides for compliance
primarily through greater use of low-sulfur coal at some of our units and the
use of emission allowances. Total capital expenditures from 1991 through 1995 in
connection with Clean Air Act compliance amounted to $4 million. The plan will
require additional capital expenditures over the 1996-2005 period of
approximately $41 million for nitrogen oxide control equipment and other plant
process modifications. In addition, higher fuel and other operation and
maintenance expenses may be incurred.
 
(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. 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.
 
(C) HAZARDOUS WASTE DISPOSAL SITES
 
The Company is aware of its potential involvement in the cleanup of several
sites. The Company has accrued a liability totaling $5 million at December 31,
1995 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 the discussion
of these and other risks in Management's Financial Analysis -- Outlook-Nuclear
Operations.
 
(B) NUCLEAR INSURANCE
 
The Price-Anderson Act limits the public 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 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 utility owners and lessees of Davis-Besse, Perry and Beaver Valley also have
insurance coverage for damage to property at these sites (including leased fuel
and cleanup costs). Coverage amounted to $2.75 billion for each site as of
January 1, 1996. 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. In addition, the Company can be assessed a maximum of $19 million
under these policies 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 80% of such estimate
per week for the next
 
 (Toledo Edison)                       F-67                      (Toledo Edison)
<PAGE>   120
 
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 Cleveland Electric through leases
with a special-purpose corporation. The total amount of financing currently
available under these lease arrangements is $307 million ($157 million from
intermediate-term notes and $150 million from bank credit arrangements). The
intermediate-term notes mature in 1996 and 1997 ($84 million in September 1996
and $73 million in September 1997). The bank credit arrangements terminate in
October 1996. The special-purpose corporation plans to obtain alternate
financing in 1996 to replace the $234 million of financing expiring in 1996. At
December 31, 1995, $93 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
$37 million, $21 million and $15 million, respectively, at December 31, 1995.
The nuclear fuel amounts financed and capitalized also included interest charges
incurred by the lessors amounting to $2 million in 1995, $4 million in 1994 and
$6 million in 1993. The estimated future lease amortization payments for the
Company based on projected consumption are $41 million in 1996, $34 million in
1997, $29 million in 1998, $28 million in 1999 and $27 million in 2000.
 
(7) REGULATORY MATTERS
 
(A) REGULATORY ACCOUNTING REQUIREMENTS AND REGULATORY ASSETS
 
The Company is subject to the provisions of SFAS 71 and has complied with its
provisions. SFAS 71 provides, among other things, for the deferral of certain
incurred costs that are probable of future recovery in rates. We monitor changes
in market and regulatory conditions and consider the effects of such changes in
assessing the continuing applicability of SFAS 71. Criteria that could give rise
to discontinuation of the application of SFAS 71 include: (1) increasing
competition which significantly restricts the Company's ability to charge prices
which allow it to recover operating costs, earn a fair return on invested
capital and recover the amortization of regulatory assets and (2) a significant
change in the manner in which rates are set by the PUCO from cost-based
regulation to some other form of regulation. Regulatory assets represent
probable future revenues to the Company associated with certain incurred costs,
which it will recover from customers through the rate-making process.
 
Effective January 1, 1996, the Company adopted SFAS 121 which imposes stricter
criteria for carrying regulatory assets than SFAS 71 by requiring that such
assets be probable of recovery at each balance sheet date. The criteria under
SFAS 121 for plant assets require such assets to be written down only if the
book value exceeds the projected net future cash flows.
 
Regulatory assets in the Balance Sheet are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Amounts due from customers for future federal
  income taxes, net                             $416     $405
Unamortized loss from Beaver Valley Unit 2
  sale                                            96      101
Unamortized loss on reacquired debt               28       28
Pre-phase-in deferrals*                          222      229
Rate Stabilization Program deferrals             188      150
                                                -----    -----
    Total                                       $950     $913
                                                -----    -----
</TABLE>
 
* Represent deferrals of operating expenses and carrying charges for Perry Unit
  1 and Beaver Valley Unit 2 in 1987 and 1988 which are being amortized over the
  lives of the related property.
 
As of December 31, 1995, customer rates provide for recovery of all the above
regulatory assets, except those related to the Rate Stabilization Program
discussed below. The remaining recovery periods for all of the regulatory assets
listed above range from 16 to 33 years.
 
(B) RATE CASE
 
In April 1995, the Company and Cleveland Electric filed requests with the PUCO
for price increases aggregating $119 million annually to be effective in 1996.
The price increases are necessary to recover cost increases and amortization of
certain costs deferred since 1992 pursuant to the Rate Stabilization Program. If
their requests are approved, the Company and Cleveland Electric intend to freeze
prices until at least 2002 with the expectation that increased sales and cost
control measures will preclude the need for further price increases. If
circumstances make it impossible to earn a fair return for Centerior Energy
common stock share owners over time, the Company and Cleveland Electric would
ask for a further increase, but only after taking all appropriate actions to
make such a request unnecessary.
 
In November 1995, the PUCO Staff issued its report addressing the rate case. The
Staff recommended that the PUCO grant the full $119 million price increase
requested ($35 million for the Company and $84 million
 
 (Toledo Edison)                       F-68                      (Toledo Edison)
<PAGE>   121
 
for Cleveland Electric). However, the Staff also recommended that the price
increase be conditioned upon the commitment by the Company and Cleveland
Electric "to a significant revaluation of their asset bases over some finite
period of time."
 
In December 1995, the PUCO ordered an investigation into the financial
conditions, rates and practices of the Company and Cleveland Electric to
identify outcomes and remedies other than those routinely applied during the
rate case process.
 
In late January 1996, the Staff proposed an incremental reduction (currently, an
aggregate of $1.25 billion for the Company and Cleveland Electric) beyond the
normal level in nuclear plant and regulatory assets within five years. The Staff
proposed that the Company and Cleveland Electric have flexibility to determine
how to achieve this incremental asset revaluation, but no additional price
increases to recover the accelerated asset revaluation were proposed. Any
incremental revaluation of assets would be for regulatory purposes and would
cause prices and revenues after the five-year period to be lower than they
otherwise would be in conjunction with any rate case following such revaluation.
The Staff's asset revaluation proposal represents a substantial change in the
form of rate-making traditionally followed by the PUCO and is inconsistent with
the Ohio statutes that define the rate-making process. The PUCO is not bound by
the recommendations of the Staff. A decision by the PUCO is anticipated in the
second quarter of 1996.
 
(C) ASSESSMENT OF POTENTIAL OUTCOMES
 
We continually assess the effects of competition and the changing industry and
regulatory environment on operations, the Company's ability to recover
regulatory assets and the Company's ability to continue application of SFAS 71.
If, as a result of the pending rate case or other events, we determine that the
Company no longer meets the criteria for SFAS 71, the Company would be required
to record a before-tax charge to write off the regulatory assets shown above and
evaluate whether the Company's property, plant and equipment should be written
down. In the more likely event that only a portion of operations (such as
nuclear operations) no longer meets the criteria of SFAS 71, a write-off would
be limited to regulatory assets, if any, that are not reflected in the Company's
cost-based prices established for the remaining regulated operations. In
addition, we would be required to evaluate whether the changes in the
competitive and regulatory environment which led to discontinuing the
application of SFAS 71 to a portion of the Company's operations would also
result in a write-down of the Company's property, plant and equipment pursuant
to SFAS 121.
 
We believe application of SFAS 121 in that event will not result in a write-off
of regulatory assets unless the PUCO denies recovery of such assets or if we
conclude, as a result of the outcome of the Company's pending rate case or some
other event, that recovery is not probable for some or all of the regulatory
assets. Furthermore, a write-down under SFAS 121 of the Company's property,
plant and equipment is not expected.
 
(D) RATE STABILIZATION PROGRAM
 
The Rate Stabilization Program that the PUCO approved in October 1992 allowed
the Company to defer and subsequently amortize and recover certain costs not
currently recovered in rates and to accelerate amortization of certain benefits
during the 1992-1995 period. Recovery of the deferrals will begin with the
effective date of the PUCO's order in the pending rate case. The regulatory
assets recorded included the deferral of post-in-service interest carrying
charges, depreciation expense and property taxes on assets placed in service
after February 29, 1988, the deferral of incremental expenses resulting from the
adoption of SFAS 106 (see Note 9(b)), and the deferral of the operating expenses
equivalent to an accumulated excess rent reserve for Beaver Valley Unit 2 (which
resulted from the April 1992 refinancing of Secured Lease Obligation Bonds
issued by a special-purpose corporation). The cost deferrals recorded in 1995,
1994 and 1993 pursuant to these provisions were $38 million, $43 million and $76
million, respectively. The regulatory accounting measures also provided for the
accelerated amortization of certain unrestricted excess deferred tax and
unrestricted investment tax credit balances and an excess interim spent fuel
storage accrual balance for Davis-Besse. The total annual amount of such
accelerated benefits was $18 million in 1995, 1994 and 1993.
 
(E) PHASE-IN DEFERRALS
 
In 1993, upon completing a comprehensive study which led to our strategic plan,
we concluded that projected revenues would not provide for recovery of deferrals
recorded pursuant to a phase-in plan approved by the PUCO in 1989 and,
consequently, that the deferrals would have to be written off. Such deferrals
were scheduled to be recovered in 1994 through 1998. 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).
 
 (Toledo Edison)                       F-69                      (Toledo Edison)
<PAGE>   122
 
(8) FEDERAL INCOME TAX
 
The components of federal income tax expense (credit) recorded in the Income
Statement were as follows:
 
<TABLE>
<CAPTION>
                                         1995    1994    1993
                                         -----   -----   -----
                                         (millions of dollars)
<S>                                      <C>     <C>     <C>
Operating Expenses:
  Current                                $ 40    $ 18    $  36
  Deferred                                  2      15      (46)
                                         ----    ----    -----
    Total Expense (Credit) to Operating
      Expenses                             42      33      (10)
                                         ----    ----    -----
Nonoperating Income:
  Current                                 (12 )   (29 )    (15)
  Deferred                                 14      31     (114)
                                         ----    ----    -----
    Total Expense (Credit) to
      Nonoperating Income                   2       2     (129)
                                         ----    ----    -----
Total Federal Income Tax Expense
  (Credit)                               $ 44    $ 35    $(139)
                                         ----    ----    -----
</TABLE>
 
The deferred federal income tax expense results from the temporary differences
that arise from the different years certain expenses are recognized for tax
purposes as opposed to financial reporting purposes. Such temporary differences
affecting operating expenses relate principally to depreciation and deferred
operating expenses whereas those affecting nonoperating income principally
relate to deferred carrying charges and the 1993 write-offs.
 
Federal income tax, computed by multiplying income before taxes by the 35%
statutory rate, is reconciled to the amount of federal income tax recorded on
the books as follows:
 
<TABLE>
<CAPTION>
                                         1995    1994    1993
                                         -----   -----   -----
                                         (millions of dollars)
<S>                                      <C>     <C>     <C>
Book Income (Loss) Before Federal
  Income Tax                             $141    $117    $(428)
                                         ----    ----    -----
Tax (Credit) on Book Income (Loss) at
  Statutory Rate                         $ 49    $ 41    $(150)
Increase (Decrease) in Tax:
    Write-off of Perry Unit 2              --      --       16
    Write-off of phase-in deferrals        --      --        8
    Depreciation                           (1 )    (3 )    (12)
    Rate Stabilization Program             (9 )    (9 )    (10)
    Sale and leaseback transactions and
     amortization                           5       5        5
    Other items                            --       1        4
                                         ----    ----    -----
Total Federal Income Tax Expense
  (Credit)                               $ 44    $ 35    $(139)
                                         ----    ----    -----
</TABLE>
 
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.
 
For tax reporting purposes, the Perry Unit 2 abandonment was recognized in 1994
and resulted in a $122 million loss with a corresponding $43 million reduction
in federal income tax liability. Because of the alternative minimum tax (AMT),
$25 million of the $43 million was realized in 1994. The remaining $18 million
will not be realized until 1999.
 
Under SFAS 109, temporary differences and carryforwards resulted in deferred tax
assets of $179 million and deferred tax liabilities of $752 million at December
31, 1995 and deferred tax assets of $178 million and deferred tax liabilities of
$719 million at December 31, 1994. These are summarized as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Property, plant and equipment                   $627     $606
Deferred carrying charges and operating           85       83
  expenses
Net operating loss carryforwards                 (44)     (54)
Investment tax credits                           (46)     (51)
Sale and leaseback transactions                   (4)      (3)
Other                                            (45)     (40)
                                                -----    -----
    Net deferred tax liability                  $573     $541
                                                -----    -----
</TABLE>
 
For tax purposes, net operating loss (NOL) carryforwards of approximately $125
million are available to reduce future taxable income and will expire in 2005
through 2009. The 35% tax effect of the NOLs is $44 million. Additionally, AMT
credits of $80 million that may be carried forward indefinitely are available to
reduce future tax.
 
(9) RETIREMENT BENEFITS
 
(A) RETIREMENT INCOME PLAN
 
Centerior Energy sponsors jointly with its subsidiaries a noncontributing
pension plan (Centerior Pension Plan) which covers all employee groups. 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 comply with the Employee Retirement Income Security Act of 1974
guidelines.
 
In 1993, eligible employees were offered the VTP, an early retirement program.
Operating expenses for Centerior Energy and its subsidiaries in 1993 included
$205 million of pension plan accruals to cover enhanced VTP benefits offset by a
credit of $81 million resulting from a settlement of pension obligations through
lump sum payments to almost all the VTP retirees.
 
 (Toledo Edison)                       F-70                      (Toledo Edison)
<PAGE>   123
 
Pension and VTP costs (credits) for Centerior Energy and its subsidiaries for
1993 through 1995 were comprised of the following components:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Pension Costs (Credits):
  Service cost for benefits earned
    during the period                     $ 10    $ 13    $ 15
  Interest cost on projected benefit
    obligation                              26      26      37
  Actual return on plan assets             (53)     (2)    (65)
  Net amortization and deferral              9     (34)      4
                                           ---     ---     ---
    Net pension costs (credits)             (8)      3      (9)
  VTP cost                                  --      --     205
  Settlement gain                           --      --     (81)
                                           ---     ---     ---
    Net costs (credits)                   $ (8)   $  3    $115
                                           ---     ---     ---
</TABLE>
 
Pension and VTP costs (credits) for the Company and its pro rata share of the
Service Company's costs were $(3) million, $1 million and $53 million for 1995,
1994 and 1993, respectively.
 
The following table presents a reconciliation of the funded status of the
Centerior Pension Plan. The Company's share of the Centerior Pension Plan's
total projected benefit obligation approximates 30%.
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Actuarial present value of benefit
  obligations:
  Vested benefits                               $304     $278
  Nonvested benefits                               2        2
                                                ----     ----
    Accumulated benefit obligation               306      280
  Effect of future compensation levels            54       37
                                                ----     ----
    Total projected benefit obligation           360      317
Plan assets at fair market value                 394      362
                                                ----     ----
    Funded status                                 34       45
Unrecognized net gain from variance
  between assumptions and experience             (68)     (79)
Unrecognized prior service cost                   15       10
Transition asset at January 1, 1987 being
  amortized
  over 19 years                                  (36)     (39)
                                                ----     ----
    Net accrued pension liability               $(55)    $(63)
                                                ----     ----
</TABLE>
 
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995, the settlement (discount) rate and long-term rate of return
on plan assets assumptions were 8% and 11%, respectively. The long-term rate of
annual compensation increase assumption was 3.5% in 1996 and 1997 and 4%
thereafter. At December 31, 1994, the settlement rate and long-term rate of
return on plan assets assumptions were 8.5% and 10%, respectively. The long-term
rate of annual compensation increase assumption was 3.5% for 1995 and 1996 and
4% thereafter. At December 31, 1995 and 1994, the Company's net accrued pension
liability included in Retirement Benefits in the Balance Sheet was $64 million
and $66 million, respectively.
 
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. 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. Prior to
1993, the costs of these benefits were expensed as paid, which was consistent
with rate-making practices.
 
The components of the total postretirement benefit costs for 1993 through 1995
were as follows:
 
<TABLE>
<CAPTION>
                                          1995    1994    1993
                                          ----    ----    ----
                                              (millions of
                                                dollars)
<S>                                       <C>     <C>     <C>
Service cost for benefits earned during
  the period                              $ 1     $ 1     $ 1
Interest cost on accumulated
  postretirement benefit obligation         7       7       6
Amortization of transition obligation
  at January 1, 1993 of $63 million
  over 20 years                             2       3       3
VTP curtailment cost (includes $6
  million transition obligation
  adjustment)                              --      --      32
                                          ---     ---     ---
  Total costs                             $10     $11     $42
                                          ---     ---     ---
</TABLE>
 
These amounts included costs for the Company and its pro rata share of the
Service Company's costs.
 
In 1995, 1994 and 1993, the Company deferred incremental SFAS 106 expenses (in
excess of the amounts paid) of $1 million, $2 million and $37 million,
respectively, pursuant to a provision of the Rate Stabilization Program. See
Note 7(d).
 
 (Toledo Edison)                       F-71                      (Toledo Edison)
<PAGE>   124
 
The accumulated postretirement benefit obligation and accrued postretirement
benefit cost for the Company and its share of the Service Company's obligation
are as follows:
 
<TABLE>
<CAPTION>
                                                December 31,
                                                -------------
                                                1995     1994
                                                ----     ----
                                                (millions of
                                                  dollars)
<S>                                             <C>      <C>
Accumulated postretirement benefit obligation
  attributable to:
  Retired participants                          $(76)    $(79)
  Fully eligible active plan participants         (1)      --
  Other active plan participants                  (9)      (7)
                                                -----    -----
    Accumulated postretirement benefit
      obligation                                 (86)     (86)
Unrecognized net gain from variance between
  assumptions and experience                      (9)      (7)
Unamortized transition obligation                 49       51
                                                -----    -----
    Accrued postretirement benefit cost         $(46)    $(42)
                                                -----    -----
</TABLE>
 
The Balance Sheet classification of Retirement Benefits at December 31, 1995 and
1994 includes only the Company's accrued postretirement benefit cost of $39
million and $37 million, respectively, and excludes the Service Company's
portion since the Service Company's total accrued cost is carried on its books.
 
A September 30 measurement date was used for 1995 and 1994 reporting. At
December 31, 1995 and 1994, the settlement rate and the long-term rate of annual
compensation increase assumptions were the same as those discussed for pension
reporting in Note 9(a). At December 31, 1995, the assumed annual health care
cost trend rates (applicable to gross eligible charges) were 8% for medical and
7.5% for dental in 1996. Both rates reduce gradually to a fixed rate of 4.75% by
2003. 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 one percentage point in
each future year, the accumulated postretirement benefit obligation as of
December 31, 1995 would increase by $3 million and the aggregate of the service
and interest cost components of the annual postretirement benefit cost would
increase by $0.3 million.
 
(10) GUARANTEES
 
The Company has guaranteed certain loan and lease obligations of a coal supplier
under a long-term coal supply contract. At December 31, 1995, the principal
amount of the loan and lease obligations guaranteed by the Company was $14
million. The prices under the contract which includes certain minimum payments
are sufficient to satisfy the loan and lease obligations and mine closing costs
over the life of the contract. If the contract is terminated early for any
reason, the Company would attempt to reduce the termination charges and would
ask the PUCO to allow recovery of such charges from customers through the fuel
factor.
 
(11) CAPITALIZATION
 
(A) CAPITAL STOCK TRANSACTIONS
 
Preferred stock shares retired during the three years ended December 31, 1995
are listed in the following table.
 
<TABLE>
<CAPTION>
                                        1995     1994     1993
                                        ----     ----     ----
                                        (thousands of shares)
<S>                                     <C>      <C>      <C>
Subject to Mandatory Redemption:
  $100 par $9.375                        (17)     (17)     (17)
    25 par  2.81                        (400)    (800)    (800)
                                        ----     ----     -----
      Total                             (417)    (817)    (817)
                                        ----     ----     -----
</TABLE>
 
(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, 1995, the Company had $183 million of
appropriated retained earnings for the payment of preferred stock dividends. The
Company is prohibited from paying a common stock dividend by a provision in its
mortgage that essentially requires such dividends to be paid out of the total
balance of retained earnings, which currently is a deficit.
 
(C) PREFERRED AND PREFERENCE STOCK
 
Amounts to be paid for preferred stock which must be redeemed during the next
five years are $1.665 million in each year 1996 through 1999 only.
 
The annual preferred stock mandatory redemption provisions are as follows:
 
<TABLE>
<CAPTION>
                                    Shares                Price
                                    To Be     Beginning    Per
                                   Redeemed      in       Share
                                   --------   ---------   -----
<S>                                <C>        <C>         <C>
$100 par $9.375                     16,650       1985     $100
</TABLE>
 
The annualized preferred dividend requirement at December 31, 1995 was $17
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 7.75% and 8.58%, respectively, in 1995.
 
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-72                      (Toledo Edison)
<PAGE>   125
 
(D) LONG-TERM DEBT AND OTHER BORROWING ARRANGEMENTS
 
Long-term debt, less current maturities, was as follows:
 
<TABLE>
<CAPTION>
                                 Actual
                               or Average
                                Interest
                                Rate at          December 31,
                              December 31,     -----------------
      Year of Maturity            1995          1995       1994
----------------------------  ------------     ------     ------
                                                 (millions of
                                                   dollars)
<S>                           <C>              <C>        <C>
First mortgage bonds:
  1997                            6.125%       $   31     $   31
  1998                           10.00              1          1
  1999                            7.25            100        100
  2001-2005                       7.85            207        207
  2011-2015                       3.85             31         31
  2016-2020                       7.82            166         67
  2021-2023                       7.74            148        148
                                               ------     ------
                                                  684        585
Secured medium-term notes
  due 1997-2021*                  8.41            238        250
Term bank loans                  --                --         62
Notes due 1997**                  8.75              8         25
Debentures due 2002               8.70            135        135
Pollution control notes due
  1997-2010                       6.59              5         99
Other -- net                     --                (2)        (2)
                                               ------     ------
    Total Long-Term Debt                       $1,068     $1,154
                                               ------     ------
</TABLE>
 
 * Secured by first mortgage bonds.
** Secured by subordinated mortgage collateral.
Long-term debt matures during the next five years as follows: $56 million in
1996, $40 million in 1997, $39 million in 1998, $119 million in 1999 and $31
million in 2000.
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 credit agreements of the Company contain covenants relating to fixed
charge coverage ratios and limitations on secured financing other than through
first mortgage bonds or certain other transactions. In June 1995, the Company
and Cleveland Electric replaced letters of credit in connection with the sale
and leaseback of Beaver Valley Unit 2 that were due to expire with new letters
of credit expiring in June 1999. The letters of credit are in an aggregate
amount of approximately $225 million and are secured by first mortgage bonds of
the Company and Cleveland Electric in the proportion of 60% and 40%,
respectively. At December 31, 1995, the Company had outstanding $52 million of
bank loans and notes secured by subordinated mortgage collateral.
 
(12) SHORT-TERM BORROWING ARRANGEMENTS
 
Centerior Energy has a $125 million revolving credit facility through May 1996.
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. The credit agreement is secured with first
mortgage bonds of the Company and Cleveland Electric in the proportion of 60%
and 40%, respectively. The banks' fee is 0.625% per annum payable quarterly in
addition to interest on any borrowings. There were no borrowings under the
facility at December 31, 1995. Also, the Company and Cleveland Electric may
borrow from each other on a short-term basis. At December 31, 1995, the Company
had total short-term borrowings of $21 million from its affiliates with a
weighted average interest rate of 6.25%.
 
(13) FINANCIAL INSTRUMENTS
 
The estimated fair values at December 31, 1995 and 1994 of financial instruments
that do not approximate their carrying amounts in the Balance Sheet are as
follows:
 
<TABLE>
<CAPTION>
                                           December 31,
                                ----------------------------------
                                      1995              1994
                                ----------------  ----------------
                                Carrying   Fair   Carrying   Fair
                                 Amount   Value    Amount   Value
                                --------  ------  --------  ------
                                      (millions of dollars)
<S>                             <C>       <C>     <C>       <C>
Capitalization and Liabilities:
  Preferred Stock, with
    Mandatory Redemption
    Provisions (including
    current portion)             $    7   $    6   $   18   $   19
  Long-Term Debt (including
    current portion)              1,126    1,137    1,227    1,116
</TABLE>
 
Noncash investments in the Nuclear Plant Decommissioning Trusts are summarized
in the following table.
 
<TABLE>
<CAPTION>
                                               December 31,
                                             ----------------
                                              1995      1994
                                             ------    ------
                                               (millions of
                                                 dollars)
<S>                                          <C>       <C>
Type of Securities:
  Federal Government                          $ 21      $ 21
  Municipal                                     11        14
                                               ---       ---
    Total                                     $ 32      $ 35
                                               ---       ---
Maturities:
  Due within one year                         $  1      $  9
  Due in one to five years                       9         7
  Due in six to 10 years                        11         7
  Due after 10 years                            11        12
                                               ---       ---
    Total                                     $ 32      $ 35
                                               ---       ---
</TABLE>
 
The fair value of these trusts is estimated based on the quoted market prices
for the investment securities. As a result of adopting the new accounting
standard for certain investments in debt and equity securities, SFAS 115, in
 
 (Toledo Edison)                       F-73                      (Toledo Edison)
<PAGE>   126
 
1994, the carrying amount of these trusts approximates fair value. 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, 1995 and 1994 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, 1995.
 
<TABLE>
<CAPTION>
                                        Quarters Ended
                           ----------------------------------------
                           March 31,  June 30,  Sept. 30,  Dec. 31,
                           ---------  --------  ---------  --------
                                    (millions of dollars)
<S>                        <C>        <C>       <C>        <C>
1995
  Operating Revenues         $ 206      $215      $ 246      $206
  Operating Income              43        45         59        41
  Net Income                    20        22         33        22
  Earnings Available for
    Common Stock                15        17         29        18
1994
  Operating Revenues         $ 217      $216      $ 227      $204
  Operating Income              43        43         53        40
  Net Income                    19        20         29        15
  Earnings Available for
    Common Stock                13        14         24        11
</TABLE>
 
(15) PENDING MERGER OF THE COMPANY INTO CLEVELAND ELECTRIC
 
In March 1994, Centerior Energy announced a plan to merge the Company into
Cleveland Electric. 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.
 
Various aspects of the merger are subject to the approval of the FERC and other
regulatory authorities. The FERC has deferred action on the merger application
until the merits of the open access transmission tariffs proposed by the Company
and Cleveland Electric are addressed in hearings. The PUCO and the Pennsylvania
Public Utility Commission have approved the merger. NRC action on the request by
the Company and Cleveland Electric for authorization to transfer certain NRC
licenses to the merged entity is not expected until approval has been obtained
from the FERC.
 
In June 1995, share owners of the Company's preferred stock approved the merger
and share owners of Cleveland Electric's preferred stock approved the
authorization of additional shares of preferred stock. When the merger becomes
effective, share owners of the Company's preferred stock will exchange their
shares for preferred stock shares of Cleveland Electric having substantially the
same terms. Debt holders of the merging companies will become debt holders of
Cleveland Electric.
 
For the merging companies, the combined pro forma operating revenues were $2.516
billion, $2.422 billion and $2.475 billion and the combined pro forma net income
(loss) was $281 million, $268 million and $(876) million for the years 1995,
1994 and 1993, 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-74                      (Toledo Edison)
<PAGE>   127
 
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
 
To the Share Owners and
Board of Directors of
The Toledo 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, 1995 and 1994, and the related statements of
income, retained earnings and cash flows for each of the three years in the
period ended December 31, 1995. These financial statements and the schedule
referred to below are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and the
schedule 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, 1995 and 1994, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1995, in conformity
with generally accepted accounting principles.
 
As discussed further in Note 9, a change was made in the method of accounting
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 schedule of The Toledo Edison Company
listed in the Index to Schedules is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states 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 LLP
 
Cleveland, Ohio
February 21, 1996
 
 (Toledo Edison)                       F-75                      (Toledo Edison)
<PAGE>   128
 
FINANCIAL AND STATISTICAL REVIEW
 
                 OPERATING REVENUES (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                                                                Steam        Total
                                                                          Total                    Total       Heating     Operating
     Year         Residential     Commercial     Industrial     Other     Retail    Wholesale     Electric      & Gas      Revenues
<S>               <C>             <C>            <C>            <C>       <C>       <C>           <C>          <C>         <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                 $ 238            184            254          65       741         133           874          --         $ 874
1994                   227            181            251          64       723         142           865          --           865
1993                   229            180            244          71       724         147           871          --           871
1992                   215            175            236          61       687         158           845          --           845
1991                   230            184            236          90       740         147           887          --           887
1985                   185            129            214          26       554          22           576           6           582
</TABLE>
 
--------------------------------------------------------------------------------
 
                 OPERATING EXPENSES (millions of dollars)
 
<TABLE>
<CAPTION>
                                   Other         Generation                                      Deferred      Federal
                   Fuel &        Operation       Facilities      Depreciation       Taxes,       Operating     Income       Total
                  Purchased          &             Rental             &           Other Than     Expenses,     Taxes      Operating
     Year           Power       Maintenance     Expense, Net     Amortization        FIT            Net        (Credit)   Expenses
<S>               <C>           <C>             <C>              <C>              <C>            <C>           <C>        <C>
-------------------------------------------------------------------------------------------------------------------------------
1995                $ 157           225              104              84              91            (17)          42        $ 686
1994                  167           229              104              83              90            (21)          33          685
1993                  173           352(a)           104              76              91             (4)(b)      (10)         782
1992                  169           236              106              77              91            (17)          33          695
1991                  178           243              113              72(c)           89              1           32          728
1985                  166           141               --              44              48             --           53          452
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                        Federal       Income
                                             Other        Deferred       Income       (Loss)
                                            Income &      Carrying      Taxes--       Before
                  Operating     AFUDC--    Deductions,    Charges,       Credit       Interest
     Year          Income       Equity        Net           Net        (Expense)      Charges
<S>               <C>           <C>        <C>            <C>          <C>            <C>
---------------------------------------------------------------------------------------------
1995                $ 188           1            6            14            (2)        $ 207
1994                  180           1            3            15            (2)          197
1993                   89           1         (232)(d)      (161)(b)       129          (174)
1992                  150           1            1            41            (1)          192
1991                  159           1            5            22            (6)          181
1985                  130         105           11            --            38           284
</TABLE>
 
--------------------------------------------------------------------------------
 
                 INCOME (LOSS) (millions of dollars)
 
<TABLE>
<CAPTION>
                                                                     Earnings
                                                                      (Loss)
                                           Net       Preferred     Available for
                    Debt       AFUDC--    Income       Stock          Common
     Year         Interest      Debt      (Loss)     Dividends         Stock
<S>               <C>          <C>        <C>        <C>           <C>
--------------------------------------------------------------------------------
1995                $111          (1)        97          18            $  79
1994                 116          (1)        82          20               62
1993                 116          (1)      (289)         23             (312)
1992                 122          (1)        71          24               47
1991                 132          (1)        50          25               25
1985                 155         (45)       174          42              132
</TABLE>
 
--------------------------------------------------------------------------------
 
(a) Includes early retirement program expenses and other charges of $107
    million.
(b) Includes write-off of phase-in deferrals of $241 million, consisting of $55
    million of deferred operating expenses and $186 million of deferred carrying
    charges.
 
 (Toledo Edison)                       F-76                      (Toledo Edison)
<PAGE>   129
 
                                                       The Toledo Edison Company
 
<TABLE>
<CAPTION>
                                                 ELECTRIC SALES (millions of KWH)
                                                        ELECTRIC CUSTOMERS
                                                         RESIDENTIAL USAGE
                                                      (thousands at year end)
                                                                                                                        Industrial
  Year       Residential    Commercial    Industrial    Wholesale     Other     Total      Residential    Commercial     & Other
<S>          <C>            <C>           <C>           <C>           <C>       <C>        <C>            <C>           <C>
-------------------------------------------------------------------- --------------------------------------
  ---------------------------
1995            2 164         1 748         4 174         2 563        500      11 149         260            27            4
1994            2 056         1 711         4 099         2 548        499      10 913         257            26            4
1993            2 039         1 672         3 776         2 146        490      10 123         255            26            4
1992            1 941         1 619         3 563         2 753        478      10 354         255            26            5
1991            2 041         1 683         3 543         2 587        482      10 336         255            26            4
1985            1 901         1 436         3 429           611        451       7 828         246            24            4
 
<CAPTION>
                                  Average     Average
  Year     Total     Customer       KWH       Customer
<S>          <C>     <C>          <C>         <C>
---------
  -------
1995        291        8 384      10.99c      $921.23
1994        287        8 044       11.04       888.30
1993        285        7 997       11.23       897.65
1992        286        7 632       11.08       845.99
1991        285        7 990       11.26       897.41
1985        274        7 770        9.72       755.00
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                           LOAD (MW & %)       ENERGY (millions of KWH)
                                                               FUEL

                 Net                                               Company Generated
               Seasonal     Peak      Capacity      Load      ----------------------------     Purchased                Fuel Cost
    Year       Capability   Load       Margin      Factor     Fossil    Nuclear     Total        Power       Total       Per KWH
<S>            <C>          <C>       <C>          <C>        <C>       <C>         <C>        <C>           <C>        <C>
--------------------------------------------------------   ----------------------------------------------------
  -----------------------
1995             1 651      1 738       (5.3)%      62.4%     4 576      6 761      11 337         299       11 636        1.32c
1994             1 726      1 620        6.1        64.7      5 160      5 419      10 579         773       11 352        1.35
1993             1 726      1 568        9.2        64.3      5 548      4 791      10 339         196       10 535        1.42
1992             1 759      1 514       13.9        63.2      4 656      6 293      10 949         (82)      10 867        1.41
1991             1 757      1 510       14.1        64.5      4 848      6 003      10 851          95       10 946        1.44
1985             1 338      1 374      (2.7)        66.8      5 744        952       6 696       1 683        8 379        1.90
 
<CAPTION>
              Efficiency
               BTU Per
    Year         KWH
<S>            <C>
------------
  ----------
1995            10 341
1994            10 298
1993            10 146
1992            10 284
1991            10 327
1985            10 124
</TABLE>
 
--------------------------------------------------------------------------------
 
<TABLE>
<CAPTION>
                                                 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
<S>            <C>        <C>                <C>       <C>              <C>          <C>           <C>           <C>
 
----------------------------------------------------------------------------------------------------------
  -------        --------
1995           $2 896           942          1 954            28            98        $ 2 080        $  56       $3 474
1994            2 899           892          2 007            30           125          2 162           41        3 502
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
1985            1 392           390          1 002         1 755           228          2 985          389        3 373
</TABLE>
 
--------------------------------------------------------------------------------
 
               CAPITALIZATION (millions of dollars & %)
 
<TABLE>
<CAPTION>
                                      Preferred         Preferred
                                       Stock,            Stock,
                                        with             without
                                      Mandatory         Mandatory
                  Common Stock       Redemption        Redemption
    Year             Equity          Provisions        Provisions       Long-Term Debt      Total
<S>              <C>        <C>     <C>       <C>     <C>       <C>     <C>         <C>     <C>
--------------------------------------------------------------------------------------------------
1995             $763        38%      5        --%    210        10%    1 068        52%    $2 046
1994              685        34       7        --     210        10     1 154        56      2 056
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
1985              950        36     154         6     230         8     1 339        50      2 673
</TABLE>
 
--------------------------------------------------------------------------------
 
(c) 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.
 
(d) Includes write-off of Perry Unit 2 of $232 million.
 
 (Toledo Edison)                       F-77                      (Toledo Edison)
<PAGE>   130
<TABLE>
<CAPTION>
                             INDEX TO SCHEDULES
                             ------------------


                                                                        Page
                                                                        ----
<S>                                                                     <C>
Centerior Energy Corporation and Subsidiaries:
--------------------------------------------- 

Schedule II     Valuation and Qualifying Accounts for the               S-2
                Years Ended December 31, 1995, 1994 and 1993

The Cleveland Electric Illuminating Company and Subsidiaries:
------------------------------------------------------------ 

Schedule II     Valuation and Qualifying Accounts for the               S-3
                Years Ended December 31, 1995, 1994 and 1993

The Toledo Edison Company:
------------------------- 

Schedule II     Valuation and Qualifying Accounts for the               S-4
                Years Ended December 31, 1995, 1994 and 1993
</TABLE>


Schedules other than those listed above are omitted for the reason that they
are not required or are not applicable.





                                                                             S-1
<PAGE>   131


                         CENTERIOR ENERGY CORPORATION

               SCHEDULE II - VALUATION AND QUALIFIYING ACCOUNTS
             FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

                            (THOUSANDS OF DOLLARS)


<TABLE>                                   
<CAPTION>                                                                                                                          
                                                       Additions                          Deductions                               
                                             -----------------------------      ---------------------------------                  
                              Balance at      Charged to                          Deductions                           Balance at  
                              Beginning         Income                               from                                End of    
Description                   of Period       Statement         Other              Reserves            Other             Period    
-----------                   ---------      ------------     ------------      --------------       ------------      -------------
<S>                            <C>           <C>              <C>               <C>                       <C>              <C>     
Reflected as Reductions                                                                                                            
  to the Related Assets:                                                                                                           
                                                                                                                                   
Accumulated Provision                                                                                                              
  for Uncollectible                                                                                                                
  Accounts (Deduction                                                                                                              
  from Amounts Due from                                                                                                            
  Customers and Others)                                                                                                            
                                                                                                                                   
       1995                    $3,519        $18,007 (a)      $3,867 (b)        $22,021 (a)(c)            $0               $3,372  
       1994                     3,703         12,779 (a)       6,047 (b)         19,010 (a)(c)             0                3,519  
       1993                     3,723         14,139 (a)       3,516 (b)         17,675 (a)(c)             0                3,703  
                                                                                                                                   
Reserve for Perry Unit 2                                                                                                           
  Allowance for Funds Used                                                                                                         
  During Construction                                                                                                              
  (Deduction from Perry                                                                                                            
  Unit 2)                                                                                                                          
                                                                                                                                   
       1995                        $0             $0              $0                 $0                   $0                   $0  
       1994                         0              0               0                  0                    0                    0  
       1993                   212,693              0               0            212,693 (d)                0                    0  
                                                                                                                                   
                                                                                                                                   
</TABLE>      
(a) Includes a provision and corresponding write-off of uncollectible accounts
    of $10,024,000, $4,695,000 and $4,550,000 in 1995, 1994 and 1993,
    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 amounts included in the
    last base rate cases.  The amounts deferred for future recovery were
    $1,716,000, $2,382,000 and $971,000 in 1995, 1994 and 1993, respectively.

(c) Uncollectible accounts written off.

(d) Write-off of Perry Unit 2 investment.


                                     S-2
<PAGE>   132

         THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

               SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS      
             FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993    
                                                                     
                            (THOUSANDS OF DOLLARS)                  
                                                                    
<TABLE>                                                              
<CAPTION>                                                                                                                          
                                                       Additions                          Deductions                               
                                             -----------------------------      ---------------------------------                  
                              Balance at      Charged to                          Deductions                           Balance at  
                              Beginning         Income                               from                                End of    
Description                   of Period       Statement         Other              Reserves            Other             Period    
-----------                   ---------      ------------     ------------      --------------       ------------      ------------
<S>                            <C>           <C>              <C>               <C>                       <C>              <C>     
Reflected as Reductions                                                                                                            
  to the Related Assets:                                                                                                           
                                                                                                                                   
Accumulated Provision                                                                                                              
  for Uncollectible                                                                                                                
  Accounts (Deduction                                                                                                              
  from Amounts Due from                                                                                                            
  Customers and Others)                                                                                                            
                                                                                                                                   
       1995                    $2,129        $12,665 (a)      $2,585 (b)        $15,053 (a)(c)            $0               $2,326  
       1994                     2,313          8,354 (a)       4,508 (b)         13,046 (a)(c)             0                2,129  
       1993                     2,333          9,280 (a)       1,813 (b)         11,113 (a)(c)             0                2,313  
                                                                                                                                   
Reserve for Perry Unit 2                                                                                                           
  Allowance for Funds Used                                                                                                         
  During Construction                                                                                                              
  (Deduction from Perry                                                                                                            
  Unit 2)                                                                                                                          
                                                                                                                                   
       1995                        $0             $0              $0                 $0                   $0                   $0  
       1994                         0              0               0                  0                    0                    0  
       1993                   124,398              0               0            124,398 (d)                0                    0  
                                                                                                                                   
                                                                                                                                   
</TABLE>                                                            
                                                                        
(a) Includes a provision and corresponding write-off of uncollectible
    accounts of $6,584,000, $2,499,000 and $2,447,000 in 1995, 1994 and 1993,
    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 amount.  

(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
    $1,273,000, $1,971,000 and $507,000 in 1995, 1994 and 1993, respectively.

(c) Uncollectible accounts written off.                     

(d) Write-off of Perry Unit 2 investment.       






                                     S-3
<PAGE>   133



                          THE TOLEDO EDISON COMPANY
               SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS    
             FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993     
                                                                  
                            (THOUSANDS OF DOLLARS)                 
                                                                   
<TABLE>                                                     
<CAPTION>                                                                                                                          
                                                       Additions                          Deductions                               
                                             -----------------------------      ---------------------------------                  
                              Balance at      Charged to                          Deductions                           Balance at  
                              Beginning         Income                               from                                End of    
Description                   of Period       Statement         Other              Reserves            Other             Period    
-----------                   ---------      ------------     ------------      --------------       ------------      ------------
<S>                            <C>           <C>              <C>               <C>                       <C>              <C>     
Reflected as Reductions                                                                                                            
  to the Related Assets:                                                                                                           
                                                                                                                                   
Accumulated Provision                                                                                                              
  for Uncollectible                                                                                                                
  Accounts (Deduction                                                                                                              
  from Amounts Due from                                                                                                            
  Customers and Others)                                                                                                            
                                                                                                                                   
       1995                    $1,390         $5,342 (a)      $1,282 (b)         $6,968 (a)(c)            $0               $1,046  
       1994                     1,390          4,425 (a)       1,539 (b)          5,964 (a)(c)             0                1,390 
       1993                     1,390          4,859 (a)       1,703 (b)          6,562 (a)(c)             0                1,390  
                                                                                                                                   
Reserve for Perry Unit 2                                                                                                           
  Allowance for Funds Used                                                                                                         
  During Construction                                                                                                              
  (Deduction from Perry                                                                                                            
  Unit 2)                                                                                                                          
                                                                                                                                   
       1995                        $0             $0              $0                 $0                   $0                   $0  
       1994                         0              0               0                  0                    0                    0  
       1993                    88,295              0               0             88,295 (d)                0                    0  
                                                                    
                                                                   
</TABLE>                                                              
                                                                       
(a) Includes a provision and corresponding write-off of uncollectible    
    accounts of $3,440,000, $2,196,000 and $2,103,000 in 1995, 1994 and 1993,   
    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
    $443,000, $411,000 and $464,000 in 1995, 1994 and 1993, respectively.   
                                                                       
(c) Uncollectible accounts written off.                            

(d) Write-off of Perry Unit 2 investment.           



                                     S-4
<PAGE>   134

          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, 1995 and December 31, 1994 and their historical income
statements for each of the three years ended December 31, 1995.

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.

<TABLE>
<CAPTION>
                 COMBINED PRO FORMA CONDENSED BALANCE SHEETS
                   OF CLEVELAND ELECTRIC AND TOLEDO EDISON
                                 (Unaudited)
                            (Millions of Dollars)

                                               At December 31, 1995           
                                 ---------------------------------------------
                                     Historical      
                                 --------------      
                                 Cleveland   Toledo   Adjust-        Pro Forma
                                 Electric    Edison   ments           Totals  
                                 ---------   ------   -------        ---------
<S>                                 <C>        <C>      <C>             <C>
Assets
------
Property, Plant and Equipment     $7,724     $3,485    $  -          $11,209
Less:  Accumulated Depreciation
  and Amortization                 2,693      1,405       1 (R)        4,099
                                   -----      -----     ----          ------
  Net Property, Plant and
    Equipment                      5,031      2,080      (1)           7,110
Current Assets                       598        327     (24)(A)          901
Regulatory and Other Assets        1,523      1,067     (11)(B)        2,579
                                   -----      -----    -----        --------

  Total Assets                    $7,152     $3,474    $(36)        $ 10,590
                                   =====      =====     ====          ======

Capitalization and Liabilities
------------------------------
Capitalization:
  Common Stock Equity             $1,127     $  763    $  -          $ 1,890
  Preferred Stock:
    With Mandatory Redemption
      Provisions                     215          5       -              220
    Without Mandatory Redemption
      Provisions                     241        210       -              451
  Long-Term Debt                   2,666      1,068       -            3,734
                                   -----      -----     ---           ------
      Total Capitalization         4,249      2,046       -            6,295
Current Liabilities                  796        329     (27)(A,R)      1,098
Deferred Credits and Other
  Liabilities                      2,107      1,099      (9)(A,B)      3,197
                                   -----      -----     ----          ------
  Total Capitalization and
    Liabilities                   $7,152     $3,474    $(36)         $10,590
                                   =====      =====     ====          ======
</TABLE>



                                     P-1
<PAGE>   135
     

<TABLE>
<CAPTION>
                                               At December 31, 1994           
                                 ---------------------------------------------
                                     Historical    
                                 ------------------
                                 Cleveland   Toledo   Adjust-        Pro Forma
                                 Electric    Edison   ments           Totals  
                                 ---------   ------   -------        ---------
<S>                               <C>        <C>       <C>           <C>
Assets
------
Property, Plant and Equipment     $7,637     $3,435    $  -          $11,072
Less:  Accumulated Depreciation
  and Amortization                 2,486      1,273       -            3,759
                                   -----      -----     ---           ------
  Net Property, Plant and
    Equipment                      5,151      2,162       -            7,313
Current Assets                       584        322     (22)(A)          884
Regulatory and Other Assets        1,416      1,018     ( 7)(B)        2,427
                                   -----      -----     ----          ------

  Total Assets                    $7,151     $3,502    $(29)         $10,624
                                   =====      =====     ===           ======

Capitalization and Liabilities
------------------------------
Capitalization:
  Common Stock Equity             $1,058     $  685    $  -          $ 1,743
  Preferred Stock:
    With Mandatory Redemption
      Provisions                     246          7       -              253
    Without Mandatory Redemption
      Provisions                     241        210       -              451
  Long-Term Debt                   2,543      1,154       -            3,697
                                   -----      -----     ---           ------
      Total Capitalization         4,088      2,056       -            6,144
Current Liabilities                  958        316     (24)(A)        1,250
Deferred Credits and Other
  Liabilities                      2,105      1,130     ( 5)(A,B)      3,230
                                   -----      -----     ----          ------
  Total Capitalization and
    Liabilities                   $7,151     $3,502    $(29)         $10,624
                                   =====      =====     ===           ======
</TABLE>
                                     P-2
<PAGE>   136
<TABLE>
<CAPTION>
               COMBINED PRO FORMA CONDENSED INCOME STATEMENTS
                   OF CLEVELAND ELECTRIC AND TOLEDO EDISON
                                 (Unaudited)
                            (Millions of Dollars)

                                           Year Ended December 31, 1995       
                                 ---------------------------------------------
                                     Historical
                                 --------------
                                 Cleveland   Toledo   Adjust-        Pro Forma
                                 Electric    Edison   ments           Totals  
                                 ---------   ------   -------        ---------
<S>                               <C>        <C>     <C>              <C>
Operating Revenues                $1,769     $ 874    $(127) (C,R)    $ 2,516
Operating Expenses                 1,371       686     (129) (C,D,R)    1,928
                                   -----      ----     -----           ------
  Operating Income                   398       188        2               588
Nonoperating Income                   31        19       (2) (D)           48  
                                   -----      ----     -----           ------  
  Income Before Interest Charges     429       207         -              636
Interest Charges                     245       110         -              355   
                                   -----      ----     -----           ------
Net Income                           184        97         -              281
Preferred Dividend Requirements       43        18         -               61
                                   -----      ----     -----           ------
Earnings Available for Common
  Stock                           $  141     $  79     $   -           $  220   
                                   =====      ====      ====              ===
</TABLE>

<TABLE>
<CAPTION>
                                           Year Ended December 31, 1994       
                                 ---------------------------------------------
                                     Historical
                                 --------------
                                 Cleveland   Toledo   Adjust-        Pro Forma
                                 Electric    Edison   ments           Totals  
                                 ---------   ------   -------        ---------
<S>                               <C>        <C>       <C>             <C>
Operating Revenues                $1,698     $ 865     $(141)(C)       $2,422
Operating Expenses                 1,302       685      (143)(C,D)      1,844
                                   -----      ----      ----            -----
  Operating Income                   396       180         2              578
Nonoperating Income                   31        17        (2)(D,E,R)       46
                                   -----      ----      ----            -----
  Income Before Interest Charges     427       197         -              624
Interest Charges                     242       115        (1)(E)          356
                                   -----      ----      ----            -----
  Net Income                         185        82         1              268
Preferred Dividend Requirements       45        20         1(R)            66
                                   -----      ----      ----            -----
Earnings Available for Common
  Stock                           $  140     $  62     $   -           $  202
                                   =====      ====      ====            =====
</TABLE>

<TABLE>
<CAPTION>
                                           Year Ended December 31, 1993       
                                 ---------------------------------------------
                                     Historical
                                 --------------
                                 Cleveland   Toledo   Adjust-        Pro Forma
                                 Electric    Edison   ments           Totals  
                                 ---------   ------   -------        ---------
<S>                                          <C>       <C>             <C>
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)
                                   =====      ====      ====            ======
</TABLE>

                                     P-3
<PAGE>   137



 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.
(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


<PAGE>   138

                                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 indicated
in parenthesis following the description of such exhibits and are incorporated
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.)

<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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 (Exhibit 10b(2)(1), 1993 Form
                    10-K, File Nos. 1-9130, 1-2323 and 1-3583).
10b(3)              CAPCO Basic Operating Agreement As Amended January 1, 1993
                    among the CAPCO Group members regarding coordinated
                    operation of the members' systems (Exhibit 10b(3), 1993
                    Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
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
                    (Exhibit 10b(4), 1993 Form 10-K, File Nos. 1-9130, 1-2323
                    and 1-3583).
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).
</TABLE>



                                     E-1
<PAGE>   139



<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
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).
</TABLE>





                                     E-2
<PAGE>   140



<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
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).
</TABLE>





                                     E-3

<PAGE>   141


<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
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).
</TABLE>





                                     E-4

<PAGE>   142


<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
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 June 29, 1995, between
                    Centerior Service Company and Donald C. Shelton effective
                    July 1, 1995 and extending until August 31, 1996.

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 (Exhibit 10e(2),
                    1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583).
</TABLE>





                                     E-5

<PAGE>   143


<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                                       <C>
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, 1995 (to be filed by amendment).
</TABLE>

                          CENTERIOR ENERGY EXHIBITS
                          -------------------------

<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                                       <C>
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 (CEC)          *Indemnity Agreements between Centerior and certain of its
                    current directors and officers.

21 (CEC)           *List of subsidiaries.

23a (CEC)          *Consent of Independent Accountants.

23b (CEC)          *Consent of Counsel for Centerior Energy.

24 (CEC)           *Powers of Attorney of Centerior Energy directors and
                    officers required to sign the Report.

27 (CEC)           *Financial Data Schedule for the period ended
                    December 31, 1995.
</TABLE>

                          CLEVELAND ELECTRIC EXHIBITS
                          ---------------------------

<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                                       <C>
3a                  Amended Articles of Incorporation of Cleveland Electric,
                    as amended, effective May 28, 1993 (Exhibit 3a, 1993 Form
                    10-K, File No. 1-2323).

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:
</TABLE>


                                     E-6


<PAGE>   144

<TABLE>
<CAPTION>


Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
</TABLE>




                                     E-7
<PAGE>   145



<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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
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).
                    No. 1-2323).
4b(65)              January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No.
                    1-2323).
</TABLE>

                                     E-8
<PAGE>   146


<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                <C>
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).
4b(69)              September 15, 1994 (Exhibit 4(a), September 30, 1994
                    Form 10-Q, File No. 1-2323).
4b(70)              May 1, 1995 (Exhibit 4(a), September 30, 1995 Form 10-Q,
                    File No. 1-2323).
4b(71)              May 2, 1995 (Exhibit 4(b), September 30, 1995 Form 10-Q,
                    File No. 1-2323).
4b(72)              June 1, 1995 (Exhibit 4(c), September 30, 1995 Form 10-Q,
                    File No. 1-2323).
4b(73)             *July 15, 1995.
4b(74)             *August 1, 1995.

4c                  Open-End Subordinate Indenture of Mortgage between The
                    Cleveland Electric Illuminating Company and Bank One,
                    Columbus, N.A., as Trustee, Dated as of June 1, 1994
                    (Exhibit 4(a), August 26, 1994 Form 8-K, File No. 1-2323).

10                 #1978 Key Employee Stock Option Plan (Exhibit 1, File No.
                    2-61712).

21 (CEI)           *List of Subsidiaries.

23a (CEI)          *Consent of Independent Accountants.

23b (CEI)          *Consent of Counsel for Cleveland Electric.

24 (CEI)           *Powers of Attorney of Cleveland Electric directors and
                    officers required to sign the Report.

27 (CEI)           *Financial Data Schedule for the period ended
                    December 31, 1995.
</TABLE>





                            TOLEDO EDISON EXHIBITS
                            ----------------------

<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                                       <C>
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).
</TABLE>

                                     E-9
<PAGE>   147

<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
                    Supplemental Indentures between Toledo Edison and the
                    Trustee, Supplemental to Exhibit 4b(1), dated as follows:

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).
</TABLE>

                                     E-10
<PAGE>   148



<TABLE>
<CAPTION>
Exhibit Number                          Document
--------------                          --------
<S>                 <C>
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).
4b(42)              September 15, 1994 (Exhibit 4(b), September 30, 1994 Form
                    10-Q, File No. 1-3583).
4b(43)              May 1, 1995 (Exhibit 4(d), September 30, 1995 Form 10-Q,
                    File No. 1-3583).
4b(44)              June 1, 1995 (Exhibit 4(e), September 30, 1995 Form 10-Q,
                    File No. 1-3583).
4b(45)              July 14, 1995 (Exhibit 4(f), September 30, 1995 Form 10-Q,
                    File No. 1-3583).
4b(46)              July 15, 1995 (Exhibit 4(g), September 30, 1995 Form 10-Q,
                    File No. 1-3583).

4c                  Open-End Subordinate Indenture of Mortgage between The
                    Toledo Edison Company and Bank One, Columbus, N.A., as
                    Trustee, Dated as of June 1, 1994 (Exhibit 4(b),
                    August 26, 1994 Form 8-K, File No. 1-3583).

24 (TE)            *Powers of Attorney of Toledo Edison directors and officers
                    required to sign the Report.

27 (TE)            *Financial Data Schedule for the period ended
</TABLE>            December 31, 1995.    
                                          

Pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, the
Registrants 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
thereunder 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 furnished by
the Registrants to share owners upon written request and upon receipt 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


                                      



                                      



<PAGE>   149
                              CENTERIOR EXHIBITS